SandRidge Energy, Inc. (SD) Q2 2021 Earnings Report, Transcript and Summary

Good day, and thank you for standing by. Welcome to the SandRidge Energy Second Quarter 2021 Earnings Call. [Operator Instructions] Please be advised that today's conference is being recorded. [Operator Instructions] I'd now like to hand the conference over to your speaker today, [ Mr. Prestwich ], Director of Finance and Investor Relations. Please go ahead.

Thank you, and good morning, everyone. With me today are Grayson Pranin, our Chief Executive Officer and Chief Operating Officer; Salah Gamoudi, our Chief Financial Officer and Chief Accounting Officer; and Dean Parrish, our Vice President of Operations. Other members of the management team are joining us this morning as well. We would like to remind you that today's call contains forward-looking statements and assumptions, which are subject to risk and uncertainty. 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. Hopefully, at time we review the earnings release, we posted yesterday after the market closed. For the last several years and particularly over the last 15 months, Board of management have worked to transform our company in almost all respects. This transformation, focusing on asset base, streamlining our organizational and cost structures more than a full flip of net debt to net cash, to position the company well in assisting the tailwind of recent commodity price improvements to include an expanded capital program to reactivate over 100 wells in the second half of this year. Before I discuss these points in more detail, Salah will touch on a few highlights from the second quarter.

Thank you, Grayson. Simply put, 2Q '21 was a strong quarter. Despite no new drilling or completion activities, our Mid-Continent daily average production increased from 17,500 BOE per day last quarter to 19,000 BOE per day this quarter and was flat compared to Q4 of 2020. The quarter-over-quarter growth was driven in part by the reactivation of 49 wells curtailed during last year's commodity price downdrafts. During the quarter, our cash and cash equivalents balance, including restricted cash, increased to $90.6 million, a $14 million increase from the prior quarter, primarily as a result of higher production, commodity -- higher commodity price realizations and our continued focus on cost minimization, and despite being offset by the acquisition of the ORRIs held by the SandRidge Mississippian Trust I for a purchase price of $4.9 million. Total debt outstanding remained at $20 million with de minimis interest expense during the first half of 2021. Despite closing on the sale of our North Park Basin assets, during the first quarter of this year, our adjusted EBITDA remained relatively flat from the prior quarter at $20.8 million compared to $21.7 million. For reasons I'll discuss in a moment, I'd like to point out that EBITDA has very little I and no federal income taxes affecting T. Commodity price realizations remained strong over the quarter, at $64.73 per barrel for oil, $1.66 per Mcf for gas and $17.33 per BOE of NGLs. I would like to remind our investors that these figures represent 2Q averages and do not reflect movements made in benchmark commodity prices over the last several months in the third quarter. As I alluded to earlier, regarding our EBITDA, we have maintained our large NOL position, which was over $1.6 billion as of the end of the second quarter of 2021. Our NOL position has and will continue to allow us to shield our future cash flows from federal income taxes. Our cost discipline continued to improve during the quarter the previously implemented initiatives further manifesting in our financials, partially offset by an increase in workover activity associated with well reactivations. This quarter, adjusted G&A was approximately $2 million, or $1.13 per BOE, and $3.8 million, or $1.14 per BOE, for the first half of the year. The team also held LOE and expense workovers to $9.2 million, or $5.33 per BOE, during the quarter, while also reactivating 49 wells over the first half of the year. This level of LOE should be sustainable going forward even with an expanded planned well reactivation program in the second half of the year. We believe we compare favorably with our peers on both G&A and LOE on a per BOE basis. Also, it's relatively rare for an E&P company to generate net income. We did that. However, for the last 2 quarters, earning net income of approximately $16 million for the first quarter -- for this quarter and $51 million over the first half of the year, which included an almost $20 million gain on the sale of North Park Basin. Also, on the rarity category, we had no oil and gas impairments for the second consecutive quarter. Another notable item during the first half of 2021 was the simplification of our asset base. We exited North Park Basin in February with a higher decline, higher cost assets. We are now focused solely on our core long-lived predominately PDP Mid-Con properties and no longer engage in the routine flaring of produced natural gas. As discussed previously, during the quarter, we purchased for $4.9 million in cash, all the overriding royalty interest assets of standard Mississippian Trust I. When that trust, along with Mississippian Trust II ultimately liquidate, our company will no longer have any affiliated trust. Finally, our Board has approved the initiation of a share repurchase program as a means of opportunistically returning capital to shareholders. As a result, the company may purchase up to $25 million worth of its outstanding common stock beginning as early as August 16, 2021. We should note that the release posted yesterday and the 10-Q that we will file later today, provide further detail on our financial and operational performance during the second quarter and first half of 2021.

Thank you, Salah. That would be helpful to walk through some of the company's highlights, management strategy and other business details. For the last few years, the Board and management have focused the company's assets, optimized production profile, streamlining its organization and cost structure that strengthened its balance sheet. With the divestment of North Park in February of this year, the asset base is now focused in the Mid-Continent region, but primarily PDP relevant, which do not require the certified produce gas. These well listed assets are most fully held by exceptions along industry shallowing and diversified production profile. We have little to no substantial future geologic reservoir or materially concentrated capital risk across the producing assets. Some of the points of these assets are long histories and long lift. Double-digit reserve life enable high risk reduction history [indiscernible]. More than 1,000 miles each are owned and operated SWD and electric infrastructure over our footprint. This substantial owned and integrated infrastructure provides the company with both costs and strategic advantages, bolstering asset operating margins through reduced lifting as well as water handling and disposal costs, while derisking positive free cash flow. In addition, that interconnectivity and ample capacity help buffer these unforeseen curtailments, shallow decline. We began this year with base profile defining expectations at the upper teens, which are anticipated to be extended further to the low teens, driven in part to our well reactivation of workover. Diversified production profile, both on the gas liquid hydrocarbon mix perspective, and over 975 producing well-based perspective. Our interest is in mostly HBP, which gave breakeven to mix in commitment submitted. As a result of this focus in Mid-Con, the company was able to increase quarter-over-quarter production from 17.5 to 19 MBoe per day despite no new drilling or completion driven in part by the reactivation of 49 wells through the first half this year. Our assets have robust free cash flow capability, which contributes to the increase of $14 million worth of cash this quarter, now totaling over $90 million. Our high EBITDA free cash flow conversion is aided by our low per BOE cost structure and light CapEx requirement as well as improving commodity prices and realizations. This cash generation potential provides several paths to increase shareholder value. This all sums up to [indiscernible] proved developed PV-10 reserve value that we believe approximates more than $320 million. And we have begun to build on that by, one, extending and flattening our production profile with high grade reserve projects and well reactivations. We plan to reactivate another 100 wells in the second half of this year; two, actively managing on our realizations and further reducing costs; three, growing our asset base with opportunistic economic needs and free cash flow accretive acquisitions; four, maintaining an appropriate level of exposure to commodity upside. As we realized value generate cash, our product is committed to utilizing our assets, including noncash to maximize shareholder value. SandRidge's value proposition is materially derisk from a financial perspective our strengthened balance sheet above net cash position, financial flexibility and over $1.6 billion in NOL. Further, the company is not subject to MVCs or other significant off-balance sheet financial commitments. And with the recent purchase of the overriding royalty interest at SandRidge Mississippian Trust I during the quarter, we have simplified our operated net. Our goal or strategy is to grow the cash volume and generate capability of our business in a safe, responsible, efficient manner for our remaining disciplined for value-accretive opportunities. This strategy has 4 points. Again, we'll building that to our plan to maximize the cash value generation capacity of our expanding Mid-Con PDP asset by extending and flattening our production profile of the primary reserve workover and well reactivation, actively managing marketing opportunities to maximize price realizations, continue to press on operating and administrative costs. The second, ensure we converted much EBITDA to free cash flow, through capital discipline, in investing in value-accretive opportunities that have high risk-adjusted fully driven rates of return. The third is to keep vision to maintain optionality for opportunistic value-accretive acquisitions. We'll focus on PDP-related assets that fits our competency, cost efficiency and production optimization at sufficient midstream optionalities and are in a favorable regulatory area. The final thought is to uphold our ESG responsibilities. In regard to cost discipline up in the last several years, the Board of management has implemented measures that led to an absolute and per BOE reduction in LOE of 70% to more than 30%, respectively, since 2016. We will continue to press on operating costs. However, we anticipate expenses with the workover expenses will increase near term as we reactivate more wells for the remainder of the year. Fundamental to our culture has been a deliberate shift of focus for the organization. And as a result, we have tailored our organization to a PDP and cash flow-focused structure to be more fit for purpose. This change has rebalanced the weighting of field versus corporate personnel to reflect where we actually create value and outsource necessary those more functionary and less core functions such as operations accounting, land administration, IT, tax and HR. Beyond more than $6 million and per year G&A due, outsourcing provides us greater flexibility and scalability to adjust to the changes in our business or the market. With regards to production optimization, we focused on relatively low quick payback and high return workovers over the last year and have enjoyed success in our execution. We are purposely disciplined in our approach as we work to delever our balance sheet, expand our liquidity and capital access over the latter part of 2020. Now with a much stronger balance sheet and liquidity position as well as a vastly improved and firming price realizations, we plan to more aggressively pursue initiatives that will further flatten our already shallowing base decline. Over the first half of the year, we brought back online 49 wells, which collectively added 1,500 gross barrels equivalent per day and delivered over 100% rate of return. We plan to expand this program in the second half of this year, targeting over 100 wells for reactivation. Projected economics for this well set are now also over 100% rate of return. In addition, we will plan to convert a subset of these wells to a more efficient long-term artificial lift method, which will likely reduce their go-forward cost. Well reactivation projects are the highest risk-adjusted returns in the company's inventory. Unlike drilling, there's very little relative geologic reservoir of mechanical or risk concentration. Recently, we have filed 2 recompletion permits to the Oswego and Red port formation in legacy vertical wells. Initial work is scheduled for this year and tested pressure as well as oil and gas composition will bear the influence on completion and capital decisions. We will continue to evaluate the opportunity for these types of relatively low capital, high-return projects across our almost 375,000 acre footprint to help further spend declines in the future. Our performance continues to exceed the expectations that we laid out earlier this year. As we discussed previously, this outperformance driven by a material uplift in realized prices, find the successful well applications earlier this year. We plan to expand this well reactivation program by bringing on an additional 100 wells over the second half of this year. As such, we are adjusting our guidance that will reflect the uplift in production, increasing the midpoint of guidance by over 15%, as well as the associated increase in capital and expense needed to do so. Please note that while expense is estimated to be up an increase on an absolute basis, it is not increasing on a per unit, demonstrating that we are bringing on more production and cost effectively. Please note that the revised guidance does not budget for doing it this time as we'll focus on our well reactivation program near term and do so in a safe, efficient and cost-effective manner. We will continue to evaluate opportunities for drilling the strengthening prices firming around current spot or above. In summary of the company's and its assets current strengths, we have low overhead top-tier G&A of $1.37 per BOE in the first half '21. We have low operating costs benefiting from a large F&D and electrical infrastructure, requiring little to no future capital to maintain substantial free cash flow and a growing net position supported by a diverse production profile, low decline multi-digit life asset base. Inventory of low-cost high-return well reactivations will help flatten production decline. No routine flaring of produced natural gas among other factors. This concludes our prepared remarks. Thank you for your time. We'll now open the call to questions.

[Operator Instructions] Your first question, line of Noel Parks with Tuohy Brothers Investors.

A couple of things. You're talking about converting to more efficient artificial lift. Are those like rod pump conversions or?

Yes, we're converting from the initial artificial lift which were predominantly ESP or gas lift to a long-term artificial lift system, which is either rod pump or plunger lift.

Great. Okay. And I was -- it's been a terrific time to be unhedged given the upswing you've seen in commodity prices the last couple of quarters. And could you just refresh my memory, did you monetize some 2021 hedges at some point earlier in the year?

Noel, yes. This is Salah. We did end up doing that. We monetized our hedges in 4Q of '21 -- or 4Q '20, sorry.

Okay. And I was just curious, in your program of returning wells to production, are there any third-party infrastructure issues that are standing in the way of returning any of the wells? I guess with better commodity prices, especially on the gas and NGL side, I was just thinking about the possibility of infrastructure getting a little bit more tax than it's been in recent times.

No, no. That's the benefit of having it owned and operated large infrastructure system, and we're better able to take advantage of the ample capacity that we have in each of those systems.

Okay. Great. And I think my last one. Just thinking about the transaction environment, we've seen a lot of activity across a number of different basins. I'm just thinking about in the Mid-Con, particularly conventional reservoirs, are there PE that private players still out there and in your area? And I'm just curious if among those, if any of them also are spending any significant CapEx these days.

Sure. Yes. There continues to be private equity players in and around Mid-Con. We like to remain wide eye to both their operations as well as public company operations, just so that we can benchmark our performance relative to them. And we think that we compare favorably. In addition, we remain vigilant and research potential opportunities in the market in Mid-Con and are really just looking for something that's the appropriate fit at the right price. And I hope I addressed that question correctly.

Your next question, the line of Brett Hendrickson with Nokomis Capital.

It's Brett with Nokomis Capital. And I'd love to follow up with you guys off-line on this maybe. But congrats on what looks like a really high return reactivation program. I am assuming that you guys are probably in a pretty rational actors. So you did the -- I imagine you did the best reactivations first in the 49 or are they more linear in terms of the uptick that you get from an incremental reactivation on the next 100? Just any color would be appreciated.

Sure. It's a mix. There was a subset there that didn't require any wells integrating into workover. So it's just a matter of going on and turning on the well. So those got turned on quickly. We did go in, in high grade. And as we've had continued price uplift, we felt it was appropriate to bring on the next 100-well tranche in the back half of this year.

Okay. So you had somehat they were just easy to turn on --to turn them on but there might not have been much production. So then I guess the follow-up would be how many of the next 100 -- I think, 30 of the first 49 required a workover. How many of the next 100 or so will require workover?

The majority.

The majority one, okay. And remind me, what's the average cash cost on a workover?

These workovers vary. On average, they're about $65,000.

[Operator Instructions] Your next question, the Josh Young with Bison Interests.

So a couple of questions. One on the price realizations. It looks like the realizations for gas and NGLs weren't up that much, even though the headline price for those commodities were up or, I guess, if you could help reconcile kind of where that difference is and if there are any opportunities to improve your realizations versus the houses?

Yes. Thanks, Josh, and good morning. I'll touch on a few points, and then I'll turn it over to Salah to reinforce some others. So we've seen improvement in realization since last year. We're focused on further improving these realizations by actively working with our largest purchasers. In addition, we believe that as the benchmark increases, Sand realization will also improve as the fixed cost components are less impactful, subject to change in local market conditions. Salah?

That's correct. And one thing we just wanted to make sure that everybody was -- and Josh, I know you are, but just all of our investors are aware that 2Q of '20 -- of '21, sorry, the commodity prices that -- the posted commodity prices weren't -- they weren't as gangbuster as they have been in the third quarter. And so I know there's a lot of excitement about where Henry Hub is going and things like that, but we still saw -- certainly, we saw commodity price improvements from the prior year. And just as Grayson said, we continue to expect that the realizations will continue to improve as we go along here. So with our efforts on the marketing side as well, fixed cost component that Grayson was speaking of, I think that we'll continue to see that.

Great. Okay. That's helpful. And then my other question is on -- it looks like there are a couple of drilling permits that were filed for you guys. Are those workover wells or new wells? And then I guess, to the extent that they aren't -- to the extent they're just kind of workovers that were prior rigs, is there a price that you guys are tracking where you see new wells in drilling your PUDs? Is there a breakeven price that you'd track where at a certain price or higher, it would start to become economic and compelling call for capital to start drilling new Mississippian Lime wells?

Yes. Thanks, Josh. You may have heard it during the call. But the 2 recompletions that I mentioned related to the permanence question. And there, we're looking at testing the Aswego and Red port. As I mentioned, we're really focused on what's the highest risk-adjusted return in our inventory right now, which is the well reactivations. We remain focused on potential for drilling opportunities. And I think you can see us lean into that as prices firm around current spot degrader. But right now, we do have inventory that's economic. But you'll see us be a little bit more conservative in ensuring that we deliver a very high risk adjusted fully rate of return out to the shareholders as we realize those success. So we're not going to drill in low double-digit return properties.

Got it. That's really helpful. And then just one quick follow-on on that. It looks like you guys amended your credit agreement to be able to start to hedge if you choose to you did a great job in covering your hedges at a cost and total market kind of penalty for that late last year that we saw in filings this year. Do you guys have plans to hedge? Or could you kind of clarify a little bit in terms of like what the thinking there is in getting that change in the credit agreement?

Yes, Josh, the change in the credit agreement really was administrative in nature in the sense that we wanted to be able to enter and exit hedges in the normal course. The way that the credit agreement was structured, we made that difficult. And so we discussed that with our lender about that past. With that said, we'll always continue to look at the potential for hedging, especially as our capital program here has been increased, and we'll continue evaluating that. But the change in the credit agreement in and of itself was really just allowing us to act in the normal course of any -- as a typical E&P company would.

[Operator Instructions] Your next question, line of Michael Melby with Gate City Capital Market.

Congrats on the good results. Could you update us -- you had a nice slide last quarter on your infrastructure assets, and I appreciate the update here. Can you talk about any other strategic or other ways you might be looking to gain value off of your infrastructure assets?

Yes, good morning Michael. Thank you for the question. That's something that we continue to evaluate. We have the benefit of having that large infrastructure position, and we're always looking at ways to increase profitability or cash flow around them. But I don't have anything to report out today.

Got it. And the share repurchase was nice to see. I guess my understanding is with a dividend, you could deliver capital back without -- in a tax-efficient way, I guess, I should say. Could you talk about your decision for share repurchases versus the dividends?

Thanks, Michael. That's a great question. The way that we saw it is on implementing the program and reviewing the fact and figures internally, we still believe as a company that's -- they're still a value disconnect between our share price and our intrinsic value. So we thought it would be prudent to allocate capital in such a way that would give our investors the highest return. And when we reviewed that buying back our own stock to potentially be an avenue for that. I'd also like to point out that the share repurchase program is concluded at our discretion. It is a 10b-18 program, which allows us to purchase when and where want and how much. And so the $25 million that's approved is an up Q amount and we will evaluate each one of those decisions in isolation as we go.

[Operator Instructions] And there are no other questions at this time. This concludes today's conference call. Thank you for participating. You may now disconnect.