Prairie Operating Co. (PROP) Earnings Call Transcript & Summary

Thanks, Operator. Hello, everyone, and we appreciate you being here for Prairie Operating Company's call covering results from the second quarter of 2025. Prior to sharing our comments, I want to remind everyone listening that today's remarks will contain forward-looking statements, and those carry certain risks, uncertainties, and assumptions. Results in reality may differ materially from what any forward-looking statements suggest. We might also discuss non-GAAP measures; for a fuller discussion of the risks and uncertainties that could make actual results differ materially from any forward-looking statements, plus reconciliations from any non-GAAP financial measures, please review the company's public filings, among them the Form 8-K filed today. An updated investor presentation has also been posted on our website. With 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; so now I'll hand things over to our Chairman, CEO, and Co-Founder, Ed Kovalik.

Thanks, Wobbe, and good morning to all of you. I'm glad you could be with us today. For Prairie, the second quarter of 2025 represents a significant leap forward, as we keep delivering across every aspect of our operations: operationally, financially, and strategically. The strides our team has taken make me extraordinarily proud. Looking ahead, we stay focused on generating durable, long-term value via prudent expansion, robust capital efficiency, and selective portfolio growth; adjusted EBITDA for the second quarter came in at $38.6 million, a fresh record for the company that speaks to the quality of our asset base, careful capital deployment, and ongoing emphasis on controlling costs. For the quarter, capital expenditures reached $56.6 million, completely in line with our one-rig development program, which aims at roughly 60 wells per year on an annualized basis. This deliberate, high-return method lets us expand efficiently while preserving operational control and flexibility on the balance sheet. From the very beginning, Prairie has made cost leadership a foundational element of our strategy. Thanks to disciplined execution and the rollout of stringent cost management systems, we've brought our latest AFEs down to $5.6 million, versus offset tiers AFEs ranging from $6.5 million to $7.2 million. Those savings flow straight into better IRRs, and we think there's still more room to improve. Our operations and procurement groups keep honing our cost structures to find additional savings throughout all drilling and completions work. In the quarter, Prairie hit a number of important milestones that highlight our company's strength and the momentum driving our strategy. We posted record production: 21,052 BOE per day, with oil making up about 50% of that, marking a quarter-over-quarter jump exceeding 540%; this expansion came from sustained robust performance at our core assets and the integration of properties we recently acquired. Crucially, our approach rests not only on organic growth but also on ongoing consolidation. Beyond our development program, we have a strong pipeline of accretive acquisition targets under continuous evaluation. Our aim is to supplement our operated inventory with top-quality bolt-ons and transactions that enhance scale, supporting capital efficiency and cash flow generation. This two-pronged strategy, disciplined organic growth plus selective high-quality acquisitions, puts Prairie in position to speed up value creation regardless of the macro backdrop. We are working to close two more acquisitions, which would add roughly 18,000 net acres and are anticipated to close in the third quarter. By putting this strategy into action and executing it, we've completed two major acquisitions since October 2024, all done off-market at appealing multiples. Every closing has brought meaningful scale, efficiency, and depth to our portfolio, greatly boosting Prairie's position as a returns-focused, oil-weighted operator in the DJ Basin. Turning to the details of each deal, the Nickel Road acquisition, finished late last year, contributed over 5,500 net acres and 26 operated wells in Weld County, plus 89 approved permits and a substantial drilling runway. The Bayswater acquisition, which closed on March 26, was a pivotal moment for Prairie. This acquisition brought in roughly 29,000 net acres, more than 350 operated locations across Weld County, Colorado, plus 77.9 million BOE of improved reserves and $1.7 billion in improved PD10 value. For our company, this deal represented a pivotal milestone. Pulling off a transaction worth over $600 million while our market cap sat below $200 million strongly validates that our team can outperform expectations, earn market confidence, and deliver with precision and credibility. Alongside our organic development, these deals constitute the foundation of our company and demonstrate our capacity to grow accretively, create value, and scale quickly while staying disciplined. My thanks go out to our entire team for their tireless efforts in sourcing, structuring, and closing these transactions. We strengthened our financial position as well by amending our $1 billion credit facility agreement with Citibank, bringing Bank of America and West Texas National Bank into our expanded lender syndicate, and reaffirming our borrowing base at $475 million with no other material changes. Our liquidity improves substantially as a result, giving us the flexibility required to carry out our strategy. Notably, after the Bayswater acquisition closed, we put in place a comprehensive hedge portfolio covering approximately 85% of our pre-developed production, including Bayswater volumes through 2025. By securing pricing, these hedges help de-risk our cash flows and support capital planning across future cycles, no matter how volatile the broader oil market becomes. During integration, we front-loaded significant investments in systems and infrastructure spanning departments, consistent with our mission of scaling the company toward 100,000 barrels of oil of production; these new systems let us minimize ongoing dependence and costs tied to outsourcing, positioning us to enhance shareholder value; we stand firmly as a growth company through the drill bit and as a consolidator, keeping our commitment to capital efficiency and operational excellence; we are also on a clear path toward achieving corporate cash flow break-even. Delivering sustainable free cash flow and returning capital to shareholders, ultimately through dividends, is our mission, and our strategy in every respect aligns with that goal. With that, I'll hand the call over to our CFO, Greg Patton, who will walk through the financial and liquidity position in more detail.

Thanks, Ed, and good morning to all of you. For Q2 of 2025, we posted robust financial results. Adjusted EBITDA reached roughly $38.6 million, which is an increase of more than 600% compared to the prior quarter. That gain stemmed from a mix of greater production volumes alongside better commodity pricing, and together those factors drove a solid financial outcome. Net income for the period was $35.7 million, which speaks to our disciplined capital deployment and the fundamental strength of the assets we hold. On the top line, we recorded total revenue of $68.1 million for the quarter, backed 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 came to $35.7 million, or $1.04 per share outstanding. As I noted, adjusted EBITDA was $38.6 million, which highlights the operational and financial progress we keep delivering. Net cash provided by operating activities for the quarter was $9.7 million. On a per barrel of oil equivalent basis, total operating expenses were $25.66 per BOE, and that figure 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 came to $8.58 per BOE. Depreciation, depletion, and amortization expense was $6.37 per BOE. These metrics reflect our integration and system implementation costs, and a significant portion of those are one-time in nature. Going forward, we will stay focused on operational efficiency, cost control, and the advantages of greater scale that followed our recent acquisitions. CapEx for the quarter was $56.6 million, in line with our development plan and reflecting continued execution of our high-return drilling program. We remain on track with our full-year capital budget, which we expect to fall between $260 million and $280 million. Now turning to our financial position as of June 30th, 2025: our leverage ratio stood at approximately 1x on an adjusted 12-month rolling average, and total liquidity was approximately $98.7 million, made up of $88 million of availability under our revolving credit facility plus $10.7 million in unrestricted cash. As a reminder, we amended our credit facility in March, reaffirming the borrowing base and aggregate elected commitment at $475 million, with an overall facility size of $1 billion and a maturity date of March 26th, 2029. That gives us ample financial flexibility to support our development program and to evaluate strategic opportunities as they come up. Our hedging program remains central to how we manage risk. After the Bayswater close, we established a comprehensive hedge portfolio to shield our expected production from commodity price fluctuation and volatility; these hedges lock in pricing of $68.04 per barrel of oil and $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. Securing prices for the bulk of what we produce means we've largely shielded the business from commodity price swings in the near term, and it puts us in a better spot to forecast cash flows and capital spending with confidence; taking this step early shows we remain dedicated to capital discipline and fiscal responsibility over the long haul. Now on to reserves: Prairie closed the quarter with total approved reserves of roughly 100 million BOE. Within that figure, 55 million BOE sits in the approved developed producing, or PDP, bucket, while the other 45 million BOE falls under approved undeveloped, or PUD. Our present development inventory holds more than 600 gross drilling locations. These reserves speak to the strength of our asset base, how deep our inventory runs, and the enduring value we're creating via disciplined investment and operational execution. Regarding integration, the handover of the assets we recently acquired has gone smoothly. We've synced up systems, made processes leaner, and drawn in and onboarded essential staff from top-tier industry players. Cultural fit has come together better than we anticipated, and the merged team is already producing results. We've likewise made important moves to guarantee continuity and efficiency throughout our supply chain. A considerable amount of effort has gone into cultivating ties with midstream providers, which locks in guaranteed takeaway optionality for the foreseeable future. Beyond that, we've finalized contracts with ProCraft and Precision Drilling that back our 2026 capital plans. Together, these agreements assist in controlling costs and reducing the risk of service interruptions. With that, I'll hand the call to Gary Hanna, our President and Co-Founder, for a thorough operational update.

Thanks, Greg. First, I want to call attention to how safely we operated throughout the business, with zero lost-time or recordable incidents during Q1 and Q2. For Prairie, protecting the environment and keeping people healthy and safe stays at the forefront, particularly while we bring newly acquired assets into our safety culture. Turning to field operations, we delivered a really strong second quarter, with certain technical advances and ongoing momentum throughout our development programs. Over the quarter, 18 wells were drilled and nine were completed. We're still positioned to bring more than 35 new wells online in total before the year is out. Our typical spud-to-total-depth time keeps getting better, and it now sits at an average of only 5.3 days, which speaks to how focused and efficient our field teams are. We're staying disciplined on costs, with well costs coming in within 5% of AFE and average D&C costs on the latest wells of roughly $5.6 million. We're continuing to push our 2 mi well AFE down in the direction of $5 million per well. One standout was how well we executed at our Rusch Pad in Weld County, made up of 11 2 mi lateral wells — eight drilled toward the Niobrara and three toward the Codell. A single run using Schlumberger's NeoSteer rotary steerable system drilled eight of those wells, which pushed average rates of penetration above 450 ft per hour, cut drilling costs, and shrank our CO2 footprint. Initial output from the Rusch Pad remains on track for early in the third quarter, showing how sharply the operational team focuses on capital efficiency. In the second quarter, Prairie hit an engineering milestone by deploying sophisticated U-shaped lateral designs along with novel well architecture, letting horizontal wells loop back inside the lease boundary and thereby raise productive lateral length in a constrained footprint. With this method, we can hit several reservoir zones and sidestep lease line constraints, boosting recovery with no extra service locations. These U-turn, or U-well, laterals amount to an innovative way of developing the subsurface that, as far as we know, has been tried in just a small number of DJ Basin wells. We managed to apply this design at our single section noble pad, where four out of the seven wells use U-shaped trajectories to maximize drainage across two stacked producing zones. Compared with standard linear 2 mi drills, those wells needed just 14 hours of extra drilling time yet deliver a 25% — 30% savings. Since we're confident about drilling and completing such wells efficiently, we are clearly looking into further uses. Ensign finished drilling all seven surface holes in May, and Precision's production rig started drilling the production intervals in early June; we also brought in an electric frac fleet, which substantially cut emissions and lowered completion costs, moving our operations even more in line with sustainability targets; in May, we kicked off completions at the Opal Coalb ank pad, going after nine previously drilled but uncompleted wells picked up in the Bayswater transaction. We carried out our first super frac with outstanding efficiency. We averaged 14 stages each day, and by the last week we had ramped up to 18 stages daily, all while averaging 22 hours of pumping time per day. Early pressure readings look encouraging — frac pressures came in roughly 10% above offset activity, which points to the possibility of better well performance. Completion work wrapped up in Q2, and the pad was opened to flow back in July. Within the first week, all nine wells were producing oil, helped by strong average flowing tubing pressures above 1,500 psi. Since we've integrated the producing Bayswater and Nickel Road assets, we've also made production optimization a priority through ongoing evaluation of every pad; that covers gas lift optimization, workover opportunities, and getting the most out of surface facilities. For instance, during the second quarter we installed gas-assisted plunger lift systems on 30 wells, which are intended to boost liquid recovery and lift overall well efficiency. Evaluation is underway on another 25 to 30 wells for implementation in Q3. On top of that, we identified and completed three high-return workovers in Q2, and more are lined up. After successful reworks, two wells came back online in June, and the third went on production at the end of July. The growth through Q2 has been tremendous, and we now run more than 360 producing wells, with additional ones on the way. Our operations team, and the organization as a whole, has been rounded out with skilled, seasoned professionals, which makes us highly scalable going forward. All in all, how we performed operationally in the second quarter shows Prairie's dedication to efficiency, innovation, and disciplined growth; we're maximizing asset value while maintaining the highest standards of environmental stewardship, capital returns, and, most importantly, safety. Once again, we stay uncompromising in our commitment to safety and environmental stewardship, both of which are central to Prairie's culture and long-term value proposition; with that, I'll turn it back to Ed for closing remarks.

Thanks, Gary. We're raising the initial full-year 2025 guidance we gave back in January, and that reflects two things: the Bayswater deal closed on March 26 of this year, and we now have better visibility across our platform following a strong quarter of integration. On production, the full-year figure moves up from 7,000 to 8,000 BOE per day to a new range of 24,000 to 26,000 BOE per day. Capital expenditure for the full year also goes up, from $120 million — $130 million to $260 million — $280 million. And finally, full-year adjusted EBITDA is being revised from $100 million — $140 million to $240 million — $260 million, assuming a WTI price of $60 to $70 per barrel. Our operational execution and results so far this year, together with the momentum we're seeing across the portfolio, are still solid, and we keep gaining from better capital efficiency and the smooth integration of acquisitions made recently. We stay disciplined in how we operate and we're excited about Prairie's future. Our commitment to building long-term shareholder value comes through two paths: pursuing double-digit organic growth via the drill bit, and going after opportunistic, transformative M&A. Above all, the company is advancing significantly toward its central goal of giving cash back to shareholders through a regular dividend program. I'd like to thank our amazing team for all their effort and commitment. Prairie's foundation has never been as strong as it is now; we're in an excellent position to keep delivering outstanding results for the rest of the year and after that. Our growth story has only just started, and we appreciate your continued loyalty; with that, I'll hand the call back to the operator so we can open the line for questions.

Hello.

Hi, Chris.

Hey, Chris.

Hey, Chris.

Hi there, it's wonderful to hear from everyone, and congratulations on both a solid quarter and getting the Bayswater acquisition integrated. I'm just wondering — when you take a look at the M&A landscape, there's been quite a bit happening up north, plus some non-core asset sales from bigger operators in the basin. What I'd like to know is how you go about evaluating returns for those incremental development locations in your portfolio against other acquisitions. In what way do you assess the potential for returns and capital accretion?

Yes, thank you, Chris. It's clear, considering the track record we have when it comes to buying assets and pulling that off — you know, big and small, from bolt-ons all the way to major acquisitions — our focus is squarely on accretive acquisitions. Because of that, we're extremely selective, and that really gets at what you're asking. We've noticed some newer press from peers in the Rockies involving divestitures at multiples of 4x EBITDA or higher. When it comes to executing deals, we've stayed very disciplined, doing them between 2x and 2.5x EBITDA. You know, we've got a fairly strong pipeline of deals we can keep executing at those levels; we truly don't see ourselves pursuing transactions that climb to those sorts of valuations; on top of that, every deal we've completed so far has been off-market rather than done through auctions, which I believe has been a big help. For us to complete accretive deals, we genuinely need to do them at a multiple that sits below the multiple our own company trades at. If we assume a 4x valuation for our company, then our stock ought to be worth roughly $9 to $10 per share. To my mind, that's an excellent multiple for us as an acquirer, yet I think it's rather pricey for the target assets we'd be buying, given how our current trading valuation stands.

All right. When you consider the different approaches for carrying out operational gains, I believe you said well costs would be brought from roughly $5.6 million to $5 million. In your view, which elements matter most for reaching those targets?

Appreciate that. A genuinely central element of the whole plan we have is keeping costs front and center, honestly to the point of treating it almost like a religion. At the outset of that effort, the quotes we received ran from $6.5 million to $7.25 million per well once every line item across the AFEs gets added up. As of today, that remains the level our offset peers are paying. Our response was to target the easiest wins initially; the largest line items got reduced first and above all else. At this point we're chasing the $50,000 here and $20,000 there. Some substantial items are still left for us to address, and a clear line of sight exists toward bringing it to $5 million for a 2 mi AFE. Operating a complete one-rig program at 100% utilization is a major help when it comes to extracting maximum efficiency from our operations. The current market also makes this a favorable moment to be a buyer. Across each line item in our RFP, we can conduct genuinely competitive RFP processes among vendors. Some unconventional moves have been made too, such as asking out-of-basin companies to submit bids. There's no justification for the DJ to function as a walled garden in which local vendors can freely inflate costs however they please; ours has become a national RFP process, and we've brought in people who are genuinely capable, highly skilled, and ready to compete. That's the route we are already far along, and more work remains, with progress to be shared on the following call.

Great. Thanks for the update, and I can't wait to see you before long.

Appreciate it, Chris.

Sure, glad to take that one. What it really comes down to is how the ramp lines up with when we actually closed. When the deal went through, we used a 12/1 effective date from last year, and at that point the Bayswater assets were putting out roughly 26,000 barrels of oil per day, with a decline rate near 20% that we had expected back when we closed. Since then, output from those assets has dropped by roughly 4,000 barrels per day. On top of that, we completed the acquisition roughly two months behind our original plan. Basically, that shifted the ramp out by that same stretch of time. This year we're bringing online nine fewer wells than we would have if the deal had wrapped up sooner. The shape of the ramp itself hasn't moved. There's no change on that front. We've also dealt with some offset shut-ins caused by nearby operators, mostly Chevron, finishing wells close to us. Because of that, we shut in a portion of our own production, though that volume is now returning fairly consistently. We expect it to get back to the levels we'd projected sometime between today and our next call. Overall, it's simply a matter of timing tied to the closing and the effective date. Understood. That's useful context. I appreciate it. Now, about the Rusch Pad — I believe the press release mentions that you expect to finish that well, or that pad, during the third quarter. Since it's this afternoon and we're nearing the halfway point, could you update us on where things stand with those completions and when you might be ready to share rates?

Yes, Gary here. Glad to take that one. As of right now, all of it remains on track; we expect it to begin quite soon. The pressure data — or rather, the output — from those wells has been quite encouraging; the promise those wells hold has us genuinely enthusiastic, and we will definitely keep you updated. It stays on schedule to arrive by the quarter's close. Thanks, Gary. Thanks, Ed. Thank you.

Sure thing. Thanks.

Hey folks, I was hoping to dig a bit deeper into the production figures. Regarding what you all released, perhaps something got muddled in how the press release was worded, but back on March 26, you mentioned an addition of 25,700 net BOE per day from Bayswater. If I understood correctly, it seems that figure wasn't actually accurate. What got added was considerably less than that. Possibly that's an outdated figure from a few months earlier, and the asset would have been in decline over those months. Could you shed some light on this for me? Maybe I'm just misinterpreting the publicly available details.