Greetings, and welcome to the Second Quarter 2022 SandRidge Energy Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Scott Prestridge, Director of Finance and Investor Relations. Thank you, Scott. You may begin. Thank you, and welcome, everyone. With me today are Grayson Pranin, our CEO and COO, Salah Gamoudi, our CFO and CAO, as well as Dean Parrish, our Senior Vice President of Operations. 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. 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 morning. I'm proud to report on another strong quarter of results for SandRidge, and that the company is actively capitalizing on recent commodity price tailwinds to include expanded but focused high-graded drilling in the core of the Northwest STACK and a continuation of our well reactivation, which will add incremental production this year and in 2023. Before expanding on this, Salah will touch on a few highlights from the second quarter. Thank you, Grayson. Production for the second quarter remained flat to the first quarter at approximately 17.8 Mboe per day, despite not finishing any new well completions during the first half of the year. Production did, however, benefit from the reactivation of 29 wells during the first six months of 2022 that were previously curtailed during commodity price downdrafts in 2020. Also, production from this year's drilling program will begin adding to base levels in the second half of this year and into 2023, as we finish completions on wells drilled in the first half of the year and further drill and complete new wells. Net cash, including restricted cash, increased to approximately $205 million, which represents $5.58 per share of our common stocks issued and outstanding as of June 30, 2022. The approximate $40 million increase over the quarter was supported by production from our well reactivation program, as well as higher commodity prices and realizations and net of capital expenditures made for inventory drilling and completion activities related to our 2022 capital program. The company has no term debt or revolving debt obligations as of June 30, 2022, and continues to live within cash flow, funding all its capital expenditures with organic free cash flow and cash held on the balance sheet. Over the quarter, the company generated Adjusted EBITDA of approximately $54 million, again, despite no new production from our planned drilling or completion activities during the period. As we have pointed out in the past, our Adjusted EBITDA is a unique metric for SandRidge due to us having no I and very little T, given that we have no debt and a substantial NOL position that shields our cash flows from federal income taxes. Commodity price realizations in the second quarter, before considering the impact of hedges, increased to $109.06 per barrel or $5.30 per Mcf for oil and natural gas, and NGL realizations were $35.96 per barrel. This represents an improvement of 18%, 38%, and 7% for oil, gas, and NGLs, respectively, over the quarter. As of today, we have no open hedge positions or commodity derivative contracts. As alluded to earlier, we have maintained our large NOL position, which is estimated to be approximately $1.6 billion as of the end of 2Q 2022. Our NOL position has and will continue to allow us to shield our cash flows from federal income taxes. Our cost discipline continued to improve during the quarter, with Adjusted G&A decreasing to approximately $1.8 million, or $1.09 per Boe, from $2.2 million, or $1.35 per Boe in the prior quarter. We have also held LOE and expensed workovers to approximately $9.5 million, or $5.87 per Boe during the quarter, a decrease of approximately $1.4 million, or $0.89 per Boe from the prior quarter. This level of expense is partially driven by an increase in workover activity associated with well reactivations and well repairs at higher commodity prices. We believe we compare favorably with our peers in regards to G&A and LOE on both an absolute and a per Boe basis. We continue to generate net income for our shareholders. During the quarter, we earned net income of approximately $48 million, or $1.32 per share, up from $35 million, or $0.95 per share, an approximate 40% increase from the prior quarter. Before shifting to our outlook, we should note that our earnings release posted yesterday and the 10-Q that we plan to file soon provide further detail on our financial and operational performance during the quarter. Thank you, Salah. We thought it would be helpful to walk through some of the company's highlights, management strategy, and other business details. As I mentioned previously, we are pleased with results in the second quarter and have begun to further capitalize on robust commodity prices with high rate of return drilling in the Northwest STACK, continued well reactivations, and further strengthened cash flow from our already producing property in MidCon. We were able to keep quarter-over-quarter production flat in MidCon despite no new production from drilling and completion activity during the period. Reactivate wells averaging over 100% rate IRRs, now targeting an additional 25 projects over the remainder of the year for a total of 54 by year-end. In addition, we will convert artificial lift systems of 36 wells to rod pump, 12 of which were converted over the first half of the year, that will aid in optimizing lifting efficiency and lowering 0.4 cost for this well set. The rod pumps we have or will be installing are tailored for the wells' current fluid production and will reduce the electrical demand from the current artificial lift system. This is key to offset increases in utility costs associated with the rise in fuel surcharges from elevated commodity prices. We have successfully drilled, completed, and are now producing the first two wells in this year's capital program, targeting the Meramec in the Northwest STACK play, and are currently drilling the third in extended reach lateral. The first two 1-mile lateral wells are producing an average of approximately 400 barrels of oil per day and nearly the same level in gas as the end of July. Gross D&C costs for the two wells averaged $4.6 million. We anticipate that the gas will continue to rise to a peak level of more than 1 million cubic feet per day per well as we continue to open chokes during managed flow back of these wells. I'm extremely pleased with the planning and approach our team has taken to help control costs. As Salah mentioned earlier, we pre-purchased nearly $5 million of materials to include casing for all the 2022 drilling program, pumping units for capital workovers, and other items. The investment made earlier this year is key to warding off inflationary pressure in today's markets and has already benefited the program. Let's 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 almost fully held by production with a long history of shallow decline and diversified production profile and double-digit reserve life. PV-10 of future net discounted cash flows to proved developed oil and gas and NGL reserves of these assets is approximately $690 million. Based on year-end 2021 reserves and assumptions, roll forward to July 1, 2022, and using 2Q 2022 SEC pricing. These 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 provides the company both cost and strategic advantages, bolstering asset operating margin through reduced lifting as well as water handling and disposal costs, and combined with other advantages, help de-risk individual well profitability for more than 70% of producing wells down to $40 WTI and $2 Henry Hub. In addition, the interconnectivity and ample capacity help buffer against unforeseen curtailment. Our assets continue to yield significant free cash flow, with total net cash now post- totaling over $200 million with zero debt as of quarter end. This cash generation potential provides several paths to increase shareholder value realization and is benefited by relatively low G&A burden. As we realize value and generate cash, our board is committed to utilizing our assets, including our cash, to maximize shareholder value. SandRidge's value proposition is materially de-risked from a financial perspective by our strengthened balance sheet, robust net cash position, financial flexibility, and over $1.6 billion in NOL. Further, the company is not subject to MBCs or other significant off-balance sheet financial commitments. Currently, the company does not have any open hedging contracts beyond 2022. However, we could enter into hedges from time to time in support of securing returns for our capital campaign, managed commodity risk, or other fundamental drivers. 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 opportunities and remain watchful for potential value accretive opportunities. This strategy has four points. Maximize the cash value and generation capacity of our incumbent MidCon PDP assets by extending and flattening our production profile with high rate return workover, well reactivations, and artificial lift conversions. Continuously press on operating and administrative costs. The second is to ensure we convert as much EBITDA to free cash flow as possible by exercising capital stewardship and investing in projects and opportunities that have high risk-adjusted, fully burdened rates of return. To include executing on our expanded 12-well drilling program in the core of Northwest STACK to economically add production. The third is to remain open, patient, and maintain optionality for opportunistic value-creative acquisitions. We'll focus on value-adding opportunities that bring synergies, further leverage SD's core competencies, complement or balance the company's portfolio, or otherwise yield a competitive advantage and attractive returns. Fourth, as we generate cash, we will continue to work with our board to assess paths to maximize shareholder value to include investment opportunities, strategic opportunities, return of capital, and other uses. The final staple is to uphold our ESG responsibilities. Circling back to this year's drilling program, we have had a controlled and purposeful start to drilling and completion, and will continue to pursue with thoughtful and disciplined execution this year in order to realize high rate of return with these investments. The program consists of 12 wells that are offset to highly profitable horizontal wells and have favorable geologic and reservoir characteristics. Our current investor presentation highlights the average performance of these offsets, and at the July 25 strip, as well as today's estimated cost, delivers a nearly 90% IRR. The focus area we will be developing in this year's program has been previously delineated by SandRidge and other reputable operators. We know this area well. Approximately 60% of the program will be infill development, and the remaining 40% being first wells in section or co-development that again, directly offset productive and profitable wells. Of note is that we are benefiting from having a long-tenured history in the MidCon. Previous development programs and can leverage a very tight cost structure to add incremental barrels to our base production in a very efficient way. Gross D&C costs for a one-mile lateral is now estimated to average just over $5 million, which reflects casing, drilling, and other material, equipment, and services already secured at reasonable costs and current market estimates. The team has done a great job at bringing forward co-development opportunities, utilizing company-owned equipment and other best practices to try and combat increasing market costs associated with inflation. We will continue to lean forward into these efforts to offset inflationary pressures. However, inflation will continue to be a central focus this year and have bearing on incurred costs, which could influence future drilling decisions. As we mentioned in last quarter's call, we would continue to monitor commodity prices, costs, and results before bringing forward additional projects for this year's capital plan. We have observed commodity price improvement over the last several quarters, and both spot and future prices have sustained at generally high levels during the second quarter. In addition, we have turned online the first two wells of the program, which are currently within expectation ranges. Based on these and other factors, we will be expanding this year's program from nine to 12 wells. Given the current drill schedule, we anticipate to be drilling the last well at year-end, with completions to carry over to the next year. From a production timing perspective, we anticipate that this year's capital drilling program will add 10% more relatively oil production on top of PDP levels during the second half of the year and 13% next year. Though additional inventory is economic at today's commodity prices, program results, timing, commodity price stabilization or further flattening, well costs to include levels of inflation and effect of controls, denser well spacing and other factors will guide future drilling decisions and inventory consideration. In addition to well reactivations, we will continuously assess these factors, and along with our board, evaluate the potential for future capital allocation in next year's program in a prudent manner. Put simply, we will continue to prove out the results first and then expand from there. Shifting to expenses, we are able to lower Adjusted G&A quarter-over-quarter, even with increases in capital activity from $2.2 million or $1.35 per BOE in the prior quarter to $1.8 million or $1.09 per BOE in the second quarter. Benefiting from our core values to remain cost disciplined as well as prior initiatives, which have tailored our organization to be fit for purpose. We continue to balance the weighting of field versus corporate personnel to reflect where we actually create value and outsource necessary, but more perfunctory and less core functions such as operations accounting, land administration, IT, tax, and HR. Despite expanding activity and producing well count, our total personnel remains just over 100 people. Although corporate personnel stand at 15, we have retained key technical skill sets that have both the experience and institutional knowledge of our area of operations to support drilling and completion operations, as well as the ability to flex through additional outsourcing of specialized areas to do more. We were able to reduce LOE and expense workovers to $9.5 million or $5.87 per Boe during the second quarter, a decrease of $1.4 million or $0.89 per Boe from the prior quarter. However, while we continue to press on operating costs, we anticipate expenses, specifically workover expenses, to remain near first half levels as we reactivate and repair more wells this year. The increase in commodity prices has improved the economics of these wells that may have been or would have remained shut in otherwise. The good news is that this will translate to additional production. However, while profitable, remaining tranches of well reactivations have relatively higher operating costs, which will increase power, water, chemical, and other expenses, both on an absolute and a per Boe basis. In addition to the cost of an increase in producing well count, inflation will continue to be a theme throughout the year. We will continue to combat inflationary pressure on expenses as well through rigorous bidding processes, securing material, equipment, and services over an appropriate tenure to partially offset market increases, as well as continuing to leverage our significant infrastructure, operation center, and other company advantages. We would like to point you towards our updated guidance for the year that was included in the company's earnings release published yesterday evening. We have increased the midpoint of guidance on production roughly 5%, driven by expanded capital investment for the year. On capital, we are increasing investments to a range of $56 million-$70 million, with over half of the expansion relative to prior guidance coming from additional well reactivations and rod pump conversions, and the remainder from additional high rate of return drilling in the Northwest STACK discussed previously. We have also increased our expense guidance to account for increased workover activity and producing well count, spurred from robust commodity pricing as well as projected rise in utility, service, and other fuel-related expenses, driven by both commodity prices and inflation. As I mentioned earlier, rod pump conversions will help reduce 0.4 costs in this regard over this well set. We project that operating cash margin of the program will increase from the first half by nearly $7 per Boe in the second half of this year at the July 25 strip, despite inflationary pressures on expenses and costs, driven by the combination of strong commodity prices as well as increased production associated with expanding investing, which will continue to bolster production into next year. In summary, the company has $205 million net cash and cash equivalent at quarter end, which represents $5.58 per share of our common stock issued and outstanding. Consistent production from Q1 to Q2 2022 in our MidCon position. Expanded 2022 capital program, high return projects to economically enhance production to include 12 new wells high-graded in the core of the Northwest STACK and a continuation of our well reactivation program. Low overhead, top-tier Adjusted G&A of $1.09 per Boe. No debt, in fact, negative leverage. Significant free cash flow and a growing net cash position supported by a diverse production profile, low decline, multi-decade life asset base. $1.6 billion NOL, which will shield future free cash flow from federal income taxes. Large owned and operated SWD and electrical infrastructure, which provides cost and strategic advantages requiring little to no future capital to maintain. This concludes our prepared remarks. Thank you for your time. We'll now open the call to questions. Thank you. We will now be conducting a question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star two if you'd like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star key. One moment please while we poll for questions. Thank you. Our first question comes from Josh Young with Bison. Please proceed with your question. Hey, guys. Just want a little more clarity on these first Meramec wells that you just announced. Can you talk about how many days of production the initial rates you described represent? It sounded like production was still inclining. Just wanna clarify that the production rate is per well and not for the two wells combined. Yeah. Morning, Josh. Great questions. Yes, the production profile is still increasing. They've been online just under 30 days. Like I mentioned in my remarks earlier, you know, we anticipate the gas specifically to go from its current rate of roughly 400 MCF a day to just over 1 million. Okay, great. Again, that's per well, 400 barrels a day, plus? Great. Okay. Then, just to follow up on capital return, you know, you guys have an approved buyback. I asked this on the last call and prior ones. It does seem odd to have cash build on the balance sheet, have an approved buyback, have the stock price down, and have the company not execute on it. Could you clarify a little bit what was intended with that approved buyback as well as what the company is planning for this cash that's building on the balance sheet? Sure, Josh. I'm gonna let Salah add in here, but before I do, you know, I just wanna reinforce that's something we look at routinely and a significant priority. We discuss the topic daily and monitor the markets. As you know, the board approved a 10b-18 program to take advantage of significant dislocations in the marketplace. However, I'll point out that the 10b-18 is restricted when you have material non-public information. Because we're active in the M&A space, it can really limit the window to take advantage of the significant dislocations that may be situational. You know, we have raised the topic of a 10b5-1 program as an alternate with the board and continue to evaluate considerations for share repurchases, return of capital, and strategic uses of cash. I'd also kind of point out that, you know, our share price performance has improved substantially since early last year, so relative to that period, there's less consistent dislocations on a day-to-day basis that creates a broad window of opportunity relative to the 10b-18 program. Josh, this is Salah. Add to that just a little bit. You know, we do have a diverse set of investors and they come with a diverse set of opinions and positions. You know, our board and management take their suggestions and recommendations very seriously. There is a contingent of investors that, you know, believe that perhaps the best use of cash is one in which we'll be able to leverage our NOL position to the maximal level, which would typically follow some sort of M&A, or something or other. We're constantly having these discussions with the board. I'd just like to remind all of our investors, you know, we do take your thoughts seriously. We bring these things to our board, but ultimately the board is the only one authorized to actually perform a buyback, or execute a transaction. Okay. Thank you. As a reminder, if you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. Our next question is from Jeff Robertson with Water Tower Research. Please proceed with your question. Thank you. Good morning. Grayson, can you talk about the inventory of wells, that are still offline that could be reactivated and what their economic sensitivity is? Yeah, sure. Good morning, Jeff. Thank you for the question. You know, as I mentioned, we've reactivated 158 through the second half from the beginning of last year, 29 over the first half. We'll be adding an additional 25 with the expanded capital program that we just announced for a total of 54 for the year. You know, there are, you know, several hundred additional opportunities and it's very gradational. I don't mean to be obfuscating here, but it's a multivariate equation because it's dependent on not only commodity price, but what the costs are at the time. As you have increased costs, right, it can change the break even relative to that commodity price. There are additional opportunities that we continue to evaluate, and we do this on a weekly basis with our team and continue to bring forward projects that have you know higher rates of return. As we do with everything else, we wanna make sure that we're that's delivering all those. We're very you know conservative with our hurdle rates in that regard. Grayson, what is some of the economic consideration based on where in the system the wells are offline or located with respect to how much water they may produce and how far you have to transport the water to put it back into the ground? It's not necessarily water driven. While, you know, water is a component, it's not really the transportation of the water per se, it's really the electricity that's required to pull the total fluid out of the ground. I think you hit the nail on the head. It's, you know, we've gone from, you know, $90 oil and $5 gas to $90 oil and $8 gas. Some of these wells are more gassy. Last year, we brought on some of the more oily relative wells, and they were cheaper to fix, right? Some of them in Q1 required very little cost to bring back online. The wells that we're moving to now are higher cost per BOE, but they add incremental margin, and they also require increased capital relative to Q1 of last year. Instead of a cheaper rod pump repair, in these instances, we may be installing a new rod pump, which is just more expensive. Okay, a question on the 12 wells in the Northwest STACK. Will these wells de-risk locations that you might think about in a 2023 capital program? I'm sorry, can you repeat the question, Jeff? Will the 12 wells that you're drilling this year, will I know that it's in an area that's well defined by existing producers, but will the performance on these help further de-risk wells that you might think about in the 2023 capital program? Absolutely. Not only from extending beyond because we're, you know, directly offsetting highly profitable wells. To the extent that you push the boundary a little bit more, the boundary beyond that becomes, you know, higher confidence and materially de-risked. Also from a spacing perspective. We're drilling this program at mostly two to three wells per section. To the extent that we have outperformance, we could down space, which would add additional locations. Okay. Thank you very much. Thank you. Our next question comes from Arieh Cole with Cole Capital. Please proceed with your question. Good morning, and thank you, gentlemen, for hosting this call. One tax question for you. As you know, in Congress, there's a bill pending to change corporate tax rates, where the government would institute a 15% minimum tax rate for all corporations. Could you just explain to me, based on your understanding from lawyers, what impact this would have on you? I obviously understand you have your net operating loss carryforwards, but how would this 15% corporate tax rate potentially impact you? Yeah, good question, Arieh. This is Salah, so I'll go ahead and take this. It's a little bit sparse on details, and it is, I think, a proposal. I don't believe it's been signed by President Biden, and there's still some drafting going on. From what we understand, that minimum tax will be levied on GAAP income for corporations that have net income of 1 billion or more. You know, unless we incur or gather net income of 1 billion or more, going out into the future, and if this bill passes as it is, it shouldn't affect us, based on what we understand today. You know, those things can change, and we're constantly monitoring that. We'll be sure to alert investors if we believe it impacts us in any material way. With that said, you know, given our current position, if we have $1 billion in net income coming up, that'll be a good problem to have real quick. Great. Thanks for the clarification. Appreciate it. Thank you. There are no further questions at this time. This does conclude our conference for today. You may now disconnect your lines. Thank you for your participation.