EnLink Midstream, LLC (NYSE:ENLC) Q4 2023 Earnings Call Transcript

EnLink Midstream, LLC (NYSE:ENLC) Q4 2023 Earnings Call Transcript February 21, 2024

EnLink Midstream, LLC isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Greetings and welcome to the EnLink Midstream Q4 2023 Earnings Conference Call and Webcast. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Brian Brungardt, Director of Investor Relations. Thank you, Mr. Brain, you may begin.

Brian Brungardt: Thank you and good morning everyone. Welcome to EnLink’s fourth quarter 2023 earnings call. Participating on the call today are Jesse Arenivas, Chief Executive Officer; Dilanka Seimon, Executive Vice President and Chief Commercial Officer; and Ben Lamb, Executive Vice President and Chief Financial Officer. Walter Pinto, Executive Vice President and Chief Operating Officer, is also in the room to answer any questions during the Q&A session. We issued our earnings release and presentation after the markets closed yesterday and those materials are on our website. A replay of today’s call will also be made available on our website at investors.enlink.com. Today’s discussion will include forward-looking statements, including expectations and predictions within the meaning of the federal securities laws.

The forward-looking statements speak only as of the date of this call and we undertake no obligation to update or revise. Actual results may differ materially from our projections and a discussion of factors that could cause actual results to differ can be found in our press release, presentation, and SEC files. This call also includes discussion pertaining to certain non-GAAP financial measures. Definitions of these measures as well as reconciliations of comparable GAAP measures are available in our press release and the appendix of our presentation. We encourage you to review the cautionary statements and other disclosures made in our press release and our SEC filings, including those under the heading Risk Factors. We’ll start today’s call with a set of brief prepared remarks by Jesse, Dilanka, and Ben and then lead the remainder of the call over for questions and answers.

With that, I would now like to turn the call over to Jesse Arenivas.

Jesse Arenivas: Thanks Brian and good morning everyone. Thank you for joining us today to discuss our fourth quarter results and full 2023. We’ll also discuss our 2024 outlook, which looks like it will be another great year driven by solid business activity. Looking back at 2023, I’m proud of the team’s strong execution driving a number of records despite the challenging and volatile commodity environment. Last night, we reported fourth quarter adjusted EBITDA of $351 million and 2023 adjusted EBITDA of $1.35 billion. This marked solid growth of approximately 5% over the prior year. These solid results drove free cash flow after distributions of nearly $250 million for 2023. We continue to use our robust free cash flow after distributions to return capital to our investors.

Earlier this year, we announced a 6% increase on our quarterly distribution. Additionally, we fully executed our expanded $250 million common unit repurchase program. Since we began our consistent unit repurchase program in late 2021, we have repurchased approximately 9% of the common units outstanding. Ben will provide more details later in the call, but we forecast this momentum to continue into 2024. Growth this year will be led by our largest business, the Permian, followed by Louisiana, which we expect to become our second largest segment this year. The growth in those businesses will be offset by the impact from the noncore ORV asset sale in late 2023 and a contractual rate reset in certain legacy Oklahoma and North Texas commercial agreements.

Overall, we forecast adjusted EBITDA of $1.36 billion at the midpoint of our guidance range. The continued strong cash flow generation coupled with lower total capital expenditures will drive significant increase in free cash flow after distributions to $290 million at the midpoint of our guidance. Earlier this year, we announced that the board authorized another $200 million common unit repurchase program for 2024, which represents the third consecutive year at of at least $200 million of repurchases. Last night, we released an update around our CO2 transportation solution for ExxonMobil. Following ExxonMobil’s recent acquisition of Denbury, we expanded our commercial discussions to provide safe, reliable and cost-efficient CO2 transportation to other areas across the Gulf Coast beyond the Mississippi River corridor.

In total, the industrial facilities along the Gulf Coast between Houston and New Orleans emit over 215 million metric tons of CO2 today into the atmosphere. We’re excited for this opportunity to expand our commercialization efforts with Exxon, as it may represent a larger investment opportunity and an expanded reach into multiple markets. EnLink and ExxonMobil continue to work closely together on CO2 transportation solutions since our initial agreement in 2022 and look forward to continuing our collaboration to help reduce carbon emissions across the Gulf Coast. In connection with the expanded evaluation, while the original transportation agreement remains in place, EnLink and ExxonMobil have agreed to reassess the Pecan Island projects near term role with the expectation that other projects may be prioritized ahead of the Pecan Island project.

Meanwhile, EnLink continues to execute and gain expertise in the energy transition and CO2 transportation space. During the fourth quarter, we achieved a milestone by bringing on line our carbon capture and transportation project at our Bridgeport facility in North Texas. Ultimately, we expect to capture up to 210,000 metric tons of CO2 emitted by our Bridgeport facility and deliver it to a permanent sequestration site developed by our largest customer in North Texas, BKV. With that, I will turn it over to Dilanka to provide an update on our evolving Louisiana segment.

Dilanka Seimon: Thanks, Jesse, and good morning, everyone. Last quarter, we discussed how the Louisiana gas supply and demand market dynamics have shifted over the past year. While we continue to evaluate opportunities, I wanted to spend this time to provide an update and discuss how EnLink can benefit from the shifting dynamic in three phases. In the first phase, we are focused on realizing the full value of our assets and we stand to benefit from renewing current business at higher rates and often for longer terms. We began to see the benefit in the second half of 2023 and we expect this to continue. As contracts expire and are renewed, we estimate the value of the higher rates in 2024 is approximately $20 million and we see further upside in 2025 and beyond.

The second phase of growth for EnLink is focused on debottlenecking projects. We own and operate approximately 4,000 miles of pipeline across two major intrastate systems as well as the Henry Hub and we connect to over a dozen third party systems offering customers significant connectivity, particularly in the southern part of Louisiana. These projects are relatively quick to execute generally less than 18 months and provide very attractive economics, typically low single digit EBITDA multiples. Examples include adding compression or looping short distances of existing pipelines. Beyond quick efficient debottlenecking projects, the shifting supply and demand dynamics create a potential third phase of growth for EnLink’s Louisiana system. As LNG export capacity comes online over the next several years in Louisiana and with emerging industrial demand such as blue ammonia projects, we expect the forces impacting the markets today will only grow stronger.

The rising demand for natural gas to serve this growing market may drive the need for larger projects such as new pipelines and expansions of natural gas storage to support our customers. While we are focused on meeting the needs of customers in this new environment, we remain committed to capital efficient projects that are underwritten by strong customer commitments. In that vein, we have been evaluating opportunities to expand our natural gas storage portfolio. We currently have working natural gas storage capacity of about 11 Bcf. Since the last earnings call when we mentioned this, we have progressed engineering studies and estimate that we can expand our salt storage capacity by an incremental 9 Bcf and are currently marketing this capacity.

We will continue to provide updates on these exciting projects in the coming quarters, but this is the latest example of longer-term opportunities to grow our Louisiana system and meet our customer needs during this period of shifting supply and demand dynamics. In short, this is an exciting time for EnLink’s Louisiana system. We acquired this system over two decades ago and remain focused on optimizing this unique footprint over the next several years. With that, I’ll turn it over to Ben to provide an overview of our operations and our financial results.

Ben Lamb: Thanks, Dilanka, and good morning, everyone. Let’s start with the Permian, where segment profit for the fourth quarter of 2023 came in at $105.9 million including approximately $9.6 million of gross operating expenses tied to plant relocations and $4 million of unrealized derivative gains. Excluding plant relocation OpEx and unrealized derivative activity, segment profit in the fourth quarter of 2023 decreased 1% sequentially, but grew 11% from the prior year quarter. Producer activity behind our systems remained robust, driving a record quarter for gathered volumes, with average natural gas gathering volumes approximately 6% higher sequentially and 23% higher than the prior year quarter. Turning now to Louisiana, we experienced another quarter of solid performance in the gas segment, along with strong results in the NGL segment that benefited from normal seasonality.

Segment profit for the fourth quarter of 2023 came in at $103.6 million including $0.9 million of unrealized derivative gains. Excluding the impact of unrealized derivative activity, segment profit in the fourth quarter of 2023 grew approximately 10% sequentially and grew approximately 2% compared to the prior year quarter. During the fourth quarter, we fully exited our noncore Ohio River Valley assets for total proceeds of approximately $70 million. This represents a multiple of approximately 6 times EBITDA. Moving up to Oklahoma, we delivered segment profit of $112 million for the fourth quarter of 2023, including $1.3 million of unrealized gains. Excluding unrealized derivative activity, segment profit in the fourth quarter of 2023 grew approximately 1% sequentially and grew approximately 7% from the prior year quarter.

During the fourth quarter, we continued to be impressed with the resilience of our business, as we saw operators remain active with rigs on our acreage, driving gathering volumes flat sequentially and approximately 15% higher compared to the prior year quarter. Wrapping up with North Texas, segment profit for the quarter was $68.6 million including $0.7 million of unrealized derivative gains. Excluding unrealized derivative activity, segment profit in the fourth quarter of 2023 decreased approximately 2% sequentially and decreased approximately 10% from the prior year quarter. Natural gas gathering volumes were 1% lower sequentially and 9% lower compared to the prior year quarter. These solid results were in line with our expectations and drove another robust quarter with $350.8 million in adjusted EBITDA and $79.4 million in free cash flow after distributions.

For the full year 2023, EnLink delivered adjusted EBITDA of $1.35 billion and free cash flow after distributions of $247 million. This represents 5% growth in adjusted EBITDA over the prior year, reflecting the resilience of our diverse asset base despite the volatile commodity price environment. Capital expenditures, plant relocation expenses net to EnLink and investment contributions were $122 million in the fourth quarter of 2023. On the balance sheet side, we continue to be in a very strong position with a leverage ratio of 3.3 times at the end of the fourth quarter, and we retain ample liquidity. We remain investment grade at Fitch and one notch below investment grade at both S&P and Moody’s with a positive outlook at S&P. Consistent with our capital allocation plan to return capital to investors, we increased our quarterly common unit distribution $0.135 per unit in the fourth quarter, which represents a 6% increase over the Q4 of 2022.

During the fourth quarter, the board increased our 2023 common unit repurchase authorization to $250 million. The increase reflected our strong free cash flow generation as well as a portion of the proceeds from our sale of our noncore ORV assets. We fully executed the expanded authorization, including GIP’s pro rata share, which settled after the end of the quarter. Following our consistent approach to repurchase common units beginning in late 2021, we have now repurchased nearly 42 million common units, representing approximately 9% of the common units outstanding at the beginning of our repurchase activity. Now, let me turn to the 2024 guidance that we announced yesterday. We are in a solid position to continue the momentum we ended the year with and 2024 is forecast to be another year of solid results.

From an adjusted EBITDA standpoint, we are forecasting a range of $1.31 billion to $1.41 billion. This outlook reflects solid growth in our two largest segments, the Permian and Louisiana, while partially offset by the impact from the noncore ORV asset sale in late 2023 and contractual rate resets in certain legacy North Texas and Oklahoma commercial agreements. These contracts were extended back in 2018 and the agreement included a onetime rate reset in 2024, the contracts original expiration date to pre-agreed fees. In effect, this reset partially reverses recent years of outsized annual inflation escalators. These contracts now expire between 2029 and 2033 with annual inflation escalators and no further rate resets. When you look through these two onetime impacts, the sale of the ORV assets and the onetime contract resets, our base business is forecast to grow approximately 4% at the midpoint of adjusted EBITDA guidance compared to 2023.

Turning now to commodity prices, we remain approximately 90% fee based. For our 2024 guidance, we assumed average WTI and Henry Hub prices of $75 per barrel $3 per MMBtu respectively. Like last year, we took the opportunity in the second half of 2023 to take advantage of the supportive forward curve and hedged a large majority of our 2024 exposure to natural gas prices and Waha basis at prices significantly above current levels, providing increased visibility for 2024 financial results. Accordingly, a scenario of plus or minus $5 per barrel and $0.50 per MMBtu impacts adjusted EBITDA by approximately $6 million and $5 million respectively, assuming no change in our forecast volumes. Taking guidance down to the segment level and focusing on the midpoints of the ranges we provided, we’re projecting another year of significant growth for our Permian business with segment profit for 2024 forecast to be $455 million including plant relocation expenses, representing an increase of approximately 15%.

As a reminder, our Tiger II processing facility is expected to come online in the second quarter of 2024. Louisiana segment profit for 2024 is forecast to be $420 million representing an increase of approximately 7%. The increase is mainly driven by the improving fundamentals in our natural gas business that Dilanka has spoken about earlier. Excluding the 2023 contribution from the ORV assets that we sold, Louisiana growth would be even higher. In Oklahoma, we expect the activity from the Devon Dow JV along with a little activity from other customers will keep volumes approximately flat in 2024 compared to 2023. However, Oklahoma segment profit for 2024 is forecast to be $390 million representing a decline of approximately 8% driven in part by the onetime rate reset that I talked about earlier.

Finally, North Texas segment profit for 2024 is forecast to be $240 million representing a decline of approximately 13%. This is driven by the onetime rate reset, but also reflects a conservative view on volumes given the current gas price environment. The growth in our business the last several years has been impressive and our 2024 outlook reflects a transformation of our business. Back in 2019, Oklahoma and North Texas represented over 60% of our segment profit mix. Today, however, the Permian and Louisiana represent approximately 60% of expected 2024 second profit. Said shortly, the largest drivers of our growth are associated gas production in the Permian and downstream demand coal markets in Louisiana. While our guidance is based on the most current producer drilling plans, we recognize the extreme volatility in natural gas prices may cause producers to delay their drilling and completion plans and thereby impact our volume expectations.

We estimate a hypothetical six-month completion deferral by major customers in Oklahoma and North Texas, both gas-oriented basins would have an aggregate 2024 impact of approximately $20 million. As we’ve said before though, longer term, we remain very bullish on natural gas demand and the need for Oklahoma and North Texas to help supply that growing market in the coming years. On the investment front, total capital expenditures plus operating expenses associated with the Tiger II plant relocation net to EnLink and investment contributions are forecast to be between $435 million and $485 million. As we have previously discussed, we remain focused on capital efficient high return projects. I want to point out that our capital spending outlook includes approximately $50 million of spending for CCS projects with ExxonMobil.

As Jesse described in his opening remarks, this number may change as we at Exxon work toward finding the optimal solution for the CCS market and the way in which EnLink will participate in that solution. With that caveat in mind, from a free cash flow perspective, we expect a significant increase compared to 2023 with forecast free cash flow after distributions in the range of $265 million to $315 million. As disclosed in January, our board reauthorized the $200 million common unit repurchase program for 2024 for the third consecutive year. There is the potential to see this number rise as the year goes on as it did last year, as we gain more clarity on some of the moving pieces including Exxon related CCS projects. In summary, the EnLink team delivered solid results in 2023 and we expect the momentum to continue in 2024.

Despite the recent volatility, our assets are well positioned to grow led by our two largest segments, the Permian and Louisiana. With that, I’ll turn it back over to Jesse.

Jesse Arenivas: Thank you, Ben. In summary, I’m proud of the quick execution expanding our Louisiana assets, the bigger and broader CCS opportunity as we work with ExxonMobil and others to address CO2 emitted in the atmosphere today, and the resiliency of our assets driving growth for our business in 2024 and beyond. With that, you may now open the call for questions.

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Q&A Session

Operator: Thank you. [Operator Instructions]. Our first question comes from the line of Spiro M Dounis with Citi. Please proceed with your question.

Spiro M Dounis: Good morning, team. Maybe I want to start with something we’re getting a few questions on this morning related to Pecan Island. Just curious if you can give us some more details on what prioritization of other projects could look like there. As far as I can tell, you’ve already started spending some capital on that project. So curious, what are some of the range of outcomes there? And when would you be able to expect to update us on that?

Jesse Arenivas: I appreciate the question. First, let me start by saying we’re extremely excited about the opportunity in the expanded market. We’re going to be looking for mutually beneficial opportunities with Exxon for — to gain a larger share of that addressable market, expanding outside of the Mississippi River corridor. What that entails is we’ve identified — as we’ve said in the past, right, we believe that the Denbury acquisition leads to more opportunities for EnLink, and this is an example of an optimization of our existing agreement to find the most cost efficient, most timely solution for those initial volumes. With respect to timing, we both have obligations under the existing agreement. So we both have — are highly incented to get this work through very quickly.

So from a timing perspective, we hope to update you on the path forward very soon. With respect to the capital spend, most of that those dollars were spent on permitting right of way acquisition. We have taken a step back as we reassess and so we will not be incurring future spending until we identify the most optimized solution.

Spiro M Dounis: Okay. Understood. Thanks for that. Jesse, maybe moving on or sticking with this topic and thinking about expanding beyond that Mississippi River corridor. I know you guys have talked about I think something in the order of 30 million tons per annum within construction projects there. Just curious if we can get an update on that. And as you think about your competitive position beyond that corridor, I know one of the main selling points here was a lot of brownfield assets in the ground that you can repurpose as you expand beyond, I don’t think you’ve got as much of that. So curious how you’re thinking about some of the return multiples outside that corridor?

Jesse Arenivas: Yes. I think from a return multiple perspective, I think we you would expect those to compete with our traditional midstream business. So those multiples will have to be competitive. I think where we have a competitive advantage again is our decades long experience both in Louisiana and as we expand into Texas, Gulf Coast area is our ability to execute on agreements — on construction projects, operations of CO2 pipes. We are now in the phase of our North Texas assets. So we’ve got the experience there. I think the relationship with ExxonMobil, there is a mutually beneficial relationship and that we are a pipeline infrastructure company as we set out to be the transporter of choice that is materializing. And the value add there is going to be timely execution, experience, customer relationships. So I think we do have a value add, and I think it’s recognized by ExxonMobil.

Spiro M Dounis: Great. I’ll leave it there for today. Thanks for the time, guys.

Operator: Our next question comes from the line of Brian Reynolds with UBS.

Brian Reynolds: Hi, good morning everyone. Maybe to touch on just the Permian growth cadence a little bit, a lot of M&A among some of your counterparties in the Midland. There should be some more Delaware growth, at least that’s where it’s forecasted going into this year. And then you have Matterhorn coming into service in the back half. So it would be great if you could just maybe help us break apart the Permian there and your asset base as we think about Permian growth cadence across your footprint for this year? Thanks.

Ben Lamb: Look, you’re right there in your commentary. If you look at the driver of our Permian growth for 2023, it was largely in the Midland gas segment. This year, we expect to see more of it come from the Delaware gas side with the Tiger II plant coming into service just in time in the second quarter of this year. In terms of Matterhorn, it will be in service in the third quarter. But as a reminder, we treat that as an equity method investment and so you’re not seeing that in the guidance for segment profit for Permian. What you’re seeing there in segment profit for Permian is all of our own Permian operations, the Matterhorn JV will hit below the line so to speak.

Brian Reynolds: Great. Super helpful. And maybe to follow-up on some of the CCUS questions. I believe last quarter you kind of talked about an 80% MTPA market opportunity in Louisiana, which hopefully you’re going to capture $300 million of EBITDA as an opportunity set. Just given that we’re 2.5 times that, are you still looking to capture kind of 50% of market share like could this business ultimately make up not 20% of your ultimate earnings mix? Or are you looking to make it even more substantial than that?

Ben Lamb: So what we identified was really not a percentage of the market share when we talked about — it just worked out that 40% was 50%. But those were identified projects that we were working with our customers, and that includes ExxonMobil and beyond. Those were identified projects, not in a to put a marker out there on a percent of the total addressable market. But certainly, now that we have expanded into multiple geographic regions and a much larger addressable market, we do anticipate and are optimistic that this business gets bigger than the initial $300 million business that we identified earlier.

Brian Reynolds: Great. Thanks, appreciate the color this morning.

Operator: Our next question comes from the line of Jeremy Tonet with JPMorgan. Please proceed with your question.

Jeremy Tonet: Hey, this is Noah Katz on for Jeremy. I was just wondering if you had any additional comments on progress with incremental CCS partners other than Exxon?