Thank you, and 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 G&A, 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 am pleased to report on a strong quarter for the company.

Production averaged 18.6 MBOE per day during the first quarter, an increase of 4% on a BOE basis versus the same period in 2025. Oil production increased 31%, and total revenues increased 17% during the quarter versus the same period in 2025, driven primarily by new production from our operated development program.

Before getting into this and other highlights, I'll turn things over to Jonathan for details on financial results.

Compared to the fourth quarter of 2025, the company saw increases in the market price of both oil and natural gas. We grew production by 4% year-over-year and generated revenues of approximately $50 million, which represents an increase of 26% compared to last quarter and 17% compared to the same period last year.

Adjusted EBITDA was $33.7 million in the quarter, compared to $25.5 million in the first quarter of 2025. We continue to manage the business with a focus on maximizing long-term cash flow while growing production and utilizing our NOLs to shield us from federal income taxes.

At the end of the quarter, cash, including restricted cash, was approximately $104 million, which represents over $2.80 per common share outstanding. Cash was down compared to the prior quarter due to an increase in non-cash working capital, primarily related to the timing of payables versus receivables from our one-rig drilling program.

Working capital, as represented by current assets less current liabilities, was up by $3.7 million compared to the prior quarter. The company paid $4.4 million in dividends during the quarter, which includes both $0.6 million worth of dividends to be paid in shares under our dividend reinvestment plan.

On May 5th, 2026, the board of directors increased the regular way dividend by 8%, declaring a 13-cent dividend, as well as a one-time special dividend of 20 cents per share, both of which are payable on June 1st to shareholders of record on May 20th, 2026. Shareholders may elect to receive cash or additional shares of common stock through the company's dividend reinvestment plan.

Following these dividends, SandRidge will have paid $5.05 per share in regular and special dividends since the beginning of 2023. Commodity price realizations for the quarter, before considering the impact of hedges, were $71.11 per barrel of oil, $3.13 per MCF of gas, and $18.64 per barrel of NGLs.

This compares to fourth quarter 2025 realizations of $57.56 per barrel of oil, $2.20 per MCF of gas, and $14.92 per barrel of NGLs. Our commitment to cost discipline continues to yield results, with adjusted G&A for the quarter of approximately $2.4 million, or $1.42 per BOE, compared to $2.9 million, or $1.83 per BOE, in the first quarter of 2025.

Net income was $18.7 million for the quarter, or 50 cents per diluted share. Adjusted net income was $21.6 million, or 58 cents per diluted share.

This compares to $13 million, or 35 cents per diluted share, and $14.5 million, or 39 cents per diluted share, respectively, during the same period last year. The company generated cash flow from operations of $19.8 million during the quarter, compared to $20.3 million during the same period last year, and adjusted operating cash flow of $34.4 million during the quarter, compared to 26.3 in the same period of 2025.

Lastly, our production is hedged with a combination of swaps and collars, representing just under 30% of the midpoint of our 2026 guidance. This includes approximately 37% of natural gas production and 43% of oil.

These hedges will help secure a portion of our cash flows and support our drilling program through the year. We continue to monitor prices to take advantage of favorable opportunities, and plan to maintain meaningful upside throughout the remainder of the year.

Before shifting to our outlook, you should note that our earnings release and 10-Q will provide further details on our financial and operational performance during the quarter. Now, I will turn it over to Dean for an update on operations.

Thank you, Jonathan. Let's start with a review of the first quarter, then discuss recent drilling and completion results.

Total capital spend for the quarter, excluding A&D, was $19.9 million, which is better than expectations for the quarter, mostly due to drill schedule adjustments. A rigorous bidding process, focus on driving drilling and completion costs down in the Cherokee play, and longer artificial lift runtimes from previous years of improvements kept us on budget.

Additionally, we have been securing critical well components needed for the remainder of the year to minimize any supply or inflationary pressures that may affect our capital program. Lease operating expenses for the quarter were $10.8 million, or $6.45 per BOE, which falls right in line with expectations.

We are also securing the needed equipment and services that will be critical for production operations in 2026, similar to the capital program. We expect to continue to see pressure on diesel fuel through fuel surcharges passed on through service providers, but have strict internal protocol to reduce surcharges when diesel prices begin to decrease.

During the quarter, the company successfully completed three and brought two wells online from our operated one-rig Cherokee drilling program. We recently brought online the ninth well in our program, and are drilling the 11th, while the 10th well awaits final completion.

Our operations team continues to execute, with the 10th well that was just drilled being the fastest, lowest cost to date, driven by the team's focus and ingenuity to reduce costs. It's early, but we are seeing some incremental efficiencies on our 11th well drilling now, and will have more to share next quarter.

Moving to our 2026 capital program, we plan to drill 10 operated Cherokee wells with one rig this year and complete eight wells. The remaining two completions are anticipated to carry over to next year.

The majority of the remaining wells in our development program this year directly offset proven or in-progress wells in the area, and we continue to monitor offsetting results. Gross well costs vary by depth, but are estimated to be between approximately $9 and $11 million.

We intend to spend between $76 and $97 million in our 2026 capital program, which is made up of $62 to $80 million in drilling and completions activity, and between $14 and $17 million in capital workovers, production optimization, and selective leasing in the Cherokee play. Our high-graded leasing is focused on further bolstering our interest, consolidating our position, and extending development into future years.

With that, I will turn things back over to Grayson.

Thank you, Dean. Let us start with commodity prices.

We started the year with strong natural gas prices, which benefited January and February revenues. During this period, our largest natural gas purchaser elected to move to ethane rejection.

This means that more ethane is sold as natural gas and less is separated as NGLs. This typically results in less barrels of equivalent in volume, which impacted both our NGL and overall BOE volumes for the quarter.

It benefited natural gas volumes and revenue, as the gas was sold at relatively higher prices with increases to the BTU factor. This had a positive effect on revenue, due to dynamics of high natural gas and lower relative ethane prices during the period.

However, natural gas prices have since declined, and with it, the spread between natural gas prices and ethane. Our largest natural gas purchaser returned to ethane recovery in March, and plans to maintain recovery until there is further benefit otherwise.

Also, while natural gas prices increased during January, we did experience increased production deferment during Winter Storm Fern, which negatively impacted volumes. Despite this challenge, our team did an amazing job operating through the extreme cold weather and minimizing downtime as much as possible, and most importantly, doing so safely.

Now shifting to oil, the year began with oil prices in the mid to upper $50 range, which changed dramatically over the quarter. Despite seeing spot rates reach up to the triple-digit levels recently, WTI averaged $72.74 per barrel in Q1 because the shift occurred in late February and early March.

For the same reason, the increase in WTI prices only partially benefited our revenues during the quarter, since higher oil prices occurred in the back half of the quarter. Thus far, oil prices have remained high in the second quarter and could benefit revenues further.

While commodity prices are driven by market dynamics outside of our control, we have used our favored position when coming into the year with minimal hedges, to take advantage of the increases year-to-date, the details of which can be found in our earnings release and 10-Q to be filed later today. Combined with our prior hedges, we have hedged a meaningful portion of our PDP volumes for the remainder of the year, which allows us to secure a portion of our cash flows at prices that are materially above where we started the year and where we budgeted.

The remainder of our PDP oil volumes and all of the volumes from our current drilling program will participate at the market with exposure to current high prices. We have endeavored to balance securing cash flows while maintaining an appropriate level of exposure to commodity upside.

That said, there's been a lot of volatility in WTI pricing over the last few weeks and much speculation over futures, with the forward curve remaining in steep backwardation. While we are content with the current levels hedging this year, we will continue to monitor geopolitical events and future pricing for further adjustments, with specific focus on longer-term periods.

Now let's pivot over to our development program. As Dean discussed, we had first production on two wells this past quarter.

One well targeted the Cherokee shale in our core area, consistent with wells last year. These wells had an average peak 30-day production of approximately 2,000 BOE per day, made up of 45% oil, including the newest seventh well.

The other well turned online this quarter tested the Red Fork formation, a sandstone in the lower Cherokee group. This was an initial well in a new area for us, that offset and delineated a very productive well drilled by a reputable operator.

This well allows us to better establish performance expectations in a new target and in a new area, where leasing costs have been very attractive. Currently, we do not have any Red Fork wells planned for the rest of the year.

However, we plan to monitor the performance of this well, industry and offsetting activity, which has increased over the past year, as well as commodity prices and other factors while evaluating the go-forward plan in the new area. Given the tailwind of WTI prices and the enhancement to returns, we plan to continue our Cherokee development with one rig and further grow oily production.

While the program is attractive in a range of commodity environments, our team will continue to be diligent about prioritizing full cycle returns, monitoring reasonable reinvestment rates, and, when needed, exercise drill schedule flexibility to make prudent adjustments to our development plans in different economic environments. Also, we do not have any significant near-term leasehold expirations, and have the flexibility to defer these projects if needed for a period of time.

I'm very pleased with our team for the continued focus on safety, execution, and cost focus in the development and production optimization programs. They have truly championed safety, resulting in the continuation of our record of more than four years without a recordable safety incident.

In addition, we continue to operate at a high level with a lean, but very engaged and experienced staff, with peer-leading operating and administrative cost efficiencies. I would like to pause here to highlight the optionality we have across our asset base, coupled with the strength of our balance sheet, which sets us up to leverage commodity price cycles.

The combination of our oil-weighted Cherokee and gas-weighted legacy assets, as well as robust net cash position, give us multifaceted options to maneuver and take advantage of different commodity cycles. Put simply, we have a strong balance sheet and a versatile toolkit, which makes the company more resilient and better poised to maneuver and adjust, no matter the commodity environment.

I will now revisit the company's advantages. Our asset base is focused in the Mid-Continent region, with a PDP well set that provides meaningful cash flow, which does not require any routine flaring of produced gas.

These well-understood assets are almost fully held by production, with long histories, shallowing and diversified production profile, and double-digit reserve life. Our incumbent assets include more than 1,000 miles each of owned and operated SWD and electric infrastructure over our footprint.

This substantial owned and integrated infrastructure helps de-risk individual well profitability for majority of our legacy producing wells down to roughly $40 WTI and $2 Henry Hub. Our assets continue to yield free cash flow.

This cash generation potential provides several paths to increase shareholder value realization, and is benefited by low G&A burden. SandRidge's value proposition is materially de-risked from a financial perspective by our strengthened balance sheet, including negative net leverage, financial flexibility, and advantaged tax position.

Further, the company is not subject to MVCs or other significant off-balance-sheet financial commitments. We have bolstered our inventory to provide further organic growth opportunities and incremental oil diversification, with low break-evens in high-graded areas.

Finally, it is worth highlighting that we take our ESG commitments seriously, and have implemented disciplined processes around them. Not only do we continue to operate our existing assets extremely efficiently and execute on our Cherokee development in an effective manner, but we do so safely.

Shifting to 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 also evaluate merger and acquisition opportunities while maintaining financial discipline, consideration of our balance sheet, and commitment to our capital return program.

The strategy has five points. One: maximize the value of our incumbent Mid-Con PDP assets by extending and flattening our production profile with high-rate-of-return production optimization projects, as well as continuously pressing on operating and administrative costs.

Two: exercise capital stewardship and invest in projects and opportunities that have high risk-adjusted fully burdened rates of return, while being mindful and prudently targeting reasonable reinvestment rates that sustain our cash flows and prioritize our regular way dividend. Three: maintain optionality to execute on value-accretive merger and acquisition opportunities that could bring synergies, leverage the company's core competencies, compliment its portfolio of assets, further utilize its approximately $1.5 billion of federal net operating losses, or otherwise yield attractive returns to its shareholders.

Four: as we generate cash, we will continue to work with our board to assess paths to maximize shareholder value, to include investment and strategic opportunities, advancement of our return of capital program, and other uses. To this end, the board continues to focus on the company's return of capital to stockholders as a priority in capital allocation.

As a result, expanded its ongoing dividend program by 8% and declared a one-time dividend. The final staple is to uphold our ESG responsibility.

Now shifting to administrative expenses, I will turn things over to Brandon.

Thank you, Grayson. As we close out our prepared remarks, I will point out our first quarter adjusted G&A of $2.4 million, or $1.42 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 maintain our efficient and low-cost operation mindset and continue to balance the weighting of field versus corporate personnel to reflect where we create the most value.

The outsourcing of necessary but more perfunctory functions, 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 both the experience and institutional knowledge for our business. In summary, at the end of the first quarter, the company had approximately $104 million in cash and cash equivalents, which represents over $2.80 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 leverage, a flattening production profile, double-digit reserve life, and approximately $1.5 billion of federal NOLs.

This concludes our prepared remarks. Thank you for joining us today.

We will now open the call to questions.