Genesis Energy LP

NYSE:GEL

Greetings, and welcome to Genesis Energy, L.P. First Quarter 2025 Earnings Conference Call. [Operator Instructions]. As a reminder, this conference is being recorded.

It is now my pleasure to introduce Dwayne Morley. Thank you, Dwayne. You may begin.

Good morning, and welcome to the 2025 First Quarter Conference Call for Genesis Energy. Genesis Energy has 3 business segments. The offshore pipeline transportation segment is engaged in providing the critical infrastructure to move oil produced from a 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' 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 Louie Nicol, Chief Accounting Officer.

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 retransformational 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 a 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 sea floor in the Walker Ridge area, the Gulf of America in mid-April. And we remain on schedule to commission our new 100% owned SYNC 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 sell from Ingleside, Texas approximately 2 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 SEKCO pipeline in advance of expected first oil some 4 to 6 weeks after Salamanca starts. All oil from Salamanca will continue on to shore through our 64% owned and operated Poseidon oil pipeline.

We continue to believe these 2 new stand-alone production facilities and are 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 2 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 3 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 infill 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 later 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.

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 to 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 6 more of these infill or tieback wells to come online before the end of the year, all with a capital requirement to us of 0. This type of activity typically offsets the decline from more mature wells infills, 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 breakeven analysis of the deepwater versus onshore shale. Their response was basically that they have driven breakeven 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 breakevens for their slate of projects this year, a couple of which we will see moving through our pipelines, had a breakeven 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 deepwater projects, while larger and longer cycle from a front 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 deepwater 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 reached in excess of 50 million barrels per wellbore. 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 2 to 3 years, we are encouraged to see the Department of Interior announced 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 our press release issued by the Department of Interior on April 23, the new permitting procedures are envisioned to take a heretofore multiyear 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 time lines 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 1 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 are on pace to post record earnings from this segment in 2025. Market conditions for Jones Act tonnage remain constructive. With the 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 prohibited but new deliveries are being pushed out at least until late 2026 at the earliest, and that is if you ordered 1 today. As you can imagine, the estimated costs and time line 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 remain 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 Raceland terminals and our complementary pipeline interconnects as our 2 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 hydrosulphide 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 2 new offshore developments, combined with the cash cost 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 3-pronged approach, including continue 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 unitholders 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 cost 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 unitholders 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'm 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 Instructions] And our first question comes from the line of Michael Blum with Wells Fargo.

So 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 2 big offshore projects. I guess first question is, is there a thought to maybe hold the distribution flat this year? And if not, is it -- is the timing maybe shifting to Q4 from Q3? Or how should we think about that?

I don't know that we've changed any of our thoughts around things. I mean I know you're anxious to see Shen come on as well as Salamanca, both of which are scheduled, obviously, as we said in the second quarter, early or sometime in the third quarter. So 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 6 additional wells that are slated to come on between now and the end of the year. So 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.

Okay. Great. And then, 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?

Yes. As we said, 10 of the 22 deepwater rigs that currently working in the Gulf of Mexico are working on fields and acreage that are already dedicated to us. Obviously, the 3 fields occupy that, that we've talked about that are either doing workovers and/or drilling new development wells there. So there's another 7 active rigs that are drilling to the right that could turn to production by the end of the year.

So these wells typically, these are not HPHT wells. I mean, obviously, there's 2 other rigs working that are working on Salamanca and Shenandoah. So there's 5 others that are drilling infill or subsea tieback wells. And typically, these wells will be in the 7,000 to 10,000 barrel a day range. And so we anticipate getting a little bit of a cumulative increase of throughput from those wells as we go through the year.

And our next question comes from the line of Wade Suki with Capital One.

I know you all don't give segment guidance, but I figured I'd ask anyway, if you 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 into next year.

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 as we go through the year to be reasonably consistent with the first quarter, maybe ticking up just a hair. And that the rest of the segment margin that we anticipate given our annual EBITDA guidance is going to come from the offshore.

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? And to what extent are some of these opportunities you talked about in your prepared remarks already embedded or not embedded in guidance?

We've taken the ones that have higher visibility into account and formulating our guidance for the year, but 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. So as we -- it is typical that more it offsets, if not more than offsets the decline from more mature fields, given the position and the development and technological capabilities that basically everything within a 30-mile radius of one of these existing floating production units, which are exclusively tied to our pipeline infrastructure, are considered host platforms for subsea developments and breakevens on those are in the teens, because they don't have to amortize, if you will, the upfront floating production units and other things. So we're pretty excited about it, and I'm pretty excited about where we stand. And hopefully, we can be net additive to more than offsetting the decline with this type of activity.

And if I could squeeze one in -- one more in, I'd be grateful. Just on the new projects you've 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?

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. But as we've also reiterated, we've prebuilt in the capacity on both the SYNC laterals and importantly, on CHOPS system to be able to move significant incremental volumes and generate significant -- potentially significant incremental segment margin without having to spend any money. So that's a pretty comfortable place to be in, and that's what we're focused on. .

[Operator Instructions] And our next question comes from the line of Elvira Scotto with RBC Capital Markets.

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 and it seems like some of this remediation keeps getting pushed out a little bit. But what gives you confidence kind of in the resolution by the end of the second quarter or early 3Q? And then also on the offshore, I do realize that for producers, these are large multiyear projects that are generally more immune to near-term crude oil price fluctuations, but is there a crude oil price point at which we could see some variation in producer activity or plans?

On the first part of the question is what gives us a little bit of confidence, we were -- before our call started, we were listening to the Murphy call, and I think it's well documented at 1 of the fields that we've talked about in the past is Khaleesi, Mormont, King's Quay field. And they say basically to summarize a little bit, while the Mormont #2 and Samurai #3 wells are back on. The weather impact in the first quarter caused them to come on later than expected. The Khaleesi 2 workover has been pushed to the right as a result because it's using the same rig.

So these are -- but as I said, 2 of them are on and are now on the Khaleesi 2 well to on that workover as well as then anticipating drilling a new development well. So that's what gives us confidence, and that's explicit and real-time data there. And 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. And so 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. So 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 wellbores and stuff. So I think that we've not ever seen even when prices -- and I'm dating myself and prices went to $10 a barrel that we saw in significant, much less meaningful supply response of current production.

So again, these are long-lived wells if you're producing -- if you're recovering 20 million or 30 million barrels, much less 50 million or 60 million barrels per wellbore and yet you're seeing max initial production rates of 20,000 barrels a day, you can do the arithmetic. The individual wells are 7-, 10-, 15-year lived well. So you're not going to see, in our opinion, and based on history, we've not seen response to a low price environment and certainly. And while it's 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.

Great. And then just going back to capital allocation, and I know you've provided some good detail here, but -- 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 ratably? Any help there?

I think our long-term target leverage ratio is calculated by our banks has always been in the neighborhood of 4x and that 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's not a great -- it's not an overly burdensome thing to be able to do it.

But again, there's a little bit of noise from a GAAP accounting point of view in our disclosures and our calculated coverage ratio this quarter, but 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 the incremental segment margin, which as we've publicly stated, if the producers actually hit their numbers that they provided us would generate an incremental $160 million a year 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.

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

I think consistent with some other public company disclosures, which are certainly -- they're larger, significantly larger than we are, have publicly stated that in their opinion that rates need to go up 30% to 40% from here and be believed to be sustained in essence, for 5-plus years, because you have 2 years' worth of construction and then a 3- to 5-year payback period before they would entertain initiating a significant new build program.

So I think that what -- in today's world, what we -- inland heater barge that we built in 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.

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

Okay. Well, thanks, everyone, for participating, and we look forward to continuing the dialogue in 90 days, if not sooner. Thank you. .

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