SM Energy Company (SM) Earnings Call Transcript & Summary

Welcome to SM Energy's Second Quarter 2020 Financial and Operating Results Webcast. Before we get started on our prepared remarks, I will direct you to Slide 2 and remind you that we will be making forward-looking statements about our plans, expectations and assumptions regarding future performance. In particular, we will be providing updated guidance for 2020 and beyond as well as commentary on strategic objectives beyond 2020. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. Please refer to the cautionary information about forward-looking statements in today's earnings release, the related presentation posted to our website and the Risk Factors section of our most recently filed forms 10-K and 10-Q. Discussion of second quarter results includes non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP measures are provided in our earnings release and the investor presentation referenced during this call. Today's prepared remarks will be given by CEO, Jay Ottoson; CFO, Wade Pursell; and President and COO, Herb Vogel. I will now turn it over to Jay Ottoson. Jay?

Thank you, Jennifer. Good afternoon, and thank you, everyone, for your interest in our company. I hope that you and your families have been well. I am going to start on Slide 3. Our key message for you today is that although we are currently in challenging times from a macro perspective, our priorities have not changed, and our recent operating performance has been outstanding. As a premier operator of top-tier assets, we're focused on generating cash flow growth while spending within our internally generated cash flow and using that free cash flow to reduce debt, resulting in lower debt leverage and cash flow growth per debt adjusted share. Implicit in our concept of premier operatorship is that we want to be a model of good environmental, social and governance practices in our industry. Our team here at SM has adapted well to new safety protocols related to the COVID-19 pandemic while rapidly evolving our operating plan to adjust to lower oil prices. Our costs have moved remarkably lower over the last quarter, while our well performance continues to be strong. Wade will take you through our second quarter performance and our revised plan, and Herb will elaborate on our operating results. Before I turn the call over to them, however, I want to note that our Board took several steps recently to strengthen oversight and disclosure of our environmental, social and governance performance. Our Board has always been highly engaged on these topics, but took the additional step in their last meeting of revising the charter of our Governance Committee to specifically include environmental and social issue oversight, and they have directed us to increase our disclosure related to our ESG performance by initiating participation in the carbon-disclosure project. We will also be publishing SASB metrics, which will be included in our updated corporate responsibility report. With that, I will turn the call over to Wade.

Thanks, Jay. Good afternoon. Obviously, a lot of moving parts in the second quarter. I'm going to start on Slide 5. Wild commodity price swings, impact of the roll, production shut-ins, deferred completion timing, aggressive focus on cost and an extended debt exchange complicated the second quarter. However, we took these actions to navigate through a very challenging environment, and we believe they were effective. My comments today will be in the context of the first 2 areas of focus Jay mentioned, the importance of growing within cash flow and the importance of working leverage down, and that target is 2x. As always, refer to the schedules in the release and the appendix to the IR presentation for detailed data on the quarter's results. However, I would like to highlight a few things and walk through results of the debt exchange. I'll start by highlighting free cash flow. Capital discipline, better-than-expected performance from previously completed wells and cost management complemented our good hedge positions to deliver $28 million in free cash flow. On a trailing 12-month basis, we have generated $124.7 million in free cash flow. And for those of you calculating a yield to market cap, that's a very healthy 29%. Capital expenditures of $125 million were well below our guidance of $165 million to $175 million. But this is predominantly due to further cost deflation and cost management as well as some timing differences. Well costs have continued to come down, and Herb will elaborate on this further. So let's look at certain line items now. Starting with second quarter price realizations for Permian oil revenue, which makes up the majority of total revenue. Realizations were understandably tough to model, so here are the components. Benchmark oil was $27.85. From that, the Midland differential averaged a reduction of $0.27, the effect of the roll averaged a reduction of $3 and then subtract general point of purchase differences and you get $22.86. This does not include hedges. We realized a $25.81 per barrel increase in oil prices from hedging. Second quarter operating cost came in better than expectations, which was a combination of aggressive cost management and the deferral of certain workovers. We have lowered guidance for LOE for the year to reflect cost savings, but do expect third and fourth quarter operating expenses to be higher than the second quarter on a per BOE basis, inclusive of workovers. I believe most of the other line items are self-explanatory. So turning to hedging on Slide 6. We're very well hedged for the second half of 2020, with about 90% of oil production hedged at $55 per barrel or higher and about 50% of natural gas production hedged at an average of $2.20 per MMBtu, and we have separate Waha hedges for our Midland natural gas. We've also added significant positions for 2021 to protect the downside, including oil hedges at around $40 per barrel, gas hedges around $2.40 per MMBtu to Houston Ship Channel, plus additional Permian gas hedges to Waha. As always, the detail by quarter is in the appendix to the slide deck. So turning to the balance sheet on Slide 7. The debt exchange successfully reduced long-term debt by $290 million and pushed out and reduced near-term maturities in 2021 and 2022 by $249 million. To recap, $612 million of unsecured senior notes and $107 million of convertible notes were exchanged for $447 million of new second lien notes, $54 million of cash, and warrants to certain holders to acquire the 5% of the outstanding stock of the company under certain conditions, that being the achievement of at least $1 billion in market cap for 4 or 5 consecutive trading days prior to expiration on June 30, 2023. In terms of debt strategy going forward, this leaves only $65 million due in 2021 and about $294 million due toward the end of 2022. And this compares to $865 million of availability under the revolver as well as significant current additional second lien capacity. Our total leverage, that is debt-to-trailing 12-month EBITDAX at the end of the second quarter is just under 2.5x. As a reminder, the covenant under the revolver is 4x. As I will now discuss, our planned forecast growing within internally generated cash flow for the foreseeable future at current strip prices. So let's turn to that midyear forecast now on Slide 8 and see where we're headed over the next few years. Considering the difficult macro environment, we're pretty excited about our direction. So let me take a few minutes with this, and then Herb can elaborate on the great operations driving the results. Again, our current focus is to grow within cash flow and reduce leverage to 2x. In this current low price environment, that means keeping leverage in the 3x area then moving toward 2x over time sooner with even a modest recovery in commodity prices. The forecast we have laid out reduces total capital expenditures for this year to $610 million to $630 million, which incorporates lower cost and deferral of certain activity. Capital activity stays relatively flat in third quarter from second quarter, then ramps up in the fourth quarter with a second crew and more completions. As a result, we expect declining production in the third quarter and fourth quarter with a stronger exit rate, leading to higher first quarter 2021 production. Applying strip pricing, the third and fourth quarters are free cash flow neutral to positive and debt to EBITDAX at year-end is around 2.75x. Looking ahead into 2021 and again, assuming strip pricing. We expect a slightly increased capital budget that will be more heavily weighted to completion activity, growth in total production driven by oil, free cash flow neutral to positive, with net debt to adjusted EBITDAX ending around 3x at the end of the year. And then looking further ahead to 2022, again, assuming strip pricing, leverage falls well into the mid-2s area. And with the recovery of oil prices to the $50 area, our forecast shows leverage in the 2x target area. So on that positive note, I'll turn the call over to Herb. Herb?

Thank you, Wade. As Wade noted, there were a lot of moving parts in the second quarter, driven by the commodity price environment. I'll start with a few comments about our proactive response and how that affected production before turning to the slides in the deck. Key factors influencing production were better-than-expected existing PDP well performance, curtailment or shut-in of some production, deferral of turning newly completed wells to sales to the end of the quarter, and reduction in the number of wells turned to sales in the quarter relative to previous quarters. In the Midland Basin, performance from our existing PDP wells was better than we had modeled at several well pads. Notable outperformance relative to expectations came from the Merlin Maximus, Balboa, Tackleberry and McFly pads. This outperformance was offset by voluntary curtailments or shut-ins of certain producing wells in response to the adverse pricing environment. This amounted to an average reduction for the quarter of around 3,000 BOE per day at a relatively high oil percentage. Another action we took during April and May was to defer bringing online newly completed wells in the Midland Basin. All 10 net completions in the second quarter returned to sales during June rather than spread through the quarter. Finally, as we indicated we would do in the first quarter call, we reduced overall D&C activity. Over the past couple of years, we completed an average of more than 20 net wells in the Midland Basin each quarter. So with just 10 net completions, we were well below our norm for our quarter. One effect that you will note from the delayed start-up of completed wells and fewer total completions in the quarter was an increase in the percentage of gas production relative to our total Midland Basin production. For those of you who are not very familiar with well performance, the percent oil content is highest when a well first comes on production then slowly declines as a percent of total well production over time at a very predictable rate. Our deferral actions led to a higher proportion of production from gassier existing wells rather than oilier new wells during the quarter. This production mix, coupled with less layering, thanks to strong third-party gas plant uptime, resulted in the higher gas percentage from our Midland Basin production. Now it's worth noting that Howard County production has some of the highest oil percentages in the basin. As wells undergo depletion, the gas oil ratio increases at a slower pace in Howard County, Wolfcamp and Spraberry wells than farther West in the center of the basin, as a result of the unique characteristics of the oil and reservoir pressures and temperatures in the county. This is obviously an attractive characteristic. I will add, just to be clear, that the higher gas percentage this quarter has nothing to do with spacing or from which interval wells we're producing. So now turning to the deck and Slide 9. Midland Basin well performance continues to be very strong and delivers great economics as a result of lower CapEx and optimized completion designs. Our Midland Basin assets offer low breakeven flat oil prices. And while we are slowing total capital activity for the year in response to conditions, we remain focused on returns and will only drill well pads that meet our threshold returns. On this slide, we show our reduced activity for 2020 in terms of completion counts, slowing our spending and cadence in the current commodity price environment. As you can see, we pushed more completions into the second half, 29 in the first half with 39 planned in the second half. During the second quarter, we continued to see cost deflation and optimize our completion designs resulting in a remarkable, anticipated drill complete and equip cost of $560 per lateral foot for the second half of the year. We really need to give full credit to our ops and procurement teams for the relentless pressure they apply to make this possible while maintaining high safety and environmental standards. In the Midland Basin, we currently have 4 rigs and 1 completion crew active and expect to drop 1 rig and add 1 completion crew in October. Turning now to Slide 10. I'd like to highlight how really strong our Midland Basin economics are. RSEG or Envers analysis ranks SM as having the lowest breakevens in the Midland Basin for 2019, and I suspect our low 2020 well costs will again position us in the top tier among peers this year. Slide 11 breaks down some of the contributors to the extraordinary cost improvements year-to-date. We are drilling and completing substantially more lateral feet per day now than even the exceptional rates we delivered in 2019. Year-to-date, we are drilling 18%, completing 33% faster than last year. On top of that, we have cut sand costs in half since the start of 2019 and continue to gain efficiencies by extending lateral lengths, thanks to our contiguous acreage position. Now turning to Slide 12 in South Texas. In response to adverse commodity prices, we have also cut back capital activity in South Texas, reducing from 16 net drills and 9 net completions in the February plan to 12 net drills and 4 net completions in our latest plan for the year. We are also reducing well costs further down to around $600 per lateral foot anticipated for the second half of the year. Delaying certain activity sets us up for economic advantages in 2021, as contracted costs for produced gas transportation decline and condensate sales prices increase relative to index from where they are today. Combine this with higher oil content of Austin Chalk wells and the result is breakeven economics as an entirely new and attractive level in South Texas. As we've talked about the last several quarters, our geoscience teams identified the potential for substantial economic inventory additions from the Austin Chalk on our South Texas acreage. The Austin Chalk extends over a wide area, but we believe it has unique attributes in particular, higher permeability on our acreage. It's also substantially more condensate and NGL rich than the deeper Eagle Ford, and that significantly enhances revenues from Austin Chalk production. As a result, we embarked on a delineation program that has delivered 9 Austin Chalk wells to date, 2 of which just commenced flowback this month that I will not address today. We gathered substantial science data from these wells and have continued to optimize landing zones and completion designs. If you turn to Slide 13, I will highlight our latest 3 Austin Chalk wells that have been producing for more than a month. The Briscoe 109H, San Ambrosia 1009H and Galvan 910H outstanding new wells and have set new records for oil and condensate production for us. In fact, the 109H and 1009H have delivered higher oil rates any of the South Texas wells we completed over the last 10 years. Initial rates for these wells are shown on the slide. But let me point out in particular that both of these wells had more than 58% oil and 80% liquids in their 3-stream production. The new 910H well has only been flowing for 5 weeks. This well is located further East on our Galvan acreage, where the reservoir is deeper and more overpressured. It is early days for assessment, and we have not yet reached an IP30 yet. But based on wellhead pressures and production rates this looks to be a very strong well. The 24-hour IP was 3,960 BOE per day 3 stream, with 32% condensate and 61% liquids, and that rate is constrained by our facilities. The API gravity of the oil or condensate from these wells ranges between 51 and 53, significantly lower and therefore, have more value than our historical condensate production. Bottom line, and based on go-forward development costs, we estimate that these wells have a flat oil price breakeven 10% return that is below $20 per barrel for the 1,009H and 109H and around $31 per barrel for the 910H. This assumes gas of $2 per million BTU for the first half of 2021 and then $2.40 per million BTU gas after that. Simply put, these latest well economics are competitive with any basin in North America. So let's recap the value drivers of our South Texas activity. Austin Chalk wells have higher oil and NGL content and better economics than former Eagle Ford wells at current strip prices for natural gas. We've optimized completion designs, refined optimal landing zones and reduced costs significantly so that we now see top-tier drilling opportunities on our acreage. Our South Texas gas production is subject to a step-change improvement in transportation costs of $0.25 and an additional $0.35 per Mcf in mid-2021 and mid-2023, respectively, that will enhance revenues from our South Texas asset. In addition, we anticipate that prices for condensate will yield an additional $5 per barrel relative to index starting late this year. Each of these efforts adds up to a sizable value creation for our South Texas position. While we focus on the liquids-rich Austin Chalk now, we also retain the option to drill natural gas in the Eagle Ford, if prices rebound next year as some have suggested. Turning to Slide 14. Let me highlight some of the advances in ESG for a moment. Jay mentioned the steps we have taken at the Board level to enhance ESG oversight as well as our efforts to expand our public reporting of metrics through CDP and SASB. We have also published to our website our 2019 performance on key metrics for the upstream sector. Compensation for all employees has performance targets for safety, greenhouse gas and methane emissions and spills. In 2019, we recorded top quartile results among our peers who report greenhouse gas and methane emissions and spills. Stewardship is implicit in being premier operators. We seek to foster a cultural stewardship beyond compliance and compensation targets that incorporates innovation and responsible decision making at all levels in our day-to-day operations as well as in our long-term planning. I'll now turn it back to Jay for closing remarks. Jay?

Well, thank you, Herb. In summary, I'll reiterate that although we are in challenging times, our priorities have not changed. We've done exceptional work year-to-date to generate free cash flow and reduce debt, and intend to continue running our business, spending within our internally generated cash flow and applying that free cash flow to debt reduction in order to deliver improved leverage and cash flow growth per debt adjusted share. I think anyone who works with us regularly in any of our office or field locations knows that our team members are highly committed to environmental stewardship, safety performance and social responsibility, but we are going to do more to improve transparency with respect to our ESG data, goals and results. We look forward to taking any questions you might have during our live Q&A session tomorrow morning, and we thank you for your time and attention.