PED Q2 2026 Earnings Call: Revenue Rises 561%, EBITDA Guidance Reaffirmed

PED’s Q2 2026 results reflected the larger production base created by the Juniper merger, stronger realized oil prices and continued debt reduction. Management also reaffirmed full-year adjusted EBITDA guidance and outlined a more active development program for late 2026 and early 2027.

Key Takeaways

• Q2 revenue reached $46.1 million, up 561% year over year and approximately 15% sequentially, driven by higher sales volumes and realized pricing.
• Production totaled 618,912 BOE, or approximately 6,800 BOE per day. Volumes declined 16% sequentially as late-2025 DJ Basin wells followed their natural decline curves.
• The average realized oil price increased 53% year over year to $94.07 per barrel, helping offset lower sequential production.
• CFO Robert Long reported adjusted EBITDA of $18.5 million, versus $3.0 million a year earlier and $18.1 million in Q1 2026.
• PED repaid $13 million of revolving credit borrowings, reducing debt to $85 million. Net funded debt was approximately $73 million after adjusting for $12.1 million of cash.
• Management reaffirmed 2026 adjusted EBITDA guidance of $60 million to $70 million and plans to drill or participate in more than 20 gross wells across its asset base over the coming months.

Core Financial Data

Revenue increased by $39.1 million year over year. Management attributed $35.8 million of the increase to higher sales volumes and $3.3 million to improved realized pricing.

Derivative contracts generated a $5.0 million net gain, comprising $8.1 million of realized settlement losses and a $13.1 million non-cash unrealized gain. Management emphasized that the unrealized gain was an accounting entry rather than a cash inflow.

Business and Operating Performance

PED operates across the DJ, Powder River and Permian basins, with more than 300,000 net acres following the Juniper transaction.

In the DJ Basin, the company holds more than 88,000 net acres. Production declined as wells placed online in late 2025 moved beyond peak output. PED completed the previously drilled Hastings well after quarter-end and expects it to contribute to Q3 volumes. Nearby wells were temporarily shut in during completion work, contributing to weaker July production. Management expects volumes to improve significantly in August as those wells return to service.

In the Powder River Basin, PED holds approximately 202,000 net acres. Management said the resolution of BLM-related litigation in Wyoming improved permitting visibility and opened several higher-priority projects for development.

The Permian Basin includes approximately 14,505 net acres and 38 gross operated wells. Management described the asset as a stable production base and continues to evaluate lift conversions, well interventions and other cost-saving opportunities.

PED accelerated pump conversions, recompletions, well clean-outs and compression projects into the summer. Management said the timing was intended to avoid winter weather, improve production and generate recurring reductions in per-barrel lease operating expense.

Management Guidance

Management reaffirmed full-year 2026 adjusted EBITDA guidance of $60 million to $70 million, after reporting $36.8 million for the first half.

The company plans to drill or participate in more than 20 gross wells across its portfolio over the coming months. Management said the expanded program is not expected to contribute materially until late 2026 and early 2027. Additional details on capital spending and development plans are expected in the coming weeks.

Optimization savings are expected to build during the second half of 2026 and become more visible in the company’s 2027 operating-cost run rate.

Risks and Areas to Watch

• Sequential production declined as DJ Basin wells followed natural decline curves.
• Temporary well shut-ins and accelerated optimization work reduced July production, although management expects an August recovery.
• Lease operating expense was stable in absolute terms, but per-unit costs increased because production declined.
• Development constraints vary by basin. Management identified permitting as the main constraint in Colorado and seasonal drilling restrictions as a factor in Wyoming.
• Higher realized commodity prices improved quarterly results, while hedge settlements produced $8.1 million of realized cash losses.
• The timing and returns of the expanded development program remain dependent on project execution, permitting and commodity prices.

Analyst Q&A Highlights

Management said the expanded development program was only partly driven by commodity prices. The primary factors were the post-merger review and ranking of available projects, combined with the resolution of Wyoming BLM litigation that made additional development opportunities actionable.

PED said debt-to-EBITDA had declined to approximately 1.0x, from about 1.6x following the merger. Management believes the remaining 2026 development program can be funded within cash flow while maintaining its preferred balance-sheet position.

On operating costs, management said strong execution during Q2 increased its confidence in accelerating optimization projects. The company expects to spend a similar amount over the full year, but bringing projects forward should allow cost savings to emerge sooner.

Full Earnings Call Transcript

Complete Earnings Call Transcript

Management Remarks

Operator

Thank you. Good afternoon and welcome to BDEVCO Corp's second quarter 2026 earnings conference call. All participants are in listening mode. After the prepared remarks, we will open the call for questions. I would now like to turn the call over to Laurent Wao of Elevate IR. Please go ahead.

Unknown Speaker

Thank you, Operator, and good afternoon, everyone. Welcome to PIDAVCO's second quarter 2026 earnings call. With me today are Doug Chick, President and Chief Executive Officer, Arti Dukes, Chief Operating Officer, and Bobby Long, Chief Financial Officer. Before we begin, that today's discussion includes forward-looking statements within the meaning of the federal securities laws subject to risks and uncertainties that could cause actual results to differ materially from expectations. For more information, please refer to our second quarter 2026, Form 10-Q and other SEC filings. The company undertakes no obligation to update or revise any forward-looking statements. During today's call, we will discuss certain non-GAAP financial measures, including adjusted EBITDA and working capital, excluding derivative contract assets and liabilities.

Reconciliations to the most directly comparable GAAP measures, are available in our earnings release and TEN-Q filing. These non-GAAP measures should not be considered an isolation or as a substitute for GAAP results. I would also like to note that all per share and share count figures referenced today reflect the company's 1 for 20 reverse stock split effective March 13, 2026, applied retroactively to all periods presented. As of June 30, 2026, the company had approximately 13.3 million shares of common stock. outstanding. Here is today's agenda. Doug will begin with opening remarks, followed by Archie with an operational update, and then Bobby will walk through our financial performance. After our prepared remarks, the management team will open the call for questions. With that, I will turn it over to Doug.

Unknown Speaker

Thanks, Laurent, and good afternoon, everyone. Thank you for joining us. We are now halfway through 2026, and the second quarter provides a clear view of the earnings power of the platform we've built through the Juniper merger. Production averaged approximately 6,800 VOE per day. Revenue was $46.1 million and adjusted EBITDA was $18.7 million. Revenue increased more than fivefold year over year and approximately 15% sequentially. These results were ahead of our original expectations and reflect the combination of stronger realized oil prices and the expanded production base. To put year-over-year comparisons in perspective, Penesco was a much smaller company in the second quarter of 2025 with no debt and approximately $7 million of quarterly revenue.

Today we operate across three basins, produced more than 618,000 barrels of oil equivalent during the quarter, and generated $46.1 million of revenue. This increase in scale reflects the strategic transaction we made last October to merge with the Juniper portfolio companies, which expanded our footprint to more than 300,000 net acres across the DJ, Powder River, and Permian basins with substantial oil-weighted production and a deep development inventory. We said at the time of the merger we would significantly increase the scale and cash-generating capacity of the company, and the second quarter results demonstrate that progress. According to sequential comparisons, it is important to distinguish the impact of price from the impact of volumes. Production declined 16% from the first quarter, consistent with the production expectations we discussed on our last call. The DJ Basin wells that came online in late 2025 reached peak production early this year and have since followed their natural decline curves. As a result, the sequential improvement in revenue was driven most Our average oil price increased to $94.07 per barrel, up 53% year over year, and operating income more than doubled sequentially. from $6.7 million to $15.4 million.

Higher commodity prices, when sustained, improve the return profile of our inventory, but they do not change our approach. We're not building a plan that depends on elevated commodity prices. Our focus remains on low-cost operations, a strong balance sheet, and deploying capital only where the expected returns justify it. Turning to cost, lease operating expense was essentially flat with the first quarter on an absolute basis. Per unit costs were higher because production declined while absolute costs remained relatively stable. RT will discuss the optimization program in more detail, but our focus is on pump conversions, recompletions, well clean outs, and compression projects that are expected to reduce recurring operating costs going forward. As those savings are realized, we expect them to improve margins and strengthen the cost structure of the business over time.

The balance sheet also improved significantly during the quarter. We repaid $13 million of debt under our revolving credit facility, reducing the outstanding balance to $85 million from $98 million at the end of the first quarter. Strong cash generation allowed us to accelerate debt repayment while maintaining cash on hand. Coming out of the merger, we carried a meaningful working capital deficit. That overhang was largely resolved in the first quarter. And in the second quarter, we returned to reducing our funded debt. Adjusting for cash, net debt was approximately $73 million at quarter end.

This progress gives us greater flexibility as we evaluate additional development opportunities. With this balance sheet strength and months of asset analysis, permitting and development planning, we are now in a position to consider a more active development program. During the first half of the year, we maintained a measured approach to capital allocation focusing mostly on our production and cost optimization program and directed excess cash towards strengthening the balance sheet. That was the appropriate approach for the business and it produced the results we expected. Our stronger financial position, a more constructive commodity price environment, and the resolution of certain litigation matters in Wyoming now allow us to begin a more active development program for the remainder of the year in early 2027. Over the past several months, we have conducted extensive analysis on our 300,000-plus acre position and have identified actionable, high-rated return projects available for near-term development. We have recently completed a previously drilled well in the DJ Basin, and over the next several months we plan to drill and participate in over 20 gross wells across our asset base.

We will be announcing the details of this expanded capital program and development plan in the coming weeks. With $36.8 million of adjusted EBITDA generated in the first half, we are reiterating our full year 2026 adjusted EBITDA guidance of $60 million to $70 million. The expanded second half development program is not expected to contribute until late 2026 and early 2027, and our outlook for the balance of the year reflects the production outlook we have discussed previously. More broadly, our capital allocation framework remains straightforward. We will prioritize a strong balance sheet and the operating integrity of the existing asset base. We will then invest in optimization and development projects that meet our return thresholds while preserving the flexibility to pursue acquisitions and leasehold opportunities that strengthen our core positions. The expanded platform gives us more ways to create value, but it does not change the discipline we apply to each and every investment decision.

Taken together, we are entering the second half of the year from a stronger position than we expected at the start of 2026. The combined platform is generating meaningful cash flow, the balance sheet is healthy, and we have the flexibility to fund a disciplined development program while maintaining our return thresholds and financial priorities.

Unknown Speaker

I will turn it over to Artie. Thanks, Doug, and good afternoon, everyone. I'll keep my remarks focused on how the assets performed this quarter and what we're building toward in the second half before handing it back to Bobby to walk you through the financial results. The second quarter production of 618,912 BOE, or 6,800 BOE per day, was in line with our internal plan. The sequential decline was expected as we highlighted last quarter. As Doug mentioned, the first quarter benefited from the timing of the DJ Basin wells that came online in late 25 and reached peak production early in the year. Those wells have followed their natural decline curve since.

Let me walk through our three major basins. In the DGA, we hold approximately, or a little bit over, 88,000 net acres, an interest in 74 gross, almost 67 net operated wells, and 110 gross, 12 and a half net non-operated wells. During the quarter, we continued our field optimization program. first half participation in 10 non-operated wells with working interest ranging from 1.1 to 6.3% were completed in the first quarter. After the quarter ended, we completed the drilled but uncompleted well in Q3, our Hastings well, and we expect it to contribute to third quarter volumes. In connection with the completion, certain nearby wells were temporarily shut in, and we also accelerated several optimization projects into the third quarter. As a result, July production was lower than initially expected, but volumes will improve significantly in August as those wells return to service and the Hastings well begins contributing to our volume. In the Powder River Basin, we hold approximately 202,000 net acres and interest in over 150 gross wells, 130 net wells, of which 16 gross, 1.4 net or non-op.

During the quarter, permitting matters did improve in Wyoming through BLM through some litigation that was the result of that was resolved with the BLM. That is an important development for us because it's allowed us to permit some of our top tier wells that we plan to develop in the next year or two. And part of that underpins the second half program that Doug described. In the Permian Basin, we hold approximately 14,505 net acres and interest in 38 gross, 34 and a half net wells, all of which we operate. The asset continues to provide a stable production base. We remained focused on the operating efficiency and continued to evaluate lift conversions, well interventions, and other optimization opportunities to help improve our cost structure and margins in the basin. Now a word on the optimization program and the progress we're making.

Because it is central to our cost structure over time, we have pulled a meaningful portion of our optimization program forward. We initially had much of it spread out over most of the year, but we We have pulled that into the summer to beat worse weather in the winter. The trade-off and a little bit of cost sooner in the year for better production and better cost later in the year was deliberate. The pump conversions, re-completions, well clean-outs, and compression projects are designed to lower our per barrel lease operating expense on a recurring basis. When those savings are achieved, they are durable and they show up in LOE every period from here on after. We expect the benefit to build through the back half of the year and be more reflected in our 2027 operating cost run rate. The bottom line on operations is the asset base is performing in line with the plan.

Integration continues and we are now ready to move into an active development program with a balance sheet to support it. Bobby, I'll hand it over to you.

Robert Long

Thank you, R.T., and good afternoon, everyone. This second quarter brought together the financial priorities we have emphasized since the merger, stronger earnings, disciplined cost management, and continued balance sheet improvement. Higher realized oil and NGL prices more than offset lower production, while lease operating expenses remained essentially flat on an absolute basis, and we used available cash to accelerate debt repayment. I'll walk through each of those areas, beginning with revenue and operating costs. Starting with our second quarter results, revenue was $46.1 million, up 561% from $7 million in the prior year period, and approximately 15% from the first quarter. The year-over-year increase reflects the contribution from the expanded asset base and higher average real estate. oil price. Of the $39.1 million increase, $35.8 million was attributable to higher sales volumes and $3.3 million to higher realized pricing.

Total operating expenses were approximately $30.8 million, resulting in operating income of $15.4 million. Within that, LOE was $16.4 million and G&A was $3.4 million. The OE was essentially flat with the first quarter on an absolute basis. The year-over-year increase in G&A reflects additional payroll expense associated with the larger company and higher legal and audit costs due to the growth of the company. DD&A was $10.2 million, up $6.3 million year-over-year, driven by higher production and the expanded asset base. We also recorded $2 million of interest expense, consisting of $1.8 million of interest on credit facility borrowings and $0.2 million of amortization of deferred financing costs compared to no interest expense in the prior year period. Below the operating line, the most significant item was $5 million of net income on derivative contracts.

As in prior quarters, I want to separate the realized and unrealized components. We recorded 8.1 million of realized settlement losses, which were cash items resulting from realized oil prices exceeding the fixed prices in our contracts. This was more than offset by a 13.1 million non-cash unrealized market gain reflecting the declining commodity prices from March 31st to June 30th on our open positions. The 13.1 million unrealized gain is an accounting entry, not a cash inflow. The purpose of our hedge program is to reduce cash flow volatility, protect the capital plan, and maintain financial flexibility. GAP net income was $17.5 million, or $1.31 per share, compared to a net loss of $1.7 million in the second quarter of 2025, reflecting higher operating income from the expanded asset base and the $5 million recognized on derivative contracts. Adjusted EBITDA was $18.5 million. compared to $3 million in the prior year period and $18.1 million in the first quarter.

This represents an increase of approximately 3% sequentially. The full reconciliation from net income to adjusted EBITDA is included in our earnings press release. Turning to the balance sheet and capital allocation, at June 30th, we had cash of $12.1 million. During the quarter, we reduced borrowings under our senior secured revolving credit facility to $85 million from $98 million at March 31st, a $13 million repayment. Adjusting for cash, net funded debt was approximately $73 million, better than we had forecasted. We also had $40 million of funding availability under the facility at quarter end. Challenge Sheet is performing as we expected.

We generated more cash than planned and used a portion of the cash to reduce debt faster than planned while maintaining the capital program. This financial flexibility supports the second half development program Doug described earlier. Thank you all for your attention. I will now turn it back to the operator for questions.

Operator

Thank you. We will now begin the question and answer session. To ask a question, please press star 1-1 on your telephone and wait for your name to be announced. To withdraw your question, please press star 1-1 again. Please stand by while we compile the Q&A roster. Once again, that's Star 11 to ask a question at this time. Our first question comes from the line of Dave Storms with StoneGate. Your line is now open.

Question-and-Answer Session

David Joseph Storms

Good afternoon and thank you for taking my question. I wanted to start with the development plan. We're still evaluating your 2026 development plan last quarter, obviously added the 20 gross wells into it. Is this just mostly commodity price driven? Are there any other variables that we should be thinking about that drove this? And apologies, I did miss the first half of the call. So apologies if this was already addressed.

Unknown Speaker

Hey, Dave, good afternoon. This is Doug. Good question. No, it's partially commensurate. commodity price driven, but really it's more a function of after the merger, We wanted to evaluate and do a deep dive on all of our assets and kind of prioritize what's available for development near term, what the returns are of all of our assets. So we were kind of ranking projects. and prioritizing everything based on what's developed, you know, what can be developed over the next six months. So that's kind of how we came up with the development program. It expanded significantly because some of the BLM litigation issues in Wyoming opened up, which brought in a few projects that we didn't have the ability to do earlier in the year. So that's really the reason for the expansion.

David Joseph Storms

Understood. So, then it's fair to say that the development program is maybe biased towards speed at this point. And then maybe before you answer that, if you could maybe compare that competing use of capital with the balance sheet, I know you mentioned that you're focused on having a pretty bulletproof balance sheet right now. Just curious as to how you think about its current iteration with regards to that development program.

Unknown Speaker

Well, so over the first and second quarter, we've been able to get, you know, a debt to EBITDA down to about one times, which, which is a level we're comfortable at after the merger, I think we came out at about 1.6 times and had some working negative working capital associated too. That's all been, that's all. really been paid down and taken into account. So now we're at a place where we can really fund our remaining employees or our enhanced development program for the remaining portion of the year within cash flow.

David Joseph Storms

Understood. I appreciate that. And then maybe just one more on the development program, if you don't mind. With those wells planned and then I guess the remaining development program that you'll announce later this year, I guess, what are you seeing as the current bottlenecks? You mentioned the BLM litigation clearing up. Is it still permitting? Is there labor constraints? I guess, what do you see as your biggest hurdles right now?.

Unknown Speaker

It really depends on the basin, right? I mean, so in the Colorado DJ Basin, permitting is the biggest bottleneck. In Wyoming, it's really steps and things like that to where you can only drill at certain times of the year. And in the Permian, we don't have really very many bottlenecks at all. So R.T., do you have any thoughts? further comment on what would be some of the bottlenecks to development?.

Unknown Speaker

No, I think you hit the nail on the head. We're getting ahead with permitting now, so we don't really see that being something that slows us down post-COVID. post-2026 with BLM litigation results. So I think we're in a really good spot to action, you know, the highest priority and highest value wells that we can go develop in our portfolio when we want to, and we've got the balance sheet to do it.

David Joseph Storms

That's great commentary. Arti, if I could sneak one last question here. Just on the optimization side of things, the LOE improvements that you're seeing, I got to imagine that you wouldn't be doing optimization if you weren't seeing the LOE improvements. Are those improvements better than you were expecting, which is why you're moving some of those projects forward? Or is this to get ahead of any demand that you're seeing in the back half of the year? Maybe just any more color you could add to that. Yes, we've got a great team that's executed really well.

Unknown Speaker

We were having great execution success through Q2, and that gave us the confidence to pull some of that forward for the reasons that Doug mentioned as well. We're a lean team that's very effective and very efficient. We're proud of the people that work for us. But we would prefer to knock those out for drilling wells too. So as we knew we had confidence in a development program in the second half of the year, we pull some of that LOE savings into this year as well, spending a similar amount of dollars across the whole year. So it looks like a win-win to us. not something you delay when you have real confidence in execution. So why spread it out over time when you're having success?.

David Joseph Storms

Great to see you maintain the momentum. Thank you for taking my questions and good luck in the next quarter.

Operator

Thank you. Our next question comes from the line of Nicholas Pope with Roth Capital. Your line is now open. Nicholas Pope, your line is open. Please check your mute button. Thank you. And I'm currently showing no further questions at this time. I will now turn the call back over to Jay Douglas Schick for closing remarks.

Unknown Speaker

Thank you, operator, and thank you everyone for your time and continued interest in FDEPCO. We look forward to seeing you again.

Operator

This concludes today's conference. Thank you for your participation. You may now disconnect.

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