Genesis Energy - Earnings Call - Q1 2025

Executive Summary

• Q1 2025 headline numbers reflect a major portfolio transition: revenue $398.3M, Total Segment Margin $121.4M, Adjusted EBITDA $131.7M, and GAAP net loss attributable to GEL of $469.1M driven by a $432.2M loss on disposal of the Alkali business (discontinued operations).
• Management introduced 2025 Adjusted EBITDA guidance of $545–$575M (post-Alkali sale and before reconcilable GAAP items), below the prior “around $700M” outlook provided with Q4 2024, as scope and timing rebase to continuing operations and the ramp of Shenandoah/Salamanca mid-year.
• Deepwater Gulf growth catalysts are imminent: Shenandoah connected to SYNC with first oil expected in June and Salamanca ~4–6 weeks behind; both are expected to ramp quickly and, with remediation of producer mechanical issues, drive sequential offshore improvement into 2H25.
• Balance sheet materially simplified: ~$1.0B Alkali-sale proceeds used to pay RCF to zero, redeem 2027s, and repurchase $250M preferreds; annual cash costs reduced by >$120M; bank leverage 5.49x LTM as of 3/31/25, nearest unsecured maturity in early 2028.

What Went Well and What Went Wrong

• What Went Well

  • Offshore projects on track: Shenandoah FPU moored; SYNC commissioning end‑May; first oil June; Salamanca arrival imminent with first oil in 3Q; both expected to ramp quickly and be long-term contributors.
  • Marine Transportation steady with constructive market: high utilization and steady to rising day rates; structural undersupply of Jones Act capacity supports outlook.
  • Balance sheet actions lowered cash cost of capital by >$120M annually; RCF at $0; 2027s called; $250M preferred repurchased, improving flexibility for future distributions/deleveraging.

• What Went Wrong

  • Offshore Segment Margin fell 22% YoY on producer mechanical issues, a contractual step-down on an older dedication, and higher operating costs; Poseidon volumes also down YoY.
  • Onshore Transportation & Services margins declined 18% YoY on lower NaHS/caustic volumes and lower onshore crude pipeline volumes, partly offset by higher rail unloads.
  • GAAP EPS sharply below consensus due to a non‑cash loss on Alkali disposal: net loss per common unit of $(4.06) vs S&P Global consensus primary EPS of $(0.23) (one estimate). Values retrieved from S&P Global.

Transcript

Operator (participant)

Greetings and welcome to Genesis Energy L.P. First Quarter 2025 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. If anyone should require operator assistance, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce Dwayne Morley. Thank you, Dwayne. You may begin.

Dwayne Morley (VP of Investor Relations)

Good morning and welcome to the 2025 First Quarter Conference Call for Genesis Energy. Genesis Energy has three business segments. The Offshore Pipeline Transportation segment is engaged in providing the critical infrastructure to move oil produced from long-lived world-class reservoirs from the deepwater Gulf of America to onshore refining centers. The Marine Transportation segment is engaged in the maritime transportation of primarily refined petroleum products, and the Onshore Transportation and Services segment is engaged in the transportation, handling, blending, and storage and supply of energy products, including crude oil and refined products primarily around refining centers, as well as the processing of sour gas streams to remove sulfur at refining operations. Genesis's operations are primarily located in the Gulf Coast states and the Gulf of America.

During this conference call, management may be making forward-looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934. The law provides safe harbor protection to encourage companies to provide forward-looking information. Genesis intends to avail itself of those safe harbor provisions and directs you to its most recently filed and future filings with the Securities and Exchange Commission. We also encourage you to visit our website at genesisenergy.com, where a copy of the press release we issued this morning is located. The press release also presents a reconciliation of non-GAAP financial measures to the most comparable GAAP financial measures. At this time, I'd like to introduce Grant Sims, CEO of Genesis Energy L.P.. Mr. Sims will be joined by Kristen Jesulaitis, Chief Financial Officer and Chief Legal Officer; Ryan Sims, President and Chief Commercial Officer; and Louis Nicol, Chief Accounting Officer.

Grant Sims (CEO)

Thanks, Dwayne. Good morning to everyone. Thanks for listening to the call. As we mentioned in our earnings release this morning, the first quarter was indeed a busy quarter. It was kind of a re-transformational quarter for Genesis as we successfully exited our soda ash business and used the net proceeds to simplify our balance sheet and significantly reduce the future cash costs of running our remaining businesses. Now that we have reached that targeted inflection point where we will be in position to generate excess cash, excess of our cash expenses, and when combined with our refocused efforts on the traditional midstream energy space, we believe we are now even better positioned to create long-term value for all of our stakeholders in future periods. As we look forward, I cannot be more excited about what lies ahead for Genesis.

Our offshore expansion projects, supported by contracts executed in August of 2021 and April of 2022, are very nearly complete and will soon be ready for first production from both Shenandoah and Salamanca over the coming months. As stated in our earnings release, the Shenandoah floating production unit was successfully moored to the seafloor in the Walker Ridge area of the Gulf of America in mid-April, and we remain on schedule to commission our new 100% owned SINK pipeline towards the end of this month in advance of expected first oil sometime in June, with all such oil continuing to shore through our 64% owned and operated CHOPS pipeline. The Salamanca FPU recently completed its final safety and operational checks. It sailed from Ingleside, Texas, approximately two weeks ago and is anticipated to arrive at its final location in Keathley Canyon any day now.

Upon its arrival, we will work closely with LLOG to finalize their connection to our 100% owned SACO pipeline in advance of expected first oil some four to six weeks after Salamanca starts up. All oil from Salamanca will continue on to shore through our 64% owned and operated Poseidon Oil pipeline. We continue to believe these two new standalone production facilities and their combined almost 200,000 barrels of oil per day of incremental production handling capacity will ramp very quickly and will likely reach their anticipated initial production levels by the end of the year, if not sooner. This will represent a significant stepwise change in the financial contribution from our Offshore Pipeline Transportation segment. There is no doubt in my mind that both the Shenandoah and Salamanca FPUs will be an integral part of the Genesis story over the coming decades.

When combined with the steady performance from our other two segments and the significant cash savings realized from the sale of our soda ash business, we believe this increasing free cash flow profile puts Genesis in a relatively unique and enviable position within the midstream space, especially for small to mid-cap midstream enterprises. With that, I'll go into a little more detail for each of our business segments. As mentioned in our earnings release, several of our producer customers continue to experience mechanical issues that are affecting production from various wells at three of the major fields that are connected to our offshore infrastructure. The producers involved have all been increasingly transparent with their public disclosures, and we can confirm that all have deepwater drilling rigs on location that are actively working to restore production from these affected wells, as well as drilling new infield development wells.

We continue to see progress on these repairs, as evidenced with the exit rate volumes in the first quarter being greater when compared to the exit rate volumes in the fourth quarter. Based on what we know today, we would reasonably expect to see this trend continue in the coming months, with expected volume levels returning to or near normalized levels as we exit the second quarter, or at the absolute latest sometime in the third quarter. While these extended mechanical issues have been unfortunate, our offshore team continues to focus on the things we can control. We continue to have an active dialogue and robust commercial discussions with multiple producers regarding additional infield, subsea, and/or secondary recovery development opportunities that could turn to additional volumes on both our pipeline laterals and pipelines to shore. Excuse me.

Along these lines, we are finalizing agreements with an operator to provide downstream oil transportation for a new subsea development with first oil scheduled for late second quarter. This single well is expected to produce in the range of 8,000-10,000 barrels of oil equivalent per day and will be tied back to an existing floating production unit in approximately 1,500 feet of water. This is yet another example of the continued generation of smaller, but meaningful and increasingly economic tieback opportunities in the central Gulf of America that continue to leverage existing platform and pipeline infrastructure. We have been told by various operators to expect at least six more of these infield or tieback wells to come online before the end of the year, all with a capital requirement to us of zero.

This type of activity typically offsets the decline from more mature wells and fields, making new developments like Shenandoah and Salamanca truly additive and incremental to our expected financial results. I want to add a little third-party color around some of the comments we made in the earnings release regarding the relatively low commodity price environment and near-term activity in the Gulf. Just last week, Chevron, one of the most active operators in the Gulf of America, and which also happens to be one of the largest landowners and leaseholders in the Permian Basin, was asked on their quarterly earnings call to comment on the cost structure and break-even analysis of the deepwater versus onshore shale.

Their response was basically that they have driven break-even costs in the deepwater to a point where they intend to continue to allocate significant capital to grow their production from the deepwater. They had to because of their opportunity set in their onshore shale position.

Just a couple of days ago, Talos highlighted on their earnings call that their break-evens for their slate of projects this year, a couple of which we will see moving through our pipelines, had a break-even of $30 to $40 per barrel that allows them to "have robustness against this current price environment." All in all, I think it is safe to say that deep water projects, while larger and longer cycle from an upfront capital perspective, will prove to be substantially more resilient during times of lower or uncertain prices, given the 20, 30, 40-plus year design lab producers consider when making these investment decisions. There is increasing evidence that the deep water clearly stacks up very well and, in some cases, might be superior to onshore shale plays, especially given technological advancements where the industry has seen recoveries reach an excess of 50 million barrels per well bore.

As you know, there have already been numerous onshore operators that have come out this earnings season and announced they were laying down rigs or slowing their current pace of development onshore due to the current pricing environment. No deepwater producers that we are aware of have announced any such actions. As we look beyond the next two to three years, we are encouraged to see the Department of Interior announce the commencement of the 11th National Outer Continental Shelf Oil and Gas Leasing Program in mid-April. Additionally, the Department of Interior recently announced they will be implementing new permitting procedures to accelerate the development of domestic energy resources and critical minerals. These measures are designed to expedite the review and approval, if appropriate, of projects related to the leasing, siting, production, transportation, refining, or generation of energy within the United States.

According to a press release issued by the Department of Interior on April 23rd, the new permitting procedures are envisioned to take a heretofore multi-year process down to just 28 days. While we do not reasonably expect to see any actionable new developments or tieback opportunities in the next few years from this new leasing program, the accelerated permitting schedule and reduced timelines could bring forward opportunities that might have been slated for the end of the decade or even later. Regardless, we believe we have decades of opportunities under existing valid leases. I might point out that 10 of the 22 active deepwater drilling rigs currently working in the Gulf of America are working on leases already contractually dedicated to our pipeline infrastructure, and one is working on a lease that would logically come through us if it's commercially successful.

Not a bad place to be from our perspective. It says a lot about our strategically positioned and practically irreplaceable infrastructure in the central Gulf of America. Our Marine Transportation segment performed in line with our expectations, and we're on pace to post record earnings from this segment in 2025. Market conditions for Jones Act tonnage remain constructive, with a consistent theme of little to no significant new construction and reasonably steady demand from our refinery and terminal customers. On the supply side, we believe this trend of flat to lower available capacity will continue across the market for the foreseeable future as more and more older barges are candidates for retirement and there are limited options for new construction.

In addition to fewer and fewer shipyards available to build a new brown water tank barge, the combination of the increased cost of steel and a limited labor pool to build such equipment is not only making the cost of a new 30,000-barrel heated tank barge cost prohibitive, but new deliveries are being pushed out at least until late 2026 at the earliest, and that is if you ordered one today. As you can imagine, the estimated cost and timeline for delivery for any larger equipment in the same class as our offshore fleet and/or the American Phoenix are even more challenging than in the inland world. On the demand side, we continue to monitor Gulf Coast and Midwest refinery utilization, as that is the primary driver of activity levels for our brown water fleet.

While we did see a little softness in the first part of the year, which is not atypical after year-end, we are now past that, and we have seen Gulf Coast refinery utilization recover over the last several months from approximately 80% in January to roughly 94% in late April. This additional activity will continue to support the need to move heavy and intermediate products within our heater barges from location to location. Demand for moving petroleum products from the Gulf Coast to the East and Mid-Atlantic markets remains steady, and we would expect this trend to continue given the lack of adequate regional refining capacity in those markets.

All of this is to say we believe the structural tailwinds in the Jones Act world today, combined with our diversified fleet and layered term contract portfolio, will continue to support steady, if not marginally increasing, financial contributions from our marine transportation segment for the foreseeable future. Switching briefly to our onshore business, I wanted to make sure everyone saw that we recently consolidated our legacy refinery services business, which was not a part of the sale of our soda ash business, with our legacy onshore facilities and transportation segment under one umbrella. We are now referring to it as our onshore transportation services segment, or OTS segment.

Our OTS segment is very refinery-centric, as we provide the critical last movements of crude oil and/or intermediate products into or out of major refining centers, along with critical sour gas processing services to help our host refiners lower their emissions and remove sulfur from their final refined products. During the quarter, we saw steady volumes across our systems, and we continue to expect to see a marginal increase in volumes at both our Texas City and Rice Land terminals and our complementary pipeline interconnects, as our two new offshore projects commence production in the next few months and flow downstream on our CHOPS and Poseidon pipelines to shore. In addition, our host refineries performed in line with our expectations and provided us with adequate sour gas volumes that allowed us to produce the necessary sodium hydrosulfide volumes demanded by our mining and pulp and paper customers.

In closing, the management team and I could not be more excited with how Genesis is positioned for the remainder of 2025 and into 2026 and beyond. The anticipated increase in segment margin contribution from our two new offshore developments, combined with the cash costs of running and sustaining our businesses having already been reduced to approximately $425 million to $450 million per year, should allow us to start harvesting significant and growing free cash flow in the quarters and years ahead. We plan to implement a capital allocation strategy that deploys the anticipated excess cash flow across a three-pronged approach, including continuing to redeem more of our high-cost 11.24% preferred units, paying down debt in absolute terms, or buying back unsecured bonds in the open market, and ultimately returning capital to our unit holders in one form or another.

As we are successful in harvesting more of our corporate preferred units and paying down debt, we will further reduce the ongoing cash costs of running and sustaining the business, which will only accelerate our financial flexibility and allow us to achieve our targeted bank calculated leverage ratio and ultimately return more capital to our unit holders in the form of distribution growth, unit buybacks, or both, all while maintaining the financial flexibility to capitalize on new commercial opportunities as they might ultimately arise. Finally, I would like to say that the management team and the board of directors remain steadfast in our commitment to building long-term value for all our stakeholders, regardless of where you are in the capital structure. We believe the decisions we are making reflect this commitment and our confidence in Genesis moving forward.

I would once again like to recognize our entire workforce for their individual efforts and unwavering commitment to safe and responsible operations. I am extremely proud to be associated with each and every one of you. With that, I'll turn it back to the moderator for questions.

Operator (participant)

Thank you. We will now be conducting a question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star two to remove yourself from the queue. For participants using speaker equipment, it may be necessary to pick up the handset before pressing the star keys. One moment while we poll for questions. Our first question comes from the line of Michael Blum with Wells Fargo. Please proceed with your question.

Michael Blum (Managing Director)

Thanks. Good morning.

I wanted to ask about your thoughts on capital allocation. Given the uncertain backdrop, you have some moving pieces in the business with some of those repairs coming online, the timing of the two big offshore projects. I guess first question is, is there a thought to maybe hold the distribution flat this year? And if not, is the timing maybe shifting to Q4 from Q3, or how should we think about that?

Grant Sims (CEO)

I do not know that we have changed any of our thoughts around things. I mean, I know we are anxious to see Shen come on as well as Salamanca, both of which are scheduled, obviously, as we said, in the second quarter or sometime in the third quarter.

I think we'll have a lot more visibility around that, as well as the pace at which the mechanical issues are addressed and also the pace at which the six additional wells that are slated to come on between now and the end of the year. I think that we will probably, in all likelihood, maintain a flat distribution for the second quarter, but certainly be in a position relative to the third quarter and beyond to consider movements in the quarterly distribution.

Michael Blum (Managing Director)

Okay. Great. Thanks for that. You mentioned the opportunity for additional infield and subsea and secondary tiebacks, which could add additional volumes. Is there any way to quantify that in terms of what that opportunity looks like from either a volume or an EBITDA or a timing standpoint? Thanks.

Grant Sims (CEO)

Yep.

As we said, 10 of the 22 deepwater rigs that currently work in the Gulf of Mexico are working on fields and acreage that are already dedicated to us. Obviously, the three fields occupy that that we've talked about that are either doing workovers and/or drilling new development wells there. There are another seven active rigs that are drilling to the right that could turn to production by the end of the year. These wells, typically, these are not HPHT wells. I mean, obviously, there are two other rigs working that are working on Salamanca and Shenandoah. There are five others that are drilling infield or subsea tieback wells. Typically, these wells will be in the 7,000-10,000 barrel a day range. We anticipate getting a little bit of cumulative increase of throughput from those wells as we go through the year.

Michael Blum (Managing Director)

Thank you.

Operator (participant)

Thank you. Our next question comes from the line of Wade Suki with Capital One. Please proceed with your question.

Wade Suki (Equity Analyst)

Great. Thank you, operator. Good morning, everyone. Appreciate you all taking my questions. I know y'all don't give segment guidance, but figured I'd ask anyway if y'all might be able to sort of bracket segment margin for the offshore segment this year. Maybe I'll push it and ask if you have a preliminary look in the next year.

Grant Sims (CEO)

We don't really—I mean, I think it's, as we said, you can do some of the arithmetic that relative we would anticipate our OTS and marine to, as we go through the year, to be reasonably consistent with the first quarter, maybe ticking up just a hair. The rest of the segment margin that we anticipate, given our annual EBITDA guidance, is going to come from the offshore.

Wade Suki (Equity Analyst)

Okay. Great. I think we've kind of talked previously about these tieback, tie-in opportunities, sort of thinking about them in the context of offsetting declines. Do we need to actually start thinking about these as growth enhancements? To what extent are some of these opportunities you talked about in your prepared remarks already embedded or not embedded in guidance?

Grant Sims (CEO)

We've taken the ones that have higher visibility into account in formulating our guidance for the year. There is potential for upside, if you will, to the extent that they come on—additional ones come on that kind of aren't on the horizon.

It is typical that more it offsets, if not more than offsets, the decline for more mature fields, given the position and the development and technological capabilities that basically everything within a 30 mi radius of one of these existing floating production units, which are exclusively tied to our pipeline infrastructure, are considered host platforms for subsea developments. The break-evens on those are in the teens because they do not have to amortize, if you will, the upfront floating production units and other things. We are pretty excited about it and pretty excited about where we stand. Hopefully, we can be net additive to more than offsetting the decline with this type of activity.

Wade Suki (Equity Analyst)

Fantastic. If I could squeeze one more in, I would be grateful.

Just on the new projects you kind of talked about, things that are potentially on the horizon, I mean, are things kind of popping up on your radar already? Any sense kind of in terms of order of magnitude or a little too early for that?

Grant Sims (CEO)

No, I think it's, again, we just wanted to emphasize that we have the financial flexibility in our view to take advantage of things, but nothing has popped up. Again, over the next several years, we're really focused on harvesting from the ramp, from the significant monies that we've spent in the past. As we've also reiterated, we've pre-built in the capacity on both the SINK laterals and, importantly, on CHOPS system to be able to move significant incremental volumes and generate potentially significant incremental segment margin without having to spend any money. That's a pretty comfortable place to be in.

That's what we're focused on.

Wade Suki (Equity Analyst)

Absolutely. Great. Thank you so much. Look forward to seeing you here in a couple of weeks. Thanks.

Operator (participant)

Thank you. Once again, if you'd like to ask a question, please press star one on your telephone keypad. That is star one. Our next question comes from the line of Elvira Scotto with RBC Capital Markets. Please proceed with your question.

Elvira Scotto (Managing Director and Equity Research Analyst)

Hey. Good morning, everyone, and thanks for all the details. Going back to the offshore, can you provide just a little more detail? I know we've talked about this in the past, but on the producer issues, it seems like some of this remediation keeps getting pushed out a little bit. What gives you confidence kind of in a resolution by the end of the second quarter or early 3Q?

I do realize that for producers, these are large multi-year projects that are generally more immune to near-term crude oil price fluctuations. Is there a crude oil price point at which we could see some variation in producer activity or plans?

Grant Sims (CEO)

Okay. The first part of the question is what gives us a little bit of confidence. Before our call started, we were listening to the Murphy call. I think it is well documented that one of the fields that we have talked about in the past is the Khaleesi-Mormont King's Key field. They say, basically, to summarize a little bit, while the Mormont number two and Samurai number three wells are back on, the weather impact in the first quarter caused them to come on later than expected.

The Khaleesi two workover has been pushed to the right as a result because it's using the same rig. These are, but as I said, two of them are on, and they're now on the Khaleesi two well on that workover as well as then anticipating drilling a new development well. That's what gives us confidence. That's explicit in real-time data there. I think on the other fields that we—I'm not sure that those have been identified in the public domain, but I think it's fair to say that the producers are incented to get it done as quickly as possible. We have a lot of confidence that they're on location and taking care of things. Relative to your second question, I mean, really, the marginal lifting cost is extremely low in the Gulf, especially given the fixed cost economics.

You've already spent several billions of dollars. You're not going to shut in production. You're not going to unman a platform and shut in production and ultimately run the risk of reducing the overall recoveries from your existing well bores and stuff. I think that we've not ever seen, even when prices—and I'm dating myself—when prices went to $10 a barrel that we saw any significant, much less meaningful supply response of current production. These are long-lived wells. If you're producing, if you're recovering 20 or 30 million barrels, much less 50 or 60 million barrels per well bore, and yet you're seeing max initial production rates of 20,000 barrels a day, you can do the arithmetic that the individual wells are 7, 10, 15-year live wells.

You're not going to see, in our opinion, and based on history, we've not seen a response to a low-price environment. Certainly, while $50/$60 is not as good for the producers as $80 or $90 or whatever, it still will not affect any of their behavior, in our opinion.

Elvira Scotto (Managing Director and Equity Research Analyst)

Okay. Great. Thanks for that. Just going back to capital allocation, and I know you've provided some good detail here, and you noted you're taking an all-of-the-above approach. Can you just remind us, though, is there a target kind of leverage ratio and distribution coverage ratio that you target before increasing the distribution more meaningfully and radically? Any help there?

Grant Sims (CEO)

I think our long-term target leverage ratio is calculated by our banks. It's always been in the neighborhood of four times, and we anticipate being able to get there fairly rapidly.

Again, the cost of increasing the distribution in terms of the cash cost, given that we only have 122.5 million units outstanding, it is not a great—it is not an overly burdensome thing to be able to do it. Again, there is a little bit of noise from a GAAP accounting point of view in our disclosures and our calculated coverage ratio this quarter. All of that is going to the noise of exiting a significant business from a GAAP point of view and going forward, as well as when we start seeing the significant ramp in incremental segment margin, which is, we have publicly stated if the producers actually hit their numbers that they provided us, would generate an incremental $150 million a year of segment margin to us.

That's pretty meaningful in being able to rapidly approach that targeted leverage ratio, as well as having the ability to consider meaningful movements in the distribution.

Elvira Scotto (Managing Director and Equity Research Analyst)

Great. That's helpful. Just, I guess, my last question is just on the marine segment. It sounds like utilization rates have been holding steady. Can you just remind us where do day rates need to go versus where they are today to kind of incentivize new construction?

Grant Sims (CEO)

I think consistent with some other public company disclosures, which are certainly, they're significantly larger than we are, have publicly stated that, in their opinion, rates need to go up 30% to 40% from here and be believed to be sustained, in essence, for five-plus years because you have two years' worth of construction and then a three to five year payback period before they would entertain initiating a significant new build program.

I think that in today's world, what we inland heater barge that we built 2017, 2018 for $3.5 million is probably order of magnitude $6 million to $6.5 million in today's world. And given that these have a 30, 35, 40-year useful life, and we have a relatively one of the youngest in the aggregate fleets on the water, we think that we're in a very good position given that kind of backdrop.

Elvira Scotto (Managing Director and Equity Research Analyst)

Excellent. Thank you very much.

Grant Sims (CEO)

Thank you.

Operator (participant)

Thank you. There are no further questions at this time. I would like to turn the floor back to Grant Sims for closing remarks.

Grant Sims (CEO)

Okay. Thanks, everyone, for participating. We look forward to continuing the dialogue in 90 days, if not sooner. Thank you.

Operator (participant)

Thank you. With that, this does conclude today's teleconference. We thank you for your participation. You may disconnect your lines at this time.