Sandridge Energy Inc Q2 FY2022 Earnings Call

Greetings, and welcome to the Second Quarter 2022 SandRidge Energy Conference Call. 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 uncertainties, 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 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 6 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 stock 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 debt and very little overhead given that we have no debt and a substantial net operating loss (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 $109.6 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 Q2 '22. 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 lease operating expenses (LOE) and expense 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 in 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's strategy and other business details. As I mentioned previously, we are pleased with the 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 properties in Mid-Con. We were able to keep quarter-over-quarter production flat in Mid-Con despite no new production from drilling and completion activity during the period, driven in part by the continued benefit of our well reactivations of 158 wells since early 2021. We will continue to reactivate wells averaging over 100% internal rates of return (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 pumps, 12 of which were converted over the first half of the year that will aid in optimizing lifting efficiency and lowering ongoing costs for this well set. The rod pumps we have or will be installing are tailored for the wells' current production conditions and will reduce the electrical demand from the current artificial lift systems. 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 2 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 2 1-mile lateral wells are producing an average of approximately 400 barrels of oil per day and nearly the same level in gas at the end of July. Gross drilling and completion costs for the 2 wells averaged $4.6 million. We anticipate that the output 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 flowback 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 proven developed producing (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, shallow and diversified production profile, and double-digit reserve life. The present value (PV-10) of future net discounted cash flows to proved, developed oil, gas, and NGL reserves of these assets is approximately $690 million. Based on year-end 2021 reserves and assumptions rolled forward to July 1, 2022, and using Q2 '22 SEC prices. These assets include more than 1,000 miles each of owned and operated saltwater disposal (SWD) and electrical infrastructure over our footprint. This substantial owned and integrated infrastructure provides the company both cost and strategic advantages, bolstering asset operating margins to reduce lifting as well as water handling and disposal costs, combined with other advantages, helped derisk 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 totaling over $200 million with 0 debt as of quarter-end. This cash generation potential provides several paths to increase shareholder value realization and is benefited by a 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 derisked 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 minimum volume commitments (MVCs) or other significant off-balance sheet financial commitments. Currently, the company does not have any open hedging contracts before June 30, 2022. However, we could enter into hedges from time to time in support of securing returns for our capital campaigns, managing commodity risks, 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 4 points: 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 workovers, well reactivations, and artificial lift conversions; 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 programs in the core of Northwest STACK to economically add production; remain open, patient, and maintain optionality for opportunistic value-accretive acquisitions, focusing 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; and 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 we'll continue to pursue with thoughtful and disciplined execution this year in order to realize high rates 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-developments that again directly offset productive and profitable wells. Of note is that we are benefiting from having a long-tenured history in the Mid-Con, with previous development programs that can leverage a very tight cost structure to add incremental barrels to our base production in a very efficient way. Gross drilling and completion cost for a 1-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 cost 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 has bearing on unsecured 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 2 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 9 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 relative 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, and commodity price stabilization are further flattening well costs to include levels of inflation and effective controls, denser well spacing, and other factors will guide future drilling decisions and inventory considerations. 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 were 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 important 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're 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, the remaining tranche 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 increasing 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 tenor 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 of roughly 5% driven by expanded capital investment for the year. On capital, we are increasing investments to a range of $56 million to $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 rising utility, service, and other fuel-related expenses driven by both commodity prices and inflation. As I mentioned earlier, rod pump conversions will help reduce operating costs in this regard over this well set. We project that the 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 investments, which will continue to bolster production into next year. In summary, the company has $205 million net cash and cash equivalents 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 Mid-Con position. Expanded 2022 capital program, high returned projects to economically enhance production to include 12 new wells high graded in the core of the Northwest STACK, and 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-digit life asset base. $1.6 billion NOL which will shield future free cash flow from federal income taxes. Large, owned, and operated SWD in 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.

Our first question comes from Josh Young with Bison.

So I 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? And it sounded like production was still inclining. And then I just want to clarify that the production rate is per well and not for the two wells combined.

Yes. Great questions. Yes, the production profile is still increasing. They've been online just under 30 days. And like I mentioned in my remarks earlier, we anticipate the gas specifically to go from its current rate of roughly 400 Mcf a day to just over 1 million.

Okay. Great. And again, that's per well, 400 barrels a day. Great. Okay. And then just a follow-up on capital return. 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 has 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'll let Salah add to this, but I want to emphasize that we routinely consider this and it is a significant priority for us. We discuss it daily and keep a close eye on the markets. The Board has approved a 10b-18 program to capitalize on significant market dislocations. However, it's important to note that the 10b-18 can be restrictive when we have material nonpublic information, especially since we're active in mergers and acquisitions. This can limit our ability to seize on certain dislocations that arise. We believe it would be beneficial to consider a 10b-5 program as an alternative with the Board and continue to evaluate options for share repurchases, capital returns, and strategic cash uses. Additionally, I want to highlight that our share price has significantly improved since early last year. Therefore, compared to that period, there's less consistent market dislocation day-to-day, which affects the opportunity under the 10b-18 program.

And Josh, this is Salah. I'll add to that just a little bit. We have a diverse set of investors, each with different opinions and positions. Our Board and management take their suggestions and recommendations very seriously. Some investors believe the best use of cash is to leverage our NOL position to the fullest, which typically follows some sort of M&A or similar activity. We are constantly discussing this with the Board. I want to remind all of our investors that we take your thoughts seriously and bring these considerations to our Board. However, only the Board is authorized to perform a buyback or execute a transaction.

Our next question is from Jeff Robertson with Water Tower Research.

Grayson, can you talk about the inventory of wells that are still offline that could be reactivated and what their economic sensitivity is?

Yes, sure. Jeff, thank you for the question. 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 to the expanded capital program that we just announced for a total of 54 for the year. There are several hundred additional opportunities, and it's very gradational. And I don't mean to be obfuscate here, but it's a multivariate equation because it's dependent on not only commodity price but what the costs are at the time. So as you have increased costs, right, it can change the breakeven relative to that quality price. So 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 higher rates of return. But as we do with everything else, we want to make sure that we're delivering on those. So we're very conservative with our hurdle rates in that regard.

Grayson, some of the economic considerations depend on the location of the wells, whether they are offline, how much water they can produce, and the distance required to transport the water back into the ground.

It's not necessarily water-driven. While water is a component, it's not really the transportation of the water per se. It's really the electricity that's required to lift the total production out of the ground. And I think you hit the nail on the head. We've gone from $90 oil and $5 gas to $90 oil and $8 gas. So some of these wells are more challenging. So last year, we brought on wells that 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 margins and then also require increased capital relative to Q1 of last year. So instead of a cheaper rod pump repair, it means you 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 derisk 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, I know that it's in an area that's well defined by existing producers. But will the performance on these help further derisk wells that you might think about in the 2023 capital program?

Absolutely. And not only from extending beyond because we're directly offsetting highly profitable wells. So to the extent that you push the boundary a little bit more down, you gain higher confidence and mature derisks, but also from a spacing perspective, so we're drilling this program at mostly 2 to 3 wells per section. And to the extent that we have outperformance, we could downspace which would add additional locations.

Our next question comes from Arya Cole with Cole Capital.

I have a tax question for you. As you may be aware, there is currently a bill in Congress proposing a change to corporate tax rates, which would establish a 15% minimum tax rate for all corporations. Could you explain what impact this might have based on your understanding from lawyers? I know about your net operating loss carryforwards, but how could this 15% corporate tax affect you?

Yes. Good question, Arya. This is Salah. So I'll go ahead and take this. So it's a little bit sparse on details. And it is, I think, a proposal, not I believe it's been signed by President Biden, and there's still some drafting going on. But from what we understand, that minimum tax will be levied on GAAP income for corporations that have net income of $1 billion or more. So unless we incur or gather net income of $1 billion or more going up to the future and if this bill passes as it is, it shouldn't affect us based on what we understand today. But those things can change, and we're constantly monitoring that, and we'll be sure to alert investors if we believe it impacts us in a material way. But with that said, given our current position, if we have $1 billion in net income coming up, that will be a 'good problem to have'.

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.