SM Energy Co Q1 FY2023 Earnings Call

Good day, everyone and welcome to the SM Energy First Quarter Results Q&A Discussion. Today's call is being recorded. I'd now like to turn the conference over to Jennifer Samuels, VP of IR and ESG Stewardship. Please go ahead.

Good morning, everyone and thank you for joining us today for our Q&A session. To answer your questions today, we have our President and CEO, Herb Vogel, and CFO, Wade Pursell. Before we get started, as usual, our discussion today may include forward-looking statements and discussion of non-GAAP measures. I direct you to Slide 2 of the accompanying slide deck, Page 8 of the accompanying earnings release and Risk Factors section of our most recently filed 10-K, which describe risks associated with forward-looking statements that could cause actual results to differ. We may also refer to non-GAAP measures, please see the slide deck appendix and 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. As a reminder, we have posted an investor presentation and the transcript to our prerecorded call from yesterday that we may reference in the call today and look for the first quarter 10-Q filed this morning. With that, I will turn it back to Herb for brief opening commentary.

Thanks, Jennifer. Good morning, and thank you for joining our Q&A call this morning. Before we get started, I'll reiterate a few key messages this quarter. We're pleased to report that we have repurchased 2.8 million shares since the inception of our return of capital program in September, and including our increased fixed dividend, we have returned a total of $134 million. We are well-positioned to provide a solid return to our shareholders in 2023 through the combination of our fixed dividend and upside through share repurchases. Execution was solid in the first quarter, not only exceeding guidance for oil and total production volumes, but recognizing notable operational achievements such as drilling 75,000 feet of lateral 20 days faster than planned or successfully drilling 5,000 to 18,000-foot laterals, which are now among the longest laterals in the Midland Basin. This is a key objective to maintain and build our inventory. During the first quarter, we made progress on this front with organic growth through the purchase of 6,300 net acres in the Midland Basin. This first quarter is a solid start to what we believe will be a great year. With that, I will turn it back to Lisa to start taking your questions.

We'll take our first question from Scott Hanold with RBC Capital Markets.

You all had a pretty good start to the year in terms of production performance. Can you provide more details on what you're observing? It seems like there’s improved operational efficiency and perhaps better well performance as you extend these laterals. Is that the case, or is that something we should expect to see in the future?

Yes. Thanks, Scott. I would say it's just regular blocking and tackling. Our well results are actually quite predictable in terms of their performance. It’s a matter of how much offset activity there is, and it was pretty much in line with what our expectations were during the quarter. The base performance has been great on our base decline of PDP wells. The new wells are performing as expected or better. In one case, in the instance of that Eagle Ford South Texas pad, seven wells came on a week early. So I would just say it's very predictable for our wells. The uncertainty lies in how much offset activity we've got to anticipate.

Okay. I appreciate that. And as my follow-up, you talked about picking up a little bit of acreage. Could you, at a high level, talk about the strategy there? Is this more tactical kind of bolt-ons? Or do you see the opportunity to continue to do more of that and scale up a little bit? I'm just kind of curious how much acquisition activity in terms of size you feel comfortable doing?

Yes. Scott, this is Herb again. I would say all along, since we really built our position in the Midland Basin, we've been looking at acreage trades and acquisitions where it makes sense. Our geosciences team is quite laser-focused on intervals that are differential in terms of their return performance. We keep looking at places where it makes sense and where we can acquire the acreage at a reasonable cost. That was certainly the case for the last quarter of last year and the first quarter of this year, and we will continue to pursue that. There are large and small packages on the market right now. As you know, private equity has been selling some of their positions. We consider those if we can acquire something that makes sense from a returns perspective. We approach it carefully, ensuring it remains within a scale that makes sense for the company, as we're not going to do something that jeopardizes the balance sheet. That's really our approach. So yes, we'll continue looking.

Okay, right. So similarly, there have been some larger deals that have happened nearby. You look at things like that, and it just has to make sense. Is that a fair way to look at it?

Right. Exactly. It has to make sense for the scale of our company and the quality of the acreage. We maintain a very high bar on that quality of acreage metric to ensure we continue to achieve the high returns we currently enjoy in the Midland Basin and Austin Chalk in South Texas.

We'll take our next question from Leo Mariani with ROTH MKM.

I wanted to follow up a little bit more on the 6,300 net acres, which you bought. It looks like around $10 million. So relatively low priced, I guess, roughly $1,600 an acre. Is this kind of more exploratory acreage? Just looking at the slide deck, it looks like it's not in Rockstar. It's not in Sweetie Peck, if I'm reading that correctly? And is there any color on whether or not there's kind of well control on this stuff? Is this kind of more away from existing assets? And maybe you've got some intel that you think this can be promising. Just any more details would be great.

Yes. Leo, I know a lot of people would be curious about that. Obviously, we're not saying we would have put it on the math if we were. You'll see more in the future about that. But right now, we're really not saying anything more.

Okay. And then just in terms of the Chalk wells, you guys have these seven wells, which you clearly said came on early, but sounded like very strong performers as well. Just trying to get a sense there. Have you guys benefited at all from the new completion designs that you’ve been experimenting with for the past handful of quarters? Is that potentially leading to some of the strong performance of the wells? Or is that something that's more likely to take effect late this year into next year? And then just on the midstream side, you guys obviously had some issues in the fourth quarter in terms of not being able to flow your wells. Do you feel like those midstream issues are behind you in the Chalk this year?

Yes. Thanks, Leo. Great questions. First of all, I'll just say that all our new Austin Chalk wells have outperformed our expectations. It has been great to see all the improvements, and some of that stems from completion design improvements. There are a number of other factors contributing to their superior performance. You’ll recall we had too much oil in our facilities last quarter and the third quarter last year. That situation has been steadily improving, and we should be done with that by the end of the second quarter. That past issue made state data look odd because wells were capped in their production capacity due to high back pressures. That's steadily being relieved, and now we're able to showcase how good those wells really are that we've been drilling. Part of that success is attributed to our optimization efforts as well. Some of that is detailed in the completion design itself, and some of it relates to the laterals and what intervals they targeted. I believe that covers all your questions?

Yes, very thorough. Appreciate it.

We'll take our next question from Zach Parham with JPMorgan.

I guess first just on cash return. You returned over 100% of free cash flow to shareholders this quarter. Going forward, do you plan to remain purely opportunistic with the buyback? Or have you considered putting in a 10b5-1 plan? Just trying to get a sense of the future pace of the buyback?

Yes. Zach, it's Wade. Just to answer the last part of that question first, there is no current plan to implement a 10b program. We're simply executing as we stated we would. I see no reason that won't continue. Our strategy is to operate during open windows, and the first quarter was probably the shortest open window of the year due to the timing of year-end reporting. We prefer to methodically go through those open windows to support the stock. We certainly have a view of NAV. So when undervalued conditions arise, we tend to lean in a bit more. I likely saw some of that in the first quarter. This will continue, and we moderate all expectations with humility towards the macroeconomic landscape and potential developments over the remainder of this year and in the next. Just a reminder, the Board authorized up to $500 million in share buybacks through the end of next year, and so far, we're close to $100 million. This indicates we're executing precisely as we stated we would.

Thanks for the color. Just to follow up on something you mentioned in your prepared remarks, you mentioned seeing some improvement in costs and noted that rig counts have moved lower industry-wide. At this point, what are your expectations for cost deflation later this year? How could that impact your CapEx budget for the back half of the year and into 2024?

I would just comment and then let Herb provide more color if he wishes. We certainly are not baking anything in at this point regarding rig rates and completion rates. As mentioned in my earlier comments, utilization does appear to be falling, and rates seem to be plateauing. This could bode well for the second half, but we're not guiding or planning on anything yet. Herb?

Yes. Zach, you might hear this from many operators, but we've clearly seen a reduction in our diesel costs, which is a significant component of our CapEx. I would estimate a 25% reduction from the fourth quarter. Steel costs are stabilizing, and regarding rig costs, we feather our rig contracts with one-year terms. Every 2.5 months, we have another rig contract coming off, giving us exposure to market rates, which, so far, appears to be flattening. There are also developments regarding pumping services, with some gas basins letting crews go and some Permian operators increasing fracs. We closely monitor how many new ones are coming to the market; in Q4 there were 7 new frac spreads, 3 in the first quarter, and many expected in the second quarter. As for sand production in the U.S., there’s been a significant uptick. We have solid contracts with a great provider for sand, and last-mile logistics driven by diesel costs will also benefit us. This is renegotiated quarterly based on cost indexes, so we have several factors to monitor regarding inflation, but we're comfortable with our current budget and assumptions. We don't see a need to make any changes at this time.

We'll take our next question from Tim Rezvan with KeyBanc Capital Markets.

I wanted to dig in a little more on the South Texas gathering issue because I know it was a big headwind at the end of the year. Herb, you just gave commentary that you think those issues will be behind you by midyear. Can you talk about specifics regarding what's happening and provide confidence that this will be resolved?

Yes, Tim. It revolves around the facilities we share with our midstream gathering partner. There are many components involved. We've discussed before the upgrades we're implementing, such as progressively installing larger pipes and line looping to enhance capacity. This includes separation optimization, pipeline modifications, and some automation to reduce manual intervention. Overall, we're increasing the liquids handling capacity of a system originally designed for much higher gas throughput from the Eagle Ford. When we drill very oily wells, particularly in the northwest area, we’ve needed to expand capacity quickly. The oil rates are much higher than we anticipated when commencing the Austin Chalk program. Therefore, we are catching up on the backlog, and we expect to resolve these issues by the end of the second quarter. It’s a great problem to have—too much oil.

You can flow; yes, it's a good problem, I guess.

That's right.

Okay. I appreciate that context. I wanted to circle back to the repurchases. I guess Wade mentioned that the window was kind of short in the first quarter, but $40 million was slightly higher than in the fourth quarter. Barring any unforeseen issues that would prevent repurchases, does that seem like a good steady-state cadence to model going forward?

Generally, yes. We assess it on a daily basis. As mentioned, there will be periods where we might lean in more based on market conditions. But generally speaking, you could assume something like that.

Okay, and if I could just sneak one last one in. You continue to build cash on the balance sheet. You have well over $350 million, which is the 2025 note size. Do you view that cash solely as an offset to that debt maturity? Would you expect to continue growing cash into the next year or two as these bond maturities come due? How do you think about the right capital structure?

Yes, absolutely. Your observations are accurate. We are building cash and generating free cash flow. Generally speaking, all else equal, you could expect that we will continue to build cash ahead of the 2025 maturity, which is over two years away and has an attractive coupon of 5 5/8%, better than many peer investments right now. The interest we earn on this cash is not too far off from that yield. Therefore, there’s minimal cost to maintaining cash reserves. This approach feels right in the current environment, especially due to ongoing uncertainties. We will reassess our strategy regarding this once the bonds become callable at par in a couple of months. You'll see us address those maturities eventually, but in the meantime, we are satisfied with our cash balance and its growth prospects, depending on unpredictable opportunities. Overall, we're pleased with our balance sheet condition.

We'll take our next question from Oliver Huang with TPH & Company.

A quick question on the longer laterals. It looks like the team has successfully pushed the envelope at this juncture, with 5,000-foot and 18,000-foot lateral wells online in Q1. I wanted to see if we could get more detail regarding the primary challenges you've encountered and your expectations for well productivity on a per-foot basis compared to the standard two-milers you predominantly averaged over the last few years? How many more of these currently sit as prospective on your acreage footprint?

Yes. Oliver, that's an excellent question. We monitor this very closely. You might be aware we hold records for some of the longest wells in the Midland Basin, supported by a substantial database. Initially skeptical, I've found that the performance is comparatively one-to-one ratios. Notably, we hold the Texas record with the longest lateral at nearly 4 miles. We're pleased with how the longer laterals are performing. The geometry primarily drives how long those laterals become. We pursue opportunities to extend and significantly improve economics when feasible. Some challenges of longer laterals, as you may know, arise with low GOR wells with high oil percentages—the electric submersible pumps can only pump so much. Consequently, longer laterals may plateau longer compared to shorter ones. Nonetheless, these wells provide excellent returns due to significantly lower costs. It’s technically vital to achieve a successful drilling process, requiring excellent coordination between drilling, completions, fracs, and drill-outs. We've adopted measures to ensure we gain complete contributions from the toe stages. I think you'll find we're succeeding in this area as well. That's a synthesis of our approach. I’m not forecasting the number of these we may develop, but they remain excellent opportunities and we are seriously evaluating them.

That makes sense. And for a second question, just on the production side, a solid quarter relative to the expectations you laid out. Another difficult question, but we were wondering if you could provide any details regarding how much higher production levels could have looked if wells performed at optimal levels, without frac shut-ins caused by offset operator activities? We're hoping to help investors better understand the complete potential of your asset base.

Yes, Oliver. I would say the number of wells we have in the Permian Basin are reliable in terms of type curves. We don’t adjust them significantly year-over-year; they remain solid and additional intervals are coming online. As you're aware, we forecast eight potential target zones, and they're arriving as anticipated. We excel at optimizing spacing, both vertically and horizontally, and we are co-developing. So, the well results in the Austin Chalk are now very predictable. I believe we have 75 wells that have reached the IP 30, and there are an additional seven wells online, for a total of 82. This predictability is reassuring. What remains difficult to forecast is the impact of offset operators—particularly in the Permian, where their activities can affect performance. We provide reasonable forecasts and maintain communication about their schedules; however, delays and changes can sometimes alter our operations. Therefore, it doesn't make sense to state what wells could have produced since it’s contingent upon various individual circumstances. Over time, we will demonstrate continued great performance from our wells. Ultimately, it comes down to maximizing free cash flow, as we have structured our operational strategy over a two-to-three-year period with that focus.

Awesome. That’s helpful. And if I could squeeze one last question in. You highlighted six Leonard well tests in the first half of the year and seven Wolfcamp D tests in 2023. Just any color on the spacing designs of these tests? Are they part of a co-development pad? Are these across a specific portion of your acreage? Or are they a bit more localized? We'd like to understand that better.

Yes. I can say that the Wolfcamp D is entirely isolated, with a thick section between Wolfcamp D and the prospective Wolfcamp B, so there's no frac interference, which eliminates the need for co-development. We have been working on determining the optimal lateral spacing and best target interval. The Wolfcamp D is quite fixed, indicating that’s our focus. We have several wells there, and many offset operator wells are also in proximity, offering us a substantial database to better forecast performance. As for the Leonard, it will function where it has firm thermal maturity. To ensure optimal performance, we need to have a solid understanding of the thermal maturity within the Leonard. We’re gathering additional data, and we currently do not have additional results to provide regarding the Leonard and Wolfcamp D. However, this remains a focus for 2023.

And we have a follow-up question from Leo Mariani with ROTH MKM.

I guess just a quick question around cash taxes. Do you have an estimate for how much you think that is going to be at current commodity prices here in 2023?

Leo, it's pretty similar to what we said before—pretty nominal this year. For 2023, I think it will be between $0 and $10 million. Based on current commodity prices, if you look out to next year, it could be a bit lower than I would have anticipated—something in the $60 million range, which would represent a run rate for a few years starting next year. That is our best estimate at this time, and, of course, it was $0 this quarter.

And there are no further questions at this time. I would like to turn the call back over to Herb Vogel for closing remarks.

Okay. Thanks, Lisa, and thank you all for your interest. We look forward to seeing many of you at the upcoming May and June conferences in Houston and New York. Thank you.

And that does conclude today's presentation. Thank you for your participation, and you may now disconnect.