Ladies and gentlemen, thank you for joining us and welcome to the third quarter 2026 Sandridge Energy conference call. After today's prepared remarks, we will host a question and answer session. If you would like to ask a question, please press star 1 to raise your hand. To withdraw your question, press star 1 again. I will now hand the conference over to Scott Prestridge, Senior Vice President of Finance and Strategy. Scott, please go ahead.

Welcome, everyone. With me today are Grayson Pranin, our CEO, Jonathan Frates, our CFO, Brandon Brown, our CAO, as well as Dean Parrish, our COO. We would like to remind you that today's call contains forward-looking statements and assumptions, which are subject to risk and uncertainty, and actual results may differ materially from those projected in these forward-looking statements. These statements are not guarantees of future performance, and our actual results may differ materially due to known and unknown risks and uncertainties, as discussed in greater detail in our earnings release and our SEC filings. We may also refer to adjusted EBITDA and adjusted GNA and other non-GAAP financial measures. Reconciliations of these measures can be found on our website. With that, I'll turn the call over to Grayson.

Thank you, and good afternoon. I'm pleased to report on a strong quarter and year-to-date for the company. We continue to grow year-over-year production and revenue, driven primarily by new production from our Operated Development Program, higher oil prices, and recently acquired Cherokee assets. This bolt-on acquisition closed during the quarter, with PDP adding oily production for a portion of the period, while the proven locations further bolster our future development inventory. Before getting into this and other highlights, I'll turn things over to Jonathan for details on financial results. Thanks, Grayson.

During the quarter, the benchmark price of oil averaged $87 per barrel for the price of natural gas remained at roughly $3 per MCF. The company grew production to 20.9 MBOE per day, representing an increase of 10% year-over-year on a BOE basis, while oil increased 8% over the same period. Revenues were $54 million, representing a 37% increase year-over-year, and adjusted EBITDA was $39 million, representing a 44% increase over the same period. As usual, we continue to manage the business with the goal of maximizing long-term cash flow while growing production and utilizing our NOLs to shield us from income taxes. At the end of the quarter, cash, including restricted cash, was approximately $70 million, which represents roughly $1.89 per common share outstanding. Before post-closing adjustments, we funded our recently announced Cherokee acquisition with $48 million of cash on hand. The company paid $4.8 million of dividends during the quarter, which included $0.4 million worth of dividends paid in shares under our dividend reinvestment plan. Including special dividends, Sandridge has now paid $5.18 per share in dividends since the beginning of 2023. on November 3rd, 2026, the board of directors declared a 13 cents per share dividend payable on November 30th to shareholders of record on November 19th, 2026. Shareholders may elect to receive cash or additional shares of common stock through the company's dividend reinvestment plan. Commodity price realizations for the quarter before considering the impact of hedges were $85.27 per barrel of oil, $1.62 per mcf of gas, and $22.68 per barrel of NGLs. This compares to second quarter realizations of $95.35 per barrel of oil, $1.36 per mcf of gas, and $21.68 per barrel of NGLs. Despite a growing asset base, the company maintained its best-in-class corporate overhead with adjusted G&A for the quarter of approximately $1.8 million, or $0.94 per BOE, compared to $2.1 million, or $1.23 per BOE in the third quarter of 2025. We continue to expect adjusted G&A of $10 to $12 million for the year. Net income was approximately $31 million for the quarter, for 83 cents per common share and adjusted net income was 23.8 million or 64 cents per share. This compares to 16 million or 44 cents per common share and 15.5 million or 42 cents per share respectively during the same period last year. Earnings for the quarter included a tax benefit of roughly 14 million related to the revaluation of our deferred tax assets. The company generated cash flows from operations of $32 million during the quarter compared to $25 million during the same period last year and adjusted operating cash flow of $39 million compared to $28 million in the third quarter of 2025. The company has no debt and expects to fund all 2026 capital expenditures and capital returns with cash flows from operations. Lastly, Our production is hedged with a combination of swaps and callers representing just under 30% of the midpoint of our 2026 guidance. This includes approximately 37% of natural gas production and 43% of oil. We recently added 475 barrels a day of costless callers on oil through the first half of 2027 to $80 by $100 a barrel. These hedges will help secure a portion of our cash flows and support our drilling program throughout the remainder of the year and into 2027. We will continue to be opportunistic with our hedging program, but plan to maintain meaningful upside throughout the year and next. Before shifting to our outlook, you should note that our earnings release in 10Q will provide further details on our financial and operational performance during the quarter. Now we'll turn it over to Dean for an update on operations.

Thank you, Jonathan. Let's start with a review of the third quarter, then discuss recent drilling and completion results. Our Cherokee area natural gas purchaser remained an ethane rejection for the quarter. With ethane left in the gas stream, we recovered fewer NGL barrels, which lowers reported VOE volumes. However, it increased the BTU content of our residue gas and with higher methane to ethane realizations, that was a net benefit to revenue. With ethane prices improving, we have moved back to ethane recovery in October and will continually monitor price dynamics to make the shift between recovery and rejection where prudent. Total capital spend for the quarter excluding A&D was $24.5 million, which is higher quarter over quarter mostly due to activity timing, but remains within expectations for the year. While we continue to see technical efficiencies in our program and benefits from our previously secured well components, higher diesel prices are a headwind to capital costs. We are in the process of planning for next year, securing the necessary services and critical components to extend our one-rig Cherokee program. While it's early, there are some indications of inflationary pressures in the marketplace in certain areas like drilling rig rates, tubulars, and pressure pumping. However, we plan to exercise rigorous bidding processes, evaluate alternatives, and further implement cost efficiencies to combat these pressures. Lease operating expenses for the quarter were $11 million, for $5.75 per BOE, which falls right in line with expectations. Similar to our capital program, we continue to see pressure on diesel through fuel surcharges passed on by service providers, but have strict internal protocol to reduce surcharges when diesel prices begin to decrease. During the quarter, The company successfully brought three wells online from our operated one-rig Cherokee drilling program. We recently brought online one additional well in October, are currently completing one well, and are drilling the ninth out of 10 wells for the year. We will continue to focus on lowering drilling and completion costs while looking for opportunities to extract additional value from legacy assets. Moving to our 2026 capital program. We remain on track to drill 10 operated Cherokee wells with one rig this year and complete eight wells that were drilled in 2026. The remaining two completions will carry over to next year. A majority of the remaining wells in our development program this year directly offset producing or in progress wells in the area, and we will continue to monitor offsetting results. Gross well costs vary by depth, but are estimated to be between $9 and $11 million. In addition to the operated Cherokee program, we now plan to drill one operated horizontal well within our existing legacy acreage. This well is targeting a proven formation that has been produced vertically with strong oil production, and gross well cost is estimated to be just under $3 million. Successful results from this well could unlock future development locations. With that, I will turn things back over to Grayson. Thank you, Dean.

To re-emphasize the backdrop, let's quickly touch on production revenue in EBITDA, which all grew quarter over quarter, year over year, and is the highest it has been over the last five years. complemented by our low cost structure and efficient organization. This has been driven by our one rig program in the Cherokee play and the closing of the previously announced bolt-on acquisition, which has been benefited by the strong WTI prices this past quarter and year to date, with current WTI features providing further potential tailwinds through the end of the year and into next. Let's start with our recent Cherokee acquisition. which adds producing assets and leasehold interest, expanding our efficient operations in the Cherokee Plate. After customary adjustments, the company paid just under $48 million at close, which translates to an implied LTM EBITDA multiple of the producing properties in line to better than our target in previous acquisition. The acquisition was underwritten with attractive return targets based on pricing below STRIP at the time. The assets include interest in 21 producing wells to include additional interest in four Sand Ridge operated wells and 7,000 acres of leasehold. Leasehold includes 8 to 10, depending on well configuration, high confidence, proven locations, at the average 30-day peak IP, the operated producing wells with more than 2,000 DOE per day. We view this as a very complimentary bolt-on that expands our performer footprint to roughly 37,000 acres in the Cherokee play, adding quality oil-weighted production while bolstering our operated Cherokee inventory with acreage that immediately offsets our current drilling and leaching programs. We're focused on integrating these new assets and applying our low-cost know-how to operations with plans to incorporate the proven locations and to our future development next year. Please note, since the acquisition closed in a quarter, only a portion of the production contributed to our volume and cash flows for the period. However, the company will benefit from the contribution of the producing assets over the full fourth quarter and going forward. Worth highlighting, we did not add people as a result of the acquisition and benefiting from the increased production had less than $1 per BOE of adjusted GNA for the third quarter. Now, let's pivot over to our development program. As Dean discussed, we had first production on three new wells this past quarter, making seven wells year-to-date with an eighth well now flowing back, which averaged peak rates of approximately 1,600 BOE per day for the Cherokee Shale. The third quarter well set tested the Cherokee Shale outside of our historical position in order to delineate across the expanding play and prove an increased well set that extends deeper into the play by holding acreage across our footprint. It's topical here to provide an update on another well I mentioned last quarter, which in the same area targeted a sub-member of the larger Cherokee formation immediately below the Cherokee Shale. This well had an initial 30-day average rate of nearly 12,000 NCFE per day and has produced over 2 BCF after 200 days, while demonstrating exceptionally flat production. While we want to see additional production data, initial long-term estimates are very promising. This well result allows us to better establish performance expectations for this new target, and combined with wells currently being developed in the Cherokee Shell will allow us to evaluate the economics between the Cherokee Shell and this new interval, as well as refine the long-term development plan in this new area. To that end, we are assessing whether this new target and the Cherokee Shell are truly unique reservoirs and the potential for stack pay, which is confirmed to provide further future development optionality to include gas. As we look towards the end of the year and into next, We are planning on focusing our development with one rig on high-graded oil-weighted infill locations to take advantage of the tailwind from WDI prices. While the program is attractive in a range of commodity environments, our team will continue to be diligent in monitoring results and costs while prioritizing full cycle returns and reasonable reinvestment rates, and, when needed, exercise drill schedule flexibility to make prudent adjustments to our development plans. I'm very pleased with our team for the continued focus on safety, execution, and cost focus in the development and production optimization program. They truly have championed safety, resulting in the continuation of our record of more than five years without a recordable safety incident. In addition, they continue to operate at a high level with a lean are very engaged and experienced staff with peer-leading operating and administrative cost efficiencies. I'd like to pause here to highlight the optionality we have across our asset base, coupled with our strength in our balance sheet, which sets us up to leverage commodity price cycles. A combination of our oil-weighted Cherokee and gas-weighted assets, as well as robust net cash position, give us multifaceted options to take advantage of different commodity cycles. Put simply, we have a strong balance sheet and a versatile kit bag, which makes the company more resilient and better poised to maneuver the matter of the commodity environment. I will now revisit the company's advantages. Our asset base is focused in the mid-continent region with a PDP wealth set that provides meaningful cash flow, which has a shallowing and diversified production profile with a double-digit reserve life and a majority of our legacy producing wells, producing properly down to roughly $40 WTI and $2 Henry Hub that do not require any routine flaring of produced gas benefited by a low GNA burden. Bolstered inventory to provide further organic growth opportunities and incremental oil diversification. A strong balance sheet, including negative net leverage, financial flexibility, and Advantage Tax Position. Finally, it is worth highlighting our ESG culture and the recent achievement of five years without a recordable safety incident. Shifting the strategy, we remain committed to growing the value of our business in a safe, responsible, efficient manner while prudently allocating capital to high return growth projects. We will continue to evaluate merger and acquisition opportunities while maintaining financial discipline, consideration of our balance sheet, and commitment to our capital return program. This strategy has five points. One, maximize the value of our incumbent MidCon PDP assets by flattening our production profile and continuously pressing on operating and administrative costs. Two, exercise capital stewardship by investing in opportunities that have attractive returns while targeting reasonable reinvestment rates that sustain our cash flows and prioritizing a regular-weight dividend. Three, maintain optionality to execute on value-accretive merger and acquisition opportunities that may bring synergy, leverage a company's core competencies, complement our portfolio of assets, further utilize our NOLs, or otherwise yield attractive returns. continue to work with our board to assess options to maximize shareholder value to include investment and strategic opportunities, advancement of our return of capital program and other uses. This includes the dividend program, which has returned over $5 per share over the last three years. The final staple is to uphold our ESG responsibilities. Now shifting to administrative expenses, I will turn things over to Brandon.

Thank you, Grayson. As we bring our prepared remarks to a close, I will highlight our third quarter adjusted G&A of $1.8 million, or 94 cents per BOE, continues to lead among our peers. The consistent efficiency of our organization reflects our core values to remain cost disciplined and to be fit for purpose. We will maintain our efficient and low-cost operation mindset and continue to focus on the proper ratio of field versus corporate personnel to reflect where we create the most value. The outsourcing of more perfunctory activities such as operations accounting, land administration, IT, tax and HR has allowed us to operate with total personnel of just over 100 people for the past several years while retaining key technical skill sets that have deep industry experience and institutional knowledge of our business. In summary, at the end of the third quarter, the company had approximately $70 million in cash and cash equivalents, which represents approximately $1.90 per share of our common stock outstanding. An inventory of high rate of return, low break-even projects, low overhead, top tier adjusted G&A, No debt, negative net leverage, a flattening production profile, double-digit reserve life, and approximately $1.5 billion of federal annual wealth. This completes our prepared remarks for today's call. Thank you for joining us. We will now open the call to questions.

We will now begin the question and answer session. If you would like to ask a question, please press star one to raise your hand. To withdraw your question, press star one again. We ask that you pick up your handset when asking a question to allow for optimum sound quality. If you are muted locally, please remember to unmute your device. Please stand by while we compile the Q&A roster. Your first question comes from Christopher Dowd with Third Avenue Management. Christopher, please go ahead.

Hey, Grayson, John, Scott. Thanks for the opportunity to ask a question. With the Cherokee assets now closed, could you help give us a sense of what Q4 production could look like within a range? I mean, are we sort of layering in three MBOE from the acquisition, or is there any nuance to the range of potential production flex that you guys are considering in the short term?

Yeah, sure, John. I appreciate the question and your time this afternoon. I think the 3,000 VOE, of course, without any additional drilling on the assets, which we plan to implement going forward, as of the May 1 effective was 3,000 VOE per day. Today, it's less than that, call it just over 2,000 DOE per day. As we look at it, it's going to add about 10% incrementally to production, but given the timing of the close in the year, it's roughly about 5% or so to annual volume.

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