Tidewater Midstream and Infrastructure Ltd
TSX:TWM
Tidewater Midstream and Infrastructure Ltd
Tidewater Midstream & Infrastructure Ltd. engages in the acquisition and development of oil and gas infrastructure, including gas plants, pipelines, NGLs by rail, export terminals and storage facilities. The company is headquartered in Calgary, Alberta and currently employs 419 full-time employees. The company went IPO on 2015-04-15. The firm is engaged in providing customers with a full service, vertically integrated value chain through the acquisition and development of oil and gas infrastructure, including gas plants, pipelines, railcars, export terminals, storage, downstream facilities and various renewable initiatives. Its operations are located in the Deep Basin, Edmonton, and Montney regions of Alberta and British Columbia. Its wholly owned subsidiary, Tidewater Renewables Ltd. (Tidewater Renewables) is a multi-faceted, energy transition company focusing on the production of low carbon fuels.
Earnings Calls
Tidewater Midstream reported a net loss of $3.3 million in Q4 2024, a significant improvement from $331.8 million in Q4 2023. Adjusted EBITDA was $20 million, slightly down from the prior year. In 2025, the company anticipates capital maintenance spending of $15-20 million. Initiatives include selling noncore assets worth up to $100 million without affecting cash flow. Additionally, due to government fuel mandates and a trade complaint about U.S. imports, market dynamics are shifting favorably for Tidewater's operations, with expectations of improving credit prices moving forward.
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Good afternoon, ladies and gentlemen, and welcome to the Tidewater Midstream and Infrastructure Ltd Q4 2024 Financial Results Conference Call. [Operator Instructions] Following the presentation, we will conduct a question-and-answer session. [Operator Instructions] This call is being recorded on Thursday, March 27, 2025. I would now like to turn the conference over to Michael Gracher. Please go ahead.
Thank you, Joelle, and welcome, everyone, to Tidewater Midstream's Fourth Quarter 2024 Results Conference Call. I'm Michael Grasher, Manager of Investor Relations. And joining me today are Jeremy Baines, CEO; and Aaron Ames, Tidewater's Midstream's Interim CFO. Also with us and available during the question-and-answer session is Shawn Heaney, EVP, Planning & Strategy.
Before we begin, please note that matters discussed on this call include forward-looking statements under applicable securities laws with respect to Tidewater Midstream and Infrastructure LTD, including, but not limited to, statements regarding investments and acquisitions by the company, commercial arrangements of the company, the business strategies and operational activities of the company, the markets and industries in which the company operates, cost and expense management, the company's leverage and plans for debt and leverage reduction, refinancing of the company's indebtedness, the value of the company's assets and the future growth, objectives, targets, financial and operating performance of the company and its businesses.
Such statements are based on factors and assumptions that management believes are reasonable at the time that they were made and information currently available. Forward-looking statements we may express or imply today are subject to risks and uncertainties, which can cause actual results to differ from expectations.
Further, some of the information provided refers to non-GAAP metrics. To learn more about these forward-looking statements and non-GAAP measures, please see Tidewater Midstream's financial reports, which are available at www.tidewatermidstream.com and on SEDAR. And with that, I will now pass the call over to Jeremy to go over some highlights for the quarter and the full year 2024.
Thanks, Michael. Thanks to everyone for joining us today. Operationally, Tidewater had another safe and successful quarter. Our downstream and midstream facilities continue to operate reliably and consistently throughout the fourth quarter. At PGR throughput averaged 10,963 barrels per day, which was 6% lower than Q3, 2024. The lower throughput was largely attributed to scheduled maintenance and third-party pipeline maintenance, which temporarily decreased the feedstock volume coming into the facility.
HDRD had an average thought of approximately 2,677 barrels per day, slightly lower than Q3 2024, which averaged 2,849 barrels per day. Keep in mind, during winter operations, the HDRD facility requires a minor reduction in throughput rate in order to optimize hydrogen production and produce high-quality, low [ flow point ] diesel that meets cold temperature specifications.
During the fourth quarter, Prince George crack spreads, spreads averaged approximately $75 per barrel, which was lower than in the fourth quarter of 2023, which averaged $87 per barrel. So far, during the start of Q1 2025 crack spreads have averaged in the low $80 per barrel range and are approximately $86 today.
During the fourth quarter, the 5-year offtake agreement with Synovus, which provided the sale of the majority of refined product volumes for PGR expired. And the company has now successfully transitioned to marketing all refined products produced at both HDRD and PGR facilities in-house. Tidewater has made significant progress in marketing its diesel and gasoline volumes for 2025. As we have previously disclosed, current market discounts are wider than most at the time the Synovus offtake agreement was entered into, largely stemming from the oversupply of imported renewable diesel in Western Canada.
On December 30, 2024, Tidewater renewables filed a trade complaint with the Canada Border Services Agency, with the aim of combating the adverse effects caused by the unfair imports of subsidized renewable diesel from the U.S. In early March 2025, the CBSA formally initiated a countervailing anti-subsidy and antidumping duty investigation into imports of renewable diesel from the United States.
In initiating the investigation, the CBSA confirms that Tidewater renewables provided satisfactory evidence to support its allegations that U.S. renewable diesel imports were subsidized and dumped causing harm to Tidewater renewables. A decision by the CBSA regarding whether provisional duties will be imposed at the Canada-U.S. border is anticipated by June 2025. Final duties, which would be in place for 5 years and can be renewed every 5 years thereafter, could be imposed by September 2025 following a ruling by the Canadian International Trade Tribunal -- if final duties are imposed at the anticipated levels in between $0.50 and $0.80 per liter of renewable diesel imported from the United State, these duties would support long-term market stability for Tidewater renewables, renewable diesel production, BC-LCFS credit prices and work to help restore balance within the BC market.
In addition to the trade complaint, on February 27, 2025, the government of British Columbia announced changes to the low carbon fuels Act, specifically to increase the renewable fuel requirement for diesel from 4% to 8% for the 2025 compliance period, together with effective April 1, 2025, requiring such renewable fuel content to be produced in Canada.
The amendments represent a good first step in leveling the unfair trade environment supporting Tidewater renewables and the broader Canadian biofuels industry. On the midstream side of the business, the Brazeau River Complex operated well. The facility averaged 132 million cubic feet per day compared to 134 million cubic feet per day in the same period last year. Gas processing activities at the Ram River Gas Plant have been temporarily curtailed due to producers shutting in their volumes as a result of depressed natural gas prices.
Natural gas prices are expected to recover during 2025, and gas processing operations are expected to resume as producer activity restarts. Sulfur handling activities continue to be operational. We also continue to remain very focused on our liquidity, and we have made great progress on noncore asset sales and deleveraging. On March 25, 2025, we announced that the company completed the previously announced sale of the BRC Roadway Network for total proceeds of $24 million of which $22.5 million was received and used to repay amounts outstanding on the 3-year delayed draw term loan.
The balance is expected to be received on or before December 31, 2025. The disposition of the BRC roadway network is expected to have an immaterial impact to Tidewater's 2025 operating results. In addition to the sale of the previously announced used cooking oil business at Tidewater Renewables for $10.6 million on January 10, 2025, Tidewater Renewables also completed the sale of its interest in the Rimrock renewables partnership for total proceeds of $7.8 million, of which $4.7 million was received on close and a further $3.1 million is expected to receive -- to be received upon satisfaction of certain post-closing conditions on or before December 30, 2025. The net proceeds of this transaction were used to repay outstanding debt.
Overall, we remain laser-focused on safe, efficient and reliable operations while maintaining liquidity and protecting the balance sheet by reducing costs and capital spending, which doesn't meet our return hurdles. In summary, I want to take a step back to when I joined in January 2024, at that time, the company had just completed a strategic review, which culminated in the sale of Pipestone and Dimsdale assets in December 2023. It is worth pointing out that there have been significant changes throughout the company from the Board of Directors to senior management called Tidewater Midstream and Tidewater renewables.
Since that time, we have continued making progress towards improving our operations and optimizing our asset portfolio across the consolidated entity. During this time, we sold three noncore assets for total combined proceeds of over $40 million, which was used to deliver. We have completed four financings totaling $290 million, including the convertible debentures to revolving credit facilities and the intercompany transaction.
We completed a major turnaround at BRC complex safely and below initial cost expectations, initiated cost and capital savings totaling over $15 million and run rate savings expected to be on the cost side between $7 million and $10 million go forward.
We commissioned the HDRD facility and got it running reliably in that capacity. We weathered unfair trade practices in the renewable diesel and emission credit market stemming from a policy breakdown and work with the government to implement necessary changes to the BC-LCFS program. We still have more work to get done.
Our strategy is underpinned by three key initiatives: maintaining safe and reliable operations, driving ongoing operational efficiencies and optimizing our asset portfolio to ensure we have the right mix of assets that are generating appropriate returns.
I'm proud of our Tidewater team, and I am confident in our ability to continue to progress on our plan and achieve our goal of delivering sustainable free cash flow and growth. I will now turn the call over to Aaron to go through our financial results.
Thank you, Jeremy. Consolidated net loss attributable to shareholders was [ $3.3 ] million during the fourth quarter of 2024 compared to a net loss attributable to shareholders of $331.8 million during the fourth quarter of 2023. The decrease in net loss attributable to shareholders is largely due to the reversal of certain noncash impairment charges previously taken in 2023 as a result of the transaction with Tidewater renewables, offset in part by the gain on the sale of Pipestone and Dimsdale in the fourth quarter of 2023. Consolidated adjusted EBITDA was $20 million during the fourth quarter of 2024 compared to $21.4 million during the fourth quarter of 2023. The change was primarily due to higher EBITDA from equity investments in the comparative period, offset in part by lower general and administrative costs in the current period.
For 2025, we expect our consolidated capital maintenance program to range between $15 million to $20 million. Finally, we amended our senior debt covenants to increase the consolidated debt-to-EBITDA to 4.5: 1 and lower interest coverage to 1.5:1. Also, following the [ road ] sale and debt repayment, we deferred the first mandatory quarterly repayment of $5 million on the term facility until April 30, 2026. These amendments provide additional financial flexibility to navigate current market conditions. I'll now ask the operator to open the call up for questions.
[Operator Instructions] Your first question comes from Rob Hope with Scotiabank.
Questions on the LCFS market. Can you update us on kind of how participants have changed their behavior following the rule changes from the BC government as well as kind of what you think kind of the clearing price could be for April? .
Thanks, Rob. Appreciate your question. So how have they changed their behavior. So if you go back to the 2024 year, about 1 billion liters of diesel was imported into British Columbia from the U.S. With the latest announcements as well as improvements or increases in the California LCFS price and D4 RIN prices in the U.S. and the pending tariffs that we expect to be in place. This is put a significant disincentive for conventional players to import U.S. subsidized renewable diesel into the BC market to generate LCFS and CFR credits.
So we have seen with the new Canadian renewable content requirements reach out and had significant discussions with customers that is supporting demand for Canadian-made renewable diesel as well as -- we have changed the way we are marketing that diesel to a fully-loaded barrel that includes the emission offsets in a lot of cases.
And we've also expanded our customer base last year with the first year, we had one significant key customer. We are now going to multiple customers. So all of that has been a big change. Obviously, the import season for BC is typically the summer because a lot of the Gulf Coast and U.S. producers are not set up to produce winter spec, low cloud point renewable diesel. So anybody who's thinking about doing that should be very aware of the potential outcomes of the trade case and the significant tariffs that they would face in importing it.
So it has been a a real important leveling of the playing field for the renewable diesel. Ultimately, with all of these things coming together, the tightening CI market that will continue to tighten to 2030 under the LCFS rules in British Columbia, tariffs and the buy Canadian mandate for renewable diesel in British Columbia, we expect to see credit prices normalize throughout the year, closer to where they were in the first half of 2020.
Obviously, the buy Canadian mandate kicks in, in April, the June mandate kicks in -- or sorry, the trade complaint interim tariffs would likely kick in early June. So we are watching that market. We have seen it improve significantly from where it was last year.
Great. That is very good and helpful. Maybe tying that into the commentary from the LCFS call just regarding kind of LCFS EBITDA getting back to H1 levels with the changes you're seeing in the credit market, plus the resolution of the duties. I guess if we're going to potentially put those into 2 buckets. If credit pricing improves about the duties or the trade complaint is not successful, where do you think improvement to get to, all else being equal?
Our view -- so let's talk long term because, like, one, we're highly confident that we will be successful. The subsidy is crystal clear, and I think the trade case will acknowledge that and we've been harmed. So we do expect to be successful and those duties are material.
In the long term, the British Columbia market needs to see significant portion be supplied the diesel market by renewable diesel. And we expect that with the tightening CI, we're going to have a very -- in fact, we start to see deficits and are going to see a tightening market as we go forward in the long term. So ultimately, between the actions the BC government has made, they've also publicly pledged that they're going to watch the Canadian content number to make sure that the market stays balanced, and we'll look to increase it as warranted.
We expect that we will get to a level that provides for economic and profitable -- long-term profitability at the RD facility. I can't speculate what -- it's a moving target, and we are pretty confident that tariffs are going to take place and that's our expectation, and we'll see that will move closer to first half numbers as we move through the year and into 2026.
Next question comes from Maurice Choy with RBC Capital Markets.
Just wanted to turn to the downstream business. I know that you mentioned that -- in one of your disclosures that if the downstream products, if not all of it could be placed in Western Canada, the balance may be exported to potentially lower-margin markets. Now I know this is not -- this something that you've obviously said in the past, it is not new. But could you give us an update on how these alternative markets kind of look like -- or given how crack spreads currently are at the low to mid-80s that urgencies about that?
Yes. I mean we -- look, we look every day to optimize the netbacks of our sales out of the refineries and place our product. Historically, our best markets have been British Columbia and inside what we call the Prince George Orbit, where we're logistically advantaged there, and there is significant economic activity in that area from mining, forestry, oil and gas and all of those things, that are sort of base industry, so we try to place as much of our product there, but we do look every day to make sure that we are optimizing volume and price.
And -- we've actually been doing some creative things where we're moving product in different spots when it makes sense. Obviously, we're subject to the macro environment and the crack spreads, and they have been soft over the Q4 and early Q1. But we'll continue to do that. Our desire is to place as much of it as a product as we can in close proximity to the Prince George Refinery just on logistics savings that we get by doing that.
Maybe on that note, just switching over to tariffs, threat of tariffs at least. Like any thoughts on what that could do to producer activity, which obviously is already impacted by AECO as well as the supply and demand for your products?
Yes. Look, we have various different analyses, we do think when you look at the feedstock we use in our refineries, it might actually be an advantage for us and that our feedstock will become more advantaged versus where the people that are buying the heavy from and so forth that would be supportive. Obviously, Western Canada is long refined products with the refining complex we have. And so how will markets balance will more go offshore or more go to East Coast and keep the market in balance versus what typically, we'll go into the U.S. today.
So it's -- we're watching it. We feel like we're relatively isolated from that. And obviously, our case would put tariffs on -- there could be a case where there's outside of our trade case, the government decided to put tariffs on core product that's imported in that would be supportive of us as well.
Maybe just a quick cleanup question on the CapEx that you shared today. So last year, for example, the maintenance CapEx was just below your $25 million to $30 million guidance. The guidance itself having previously been downgraded from 35 to 40. So for 2025, when you've announced $15 million to $20 million, can I confirm if this is only maintenance? And separately, if you could just help us walk through the year-over-year differences between...
We don't have any -- we had a turnaround last year. So that's where you had a bigger bump. And it is mostly maintenance CapEx, a very small amount of growth CapEx. So that's where it's coming...
Your next question comes from Robert Catellier with CIBC Capital Markets.
Just to follow up on the capital spending question. I'm curious if that $15 million to $20 million includes the annual turnaround at PGR.
This is Shawn, you're talking just annual maintenance at PGR or turnaround PGR.
Well, the maintenance, it usually takes facility offline, I think, in the second quarter for a brief period.
It will factor in annual maintenance, but there's no turnaround schedule for PGR this year. We obviously got through our last one in 2023. So the next major turnaround is not scheduled until 2027. So -- what we disclosed today will include, call it, our normal course, non-turnaround your annual maintenance spend.
Got it. And then I'm just curious on the progress you've made we've made since you started marketing the PGR volumes. And what trends you're seeing in the wholesale discounts obviously indicated that they're wider discounts on lower margins. But -- can you give us a sense of degree and how the markets evolved since you started marketing your own product? .
Yes, sure. I mean, obviously, when we had the offtake with Synovus, they were taking like 90% plus of the product. And so we didn't have to really worry too much about it. We knew that contract was coming up and we started discussions last year, and we've just been getting better and better. We've been expanding our customer base, finding the optimal spots where we have logistic advantages to market to -- we've recently won some mining RFPs that are supportive -- and we'll continue to optimize that.
Ultimately, there are some very big buyers with downstream retail networks that we are working on, and we're seeing some success there. So it's a work in progress, but -- we are moving the product and now trying to optimize our netbacks and where we can sell the product advantage versus what else is in the market.
Okay. And then what do you expect it's going to take you in terms of producer, to get producer activity to a level that justifies bringing the Ram River plant back fully online?
Yes. Look, I think if they can see sustained prices, call it, above 250. We still -- the forward curve is still pretty soft in the summer of '25. But I think with LNG Canada coming on, it sounds like they were energizing and starting to cool things that by the back half of the year, we should see a much better and more supportive gas environment out there.
Your next question comes from Patrick Kenny with National Bank Financial.
Just on the production levels on PGR. I know there was some normal optimization going on in Q4 there with winter operations. But maybe just if you could comment on how utilization rates have been trending year-to-date, especially following the expiry of your committed tolling agreement there? And then also if you can comment on any mitigation plan you might have in place if you do lose access to the pipeline? .
So the first one, yes, we did see a little bit lower utilization in Q4. There were some -- a little bit of just normal maintenance that we did as well, that was coinciding with an outage by upstream infrastructure that supplies us oil there. So that was the real reason why we saw it trend down. We expect to run those -- that refinery as sort of in that 90, low to mid-90s kind of utilization on a long-term go-forward. But that was the reason in Q4 for a little bit of a trend downwards. In relation to the pipeline, I got to be careful what I say. Obviously, we're in the middle of a regulatory hearing.
That is a commentary pipeline. It is regulated by the BCUC, our view is the application by Pembina around the abandonment is really just negotiating and positioning. They tried this -- they've tried this before in the past and made that same application. And obviously, as a common carrier, typically, one of the key things required to actually get in are allowed to abandon is consent of shippers. And obviously, we wouldn't provide that. So we think they're just blowing a bit of smoke there and we're working through the regulatory process and other commercial arrangements and -- we view that as a good long-term transportation alternative to provide crude at the PGR refinery.
Okay. And then just on the sale of the roadway at BRC. Can you maybe just provide a bit of an update on where you're at with your broader noncore asset sale program, what might be remaining or available throughout the course of 2025.
Yes. So thanks for the question, Pat. So as we stated in -- obviously, in 2023, they went through a large strategic review of assets. We've continued to execute on that optimization through a number of noncore asset sales. There are still probably about $100 million worth of assets that generate no to negative to low return in the portfolio that we were in various stages of discussions on.
Obviously, we need to get the right value for these, but we will continue to optimize the portfolio, and there are significant value in some of these noncore assets and -- we've got various discussions ongoing. Obviously, we can't comment more than that. But if everything went right, you could see $100 million of divestitures over the next 12 months. That would not impact cash flow and EBITDA at all or materially.
Okay. Got it. I appreciate that. And then would that, I guess, allow you to return to the normal covenant levels? Or perhaps would you have other credit ratio targets that you're hoping to hit by year-end?
Yes. It would obviously generate a significant amount of liquidity to put the business into much better spot. And yes, I think we would be comfortable with that level of deleveraging, obviously, subject to all of the normal risk factors that we face around the crack spreads and gas prices and those things. But in the current environment, it would be a very stable situation.
There are no further questions at this time. I will now turn the call over to Michael for closing remarks. .
Thanks, everyone, for joining the call. The team is available to address any outstanding items with the contact information at the bottom of today's press release. Thank you.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.