Thank you for standing by, and welcome to the SandRidge Energy Third Quarter 2024 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. Thank you. I'd now like to turn the call over to Scott Prestridge, SVP of Finance and Strategy. You may begin.

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'm pleased to report on a positive quarter for the company. At the end of August, we closed on our acquisition in the Western Anadarko Basin. From September, total production for the first month, reflecting the contribution of these assets averaged approximately 19 MBoe per day, made up of 52% liquids and the company's activity continues to translate to free cash flow from our producing assets. Before expanding on this, Jonathan will touch on a few highlights for the quarter.

Thank you, Grayson. Despite the downdraft in natural gas prices during the period, the company generated adjusted EBITDA of nearly $18 million in the third quarter. As we have pointed out in the past, our adjusted EBITDA is a unique metric for SandRidge due to us having no debt and a substantial NOL position that shields our cash flows from federal income taxes. On the interest portion, we generated approximately $1.6 million of interest income during the quarter from cash held in various high-yield deposit accounts, which nearly offset our adjusted G&A for the quarter. The company initiated a return of capital program last year with total cumulative dividends paid to date of approximately $150 million or more than $4 per share. On November 5, 2024, the Board of Directors declared an $0.11 per share cash dividend payable on November 29, 2024, to shareholders of record on November 15, 2024. Following our recent acquisition, cash, including restricted cash at the end of the third quarter was more than $94 million, which represents more than $2.50 per share of our common stock issued and outstanding. The company has no term debt or revolving debt obligations and continues to live within cash flow, funding all capital expenditures and capital returns with cash flow from operations and cash held on the balance sheet. Commodity price realizations for the quarter, before considering the impact of hedges, were $73.7 per barrel of oil, $0.92 per Mcf of gas and $16.25 per barrel of NGLs. As mentioned earlier, we have maintained our large federal NOL position, which was roughly $1.6 billion at quarter end. Our NOL position has and will continue to allow us to shield our cash flows from federal income taxes. Our commitment to cost discipline continues to yield results with adjusted G&A for the quarter of approximately $1.6 million or $1.02 per Boe. We continue to generate net income for our shareholders. And during the quarter, we earned approximately $26 million or $0.69 per basic share. Net cash provided by operating activities was approximately $21 million during the period. Over the first nine months of the year, the company generated approximately $34 million in free cash flow, which represents a conversion rate of approximately 76% relative to adjusted EBITDA. Before shifting to our outlook, we should note that our earnings release and 10-Q will provide further details on our financial and operational performance during the quarter.

Thank you, Jonathan. I thought it would be useful to give a brief update on our recent acquisition before touching on other company highlights. As a quick recap, our recent acquisition in the Western Anadarko Basin focused in the Cherokee play included 44 producing wells and four drilled but uncompleted wells concentrated in Ellis and Roger Mills Counties of Oklahoma as well as interest in 11 drilling and spacing units. From an activity standpoint, two of the four DUCs have now been completed with the most recent achieving a 30-day IP over 1,000 Boe per day, 70% oil. We recently finished completions on the last two DUCs with anticipated first production later this month. As Jonathan mentioned earlier, the contribution of these new assets helped the company achieve a new peak average daily rate this year at nearly 19 MBoe per day, while also increasing our percentage of oil and liquids. This represents a 27% increase to the second quarter average daily production rate on a Boe basis and a 65% increase on an oil basis. Please keep in mind that September was the first full month of contributions from the newly acquired assets to our financials and Q4 will be the first full quarter. Revenue for the acquired assets in July and August were recorded as downward adjustments to the purchase price with details provided in our 10-Q. This acquisition provides key benefits for the company to include bolstering our base production and cash flow levels while preserving our strong balance sheet and planned capital return program, diversifying the commodity mix of our producing asset base and providing commodity optionality with future investments, upgrading our inventory through the Cherokee shale play, adding 22 two-mile laterals focused in highly productive areas of the play with breakevens roughly at $35 WTI. This provides synergies with the areas where we've been recently investigating the potential for new SandRidge-operated drilling opportunities, enabling our team to be well-positioned to evaluate and execute on future organic growth opportunities. The Cherokee formation of the Western Anadarko Basin has become a highly productive hydrocarbon target with increased horizontal activity over the last few years. This is comprised of mostly self-sourcing shales with integrated high porosity sands. The play is currently being developed and delineated across Northeast Texas, Panhandle and Western Oklahoma, encompassing five counties. The DSUs we will be developing are focused in the southern area of the Cherokee core, offsetting some of the more productive wells in the play. Two recent wells in which we have interest in Roger Mills County, which were codeveloped, meaning that the first and second wells were drilled and completed together had an average IP30 of approximately 1,400 BOE per day with 60% oil. Another pair of codeveloped industry wells just to the north of these results had an average IP30 of just under 2,000 BOE per day which were 65% oil. PDP assets included in this acquisition are in the core of the play and are connected to Mid-Con midstream purchasers' end markets and do not require any substantial infrastructure investments. The assets are relatively new horizontal wells with the oil produced being just a few years old, which helps from a breakeven or reserve life perspective. We have endeavored over the past few weeks as we have with our incumbent asset base to focus on efficiently integrating these new assets and implementing our low-cost operating expertise to these assets. Our lease operating expense for the quarter was approximately $9.1 million or $5.82 per BOE, which is a 9% reduction from the prior quarter on a BOE basis, despite the incremental LOE associated with the expanded asset base from the acquisition. While we continue to be mindful of commodity prices and impacts to capital allocation, the transaction provides the potential for expanded activity, which could include the initiation of a development program this year. To sum up, the recent acquisition balances our portfolio of assets through commodity diversification, near-term development optionality and improving reserve life and durability. Through this acquisition, we now have the multifaceted options to develop near-term in a constructive WTI price environment as well as our incumbent properties in the appropriate natural gas and liquids price scenario for both when both WTI and Henry Hub prices are favorable. In summary, this adds to our hit back and better positions us to capitalize on not only the current but future commodity cycles. Now pivoting back to the base business, I will turn things over to Dean.

Thank you, Grayson. Let's start on our capital program. The DUCs that were previously discussed were an anticipated expansion of activity associated with our recent acquisition. From a timing standpoint, two of the DUCs were completed during the third quarter and the operated well had a 30-day IP over 1,000 Boe per day with 70% oil. The last two DUCs were completed during the fourth quarter and are planned to come online later this month. We did see some meaningful cost efficiencies with the most recent completions and are hopeful to leverage these savings going forward. In addition to the DUCs, we have focused on optimizing production from our incumbent asset base this year through high-return and value-adding projects that provide benefits such as lowering forward-looking costs, enhancing production on existing wells and further moderating our base decline profile. The artificial lift systems we have and will be installing in our conversion program are tailored for the well's current fluid production and will reduce the electrical demand from the current artificial lift system, which is key to decreasing future utility costs. The focused efforts over past quarters in optimizing our wells production profile and costs contributed to flattening the expected base asset level decline of our already producing assets. In addition to artificial lift conversions, our production optimization campaign has included heel completions, recompletions and refracs. The heel completion that we piloted last quarter was successful, adding four times the production from pre-heel completion time. We have added three additional heel completion projects that will be executed this quarter. Our incumbent leasehold remains approximately 99% held by production, which cost-effectively maintains our development option over a reasonable center. These non-Cherokee assets have a higher relative gas content, and commodity price futures are not yet at preferred levels to resume further developments or more reactivations at this time. Commodity prices firmly over $80 WTI and $4 Henry Hub are needed before we return to exercise the option value of further development or well reactivations. With that said, we have and will be leasing in a Cherokee play, which will further bolster terrace development opportunities next year. The oilier content and increased productivity from these Cherokee wells will help to boost relative rates of return while decreasing breakeven pricing in high-grade areas down to roughly $35 WTI. Now shifting to lease operating expenses. Despite continued inflationary pressures and increased well count from our recent acquisition and prior capital programs, LOE and expense makeovers for the quarter were held to approximately $9.1 million or $5.82 per Boe, an approximate $9 per Boe reduction to the prior quarter. This was driven by successful integration of the newly acquired assets in addition to reduced water handling costs. We will continue to actively press on operating costs through rigorous bidding processes, leveraging our significant infrastructure, operation center, and other company advantages. In regards to price realizations, the company's largest natural gas purchaser continues to be in ethane recovery during the quarter, which increased NGL volumes for the period but also impacted natural gas and natural gas liquid pricing as more ethane is pulled out of the natural gas stream and recovered as natural gas liquids. The duration of ethane recovery is unknown at this time and is dependent on the dynamics of pricing between natural gas and ethane moving forward. Additionally, natural gas realizations were also impacted this quarter by both low Henry Hub benchmark prices, which averaged $2.19 per Mcf over the quarter, which is fixed infield gathering and transportation costs that took up a larger percentage, as well as widening local basis. Markets are forecasting for Panhandle Eastern, where the majority of our gas is sold, to return to historical trends. In addition, with the forecasted increase of Henry Hub over this winter and into next year, the fixed portion of our deductions will become a smaller percentage of the difference, translating into improved price realizations and higher benchmark prices. With that, I'll turn things back over to Grayson.

Thank you, Dean. Let us pause for a moment to revisit the key highlights of SandRidge. Our asset base is focused in the Mid-Continent region with a primarily PDP well set, which do not require any routine flaring of produced gas. These well-understood assets are mostly fully held by production with a long history, 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 derisk individual well profitability for a majority of our legacy producing wells down to $40 WTI and $2 Henry Hub. Our assets continue to yield free cash flow with total cash after our recent acquisition as of quarter-end of more than $94 million. This cash generation potential provides several paths to increase shareholder value realization and is benefited by a low G&A burden. SandRidge's value proposition is materially derisked from a financial perspective by our strengthened balance sheet, robust net cash position, no debt, financial flexibility and approximately $1.6 billion in federal NOL. Further, the company is not subject to MVCs or other significant off-balance sheet financial commitments. Bolstered inventory that provides further organic growth optionality and further oil diversification with breakevens roughly down to $35 WTI in high-graded areas. Financial flexibility that allows us to make adjustments to our business to take advantage of commodity cycles. This flexibility extends to our net cash position, which among other advantages and strategic uses, includes the return of capital, providing the buffer, if not a benefit, to any commodity headwinds and the optionality to further grow our business. Finally, it's worth highlighting that we take our ESG commitment seriously and have implemented disciplined processes around them. We remain committed to our strategy to focus on growing the cash value and generation capability of our business in a safe, responsible, efficient manner, while prudently allocating capital to high-return organic growth projects. We also remain vigilant and evaluate further merger and acquisition opportunities in a disciplined manner with consideration of our balance sheet and commitment to our planned return of capital program. Our strategy has five points. The first is to maximize the cash value and generation capacity 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. The second is to 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 to optimize our EBITDA to free cash flow conversion. The third is to maintain optionality to execute on value-accretive merger and acquisition opportunities that could bring synergies, leverage the company's core competencies, complement our portfolio of assets, further utilize our approximately $1.6 billion of federal net operating losses or otherwise yield attractive returns for our shareholders. Fourth, as we generate cash, we will continue to work with our Board to assess paths to maximize shareholder value to include investment in strategic opportunities, advancement of our return of capital program, and other uses. To this end, the company expanded its return of capital program earlier this year with $1.83 per share of dividends paid this year and a total of more than $4 per share since last year. The final staple is to uphold our ESG responsibilities. As we look forward to next year, we plan to further progress our Cherokee development and anticipate extending our capital investment in these very high-return projects in order to help maintain our production levels while providing further oil diversification. Please keep in mind that our return of capital program will continue to be our top priority. And given our financial flexibility, we will exercise capital stewardship to respond to changes in commodity prices to include activity slowdown with any potential commodity downdraft or expanded activity with commodity tailwinds.

Thank you, Grayson. We were able to keep adjusted G&A to $1.6 million for the quarter or $1.02 per BOE, which is leading among our peers. As noted, the interest earned from our existing cash deposits after the acquisition nearly offset adjusted G&A for the quarter. The efficiency of our organization stems from our core values to remain cost disciplined as well as prior initiatives, which have tailored our organization to be fit for purpose. We plan to maintain our low-cost and efficiency-focused mindset moving forward, including the recent acquisition, which will further benefit our per BOE cost metrics. We will continue to balance the weighting of field versus corporate personnel to reflect where we actually create value and have outsourced necessary but more perfunctory and less core functions, such as operations accounting, land administration, IT, tax, and HR. Given our efficient structure and ability to flex with both activity and commodity prices, our total personnel has remained consistent at just over 100 people, while retaining key technical skill sets that have both the experience and institutional knowledge of our area of operations. In summary, the company had a 76% EBITDA to free cash flow conversion rate over the first nine months of 2024, more than $94 million in cash and cash equivalents at quarter-end, which represents more than $2.50 per share of common stock issued and outstanding and expanded inventory of high rate of return, low breakeven projects. A Mid-Con position that is approximately 99% held by production, which preserves the option value of future development potential in a cost-effective manner. Low overhead, top-tier adjusted G&A of approximately $1.02 per BOE for the quarter. No debt, in fact, negative leverage, positive free cash flow and a growing net cash position supported by a flattening production profile and double-digit reserve life asset base and $1.6 billion of federal NOLs, which will shield future free cash flow from federal income tax. This concludes our prepared remarks. Thank you for your time. We will now open the call to questions.

Your first question comes from Kyle May from Sidoti & Company. Your line is open.

Hey, good afternoon everyone. I was wondering if we could start with the latest acquisition and if you could maybe expand on your drilling activity plans for the Cherokee play asset?

Sure, Kyle. I appreciate you calling in and great question. Our recent plans have been to complete the DUCs Dean talked about on the call. And we're putting together a plan to initiate drilling on our joint spacing units that will extend into next year. So we have 11 DSUs, 22 extended reach or two-mile laterals that we'll be developing over the next couple of years.

Okay. Great. Any sense of how many you might drill next year?

I think our plan right now is to develop with one rig or a partial rig this year, and you can drill one well every 30 days. So you get a maximum of 12 wells in a year. That would be our threshold for where we're at right now.

Okay. Great. And one follow-up for me. Can you provide any details about the well cost and expected returns in the Cherokee play compared to your legacy asset?

Sure. We're glad to expand on that. I think, as I've mentioned a couple of times on the call, the Cherokee assets have higher oil content relative to our legacy assets, which are more gassy in nature. Therefore, the economics are more attractive just given the ratio between WTI and Henry Hub. Again, as that changes in the future, this acquisition gives us more tools in the kit bag for capital allocation purposes where WTI is constructive, and we can lean more into the Cherokee assets. If gas is projected in Contango to be higher in the future, we can exercise our development options on those legacy assets in a favorable environment for both commodities, but we can lean into both. I think the returns in the area are robust enough, that we feel it makes sense to continue to allocate capital there going into next year. The breakeven is roughly $35 per barrel WTI to give you a relative sense on where the floor is at.

Okay. Great, I appreciate the time today.

Yeah. Thank you, Kyle.

And we have no further questions. This does conclude today's conference call. We thank you for your participation. You may now disconnect.