SM Energy Company (SM) Earnings Call Transcript & Summary

Welcome to SM Energy's Third Quarter 2021 Results Webcast. Before we get started on our prepared remarks, I remind you that our discussion today will include forward-looking statements. I direct you to Slide 2 of the accompanying slide deck, Page 6 of the accompanying earnings release and the Risk Factors section of our most recently filed 10-K and 10-Q, which describe risks associated with forward-looking statements that could cause actual results to differ. We will also be discussing non-GAAP measures. Please see Slides 28 through 31 of the slide deck and Pages 14 through 17 of the earnings release for definitions and reconciliations of non-GAAP measures to the most directly comparable GAAP measures and discussion of forward-looking non-GAAP measures. Today's prepared remarks will be given by our President and CEO, Herb Vogel; and our CFO, Wade Pursell. I will now turn the call over to Herb.

Good afternoon, and thank you for your interest in SM Energy. Third quarter results were, by any measure, terrific. Wade will walk you through the financial detail. But first, I'd like to focus on our operational execution. Our operational execution differentiates SM Energy, and it is translating into real value creation for all shareholders. I'll start on Slide 3. I'll highlight 3 topics today. First, our relentless drive to optimize returns. Our top-tier well performance and high returns are by design, and we're not done. Today, I'll give you a little insight into the new completion design we are employing in the Midland Basin. Second, building high-value inventory with no incremental acquisition cost. The Austin Chalk story keeps getting better, and the success of development spacing is a notable milestone. So I'll give you an update on what we are seeing and what to look for. Third, our focus on generating free cash flow and accelerating the transfer of value to the equity holder through debt reduction. The outlook for 2022 is shaping up very well. Let's preview what to look forward to in February when we plan to roll out our operations plan for next year. Starting with great well performance in the Midland Basin, this quarter, I'd like to highlight the completion design improvements we implemented in 2021. Skipping ahead to Slide 10. Looking at the 2021 Midland Basin program of 90 gross completions through September, the vast majority, 80 wells, have employed higher proppant loadings and some increased fluid loadings. The larger designs had proppant loadings of more than 2,300 pounds per foot, with some testing more than 3,000 pounds per foot. About 40% of these higher proppant loading tests were paired with higher fluid loadings. At current development spacing, the larger completions are driving stronger performance and better economics. As I mentioned earlier this year, it generally takes 6 to 12 months to see the benefit of completion design changes like these as it usually shows up as a shallower decline. Of the new wells this year, 28 have been online for at least 6 months. We have already confirmed an overall improvement in cumulative production performance from these 28 wells relative to expectations with the previous completion design. 1 pad in our Coyote Valley area, the northeast portion of our Howard County position, saw uplift sooner. The 3 Miracle Max wells were completed with 2,980 pounds per foot proppant and about 64 barrels per foot of fluid and are exceeding the base type curve by around 64%, as shown in the slide. And I need to point out that these wells have been online for less than 6 months. Turning now to the future. I'll start with a little background on how we get better from here. Our technical team set out to optimize the performance of future wells by employing a series of data analytics tuned to pass well performance. To summarize a large project, data from a very large number of previous well completions and production performance was input to the analysis, including from our own SM wells as well as data from regional data trades. We included a number of variables unique to each well to enable rapid assessment of the tie between completion design parameters, reservoir characteristics and optimal well performance. Looking ahead to 2022, the team has modeled and recommended a standard completion design that details proppant, fluid, cluster spacing, clusters per stage and stage spacing based on their analysis. This is expected to lead to higher average EURs and NPV per well in the go-forward program. We then incorporated these design enhancements to ultimately enable free cash flow optimization in our planning model. Turning to Slide 11. Last quarter, we talked about drilling the longest lateral in Texas and simul-frac success. This quarter, completion optimization. In short, our team is driven to optimize returns, and I believe there is more to come as I just previewed. Next, let's look at updated Austin Chalk results. Skipping ahead again to Slide 14. A few weeks ago, we provided the results of a 6-well development with wells spaced between 675 feet and 1,000 feet apart in the Austin Chalk. We have updated the performance of these 6 wells on this slide. This is certainly a milestone in building the confirmation of the estimated 400-well Austin Chalk inventory. These 6 wells averaged more than 50% oil and have projected returns at strip pricing in excess of 100%. They have together already produced 0.5 million barrels of oil and are projected to pay out in less than 5 months. Turning to Slide 15. Our 2021 operating plan for the Austin Chalk includes 30 net wells drilled and 25 net wells completed. This slide updates the performance of the 22 Austin Chalk wells we have completed to date that have reached their peak IP30 rates. As each month goes by, it is becoming clear how well the production from these wells is holding up and how economically advantaged this western Austin Chalk play truly is. We will seek to further demonstrate the value of the Austin Chalk position with continued development in 2022. I'd like to put a little meat on this with an internal estimate. Our estimate of the 2021-2022 drilling program in the Austin Chalk has an average PV10 greater than $10 million per well using $60 oil and $3 gas. Looking at Slide 16 with Enverus data. You can see the very competitive economics of our Austin Chalk program. And you can also see that the economics of our Austin Chalk and Midland Basin programs are both top tier, right next to each other in attractiveness. The Austin Chalk is certainly shaping up to be a sizable, low-breakeven and high-return asset with no incremental acquisition cost. Right now, we're designing our 2022 South Texas drilling program, which will be predominantly focused on the Austin Chalk at anticipated development spacing. Well performance in both the Midland Basin and South Texas has supported higher-than-expected production in 2021. This has combined with our continued focus on capital discipline and capital efficiency, plus a nice tailwind from commodity prices, to generate very strong free cash flow for the third quarter. In addition, the increasing EURs and NPVs in the Midland Basin from our improved completion designs and increased confidence in the Austin Chalk inventory is driving reserve and NAV growth. We definitely have excellent momentum entering 2022. Turning now to Slide 17 and a free cash flow comparison to peers. Looking ahead, our long-term plan put forth just this past February generated substantial free cash flow in 2022 considering a much lower commodity price environment. As we now enter 2022, we have further improved well performance, commodity prices higher, and our objectives remain unchanged. You can look for continued capital discipline and capital efficient execution. We look forward to employing our recent successes with completion design optimization, simul-frac and long laterals. Production will be an output, not an input, of our planning process that targets free cash flow and will likely range from flat to single-digit growth on an annual average to annual average basis. Quarterly variation should be an expectation as we seek to optimize cost, the scale of pad developments and the timing of turning wells in line. At current commodity prices, we expect wells in both the Midland Basin and Austin Chalk to generate comparable returns. We expect substantial growth in free cash flow in 2022, and this slide with JPMorgan data supports our expectation to generate an attractive and competitive free cash flow yield. And we will continue to reduce absolute debt, transferring that enterprise value from the balance sheet to equity holders and position SM for a multiple comparable to the lower-levered peers, which should ultimately lead to multiple expansion. Now turning to ESG on Slide 18. Optimizing performance includes minimizing our impact on the environment. We created an internal team with the purpose of evaluating and implementing field technologies to better measure, monitor and decrease emissions. This collaboration between operations and our information technology team has led to the initiation of a pilot project in Sweetie Peck to provide continuous methane emissions detection. This new technology measures and monitors emissions using laser technology and machine learning, identifying methane emissions with greater accuracy. This is one of multiple technologies to be evaluated by this team in the coming quarters. Now I'll turn it to Wade for the remainder of our 3Q update. Wade?

Thank you, Herb, and good afternoon, everyone. I'm going to flip back to Slide 4 and start there. So hopefully, you'll find most of the details you need in the published materials. I'm going to try to add some context on a few points. Third quarter production certainly exceeded our expectations. The outperformance is a result of several contributing factors. Midland volumes benefited from higher base production, reduced flaring and, as Herb has already covered, the uplift we are starting to see from our larger simulations. Higher base production is partially attributable to less impact from offset activity than we had modeled. South Texas volumes included the earlier-than-expected turn in line of 5 wells that were scheduled to come on in 2022. This was possible due to remediation of casing issue in the vertical section of 3 wells on 1 of the 2 pads that we talked about during the February call. Very fortunately, this meant that the wells did not need to be redrilled, although the effective lateral completion links were less than originally planned for some of the wells, with the wells averaging around 8,400 feet. These 5 wells came on with high oil content of around 58% to 79%, and they have yet to reach their 30-day peak IP rates. Capital expenditures of $160 million came in under our guidance range of $170 million to $190 million. This relates primarily to timing as our capital guidance for the full year remains in the same range. During the quarter, we drilled 24 net wells and brought on 35 net flowing completions. Year-to-date, CapEx has totaled $559 million, and we have drilled 64 net wells and brought on 97 net flowing completions. In the fourth quarter, we expect 17 net drills and 13 net completions, so for the full year totals of 80 and 110, respectively. On Slide 5 now. Operating cost per BOE benefited on the LOE side from: increased water recycling in the Midland Basin, which reduced water disposal costs; and better artificial lift performance, meaning less expenditure for workovers. On the transportation side, the higher gas volumes, combined with the better contract rates that began in July, reduced transportation cost per BOE. DD&A expense per BOE also came in favorably, which largely reflects internal midyear updated reserve estimates. Turning to Slide 6 and the balance sheet. It was a great quarter for the balance sheet as well. Debt-to-EBITDAX fell below 2x to 1.96 by quarter end, meeting our year-end 2022 objective. That's 5 quarters earlier than we projected at the beginning of this year. Net debt was reduced by $148 million during the quarter as we used free cash flow to retire the remaining $65.5 million of outstanding convertible notes and outstanding revolver balances, leaving some cash on hand at the end of the quarter. And then subsequent to quarter end, the revolver was actually reaffirmed by the bank group at $1.1 billion. So turning to hedges on Slide 7. Hedge details, all the details by quarter is in the slide deck appendix. Our long-standing hedging strategy remains to tie hedge levels to leverage levels, protecting the downside. With leverage reduced to less than 2x, we expect to hedge closer to 50% of 2022 volumes, rather than the 80% range that we have hedged this year and last year actually. Using 2021 production volumes as a proxy, we're currently less than 40% hedged for production volumes next year. Given our outperformance year-to-date on both revenue and the cost side, we've updated guidance to reflect the improved expectations. So on Slide 8, updated full year guidance includes increased production volumes of 49.5 million to 50.0 million BOE or 135,600 to 137,000 BOE per day, with 54% to 55% oil expected. Capital expenditure guidance is narrowed to $670 million to $675 million as we will likely end up near the high end of the range for well completions. LOE is narrowed at the low end to $4.50 to $4.60 per BOE, and transportation should end up around $2.75 per BOE. Higher commodity prices increase taxes, so ad valorem plus production tax will likely be in the $2.70 to $2.75 per BOE range. Exploration expense is reduced to around $40 million. DD&A is reduced to a range of $15 to $15.50 per BOE. And G&A is rounded up to a range of $100 million to $110 million accommodating the potential for an increased bonus for significant outperformance. This implies fourth quarter production volumes of 12.7 million to 13.2 million BOE or 138,000 to 143,500 BOE per day and fourth quarter CapEx of $111 million to $116 million total. Keep in mind, we accelerated activity into the second and third quarters of 2021 to benefit from the added cash flow from wells turning in line sooner and the potential benefit to capital cost as inflation was projected to kick in. We have seen only nominal inflation in our 2021 well costs. Looking ahead into 2022, very generally, we're working with our vendors on our activity and plans. On the cost side, we're hearing some inflation on rigs, pressure pumping, tubulars, chemicals, fuel, labor and trucking and will work that into our final operations plan as appropriate. On the production side, our slowed capital activity in the fourth quarter of 2021 will translate into a modest step-down in production in early 2022 as we gear up again in January. Of course, production is an output of our plan. In 2022, we will remain focused on free cash flow and absolute debt reduction. We expect 2022 to be a very exciting year for SM, and we're positioned very well to generate significant free cash flow and, in turn, reduce leverage. So I'll now turn it back to Herb and back to Slide 3 to wrap it up. Herb?

Thank you, Wade. We wind up another great quarter with ample momentum steered toward: meeting a leverage target less than 1.5x before the end of 2022; generating a differential free cash flow yield that we see as top tier among our peers and, importantly, competitive across industries; and increasing our reserve and NAV values through both stronger EURs and confirmation of the Austin Chalk across our 155,000 acre South Texas position. We look forward to our live Q&A session tomorrow morning at 8 Mountain Time.