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DATE

Thursday, Aug. 13, 2026, at 5 p.m. ET

CALL PARTICIPANTS

• Elevate IR-Laurent Weil
• President and Chief Executive Officer-Doug Schick
• Chief Operating Officer-R.T. Dukes
• Chief Financial Officer-Bobby Long

TAKEAWAYS

• Revenue -- $46.1 million, a 561% increase year over year, driven by higher sales volumes following the Juniper merger and higher realized pricing.
• Net Income -- $17.5 million, representing $1.31 per share, compared to a net loss of $1.7 million in the prior year period.
• Adjusted EBITDA -- $18.7 million, increasing 516% year over year and 3% sequentially, reflecting the expanded production base.
• Average Daily Production -- 6,801 BOE per day, a 348% increase year over year but a 16% sequential decline.
• Total Production -- 618,912 BOE, comprising 450,607 Bbls of crude oil, 512,805 Mcf of natural gas, and 82,838 Bbls of NGLs.
• Realized Oil Price -- $94.07 per barrel, representing a 53% increase versus the second quarter of 2025.
• Realized Natural Gas Price -- $2.10 per Mcf, a 22% decrease compared to the prior year period.
• Realized NGL Price -- $31.98 per barrel, a 22% increase year over year.
• Lease Operating Expense -- $16.4 million, remaining essentially flat with the first quarter on an absolute basis while increasing year over year due to the expanded asset footprint.
• General and Administrative Expense -- $3.4 million, a 101% increase year over year, driven by additional payroll and higher legal and audit costs associated with company growth.
• Depreciation, Depletion, and Amortization -- $10.2 million, up $6.3 million year over year due to higher production and a larger asset base.
• Interest Expense -- $2.0 million, including $1.8 million in credit facility interest and $0.2 million in amortization of deferred financing costs.
• Derivative Contract Income -- $5.0 million, reflecting a $13.1 million unrealized mark-to-market gain that offset $8.1 million in realized settlement losses.
• Credit Facility Debt -- $85 million, a $13 million reduction from $98 million at the end of the first quarter as the company accelerated repayments.
• Net Funded Debt -- Approximately $73 million, when adjusted for the cash balance at quarter's end.
• Working Capital Deficit -- $8.6 million, excluding derivative contracts, representing a reduction from $34.1 million at the end of 2025.
• Adjusted EBITDA Guidance -- $60 million to $70 million for the full year 2026, supported by $36.8 million generated in the first half of the year.
• Development Inventory -- Over 20 gross wells, planned for drilling or participation across the asset base during the remainder of the year.
• D-J Basin Acreage -- Approximately 88,605 net acres, containing interests in 74 gross operated and 110 gross non-operated wells.
• Powder River Basin Acreage -- Approximately 202,100 net acres, including interests in 156 gross wells with stable production.
• Permian Basin Acreage -- Approximately 14,505 net acres, with interests in 38 gross wells providing a stable production base.
• Cash and Restricted Cash -- $12.1 million, providing liquidity to support the upcoming second-half development program.
• Capital Expenditures -- $20 million paid for drilling and completion costs during the first six months of 2026.
• Operating Income -- $15.4 million, more than doubling sequentially from $6.7 million in the first quarter.
• Shares Outstanding -- 13.3 million shares, as of June 30, 2026, following the 1-for-20 reverse stock split.

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RISKS

• Dukes stated, "July production was lower than initially expected," because of temporary shut-ins related to completion activities and the acceleration of optimization projects.
• Schick warned that in the D-J Basin, "permitting is the biggest bottleneck," which impacts the pace at which wells can be brought to development.
• Schick indicated that in the Powder River Basin, drilling is restricted by seasonal stipulations "to where you can only drill at certain times of the year."

SUMMARY

PEDEVCO (PED -1.51%) management reported that the second-quarter results reflected the expanded scale of the asset base following the October 2025 merger. The company transitioned its capital allocation strategy from debt reduction and working capital stabilization toward an active development program. This shift was supported by the resolution of environmental litigation in Wyoming and the stabilization of the balance sheet. Management indicated that operational focus has centered on field optimization projects intended to reduce recurring costs. The company stated that it intends to fund its enhanced drilling activities through internal cash flow while maintaining a target leverage profile.

• Dukes indicated that the company pulled forward its optimization program into the summer "to beat worse weather in the winter" and trade off earlier costs for durable long-term savings.
• Schick noted that the development program expansion was possible because "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."
• Management reported that it identified near-term projects after performing "months of asset analysis, permitting and development planning" following the close of the merger.
• Schick reported that the company achieved a debt-to-EBITDA ratio of "about 1x," representing a reduction from 1.6x immediately following the merger.
• Long explained that the unrealized mark-to-market gain of $13.1 million on derivative contracts was an accounting entry rather than a cash inflow.

INDUSTRY GLOSSARY

• BLM: Bureau of Land Management, a federal agency responsible for managing public lands and mineral rights.
• BOE: Barrels of oil equivalent, a unit of energy that combines oil and natural gas volumes based on their energy content.
• D-J Basin: Denver-Julesberg Basin, a hydrocarbon-producing geological formation in the Rocky Mountain region.
• DUC: Drilled but uncompleted well, a well that has been drilled but has not yet undergone hydraulic fracturing or completion for production.
• EBITDA: Earnings before interest, taxes, depreciation, and amortization.
• LOE: Lease operating expense, the costs required to operate and maintain wells and related equipment.
• Mcf: Thousand cubic feet, a standard unit of measure for natural gas volume.
• NGL: Natural gas liquids, hydrocarbons such as ethane, propane, and butane that are separated from natural gas.
• PRB: Powder River Basin, a major coal and oil-producing region in Wyoming and Montana.
• 3-Way Collar: A derivative strategy used to hedge commodity prices, involving the purchase of a put option and the sale of a call option and a lower-priced put option.

Full Conference Call Transcript

Operator: Good afternoon, and welcome to PEDEVCO Corp's Second Quarter 2026 Earnings Conference Call. [Operator Instructions] I would now like to turn the call over to Laurent Weil of Elevate IR. Please go ahead.

Laurent Weil: Thank you, operator, and good afternoon, everyone. Welcome to PEDEVCO's Second Quarter 2026 Earnings Call. With me today are Doug Schick, President and Chief Executive Officer; R.T. Dukes, Chief Operating Officer; and Bobby Long, Chief Financial Officer. Before we begin, I'd like to remind everyone 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 10-Q filing. These non-GAAP measures should not be considered in 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 R.T. 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.

John Schick: 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 BOE 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, PEDEVCO 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 D-J, 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. Turning 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 D-J Basin wells that came online in late '25 reached peak production early this year and have since followed their natural decline curves. As a result, the sequential improvement in revenue was driven mostly by oil prices. 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. R.T. will discuss the optimization program in more detail, but our focus is on pump conversions, recompletions, well cleanouts, 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 toward 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 rate-of-return projects available for near-term development. We have recently completed a previously drilled well in the D-J 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. With that, I will turn it over to R.T.

Reagan Dukes: 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. 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 D-J Basin wells that came online in late '25, and reached peak production early in the year. And those wells have followed their natural decline curve since. Let me walk through our three major basins.

In the D-J, 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, 12.5 net non-operated wells. During the quarter, we continued our field optimization program. Our planned 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 are non-op. During the quarter, permitting matters did improve in Wyoming through BLM through some litigation that was resolved -- environmental litigation 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, 34.5 net wells, all of which we operate. The asset continues to provide a stable production base. We remain focused on the operating efficiency and continue 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 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, recompletions, well cleanouts, 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 benefits 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 realized 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. LOE 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 mark-to-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. GAAP 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 $18.7 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. The balance 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: [Operator Instructions] Our first question comes from the line of Dave Storms with Stonegate.

David Storms: I wanted to start with the development plan. We were 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.

John Schick: Hey, Dave. This is Doug. Good question. No, it's partially 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, 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 Storms: Understood. So then it's fair to say that the development program is maybe biased toward 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 in your prepared remarks 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.

John Schick: Well, so over the first and second quarter, we've been able to get a debt to EBITDA down to about 1x, which is a level we're comfortable at after the merger, I think we came out at about 1.6x and had some 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 -- our enhanced development program for the remaining portion of the year within cash flow.

David 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?

John Schick: It really depends on the basin, right? I mean, so in the Colorado D-J Basin, permitting is the biggest bottleneck. In Wyoming, it's really stips 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 further comment on what would be some of the bottlenecks to development?

Reagan Dukes: 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-2026 with BLM litigation resolved. So I think we're in a really good spot to action 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 Storms: That's great commentary. R.T., 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.

Reagan Dukes: Yes, we've got a great team that's executed really well. 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 could 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?

Operator: Our next question comes from the line of Nicholas Pope with ROTH Capital. And I'm currently showing no further questions at this time. I will now turn the call back over to J. Douglas Schick for closing remarks.

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

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