Southwestern Energy Company (NYSE:SWN) Q3 2023 Earnings Call Transcript

Southwestern Energy Company (NYSE:SWN) Q3 2023 Earnings Call Transcript November 3, 2023

Operator: Good morning, ladies and gentlemen, and thank you for standing by. Welcome to Southwestern Energy’s Third Quarter 2023 Earnings Call. Management will open the call for a question-and-answer session following prepared remarks. In the interest of time, please limit yourself to two questions and re-queue for additional questions. This call is being recorded. I will now turn the call over to Brittany Raiford, Southwestern Energy’s Vice President of Investor Relations. You may begin.

Brittany Raiford: Thank you. Good morning. And welcome to Southwestern Energy’s third quarter 2023 earnings call. Joining me today are Bill Way, Chief Executive Officer; Clay Carrell, Chief Operating Officer; Carl Giesler, Chief Financial Officer; and Dennis Price, Senior Vice President of Marketing & Transportation. Before we get started, I’d like to point out that many of the comments we make during this call are forward-looking statements that involve risks and uncertainties affecting outcomes. Many of these are beyond our control and are discussed in more detail in the risk factors and the forward-looking statements sections of our annual report and quarterly reports as filed with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance.

Actual results or developments may differ materially, and we are under no obligation to update them. We may also refer to some non-GAAP financial measures, which help to facilitate comparisons across periods and with peers. For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release on our website. I will now turn the call over to Bill Way.

Bill Way: Thank you, Brittany, and good morning, everyone. We appreciate you joining us today to discuss our third quarter operating and financial results. Before I begin, I’d like to express my thanks to our dedicated team of constantly delivering on our priorities and driving improvements to our business, and value for shareholders quarter-after-quarter. During the third quarter, we continued our disciplined optimization of free cash flow generation and capital investment. This approach underscores our strategic priorities of both reducing debt and maintaining the Company’s productive capacity. We believe we have materially improved our capital efficiency and positioned the Company for enhanced through-the-cycle price realizations, with a more moderate go-forward hedging practice.

Our progress on these priorities this year has further strengthened the business and positions us for differentiated value capture, as we shift towards an improving macro environment, driven primarily by growing LNG demand. We’ve been encouraged by the industry-wide discipline and activity reductions in response to this year’s natural gas prices. Rig counts remain well off their highs from the beginning of the year, particularly in the Haynesville, where rig counts are down approximately 40% year-to-date. Given the production profile of wells in the Haynesville, we expect overall Haynesville basin production to decline at least into early next year, giving us further confidence in the strengthening macro view. Beyond reduced activity and the slowdown in supply growth that suggests LNG exports are up over 2 Bcf per day year-over-year, recently exceeding 14 Bcf per day, while weather adjusted power demand is up 2 Bcf a day and exports to Mexico are up almost 1 Bcf a day.

These factors have helped to significantly dampen the end-of-season storage surplus with new LNG in service dates beginning next year. By the end of ’24, we expect LNG exports to grow to 16 Bcf per day, over 90% of which is located along the Texas and Louisiana Gulf Coast. When we acquired our Haynesville assets, one of our guiding tenets was firm access to markets of choice. Both of our Haynesville acquisitions included strategic connectivity to advantaged markets along the Gulf Coast, including to LNG, which we increased shortly after closing. With a portion of that expanded capacity already in service and additional capacity expected to go into service by next year, we are well-positioned to supply the next wave of LNG facilities, as the largest current supplier of natural gas to LNG exporters.

As we look ahead to 2024, we expect new LNG facilities to increase demand throughout the year. However, we believe strip prices are not yet high enough to incentivize production growth. Given this dynamic, we intend to continue optimizing free cash flow and capital investment to meet our dual priorities of progressing towards the $3.5 billion top end of our target debt range, while maintaining the flexibility and optionality in the business. Our unique asset base provides capital allocation flexibility between basins, commodity windows as well as assured firm market access. We will continue to optimize investment with the optionality to add back in the back half of ’24, should market fundamental support. We believe this approach to managing the business in a volatile commodity environment is prudent and will best position SWN to sustainably return capital to shareholders.

Our hedging strategy helps to ensure debt reduction while also providing upside commodity risk exposure, as we move through 2024 and 2025. We continue to target a range of 40% to 60% of natural gas price protection, when entering a new year. Basis protection is also key to commodity risk management. With the physical sales agreements and financial basis hedges, we expect to continue our practice of proactively protecting basis. During the third quarter, our basis hedging program helped to offset wider Appalachia basis differentials and we expect to continue layering on additional protection for future periods as we look to next year. While commodity prices in ’23 are well off the highs we experienced last year, we have successfully progressed our key enterprise priorities.

Strategic adjustments to our development plan are resulting in free cash flow, while maintaining our productive capacity. With this free cash flow, along with the proceeds from non-core asset sales, we have already reduced debt by approximately $300 million, in a year when natural gas prices are expected to average less than $3. Additionally, our team is driving further operational and capital efficiency improvements, especially in Haynesville, which is helping to continue lowering our enterprise cost structure. We are also proud to have progressed our leading sustainability programs and initiatives including reducing our emissions, as outlined in our recently released 10th annual Corporate Responsibility report. As we look forward to 2024, we are well-positioned to build on the successes of ’23 and continue to drive sustainable shareholder value.

I’ll now turn the call over to Clay for some operational updates.

Clay Carrell: Thank you, Bill, and good morning. The team delivered another strong quarter while progressing our key operational initiatives. Production totaled 425 Bcfe during the third quarter, consisting of 4 Bcf per day of natural gas and 104,000 barrels per day of liquids, including over 14,000 barrels per day of oil production. During the quarter, we invested $454 million capital and placed 23 wells to sales. In Appalachia, we placed 15 wells to sales with an average lateral length of more than 16,200 feet. This included a company record long lateral in Brooke County, West Virginia with a completed lateral length of over 24,000 feet. That well is our 25th producing well in Appalachia with lateral lengths greater than 20,000 feet.

Of the total wells to sales in Appalachia this quarter, 11 ran our liquids-rich acreage in West Virginia and 4 wells were across our dry gas areas in Ohio and Pennsylvania. Most of our liquids-rich wells went to sales during September, which we expect to result in fourth quarter oil production, returning to approximately 15,000 barrels per day. In Haynesville, we placed 8 wells to sales, with an average lateral length of approximately 9,100 feet. 6 of the wells were in the Middle Bossier interval and two were in the Haynesville. We continued to progress our drilling, execution and efficiency gains and recently drilled in case 2 of our longest laterals to-date at approximately 15,000 feet. Capital investment for the quarter came in below expectations, driven by some minor changes in our development program that shifted activity into the fourth quarter, combined with efficiency gains and some moderating inflation impacts.

Our program remains on track with activity levels and expected investment within our previously updated full year guidance ranges. Looking ahead to 2024, we remain optimistic about service cost deflation. We are currently in the process of securing goods and services and have approximately half of our services already contracted, putting us well on our way to securing our 2024 development plan. Overall, we are seeing a softer oilfield service market, driven by the nearly 20% reduction in the industry-wide rig count. With the recent strengthening in the oil market, we see industry expectations of deflationary savings in 2024 moderating a bit, but overall, we believe cost should be down next year. We expect to lower Haynesville well costs approximately 15% to $1,800 per foot next year and see the potential for Appalachia well costs to decline as much as 5% as we continue to capture efficiencies and reduce costs.

Given our expectation for increasing LNG demand, particularly in the back half of 2024 and into 2025, we anticipate a similar level of capital investment next year with a range of $2 billion to $2.3 billion, and increased activity offsetting deflation and efficiency gains. Our capital program is typically front-end loaded with higher capital investment in the first half of the year, resulting in higher production in the second half. Next year, we’ll likely follow that same profile, with production expected to step down in Q1, before stepping back up to current levels in the second half. This production cadence also aligns with our view that the macro will strengthen during the year as additional LNG goes into service. We continue to exhibit strong flexibility to moderate activity and manage through volatile commodity prices and we believe the Company is well-positioned for 2024 and beyond.

Now, I’ll turn the call over to Carl.

Carl Giesler : Thank you, Clay. Consistent with our front-end weighted development program, capital investment stepped down during the third quarter, which helped to generate modestly positive free cash flow. As expected, free cash flow was more than offset by typical seasonal working capital reversals, resulting in a small increase to our revolver borrowings and debt balance this quarter. We ended the quarter with $4.1 billion of debt, a level which we expect to hold through year-end, down from the $4.4 billion level at year-end 2022. Based on current strip prices, we still expect to achieve the top end of our target debt range in either late 2024 or early 2025, after which, we plan to complement continued debt reduction with sustainable return of capital to shareholders.

While leverage has ticked up modestly to 1.6 times due to the price impact on trailing EBITDA, we fully expect to return to our targeted 1.5 times to 1.0 times leverage range next year. As Bill mentioned, our debt reduction objectives are supported by our hedging program. Implementing our hedging, our approach has been to set protection at or above our key economic thresholds, including enterprise free cash flow breakeven levels, while also allowing for asymmetric upside participation. This practice also preserves for our shareholders the benefit but the higher relative operating torque of our dual basin asset base to natural gas prices. Capitalizing on the volatility we’ve seen, we layered in some additional protection for 2024 and 2025 using predominantly three-way collars.

Based on strip pricing, we plan to end the year near the middle of our target hedging range of 40% to 60% for 2024 and with a base 20% layer for 2025. Operator, please open the call for questions.

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Q&A Session

Operator: [Operator Instructions] Today’s first question comes from Charles Meade with Johnson Rice. Please go ahead.

Charles Meade: Yes. Good morning, Bill, Clay and Carl and to the rest of the Southwestern team there. I wanted to follow up on your prepared comments about ’24 and also especially in light of what Clay offered on the cadence for ’24. So, Bill, I think I heard you say that there’s a possibility to add activity in the back half of ’24, if prices warrant. And Clay said, we’re going to have the usual front-end-loaded capital program in ’24. So, if I put those two pieces together, does that mean that the base case is the front-end-loaded capital program leading to roughly flat volumes year-over-year, and that there’s a possibility to add perhaps a rig or maybe even two rigs in the back half of the year that would then bias you towards the high end of that capital guidance range. Is that the right way to think about it?

Bill Way: Yes. And Clay, layer comments in on this. Yes, we are front-loaded. That’s traditionally how we invest capital. We expect that as we move through the year and manage our free cash flow generation, along with our capital investment kind of in a dual priorities that we would be able to both, again, reduce debt, but also look at production levels overall for the year to be — to still — or to be estimated right around the — like the end of ’22.

Clay Carrell: Yes. So, Charles, you’re right that that shape will be kind of growing through the year in 2024 tied to, we believe, very constructive commodity price going into 2025, maybe that happens earlier in ’24, and we have the optionality within the program to take advantage of that as we balance all the priorities of the company. But we’re well positioned if commodity prices play out that way.

Bill Way: Economics drive these decisions. So, there’s a lot of discipline involved in making sure that value is being created.

Charles Meade: And a lot of cars left to see also. And then, Clay, your comment about the 24,000 foot lateral in Appalachia. I wonder if you could talk a little bit more about that. Obviously, it’s an achievement to successfully get off a lateral that long. But I wondered if you could talk about what you’re seeing as far as productivity from that well. And if it encourages you to do more of these or even try to extend further or alternatively that maybe max out around 20, just give us the bigger context there.

Clay Carrell: Sure. We’ve been pretty methodical over the years, maybe earlier than others in Appalachia, where we’ve been extending our laterals. Our average program is around 16,000 feet this year where we recognize the benefits of the loner lateral zone, lowering well costs and enhancing economics. And I think our team does a really good job of it. And this well based on the land position enabled us to go longer. We have many checks and balances when we drill these long laterals to make sure that everything is operating within the parameters we expect. And this is another example of that. It’s one of our super-rich wells in Brooke County. The production from the well on a 3-phase initial production was a little over 27 million cubic feet equivalent a day.

Included in that was close to 1,700 barrels a day of condensate. And so, a typical really highly economic well in our liquids-rich Appalachia that we’re able to get even greater economic benefits by going longer. The well was drilled in 19.5 days spud to rig release for over 30,000 foot measured depth. And it has obviously benefited by our vertical integration assets. We’re using our company rigs. The well was fracked with our company frack fleets. And so, all of that is part of the recipe where I included the comment about we’ve now got 25 wells that are greater than 20,000 foot lateral length that that program has been working for us for a while.

Bill Way: And given they’re SWN employees, knowledge transfer well to well and the application of knowledge and learnings is quite high.

Operator: And our next question today comes from Bertrand Donnes with Truist. Please go ahead.

Bertrand Donnes: I’m doing a little bit of acreage pinpointing here, but it looks like you guys have some Eastern Guernsey acreage and one of your peers is now touting a high liquids cut location count there. So I just wanted to address do you guys have an inventory count there? Are you seeing similar things on your acreage? And I know it’s not a large part of your portfolio, but maybe how many locations we might expect next year or a run rate?

Clay Carrell: Yes. So, we’re very knowledgeable about the area. In our minds, it’s a continuation of the geology through the product windows of the liquids-rich acreage that we have in Southwest Appalachia, and it’s — some of it is indicative of the type of well performance we’ve been delivering in our liquids-rich assets. So, not a surprise to us. We are drilling a pad there. Currently, we don’t have a large acreage position there, but we have the largest acreage position and the highest-yielding liquids-rich acreage in West Virginia with our position there. And so, we like it. It continues to have very resilient economics, as you move through the price cycles.

Bertrand Donnes: That’s great. And then just the second one, some of your peers have started getting very creative on the LNG portfolio side. And you guys have almost, it seems, pointedly chosen to take a step back and let the rest of the guys create a market. So is there any changing, does pricing change that? Or is there an evolution of the negotiations out there that are maybe making it more attractive for you?

Bill Way: Sure. I’ll take that. As you know, we’re strategically positioned to supply the growing demand for lower carbon energy with our access to the Gulf Coast and our access to the LNG corridor. As you said, we’re actively engaged in talks with a variety of buyers under a wide range of different commercial structures. We certainly see the value in portfolio diversification and gaining direct access to more volatile international price indices. But we’re taking a maybe more disciplined approach to evaluating and managing the risk associated with these transactions. So, in that respect, we have a pretty high threshold for transactions of this size, complexity and duration. It’s currently structured — I think many of the commercial arrangements involving domestic gas supply priced off of international benchmarks push most, if not all, of the risk on to the upstream gas supplier.

And our intention is to enter into internationally priced transactions when those risks become more balanced, and when we have the tools available to us that are necessary to effectively manage our exposure. As you know, we’re currently the largest supplier of natural gas to LNG exporters, and we intend to retain and potentially grow our portfolio of Henry Hub based agreements in addition to considering incremental internationally priced arrangements. The one distinction I think we might make at this point amongst our approach against our peers is we’re taking a slightly different approach targeting binding transactions on post-FID facilities as opposed to nonbinding HOAs with facilities that may or may not have reached FID yet. And so, as I suggested, that does raise the bar on the complexity of the negotiation.