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 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.