PED

Good afternoon, welcome to PEDEVCO Corp's first quarter 2026 earnings conference call. All participants are in listen only mode. After the prepared remarks, we will open the call for questions. I would now like to turn the call over to Laurent Weil of Elevate IR. Please go ahead.

Thank you, operator. Good afternoon, everyone. Welcome to PEDEVCO's first 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 first 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.

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 March 31st, 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. 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.

Thanks, Laurent, and good afternoon, everyone. Thank you for joining us. In our first full quarter as a combined company following the Juniper merger, our results exceeded our internal expectations across all key metrics. Production averaged 8,091 BOE per day, revenue was $40.2 million, and Adjusted EBITDA was $21.5 million. The 31 DJ Basin wells that came online in late 2025 mostly performed ahead of their type curves, which drove the production outperformance relative to our internal projections. Costs were in line with our expectations, and we made meaningful progress reducing the working capital deficit that existed at year end. Taken together, Q1 reflected a business that is executing on the plan we laid out at the merger close.

Before diving further into the quarter, I'd like to spend a moment on our development inventory review because I think it speaks to the depth and optionality this platform provides. Since the beginning of 2026, our team has been working through in-depth asset reviews to plan our future developments in late 2026 and 2027 and beyond, with a focus on creating substantial value for our shareholders. For the remainder of 2026, in the DJ Basin, we have one drilled, uncompleted well in which we hold over a 90% working interest that we plan to complete and bring online mid-summer 2026. Additionally, we are in constant communication with our partners about further 2026 development options in the DJ Basin.

In the Powder River Basin, we hold over 200,000 net acres of early-stage multi-formation inventory that we are advancing through technical evaluation with development decisions to follow as we gain further confidence in the highest return targets. In the Permian, our San Andres wells continue to produce in line with expectations, we are evaluating additional activity for the back half of the year. Across all three basins, any incremental capital commitments will be evaluated against our return thresholds and our liquidity position and the strength of our balance sheet. Higher commodity prices, when sustained, change the return profile of our inventory, they do not change the discipline of our framework. The commodity price environment is constructed today, if it remains so, we have both the inventory and the operational capacity to respond. We will not deploy capital ahead of returns that justify it.

However, we are focused on creating value for our shareholders, and we have many ways to do so. We believe we have one of the deepest inventories relative to our size of any publicly traded oil and gas company, and we plan to demonstrate that over the coming quarters and years. Relating to our first quarter results, I want to first address our net reported loss of $25.6 million. That figure was driven almost entirely by $31.3 million net loss on derivative contracts, of which $27.9 million was a non-cash mark-to-market adjustment reflecting the movement of commodity prices above our hedge strike prices during the quarter. Excluding that item and other non-cash charges, the business generated $6.7 million of operating income and, more importantly, $21.5 million of Adjusted EBITDA.

The EBITDA number is what we believe most accurately reflects the operating performance of the business in the quarter, and it represents a 404% increase over the $4.3 million we reported in Q1 2025. The full reconciliation from GAAP net loss to Adjusted EBITDA is included in the press release. The balance sheet moved decisively in the right direction during the quarter. Our working capital deficit, excluding current assets and liabilities related to derivative contracts, improved by $27.1 million from $34.1 million at year end to $7 million at March 31st. That improvement reflects the settlement of development capital and merger related payables that were outstanding at year end and illustrates the strong cash generation of the expanded asset base.

Adjusted for our cash on hand, including approximately $3.6 million of restricted cash that we expect to return to unrestricted status in the coming months, net debt at quarter end was approximately $87 million, $11 million below our funded debt of $98 million. We view this as an important milestone. Coming out of the merger, we carried a meaningful working capital deficit that was a function of the transaction and the development program underway at closing. One quarter in, that hangover has been largely resolved, resulting in strong liquidity. WTI prices over the past couple of months have resulted in continued strong cash generation for the company. Our cost came in as expected across the board, demonstrating efficient integration of the combined asset base.

Per unit lease operating expense, inclusive of recurring and non-recurring lease operating expense, workovers, gathering, processing and transportation expense, and severance and ad valorem taxes came in at $22.46 per BOE, essentially flat with the $22.21 per BOE in the prior year. Total G&A was $3.1 million for the quarter, and cash G&A was $2.6 million for the quarter, which equates to a cash G&A of $3.59 per BOE. Q1 G&A included some residual merger integration costs. As those costs roll off throughout the balance of the year, we expect further improvement.

I'm also happy to report that all of our capital expenditures incurred in Q4 2025 and paid in Q1 2026 relating to the 31 wells that were in process at the time of the merger were within or under our expectations. Turning to production cadence, I want to be clear about what to expect for the remainder of 2026 because I think the context is important. Q1 benefited from the timing of the 31 DJ Basin wells that came online in late 2025, all which reached peak production in Q1 2026. Production is expected to moderate through the middle quarters of the year as those wells follow their natural decline curves. Our second half development activity and optimization work are then expected to support incremental volumes heading into 2027.

The first quarter of this year was expected to be a relatively high production quarter, and we want to make sure investors appreciate that. Our production for the balance of the year is expected to show some decline over the next quarter or two, and our second half production is likely to be impacted by our development spending and results over the next several months. Based on the $16 million-$20 million of currently approved net capital expenditures, we continue to expect full year average production of 6,500 BOE-7,000 BOE per day and $60 million-$70 million of Adjusted EBITDA. If we revise our development and capital plans in the future, we will communicate the revised production and Adjusted EBITDA expectations as well.

Looking ahead, we remain focused on executing the optimization program, planning our future development plans while maintaining capital discipline and converting the platform we have built into a durable Rockies-focused energy company while improving cash flow and returns for our shareholders. With that, I will turn it over to R.T. Dukes.

Thanks, Doug, and good afternoon, everyone. I'll keep my remarks focused on where we are operationally and where we are headed. The story I want to tell this quarter is really about two things, what we've completed and what we're building towards. On the completion side, we incurred $3.8 million of capital expenses during the quarter on 10 non-operated DJ basin wells with working interests that range from around 1%-6.3%. All 10 are online and producing. More broadly, we continue to be disciplined in how we manage our acreage position. We have a considerable runway in our portfolio, and we will continue to concentrate our attention and resources on the inventory we intend to develop in the near future.

Looking ahead within the DJ, we're planning completion operations on a drilled but uncompleted well in Wyoming, in which we hold over a 90% working interest. First production is expected in early Q3, which will be a clean contribution to second half volumes. We continue to evaluate non-operator proposals from offset operators on an ongoing basis and will participate where the economics make sense. In the Powder River Basin, we hold approximately 202,000 acres. There was no operated drilling and completion activity during the first quarter, and production outperformed the company's internal plan with no major downtime or operational issues during the quarter as the asset benefited from a relatively mild winter. The company continues to evaluate its inventory development opportunities across its substantial PRB position.

Additionally, the company holds approximately 14,505 net acres in the Permian Basin. In the first quarter, there was no development activity, and the asset performed in line with internal expectations. The company continued to improve operational efficiency by accelerating lift conversions, thereby reducing operating costs ahead of schedule. The company continues to evaluate optimization and development opportunities for the back half of 2026. Now, the part of the operational story I want to spend the rest of my time on is our optimization program because I think it's crucial to what it can do for our cost structure over time. Our $10 million-$13 million that's earmarked for our operational optimization budget for 2026 is focused on a few things.

First, pump conversions, moving wells from jet pump and ESP to rod pumps, which carry meaningfully lower operating costs and lower ongoing workover commitments. Additionally, we are focused on well interventions and well cleanouts on wells where we believe there's incremental production to be captured at low incremental cost. In plain terms, we're converting wells to lower cost lift systems and selectively intervening in wells where we believe more production is recoverable at low incremental cost. The recurring cost savings when achieved are durable. They show up in LOE every period thereafter. The goal across all of it is to reduce the total lease operating costs on the combined asset base. Through our 2026 and 2027 optimization programs, we are targeting LOE reductions that can reach up to $1 million per month in cost savings.

As this program ramps through Q3 and Q4, we expect to see measurable improvement in total lease operating expenses, with the full benefit more visible in 2027. In terms of timeline, we initiated this work and built the proof of concept in late 2025, continued to advance and plan through the first quarter, and have ramped activity further this spring as field conditions have allowed. The majority of the work will be completed through the third and fourth quarters, with the LOE benefit building through the back half and more fully reflected in 2027. The sequencing is intentional, not a delay. Our team has worked hard to scale and maximize efficiencies of our program, and that work is now increasingly reflected in the cadence of activity we expect through the balance of the year.

The bottom-line in operations, the asset base is performing at or above expectations across the board. The integration is progressing, and we have clear line of sight to a lower cost, higher margin operating profile as the year develops. Our optimization activity is designed to compound through the back half, and the cost benefit will be the proof point we can hand investors over the next several quarters. With that, I'll hand it over to Bobby.

Thank you, R.T., and good afternoon, everyone. I'll walk through the key financial items for the quarter, focusing on the drivers behind the numbers rather than repeating figures Doug and R.T. have already covered. Starting with our first quarter results, revenue for the quarter was $40.2 million, up 360% from $8.7 million in Q1 2025. That increase is almost entirely a volume story. This was the first full quarter with a combined asset base, and the production outperformance R.T. described flowed directly through to the top line. Oil accounted for $36.6 million in total revenue, or approximately 91%, with a balance split between natural gas at $1.9 million and NGLs at $1.8 million. Realized oil price was $68.39 per bbl, roughly flat year-over-year.

Gas and NGL realizations were lower than the prior year period, reflecting the broader commodity price environment for those products, though their contribution to total revenue is modest. Total operating expenses were $33.5 million, resulting in operating income of $6.7 million. Within that, LOE was $16.4 million and G&A was $3.1 million, both of which R.T. and Doug have addressed. DD&A was $12.5 million, driven by the higher production volumes on the expanded asset base. We also recorded a $1.6 million non-cash impairment on the DJ Basin acreage that expired. No surprises in the operating cost structure. Below the operating line, the significant item was a $31.3 million net loss on derivative contracts. I want to separate this clearly into two components because they are very different in nature.

The realized portion corresponding to positions that settled in the quarter on an income statement basis was a loss of $3.4 million as a result of realized crude oil prices exceeding fixed prices in our contracts. On a net cash basis, derivative settlements during the quarter were a small inflow, as not all settled positions have cleared cash by quarter end. The difference between income statement timing and cash settlement timing is reflected in our balance sheet and will normalize over the next several periods. The unrealized portion corresponding to non-cash mark-to-market on our open positions was a loss of $27.9 million, reflecting the movement of oil prices above our hedge strike prices during the latter part of Q1. That $27.9 million is an accounting entry, not a cash outlay, as our hedge positions are mark-to-market each quarter.

Adjusted EBITDA of $21.5 million, which adds back the non-cash derivative loss along with other non-cash and non-recurring items, is the measure we believe best reflects how the business actually performed. On the structure of our hedge book, our position is balanced across swaps, costless collars, and three-way collars. The purpose of the program is to reduce cash flow volatility, protect the capital plan, and ensure project economics. While our credit facility requires us to maintain a certain level of hedging, we would expect to carry a prudent hedge position even without funded debt, given the importance of protecting cash flow and maintaining flexibility around our development activities. Turning to cash flow, net cash provided by operating activities was $10.5 million for the quarter.

That reflects strong cash margins from the expanded production base, partially offset by approximately $10.7 million use of cash from working capital, primarily reflecting the settlement of accounts payable carried from year end 2025. Cash paid for drilling and completion costs were $16.5 million, which includes approximately $3 million of carryover payments from the 2025 program. On an accrual basis, our 2026 capital spend is tracking within the guidance range. We drew $11 million under the revolving credit facility to fund non-operated well participation and other obligations during the quarter. At March 31st, we had total cash and restricted cash of $11.3 million and $98 million outstanding under our revolving credit facility against a $120 million borrowing base, leaving approximately $22 million of availability.

The $3.6 million of restricted cash relates to bonding requirements that are expected to be released within the next 90 days. Specifically, that $3.6 million is a remnant of pre-merger surety bond requirements that were cash collateralized. Following the merger, we entered into a new surety program that does not require cash collateral. Adjusting for total cash and restricted cash, net debt at quarter end was approximately $87 million, and total liquidity was approximately $33 million. Thank you for your attention. I will turn it back to the operator for questions.

Thank you. We will now begin the question and answer session. If you'd like to ask a question, please press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. Please stand by while we compile the Q&A roster. Our first question comes from Nicholas Pope with Roth Capital.

Evening, guys.

Hey, Nick. How are you?

Good, good. Got a couple questions here for you. I think, R.T., you were discussing kind of the split in CapEx, and kind of the impact of the optimization CapEx you're looking at. I was curious in the first quarter how much of kind of the spend on the CapEx, like, how much have y'all gotten to on the optimization CapEx so far since kinda I know it's only been a short period of time since the companies have kind of been together, but just curious how much of that y'all have gotten into so far.

Yeah. Nick, we really started in earnest in Q2. You know, just a broad update. We had two wells we did get converted to rod pump in Q1, below budget performing to plan, real happy with where we are. Good progress so far this quarter as well.

Just, and kinda looking at, like, where workover expenses were for the quarter, it seems like, you know, it was a, you know, lower number relative to where things were running in the fourth quarter. I guess, does it kinda tie into the same kinda starting things somewhat in earnest? 'Cause it seems like there's some connections, I would think, between that workover line item and, you know, some of the optimization CapEx work. I'm just curious as you kinda look at the field and as you've kind of integrated assets here, you know, some of that type of, like, low-hanging fruit on the expense side, where things are and what that might look like going forward.

Yeah. There's a couple of things. It was a relatively mild winter, on top of that, we spent a couple of years really preparing the fields, really after we got a cold winter a couple of years ago and had good reliability. It really kind of proved the point of what we thought, making sure our wells stayed online through, you know, the colder seasons in the winter and in the Rockies is important. We have worked to make sure our operations are resilient, I think you see that. No real issues through the winter. We purposely target that and try to make sure we have good reliability in the winter. If there's preventative things we can do in Q4, leading into the colder part of the year, we do that. I think you see that reflected in Q1.

R.T., to add to that also, that's Nick, that's partially why our optimization projects are planned mostly for spring, fall or spring, summer and fall, is so we're not out there in the middle of winter.

Got it. I'm trying to clarify a little bit on the development plans y'all talked about. You know, once that ramps up, I think y'all said one DUC that you're working on in Wyoming, and then is it that the remaining, or sorry, yeah, the one DJ DUC, right?

Correct.

Sorry. I'm looking for the split between DJ and Powder River as you kinda look at that second half development plan.

We're completing the DUC in the DJ in this summer. Optimization projects are planned for the Powder River, the DJ, and the Permian, but we haven't really split out exactly to the market what we're doing where. They're just cost saving projects across the board. We're evaluating some other development options for later this year that we'll announce when we have those, when we have that all tied up.

Got it. All right. Well, that's all I have for now. I can jump back in if I'll let somebody else ask some questions. Thanks. Look great, guys.

Great. Thank you.

Our next question comes from Dave Storms with Stonegate.

Evening, appreciate you taking my question. Wanted to start maybe with the optimization plan, just a clarification. These pump conversions and the interventions, is that across your entire portfolio, or are there portions of your portfolio where it's not appropriate maybe to do an intervention? Just maybe any breakout there would be helpful.

R.T., you wanna take that?

Yeah, for sure. I think it's fair to say it's across the bulk of the portfolio. I mean, we run ESPs and jet pumps across the entire portfolio, and just as you come off of your highest fluid producing years, you know, it makes sense to move to a more efficient lift method. Much of this was planned for years, and what we've done is just seen the ability to execute at a high level that's made us pull some of this forward. Instead of spreading it over several years, we've decided or made a decision to speed it up and complete most of the fields where we see that optionality this year and into next.

That's perfect. I appreciate it. Then maybe just wanted to double-click on development plans again. Should the environment, the macro environment stay kind of constructive for you, how would you characterize your ability to maybe go fast if needed? Do you feel like you have the capacity to really take advantage, should that be the route you decide?

Yeah. We're currently going through all of our assets, reviewing everything, identifying opportunities for late stage 2026 and 2027 development. There's some areas that we can move very fast, and there's some areas that take longer lead times, right? You know, that just depends on permitting and things like that. You know, our Permian assets, we can move very quickly on them. Our DJ Basin assets, a lot of them we can move very quickly on. Our large non-op positions in the Colorado DJ, we're working with partners on that for some second half 2026 and 2027 development. Once that comes into scope, that moves fairly quickly as well. Powder River Basin's a little longer lead times right now.

Understood. That's very helpful. Thank you. Maybe one more. I know you're kind of constrained from a government standpoint when it comes to hedging. Just given the volatility we're seeing in commodity prices, are you having to maybe spend more to put more hedges on or anything like that? Maybe said another way, you know, just what are your thoughts around your overall philosophy around your hedging portfolio outside of the government's point?

Well, when we executed the merger back in October, we were required by the bank group to hedge 75% of our production, right? I think currently right now we're somewhere in the high 60s hedged. We've benefited from some of the hedges that we put on in place. You can go through the 10-Q and look at the hedge positions. We do have some three-way hedges that have calls at 80%, we are participating in a lot of upside that we otherwise wouldn't be participating in. Looking out, you know, further over the next year or two, earlier in the month, the oil curve was heavily backwardated.

That backwardation is coming up a little, so future prices out several months are coming up to closer to what the current price is. As that happens, that could potentially give us some very nice hedging opportunities for late 2026 and 2027.

That's great. Thank you very much. I'll get back with you.

All right. Thank you.

I'd like to turn the call back to Douglas Schick for closing remarks.

Great. Thank you, operator, and thank you for all your questions. Before we close, I just want to reiterate a few things from this quarter. First, the combined platform is performing above expectations. It generated 8,091 BOE per day in the first quarter and $21.5 million of Adjusted EBITDA. The assets are operating in line with our underwriting assumptions and continue to demonstrate the scale and cash flow profile of the business post-transaction. Second, we are reiterating with confidence our full year guidance of 6,500 BOE-7,000 BOE per day and $60 million-$70 million of Adjusted EBITDA at $16 million-$20 million of net capital expenditures. Q1 was a high watermark for the year for production.

The year is slightly front-loaded due to our Q4 2025 development program that reached peak production in Q1 2026. This production cadence is what we had planned at the time of the merger. If we revise our development program and capital plans in the future, we will communicate that to the market. We will change our production and EBITDA expectations at that time. Third, the balance sheet moved decisively in the right direction this quarter. Our working capital deficit improved by $27 million. Our net debt is at $87 million. The optimization program that drives our 2027 cost structure is on track. We have a clear plan for the rest of 2026. We intend to execute it. Thank you all for your time. Thank you for your interest in PEDEVCO. Have a good day.

This concludes today's conference call. Thank you for participating. You may now disconnect.

Today's program is being recorded. I would now like to turn the call over to Laurent Weil of Elevate IR. Please go ahead, sir.

Thank you, operator, and good morning everyone. Welcome to PEDEVCO's fourth quarter and full year 2025 earnings call. With me today are Doug Shick, President and Chief Executive Officer, R.T. Dukes, Chief Operating Officer, and Bobby Long, Chief Financial Officer. Before we begin, I would like to remind everyone that today's discussion includes forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially. For more information, please refer to our 2025 Form 10-K and other SEC filings. The company undertakes no obligation to update or revise any forward-looking statements. During today's call, we may discuss certain non-GAAP financial measures, including adjusted EBITDA. Reconciliation to the most directly comparable GAAP measures are available in our earnings release and 10-K filing. These non-GAAP measures should not be considered in isolation or as substitutes for GAAP results.

I would also note that all per share and share count figures referenced today reflect the company's one-for-20 reverse stock split, which became effective on March 13, 2026, and has been applied retroactively for all periods presented. As of March 27, 2026, the company had 13,300,621 shares of common stock outstanding. As many of you know, this is PEDEVCO's first earnings call as a combined company following the completion of the Juniper merger on October 31st, 2025. Today, you will hear about both the reported results and the normalized earnings power of the combined platform, which we believe is the more relevant lens for evaluating the company going forward. Here is today's agenda. Doug will begin with opening remarks outlining the company's strategy and investment case, 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.

Thanks, Laurent, and good morning everyone. Thank you for joining us today for our first earnings call as a combined company. 2025 was a transformational year for PEDEVCO. Through the closing of our merger with the Juniper portfolio companies on October 31st, we built a scaled, Rocky-focused energy platform, which we believe is unique in the public oil and gas space due to its extensive development inventory relative to its market cap. We went from producing approximately 1,500 bbl of oil equivalent per day to a combined rate that averaged over 5,300 BOE per day in the fourth quarter. Our proved reserves nearly doubled to 32.1 million BOE, or approximately $27 per share on a post-split basis.

We hold over 310,000 net acres across the DJ Basin, Powder River Basin, and Permian Basin with an approximately 88% liquids mix and well over a decade of identified inventory. Our independent reserve engineers' valuation of our proved reserves provides a useful floor for the asset value discussion, and that valuation does not include over 1,000 additional identified drilling locations, a vast majority of which are high impact wells that can be pad drilled to multiple formations to maximize efficiency and cash returns on capital deployed. I also want to underscore the alignment at this company. Insiders, including the management team, own a significant majority of PEDEVCO, so we are focused on maximizing the value of the shares while minimizing risk.

Our largest investor, Juniper Capital, is a seasoned oil and gas private equity firm that has been investing in the space for over 20 years. Juniper invested approximately $18.6 million of new equity at the merger, which demonstrates their strong commitment to the company's success. Turning to our fourth quarter results, it's important to note that because the merger closed on October 31, our reported results only include a partial contribution from the acquired assets. In the fourth quarter, we generated $15.4 million of adjusted EBITDA on over 5,300 bbl of oil equivalent per day of production, reflecting an initial period of combined operations.

Bobby will walk you through the full bridge and our 2026 outlook, but the headline is this. Adjusted EBITDA in the fourth quarter grew 203% year-over-year, despite a 16% decline in realized crude oil prices, reflecting both the impact of the merger and the underlying operational strength. This merger wasn't just about getting bigger. It was about building scale and adding capabilities to the team, which will allow for efficiencies and additional growth. We now have production and cash flow base that allows us to operate the business more efficiently and generate strong margins while utilizing our internally generated cash flow to further develop our extensive asset base. Importantly, the core business stands on its own. We do not have to do deals to be a good company because we have such an extensive development inventory already.

From here, acquisitions are about building on our strong foundation, and our focus for any acquisition will be to build upon what we already have, which is an efficient company that generates significant cash flow and owns a large amount of attractive development opportunities. We will weigh every potential acquisition relative to our existing opportunity set. We have significant development opportunities across all three basins and will pursue that development at a pace that reflects financial discipline. The management team and our large shareholders are focused on maintaining a strong company that can thrive in any commodity price environment. Looking ahead, our focus is straightforward. First, we will continue to optimize the business, driving down cost and improving margins across the asset base. We are also focused on prioritizing our extensive development opportunity set with a goal of maximizing the risk-adjusted returns on our capital deployed over many years.

With over 1,000 identified drilling opportunities across three basins in over a dozen different formations, we have substantial optionality on where to deploy capital. I want to give investors a clear message of what we are focused on. First, you will see our cash realized per bbl produced improve over the course of 2026 as our ongoing optimization projects continue to improve our cost structure. Second, you will see us execute on a capital plan that generates strong returns on capital while maintaining a strong balance sheet. Finally, you will see PEDEVCO maintain and grow its deep inventory of development opportunities, which we plan to more fully detail over the coming quarters. As we think about 2026, the macro environment has become more constructive in the recent weeks, with geopolitical developments supporting higher oil prices. That said, our approach does not change.

We're not building a plan that depends on commodity prices moving in our favor. Our focus remains on maximizing the efficiency of every bbl produced and every dollar spent while generating consistent cash flows across cycles. If the current price environment holds, it provides incremental upside, both in terms of cash flow and the pace at which we can execute our development plans. We will remain disciplined in how we allocate capital, and we'll scale activity in line with what our business can support. With that, I will turn it over to R.T. Dukes.

Thanks, Doug, and good morning, everyone. I wanna start with what we view as the low-hanging fruit, high return activity we began immediately after the merger closed, which is our cost optimization on our existing production base. I'll cover key operational highlights. As we look ahead to 2026, a key priority for us is indeed the execution of a comprehensive cost optimization program across our assets. When we completed the transformative merger with Juniper's Rocky portfolio late last year, it significantly increased the scale and production of our company, and it presented an opportunity to optimize our overall cost structure. Specifically, we have identified around $10 million-$13 million in capital projects that we believe will drive meaningful lease operating expense or LOE reduction.

This includes things like converting high-cost jet pumps to more efficient rod pumps, as well as compression optimization projects, recompletions and well cleanouts. We expect these projects to reduce our LOE by up to $1 million per month, equating to $10 million-$12 million in annual savings. To give you a sense of where we stand, we've begun executing on a number of these optimization initiatives in the DJ Basin, including initial pump conversions and well work. This is an active, ongoing effort with identified projects and a clear plan of execution. As we move through 2026, we expect to make steady progress across these work streams and begin to see the impact in our cost structure and margins. We will report on that progress each quarter. Now turning to operations. The DJ Basin is the largest production base of the combined company.

We hold approximately 100,000 net acres across southeastern Wyoming and northern Colorado. The DJ contributed the large majority of Q4 and full-year production and is where a majority of the current 2026 capital budget is currently expected to be allocated. During 2025 in the DJ Basin, we participated in 32 wells, of which 31 began contributing production in late 2025, and one operated well will be completed in 2026. Of the 31 new wells that came online in late 2025, two of these wells were operated and 29 were non-op. In the Permian Basin, we drilled and completed four operated wells in 2025. On the production side, there are a couple of points worth highlighting. The development work initiated before and around the merger close is now being realized.

31 of the 32 wells that were in progress at closing are online and producing, and the development program is performing well. That activity is contributing to elevated production in Q1 2026, as those wells are still in their flush production phase. In fact, it's important to keep in mind that Q1 will likely be a peak production quarter for 2026. Given the number of wells brought online in a short period of time, this is not a run rate that should be annualized for us for the year. As those wells move through their decline curves, we would expect production to settle close to the levels consistent with the merger time rate of approximately 6,400-6,500 BOE per day before accounting for natural declines in new activity. Through the merger, we added over 200,000 additional net acres in the Powder River Basin.

This is a longer-dated position with meaningful resource potential across multiple formations, including the Parkman, Sussex, Niobrara, Turner, Mowry, Teapot, Shannon, and Frontier. With break-even oil prices in some of those formations as low as $30 per bbl, other active operators in this area are targeting many of them already on offset acreage with some of the largest and most sophisticated oil and gas companies like EOG, Devon, Oxy, and Continental, amongst others. Our development timing in the PRB will be driven by commodity prices, cash flow, and our expected returns, which are continually being revised based on results of third-party drilling near our assets. In the Permian, we hold approximately 14,000 net acres on the Northwest Shelf with the San Andres formation as our primary target. This asset provides a long-term, low decline, oil-concentrated asset, providing steady cash flow. Production continues to perform in line with expectations.

Across the portfolio, our focus is on maintaining flexibility, controlling costs, and allocating capital to the highest return opportunities. With those highlights, I'll turn it over to Bobby.

Thank you, R.T., and good morning, everyone. I will cover four areas today. Our financial results for the fourth quarter and full year 2025, our 2026 outlook, the balance sheet and liquidity framework, and our capital program. Starting with our fourth quarter results, we generated $23.1 million of revenue, $15.4 million of Adjusted EBITDA, and production of 483,159 BOE. These results reflect two months of contribution from the acquired assets following the October 31 merger close and provide the most relevant view of the combined platform. On a GAAP basis, reported results reflect several items tied to the merger and transition.

For the full year, we reported a net loss of $10.4 million, driven by $7.5 million of non-recurring merger costs, $8.1 million of deferred income tax expense, $1.4 million of interest expense on our credit facility, a $1.4 million note receivable write-off, and $2.8 million of additional accelerated share-based compensation. These were partially offset by gains on derivatives and asset sales. Adjusted EBITDA removes the non-cash and non-recurring items and gives you a clearer view of operating performance. Regarding unit economics, full year direct LOE was 11.62 per BOE, up from 10.36, driven entirely by higher costs of the acquired assets. As the optimization efforts take effect, we expect per unit LOE to decline through 2026, with meaningful improvement visible by mid-year.

Cash G&A, excluding merger costs, should settle into $3.50-$4 per BOE range as a larger production base absorbs overhead. Turning to our 2026 outlook, as noted in our earnings release, we are projecting full year 2026 Adjusted EBITDA of $60 million-$70 million. That range is based on average realized oil prices of $65 per bbl and average realized gas prices of $3.50 per Mcf, and it reflects our current expected capital program. I want to be clear about what is and is not in that range. It assumes the base production profile plus the benefit of our cost optimization work. It does not assume incremental operated development beyond what has been planned. If we elect to pursue additional high return development, there will be upside to that range.

This highlights the flexibility of the company. With our deep inventory, we have many levers to pull to increase returns to shareholders. On to the balance sheet. At December 31st, we had $87 million drawn under our senior secured revolving credit facility led by Citibank. The facility has a $120 million borrowing base under a $250 million maximum commitment and matures October 31, 2029. Since year-end, we drew an additional $11 million, bringing the total to $98 million as of February 5, 2026, with approximately $25 million of total liquidity remaining. Our spring redetermination will provide updated view on borrowing base capacity.

Turning to the capital program, our currently known capital expenditures for 2026 are $16 million-$20 million, approximately $6 million-$7 million for DJ Basin drilling completion capital, including approximately $3 million of 2025 carryover, and approximately $10 million-$13 million for the optimization projects RT described. Approximately 90% of the current capital budget is allocated to the DJ Basin. However, as noted previously, the amounts and allocation are likely to be revised over time. We expect to fund the program through operating cash flow, existing cash, and facility availability. At $65 oil, we project a leverage ratio of approximately 1.2-1.3x net debt to EBITDA by year-end. Any decisions to expand the capital program will be governed by commodity prices, cash flow, and our commitment to conservative leverage.

In general, we are focused on maintaining leverage of 1.5x or less using conservative commodity price assumptions. We are not committing to a second half development acceleration at this time, though we are evaluating operating development options. As our cost optimization reaches full run rate and the combined platform generates a full year of cash flow, we expect the financial profile of this company to strengthen meaningfully into 2027. Thank you all for your attention. I will now turn it back to the operator for questions.

Certainly. Our first question for today comes from the line of Nicholas Pope from Roth Capital. Your question, please.

Hey, good morning, everyone.

Morning, Nick..

Kind of curious about the capital program. Obviously prices have been pretty elevated here for the commodities. I guess what would it take to pivot to more activity? I guess specifically in the DJ Basin, like how drill ready is Devon at this point to add more activity if kind of higher prices persist for longer, and that becomes something y'all would kinda like to pursue just more activity in the basin? I guess, how ready are you? Are the pipes ready? Are the rigs ready? How long would it take to pivot to more activity if that's what y'all decide to do at some point?

Yeah. Nick, you know, considering the current price environment, we are doing extensive asset reviews on what our second half in 2027 development programs are going to look like. Particularly in the DJ Basin, there is flexibility to stand up a rig relatively quickly, like not in the next month, but you know, in the next few months if that opportunity exists. Also, we have significant partner-operated type developments that could be coming at us in the second half in 2027 in the DJ Basin. There's There's significant flexibility to increase the development program and CapEx program if prices warrant and if the curve, you know, if the backwardation in the curve kind of straightens out a little bit.

In terms of permitting, what's the timeframe to get prepared from a permitting standpoint? I guess maybe and is it different on both sides of that Colorado, Wyoming.

Yeah. It's different on both sides of the border, right? In Colorado, it takes a lot longer. We have one permitted DSU, which is six-seven wells that is actionable. We also have another DSU in progress right now. You know, that's 12-13 wells that could be ready in the next, call it, six-nine months. On the Wyoming side, we have some infill opportunities on our North Silo field. We also have all of our partner-operated projects in Colorado that, you know, we don't necessarily control the development of those. Those, some of those AFEs will likely be coming at us in the second half and into 2027 as well.

Kind of moving over to the Powder River Basin, I guess, what steps are left in terms of evaluating the resource and the potential? I know, R.T., you hit a little bit on it. I guess what risks remain in kind of understanding that resource and maybe, you know, it sounds like maybe it's a 2027 or kind of beyond, kind of plan to kind of target more activity up there. Curious what steps are remaining there to kind of understand the potential.

There are some locations up there that are actionable sooner than 2027-2028. However, we're currently going through our asset reviews to really understand that asset. You know, we're working on a few different areas that we think are highly prospective, but we don't have any announcements on anything, you know, any development plan up there in the next six months.

Got it. All right. That's great. I appreciate the time, guys.

Thanks, Nick.

Welcome.

Thank you. Our next question comes from the line of Dave Storms from Stonegate. Your question, please.

Morning, and thank you for taking my questions.

Morning, Dave.

Morning. Just wanted to maybe start with some of the optimization initiatives. I know you mentioned the $10 million-$13 million that could be coming out this year. I guess, how far along do you feel like you are in the identification of what can be taken out? Could we see other projects of this size over the coming quarters? Is there any place that you're looking, you know, maybe the first rocks that you're looking under for those projects?

Well, the optimization projects began pretty much right before the beginning of the year. RT, what do you think the timing is on that? I mean, we basically plan to have most of that work done by the third, fourth quarter of this year, on the LOE side. On the G&A side, you know, we're working through merger costs and things like that and combining the entities and getting everything rationalized. You know, $13 million-$15 million of annualized EBITDA additions from optimization is really kind of a late 2026, 2027 event as we work through it through this year.

Yeah, that's right, Doug. You know, you know, leading into winter, we backed off, and then we're picking back up coming out of the winter, you know, up in Wyoming on our field optimization and continue throughout the year and into midyear 2027.

That's perfect. I really appreciate that. Maybe just following up on that. Post-merger, you know, you've had the company for a couple months now. I guess maybe some of your thoughts around the scale and production capacity as it currently sits relative to maybe your expectations pre-merger. I know you mentioned that you're still looking at, you know, 6,400-6,500 BOE per day. I guess has anything else changed relative to where you thought you'd be, call it, last September, October?

Yeah. I mean, I think our you know, when we did the merger, we had 32 wells in progress, right? The majority of those wells have outperformed their type curves. First quarter looks pretty good. As we stated in the script here, you know, you can't extrapolate the first quarter over the entire year. However, we do think that, you know, we've got a very solid production base. As far as growing the asset organically, for a small cap E&P company, public E&P company this size, I don't think anyone has as large of an inventory as we do, a multi-year inventory, you know, 10-year+ of inventory.

As we stated earlier, most of the near-term stuff is gonna be in the DJ Basin, and then with the Powder Basin or the Powder River Basin, kind of becoming our core focus in the next few years.

Understood. If I could just maybe sneak one more in. I know you guys are still getting your arms around this acquisition, but would just love to hear what your thoughts are around any current M&A opportunities in the market. Has the macro environment made this less conducive? Do you have any appetite if you see something attractive. Just any thoughts around any future M&A?

Yeah, sure. I mean, you know, when we partnered with Juniper to do this, our entire goal of the company was to consolidate a public company in the Rockies, right? You know, we've got the DJ assets, we have the Powder River assets. There are extensive acquisition opportunities in the Powder River Basin. Lots of small operators up there, lots of acreage that we could go acquire to build, you know, a much larger position, and we plan to do that. Of course, over time, you know, as commodity prices change, acquisitions become either more difficult or less difficult. In higher price environments, you typically wanna drill your own inventory a little more. In lower price environments, you know, you wanna be more.

You wanna do more accretive acquisitions because you can kind of lock in your returns with hedging. You know, we're gonna be active on all fronts, but acquisitions are opportunistic, right? There are some out there, but you know, we're gonna be working to acquire, and we're gonna be working to develop. Our goal here is to turn, you know, PEDEVCO from a small-cap company to a mid-cap company.

That's great. Appreciate all the color, and good luck in the next quarter.

All right. Thanks, Dave.

Thank you. This does conclude the question and answer session of today's program. I'd like to hand the program back to Doug for any further remarks.

Thank you, operator, and thank you all for your questions. 2025 was the year we built this platform. 2026 is the year we demonstrate its potential. We look forward to showing you our progress throughout the rest of the year. Thank you for your time, and thank you for your interest in PEDEVCO. Have a good day.

Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.