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Operator: Good afternoon. My name is Audra, and I will be your conference operator today. At this time, I would like to welcome everyone to the Fourth Quarter 2024 SandRidge Energy Conference Call. Today’s conference is being recorded. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] At this time, I would like to turn the conference over to Scott Prestridge, Senior Vice President, Finance and Strategy. Please go ahead.

Scott Prestridge: 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 contents contain 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.

Grayson Pranin: Thank you, and good afternoon. I am pleased to report on a positive quarter and year for the company. In the fourth quarter, total production averaged over 19 MBoe per day, made up of 48% liquids and that the company’s expanded activity continues to translate to meaningful free cash flow from our producing assets. Before expanding on this, Jonathan will touch on a few highlights.

Jonathan Frates: Thank you, Grayson. Despite headwinds from natural gas prices last year, the company generated adjusted EBITDA of $24 million in the fourth quarter and $69 million for the year. As we have pointed out in the past, adjusted EBITDA is a unique metric for SandRidge and that we have no debt and a substantial NOL position that shields our cash flows from federal income taxes. During the year, we generated approximately $7.9 million of interest income from cash held in various high-yield deposit accounts, which offset a significant portion of our corporate G&A. Cash, including restricted cash at the end of the year, was just under $100 million, which represents more than $2.68 per share of our common stock outstanding.

The company paid $72 million in dividends in 2024, made up of $16 million in regular and $56 million in special dividends. Combined with 2023, we have paid shareholders a total of $154 million in dividends, or more than $4 per share. On March 7, 2025, the Board of Directors declared an $0.11 per share cash dividend payable on March 31 to shareholders of record on March 20. As noted, 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 on the balance sheet. Commodity price realizations for the fourth quarter, before considering the impact of hedges, were $71.44 per barrel of oil, $1.47 per Mcf of gas and $18.19 per barrel of NGLs. For the full year, realizations were $74.31 per barrel of oil, $1.10 per Mcf of gas and $18.87 per barrel of NGLs. Following a run-up in prices, we added hedges for natural gas and ethane during the quarter, the details of which can be found in our earnings release and 10-K.

While we plan to continue to retain upside exposure to commodities, these hedges secure cash flows for a percentage of our production over the year. We have maintained our large federal NOL position, which was roughly $1.6 billion gross at quarter end. Our NOL position has and will continue to allow us to shield our cash flows from federal income taxes. As always, our commitment to cost discipline continues to yield results with adjusted G&A for the fourth quarter of approximately $2.4 million or $1.39 per Boe and $9.3 million or $1.54 per Boe for the year. Net income was approximately $18 million or $0.47 per basic share during the quarter and $63 million or $1.69 per basic share during the year. Net cash provided by operating activities was approximately $26 million for the fourth quarter and $74 million for the year.

Finally, the company generated free cash flow before acquisitions of approximately $13 million during the quarter and $48 million for the full year. Before shifting to our outlook, we should note that our earnings release and 10-K will provide further details on our financial and operational performance during the quarter.

Grayson Pranin: Thank you, Jonathan. We thought it would be useful to give a brief update on operations as well as our acquisition last year before touching on other company highlights. Last quarter, we successfully completed and initiated production from the company’s first operated wells in the Cherokee play with three drilled but uncompleted wells or DUCs achieving costs below historical industry average in the play. We hope to further leverage these cost efficiencies over our operated one rig development program this year. Dean will touch more on this later. The company closed a second acquisition in the Cherokee Shale play of the Mid-Continent region that exchange and increase our ownership interest in a producing and undeveloped oil and natural gas properties for $5.7 million and terminated the previously announced joint development agreement.

This allowed us to increase and optimize our undeveloped position around the best results of the play. It also allows us to control our development and operations. We see this as a real benefit as we implement our own cost-focus program, which will include efficiencies gained from pad drilling, zipper or simul-frac and other industry best practices. I would like to pause for a moment to highlight the play. The Cherokee formation in the Mid-Continent region has become a highly productive hydrocarbon target with increased horizontal activity over the last few years. It is comprised of mostly self-sourcing shales with interbedded high porosity sands. The play is currently being developed and delineated across the Northeast Texas Panhandle to 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. As the play has extended to the south, productivity has meaningfully increased with depth. Two recent co-developed non-op wells that directly offset the units we will be developing this year had an average two-stream IP 30 of approximately 1,400 Boe per day with 60% oil. And another offsetting well recently turned in line was incrementally better. We hope to share more details on this in our operated results next quarter. As I mentioned previously, production for the fourth quarter was over 19 MBoe per day. This represents a 19% increase year-over-year on a Boe basis and a 28% increase on an oil basis.

As we look forward to developing our high-return Cherokee assets this year, we anticipate growing oilier production volumes further. However, we will continue to be mindful of results, commodity prices, costs and other factors, which will shape our capital allocation decisions this year and beyond. There are no significant explorations this year, and we have the financial flexibility to adjust our development plan to respond to either tail or headwinds. Shifting over to natural gas prices. Last year saw Henry Hub prices in the low 2s, which is now up to the mid-4s, and near doubling over a short period. The increase in natural gas prices will boost our revenue and as we realize better prices, the fixed portion of our costs will be diluted at higher benchmark prices.

The combination of our Cherokee and legacy assets as well as improvement in natural gas prices give us multifaceted options to include Cherokee development in a constructive WTI environment as well as further capitalizing on the potential of our incumbent properties through well reactivations, incremental production optimization projects and possibly development if natural gas and liquid price remain strong over a meaningful tenor or potentially both when WTI and Henry Hub are both constructive. Conversely, given the relatively low breakevens of our producing properties and a cash balance of just under $100 million, we’re also well positioned to take advantage of lower commodity environments by acquiring additional producing properties at attractive prices.

Long and short, we have a more versatile kit bag, which better positions us to take advantage of not only the current but future commodity cycles. Now pivoting back to the base business, I will turn things over to Dean.

Dean Parrish: Thank you, Grayson. Let’s start on our capital program. We completed three operated and one non-operated DUCs in the Cherokee Play last year, which had an average 30-day IP of approximately 1,400 Boe per day with around 60% oil. These DUCs were located up dip towards the northern end of the play. And as we move our capital program south this year deeper into the basin, we expect productivity to be further enhanced. We did see some meaningful cost efficiencies with the most recent completions and are hopeful to leverage these savings going forward. We spud our first operated Cherokee well in February and hope to share the results of this well on our next call. We plan to drill eight operated Cherokee wells with one rig this year and complete six wells.

The remaining two completions are anticipated to carry over to next year. Roughly 75% of our planned wells are proved undeveloped or PUDs with others projected to be converted to PUDs by year-end. This means that our planned drilling locations this year will offset producing wells, which translates to higher relative confidence and well performance. Additionally, this could set up new PUD additions or extensions at the end of the year. Gross well costs vary by depth, but are anticipated to be between $9 million and $11 million. While we have taken proactive steps to help mitigate the effects of inflation, further changes to tariffs or other factors could influence these costs in the future. From a timing standpoint, most of the production from this year’s capital program will occur in the second half of the year with the benefit extending into next year.

We intend to spend between $66 million and $85 million in our 2025 capital program, which is made up of $47 million to $63 million in drilling and completions activity and between $19 million and $22 million in capital workovers, production optimization and selective leasing in the Cherokee Play. Our high-graded leasing is focused to further bolster our interest, consolidate our position and extend development into future years. We intend to fund capital expenditures and other commitments using cash flows from our operations and cash on hand. The oilier content and increased productivity from these Cherokee wells will help to boost relative rates of return while decreasing breakeven pricing in high-graded areas down to roughly $35 WTI. On optimizing production from our incumbent asset base, we are focused on 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 the past quarters in optimizing our wells production profile and costs have continued to flattening the expected base asset level decline of our already producing assets to single digits. In addition to artificial lift conversions and optimization programs to extend run times, we will reactivate previously curtailed wells to cost effectively add production. Our well reactivations are currently very targeted, but we could expand this program with further natural gas tailwinds.

Our legacy assets remain approximately 99% held by production, which cost effectively maintains our development option over a reasonable tenor. These non-Cherokee assets have higher relative gas content, but commodity price futures are not yet at preferred levels to resume further development or more well reactivations at this time. Commodity prices firmly over $80 WTI and $4 Henry Hub over a confident tenor and/or reduction in well costs are needed before we would return to exercise the option value of further development or well reactivations. While natural gas is now over $4, the curve is backwardated after 2025 and WTI has not yet reached targeted levels. At current WTI prices, we would need to see additional natural gas price increases before adding incremental capital to this year’s development plan.

With that said, we will continue to monitor commodity prices and may adjust our plan accordingly. 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 workovers for the quarter were held to approximately $11.3 million or $6.43 per Boe and $40 million or $6.61 per Boe for the full year, a nearly 3% reduction from the prior year. We will continue to actively press on operating costs through rigorous bidding processes, leveraging our significant infrastructure, operation center and other company advantages. With that, I will turn things back over to Grayson.

Grayson Pranin: Thank you, Dean. I will now revisit the key highlights of SandRidge. Our asset base is focused in the Mid-Continent region with a primarily PDP well set, which does not require any routine flaring of produced gas. These well-understood assets are almost fully held by production with a long historied, 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 electrical infrastructure over our footprint. This substantial owned and integrated infrastructure helps derisk 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, and we have negative net leverage.

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, 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 optionality and incremental oil diversification with low breakevens in high-graded areas. We maintain financial flexibility that allows us to adjust our strategy to take advantage of commodity cycles. This flexibility provides advantages and strategic optionality to further grow our business and provides a buffer to commodity headwinds while protecting our capital return program.

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 and growing the value of our business in a safe, responsible, efficient manner while prudently allocating capital to high-return organic growth projects. We will also evaluate merger and acquisition opportunities in a disciplined manner with consideration of our balance sheet and commitment to our capital return program. This 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, complement its portfolio of assets, further utilize its approximately $1.6 billion of federal net operating losses or otherwise yield attractive returns for its 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.

Final staple is to uphold our ESG responsibilities. As we look forward to the year and beyond, we plan to further progress our Cherokee development and anticipate to extend our capital investment in these high-return projects in order to help maintain our production levels while providing further oil diversification. With continued success in support of commodity prices, we’re hopeful to expand to a multiyear development plan. Please keep in mind that a 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, costs, results or other factors. Shifting to administrative expenses, I will turn things over to Brandon.

Brandon Brown: Thank you, Grayson. To wrap up, I would like to emphasize that our adjusted G&A of $2.4 million or $1.39 per Boe compares favorably to our peers. The efficiency of our organization stems from our core values to remain cost disciplined as well as our prior initiatives, which have tailored our organization to be fit for purpose. We’ll maintain our cost-conscious and efficiency-focused mindset moving forward and continue to balance the weighting of field versus corporate personnel to reflect where we create value and have outsourced necessary but perfunctory and less core functions such as operations accounting, land administration, IT, tax and HR. Our efficient structure has allowed us to operate with total personnel at just over 100 people, while retaining key technical skill sets that have both the experience and institutional knowledge of our business.

In summary, the company had free cash flow of $48 million during the year, just under $100 million in cash and cash equivalents at quarter end, which represents more than $2.68 per share of our common stock outstanding and inventory of high rate of return, low breakeven projects and overall mid-composition that is approximately 96% held by production, which preserves the option value of future development potential of our legacy acreage in a cost-effective manner. Low overhead, top-tier adjusted G&A, no debt, negative leverage, flattening production profile, double-digit reserve life and $1.6 billion of federal NOLs. This concludes our prepared remarks. Thank you for your time. We will now open the call to questions.

Operator: [Operator Instructions] All right. We’ll go first to Christopher Dowd at Third Avenue Management.

Christopher Dowd: Hey guys, thanks for taking the question. Congrats on the nice Q4 results and finishing the year strong. I’ve got one question and one follow-up for you today. Your upper bound, the 7.1 MBoe production levels are certainly exciting given where Henry Hub prices are today and possible data center and LNG demand. So in addition to what you already mentioned on the forward curve, what else would you want to see to get closer to that high end of the range? And then is there any further upside or further organic production growth available should pricing warrant? And then I’ve got a follow-up question.

Grayson Pranin: Sure. Appreciate that Chris. And – thanks for being on the call and a great question here. I think on the upward bound, we’d like to see gas prices ideally stabilize across the next 18 months at $5 with WTI more constructive solidly over $70. With that being said, we could have some tailwinds if results are better than expected or we’re ahead of schedule. Additionally, we have an inventory of well reactivations that we can dig into very quickly without much lead time. And really, I think our approach as in years past is to make sure that we have nat gas prices over a confident tenor before we start deploying more capital in that direction. But I think you’re right to point out that we do have other options in addition to development that we can utilize to help grow production in a really constructive gas environment.

Christopher Dowd: Great. That’s really helpful. And then my only other question, given that SandRidge is in somewhat of a unique position where you’ve got legacy transmission line infrastructure, there’s been a lot of chatter about data center folks trying to get in front of the grids and maybe cut direct energy deals. Does your infrastructure allow you to have maybe a unique negotiating position? Or is that not relevant?

Grayson Pranin: Yes, it’s an interesting question. I appreciate that. We do have – our infrastructure does give us strategic advantages. When it comes to selling directly to customers, a lot of our gas has to be processed – and given where NGL prices are today, those being taken out so that we can sell those in other markets and take advantage of those relative revenues. So we sell all of our gas to large purchasers that have access to other markets. And so they have the ability to sell gas in front of the grid, and we can benefit secondarily to some of that. But it’s really hard to pick up that gas at the tailgate of the plants and plug that straight into engines and electrify our own – operating own grid, if that makes sense.

Christopher Dowd: Yes. Really helpful. Thanks guys and again nice job on Q4.

Grayson Pranin: I appreciate it Chris.

Operator: We’ll move next to Sergey Pigarev at Freedom Broker.

Sergey Pigarev: Hi, everyone, and thank you for taking my question. I have a question on CapEx. As we see from the guidance, I mean, like in midpoint, CapEx 2025 is like 3x higher than 2024 figure. And should we consider this level as necessary level to maintain the current production? And would you expect similar levels in 2026 and beyond?

Grayson Pranin: Yes. Thanks, Sergey. Great questions, and I appreciate your time. I think this year is going to be different than last year, in particular, because of the acquisition that we had last year. With that acquisition came interest in high-graded undeveloped properties that we’re going to be developing this year. And as mentioned before, these are really high rate of return projects and have very low breakevens down to $35 WTI. And that was the catalyst between shifting to kind of a more defensive position last year where we had really low nat gas prices. And as you know, our legacy assets are more gas weighted. And given where Henry Hub was last year, it didn’t make sense given the cheap option value of that acreage to go deploy capital there.

And then we acquired predominantly PDP assets that came with additional undeveloped that we’re going to be exploiting this year in order to bring that value forward. I do think that we’ll be mindful of our reinvestment rates. And we’re going to target this year reinvestment rate between 55% and 80% and guiding to 50% or better next year, assuming that we continue to be execute soundly and have constructive commodity prices. But we want to make sure that we’re thoughtful about having good free cash flow, continue to build that, continue to have a regular way dividend and all the things that we mentioned that we’re going to prioritize on the call. Hopefully, that answers your question, but happy to unpack anything else.

Sergey Pigarev: Thank you. Thank you very much.

Grayson Pranin: What’s that? Well, thank you.

Operator: And we’ll move next to David Cardell [ph] at BluePointe Capital.

Unidentified Analyst: Hi. Can you talk a little bit about what you see for production growth next year, given your CapEx this year? And that’s just – maybe just assuming that commodity prices are kind of flat, what do you expect for production? I realize it’s kind of early, but I ask anyway.

Grayson Pranin: Yes. David, thank you. Great question. For next year, we’re going to look to grow oil production from this year about 30% at the midpoint of guidance. And on a BOE basis, just under 10%, and if you look at the high end of guidance, as Chris was asking earlier those multiples get better, but that’s our baseline target.

Unidentified Analyst: I’m sorry for the confusion. I meant in 2026. And the thinking is that a lot of your wells that you’re drilling now are coming on in the end of the year and will have more of an impact in 2026. So my question was really more on the production in 2026 and beyond. Like is there a way to think about how fast you can grow production going forward?

Grayson Pranin: Sure. First, I kind of want to set the playing field of we’re economic animals, and so the return on the investment is paramount relative to growing production. We do want to grow our base business because there’s a lot of ancillary benefits but we think about things from project to project and each project we underwrite with high rates of return. I know you know that, too, but for the benefit of everybody on the call, I want to reassure that we’re not growing for growth’s sake, but that it’s accretive to the business, right? And so as we look into 2026, we will have the potential for additional growth. As I mentioned on the call, excluding 2026 drilling, we’re going to have two of the eight completions carry over into 2026.

So you’re going to have some new production hit in 1Q even excluding the drilling in next year. And we’re hopeful that commodity prices stay constructive, and we can extend the runway here from this year into next year with this development program and with it furthering our oil-weighted growth.

Unidentified Analyst: Got it. Thank you. And then also, the hedges are new. And I hear you that you want to secure the cash flow based on much better natural gas prices. Could you just remind us like maybe flesh out a little bit about what percentage of production that you’re hedged or how you’re thinking about hedges in general going forward since it’s a bit of a change?

Grayson Pranin: Sure. I appreciate that, David. And I think most people on the call are aware of this, but because we have no debt, we have no bank-led hedging mandates, which is a benefit to the company. And so we typically wanted to remain or have a lot of exposure to the upside. However, given additional capital spent this year, we felt that it was prudent to secure hedges at attractive prices, and that’s why you’ve seen us favor more natural gas and some ethane here recently and less on oil just because there’s, I think, some benefit to oil to the upside. But how we think about hedges are taking some risk off the table when we’re expanding our capital or return of capital programs. So it’s really risk management or opportunistically taking advantage of attractive pricing.

And so our most recent hedges that we layered on just this week had collars with a $4 floor and an $8.20 ceiling, which are pretty attractive. So it still allows us to participate in the market at current prices or better up to $8.20. So we feel pleased with that. And so on the nat gas side, that takes us to just under 60% of PDP volume. Of course, that is a lower number when we’re looking at total production. But again, just being more cautious and prudent. We do not hedge based off of anticipated production from our soon-to-be drilled wells. So we think that, that’s a reasonable place. But we’ll continue to monitor the marketplace. The market has seen a lot of volatility, and we want to balance like having some exposure to the upside versus mitigating downside risk.

Unidentified Analyst: Okay, thank you.

Operator: And this concludes the Q&A session and today’s conference call. Thank you for your participation. You may now disconnect.