USD Partners LP (NYSE:USDP) Q3 2022 Earnings Conference Call November 2, 2022 11:00 AM ET
Company Participants
Jennifer Waller – Senior Director, Financial Reporting and Investor Relations
Dan Borgen – Chief Executive Officer
Adam Altsuler – Chief Financial Officer
Brad Sanders – Chief Commercial Officer
Conference Call Participants
Steve Ferazani – Sidoti
Jake Gomolinski – Ellington
Operator
Ladies and gentlemen, thank you for standing by and welcome to the USD Partners LP Third Quarter 2022 Results Conference Call. At this time, all participants have been placed in a listen-only mode. The floor will be open for your questions following the prepared remarks. [Operator Instructions].
It is now my pleasure to turn the call over to Jennifer Waller, Senior Director of Financial Reporting and Investor Relations for opening remarks. Please go ahead.
Jennifer Waller
Thank you Shyarly [ph]. Good morning, and thank you for joining us. Welcome to our third quarter 2022 earnings call. With me today are Dan Borgen, our Chief Executive Officer; Adam Altsuler, our Chief Financial Officer; Brad Sanders, our Chief Commercial Officer; Josh Ruple, our Chief Operating Officer; as well as several other members of our senior management team.
Yesterday, evening we issued a press release announcing results for the three and nine months ended September 30, 2022. If you would like a copy of the press release, you can find one on our website at usdpartners.com.
Before we proceed, please note that, the safe harbor disclosure statement, regarding forward-looking statements in last night’s press release applies to the statements of management on this call.
Also, please note that, information presented on today’s call speaks only as of today November 2, 2022. Any time-sensitive information provided may no longer be accurate, at the time of any webcast replay, or reading of the transcript.
Finally, today’s call will include discussion of non-GAAP financial measures. Please see last night’s press release for reconciliations to the most comparable GAAP financial measures.
And with that, I’ll turn the call over to Dan Borgen.
Dan Borgen
Thank you, Jennifer. Good morning, and thank you for joining us on the call today, and for your continued support of the partnership. Obviously, we are seeing a fair amount of volatility in the global crude markets. And as always, we are constantly updating our market point of view on where crude oil markets are today, but also where markets are headed in the future.
We do our best to rely on facts and observable market indicators. As we monitor the western Canadian macro, we continue to see future heavy crude oil production, exceeding the availability of existing egress alternatives. And we believe that the partnership strategically located assets will be well-positioned to offer long term solutions to address that imbalance.
We did have some contracts reach maturity in June of this year. But as Brad will discuss in greater detail later on the call, we’re fully engaged with our existing customers and potential new customers to renew, extend or replace those agreements.
We are highly competent and accompany market demand events that will drive highest value for our renew and extend contracts. As a reminder, we have historical experience with similar market conditions that lead to historical renewals existing or premium rates.
We believe that the Western Canadian crude oil markets will be in what we call rail parity when incentives support the use of rail egress solutions at some point in the first half of 2023, which should benefit our existing DRUbit by rail network, which of course includes the partnerships Hardisty Terminals.
In addition, we continue to have detailed discussions regarding our DRUbit by rail network with our existing DRUbit customer ConocoPhillips, as well as new customers to provide safer and economically beneficial Canadian crude transportation options.
During the third quarter our terminals performed safely and reliably and we are very pleased with our performance at both our sponsors DRU and Port Arthur Terminals. We’ve given out the performance and continue to exceed expectations at both facilities. We are delivering significant value to our DRUbit customers.
As always, we look forward to sharing future announcements with the market about the next phase of growth at the DRU and our USD Clean Fuels initiatives before the end of this year.
We continue to be confident that our assets are strategically located to benefit our customers, as certain market signals began to reveal the potential for increased demand for our services.
Next, Adam is going to give an update on the Partnership’s latest financial results and our liquidity position. Then we’ll jump back into the recent market and commercial developments.
Adam, please go ahead.
Adam Altsuler
Thank you, Dan. And thank you for joining us on the call this morning. Yesterday afternoon we issued our third quarter earnings release which included the details of our operating and financial results for the third quarter and we plan to issue our 10-Q with additional details after close of market today.
The Partnership reported a net loss of $69.4 million due primarily to a non cash impairment of the Partnership’s and tangible and long-lived assets associated with the Casper Terminal.
Net cash provided by operating activities of $13.5 million, adjusted EBITDA of $12.3 million and distributable cash flow of $9.6 million. As a brief reminder, because our acquisition of Hardisty South, which occurred in the second quarter of 2022, represented a business combination between entities under common control, the Partnership’s financial statements had been retrospectively recast to include the pre-acquisition results of the Hardisty South Terminal.
And now for the details from the quarter. The Partnership’s revenues for the third quarter of 2022 relative to the same quarter in 2021 were lower primarily due to lower revenues at the combined Hardisty Terminal due to a reduction in contracted capacity at both the Legacy Hardisty and Hardisty South terminals.
Revenues were also lowered to Hardisty Terminal due to an unfavorable variance and the Canadian exchange rate on the Partnership’s Canadian dollar denominated contracts during the third quarter of 2022 as compared to the third quarter of 2021.
Coupled with the deferral of revenues in the current quarter associated with the makeup right options, the Partnership ran into its customers with no similar occurrence in 2021. Revenue is also lower at the Stroud terminal due to the conclusion of the Partnership’s terminalling services with take-or-pay contracts with the sole customer effective July 1, 2022.
The partnership also had lower storage revenue generated at its Casper Terminal associated with the end of one of its customer contracts that occurred in September 2021. Partially offsetting these decreases was higher revenue at the Partnership’s West Colton Terminal resulting from the commencement of the renewable diesel contract in 2021.
The Partnership experienced higher operating costs during the third quarter of 2022 as compared to the third quarter of 2021, primarily attributable to the non-cash impairment of the intangible and long lived assets associated with the Casper Terminal recognized in the third quarter this year.
Partially offsetting the increases in operating costs already discussed, with a decrease in the Partnership’s as SG&A costs associated with the Hardisty South entities. Third quarter 2021 SG&A costs include service fees paid by Hardisty South to our sponsor, related to a services agreement that was in place with our sponsor prior to the Partnership’s acquisition of Hardisty South.
On the Partnership acquisition of Hardisty South, the services agreement between the acquired entities when the Partnership Sponsor was terminated, and a similar agreement was established between those entities and the Partnership. This results in the service fee income being allocated to the Partnership, and therefore offsetting the expense in Hardisty South for periods subsequent to the acquisition date of April 1 of this year.
Partnership also experienced lower pipeline expense, which is directly attributable to the associated decrease in the combined Hardisty Terminal revenues previously discussed, as compared to the third quarter of 2021. In addition, subcontracted rail service costs were lower due to decreased throughput at terminals.
Net income decreased to a net loss in the third quarter of this year as compared to the third quarter of 2021, primarily because of the operating factors already discussed, coupled with higher interest expense incurred during the third quarter of this year, resulting from higher interest rates and higher imbalance of debt outstanding during the quarter, partially offset by a decrease in commitment fees as compared to the third quarter of 2021.
Partially offsetting the decrease was a higher gain associated with the partnership interest rate derivatives recognized in the third quarter of 2022 that included the cash proceeds from the settlement of the partnerships interest rate derivatives that occurred in July of this year.
Net cash provided by operating activities for the quarter increased 53% relative to the third quarter of 2021. The decrease in the Partnership’s operating cash flows resulting from the conclusion of some of the partnerships terminalling agreements was offset by the previously mentioned cash settlement and the Partnership’s interest rate derivative that occurred in July of 2022.
Net cash provided by operating activities was also impacted by the general timing of receipts and payments of accounts receivable, accounts payable and deferred revenue balances. Adjusted EBITDA was slightly lower than the prior period while distributable cash flow decreased 11% for the current quarter relative to the third quarter of 2021.
The slight decrease in adjusted EBITDA and decrease in DCF was primarily a result of the factors already discussed. Additionally, DCF was impacted by higher cash paid for interest during the quarter partially offset by lower maintenance capital expenditures.
As of September 30, the Partnership had approximately $5 million of unrestricted cash and cash equivalents and undrawn borrowing capacity of $53 million on a $275 million senior secured credit facility, subject to the Partnerships continued compliance with financial covenants.
As of the end of the third quarter of 2022, the Partnership had borrowings of $222 million outstanding under its revolving credit facility. Partnership was in compliance with its financial covenants as of September 30 of this year. The Partnership acquisition of Hardisty South is treated as a material acquisition under the terms of its senior secured credit facility.
As a result, the available borrowings are limited to five times the Partnership’s 12 months trailing consolidated EBITDA through December 31 this year. At which point it will revert back to 4.5 times the Partnership’s 12 month trailing consolidated EBITDA.
As such, the borrowing capacity and available borrowings under the senior secured credit facility, including unrestricted cash and cash equivalents was approximately $58 million as of September 30.
Subsequent to the quarter end, on October 12, the Partnership settled its existing interest rate swap for proceeds of approximately $9 million. The Partnership plans to use the proceeds from this settlement to pay down outstanding debt on a senior secured credit facility and fund ongoing working capital needs.
Partnership simultaneously entered into a new interest rate swap that was made effective as of October 17. The new interest rate swap is a five-year contract with the same notional value that fixes the secured overnight financing rate, or SOFR to approximately 3.96% for the notional value of the swap agreement instead of the variable rate that the Partnership pays and the Partnership’s credit program.
Partnership senior secured credit facility expires on November 2, 2023. The Partnership is in active discussions with the administrative agent and other banks within the lending group, as well as other potential financing sources regarding the possible extension renewal or replacement of the senior secured credit facility, and any amendments or waivers that may become required prior to maturity.
On October 20, the Partnership declared a quarterly cash distribution of $12.35 per unit, or $49.4 per unit on an annualized basis, the same as the amount distributed in the prior quarter.
The distribution is payable on November 14 to unit holders of record at the close of business on November 2. Partnership’s board determined to keep the distribution unchanged from the prior quarter, and to evaluate the distribution on a quarterly basis going forward and will take into consideration updated commercial progress, including the Partnership’s ability to renew, extend or replace its customer agreements at the Hardisty and Stroud terminals, current market condition and management’s expectations regarding future performance.
As Dan mentioned, we’re extremely focused on extending or renewing our commercial agreements and our terminals, as well as our current growth initiatives at the DRU and USD Clean Fuels and we look forward to sharing more updates with you in the future.
With that, I would now like to turn the call back over to Dan.
Dan Borgen
Thanks, Adam. Now I ask Brad to give us a detailed update on the western Canada’s select market, recent market events and an update on our commercial activities. Brad?
Brad Sanders
Thank you, Dan. Let’s start with pricing at Hardisty. There are two critical drivers which determine price at Hardisty. First is what’s happening from a competing alternative in the Gulf Coast, ultimately, Hardisty heavy sour barrels are shipped to the Gulf Coast and have to compete with Gulf Coast alternatives.
And then secondly, we’ll get into the drivers that are unique to the Canadian macro. So starting with Gulf Coast drivers, we’ve talked about this in the past. The recent SPR releases which have been material have negatively impacted prices simply by increasing competing alternatives in the Gulf Coast.
So as these supplies are released in the Gulf Coast, then the heavy sour crude from Canada are burdened with competing with those alternatives. Fortunately, the SPR releases, at least as planned today will end at the end of the year, and we should see significant improvements on values at that point.
In addition to this supply event, there have been a couple other things that have driven values uniquely lower in the Gulf Coast. There’s been unaccounted for unplanned turnarounds both in the mid continent and the Gulf Coast here late in the year and both of those events have naturally increased demand, which has a negative impact on price as well.
Of course this demand, this refinery demand will return after the first of the year and get things back into balance. And then finally high net gas prices and high hydrogen prices both feedstocks that helped with barrel required with the upgrading of heavy sour crude are very, very high. And that is cause heavy sour crude globally to discount relative to sweet crude take into account the extra costs, the extra burden, upgrading heavy sour crude.
Finally, the critical key driver, the second critical key driver, of course, is the balances you need to candidate. So, and as Dan alluded to in his opening remarks, Canadian crude balances are in transition. So let’s take a step back and talk a little bit about that. As a reminder, Canadian supply today is greater than pre-COVID levels.
That’s significant, because compared to the U.S. which is currently still a million barrels a day, the low production levels prior to 2020 Canada has responded, Canadian producers have responded aggressively and supply is greater than pre-COVID levels, and estimated for the balance of this year and into 2023 to grow materially.
So we’re transitioning up in Canada to a macro story where supply will likely be greater than egress capabilities and that will drive prices to where incentives will return to move heavy sour by rail. As a check to that, we naturally look at that what our producing customers are providing in terms of guidance, in terms of production.
And we also look at what the current curves or what the forward market is telling us. And the forward market is nothing more than a curve that reflects producers and consumers, their ideas of what values will be in the future as a function of their ideas of what they think the macro story will be.
And naturally, if you look at that forward curve, you can see two things. You can see the front end of the curve improving as the SPR impact is removed. The negative impact is removed from the marketplace. And then you will see that starting in the second quarter of 2023 the curve on a forward basis show WCS prices at Hardisty discounting $18 to $20 a barrel relative to WTI.
That would indicate that the marketplace is assuming that balances later in 2023, starting in the second quarter of 2023, that there will be demand for crude by rail egress at that time. So there’s a lot of factual support related to this supply story. And there’s naturally a lot of factual support from a market standing, reflecting these changes that are occurring up in Canada.
As we think about what that means to our business and our assets, I want to remind our listeners about the industrial logic of both Hardisty and our Stroud asset. And when we talk about heavy sour production growing in Canada, then naturally most of that production is produced and gathered into Hardisty.
In addition, all the egress pipes effectively originated Hardisty and then finally, the USD rail asset is the only rail asset at Hardisty and it’s the only asset of such scale that provides an industry solution for Canadian producers. So naturally as the industry transitions to a supply greater than pipe egress capability and demand for rail takeaway grows, Hardisty is where that occurs and our asset is uniquely positioned to benefit from that.
As we talk about our network and specifically the Stroud. Stroud is located adjacent to the Cushing hub, which is the largest hub in the world for crude oil. That means it’s got more tanks and connectivity than any other hub related to crude support. It provides access to mid-continent and U.S. Gulf Coast refineries.
And as a reminder, the majority of WCS is refined in the U.S., is refined in the MID Continent. And then secondly, the pipelines that service the U.S. Gulf coast from Cushing, have access pipe capacity, and provide advantage, transportation costs, should you use the Cushing hub as your solution. So we think our two critical assets are uniquely positioned to benefit from this transition up in Canada that we think will occur first half of 2023.
Let’s talk a little bit about our DRU commercialization update. Naturally, the things I’ve just talked about would be a tailwind for our DRU commercialization efforts, but as a reminder, what the key drivers are, what they are most important to our customers is the cost competitiveness of the DRUbit by rail solution versus egress alternatives.
That’s driven primarily by the DRU and saving set that the value chain experiences also has to do with the critical railroad partnerships that we have that provide competitive rates to ensure the competitiveness of the solution. The assets, scalability is critical in the sense that it allows our customers to right size, their investment, which ultimately leads to a capital competitive advantage versus the egress alternative.
And then given the product quality, the EH&S environmental and ESG advantages are significant relative to the egress alternative as well. Finally, we have network value advantages given our Port Arthur pairing which provides custom blending alternatives, distribution, advantages to heavy sell refiners in the Gulf Coast, and access to export alternatives that are unique to Port Arthur.
So given these advantages, and again, we’re not sensitive to the macro story, because these advantages make the solution driven, DRUbit by rail solution advantage at all times relative to egress alternatives. We are in strong discussions with our existing and potentially new customers, very purpose discussions and hope to be able to announce something soon on our Phase 2 and maybe more growth supporting this egress solution.
Finally, I like to comment briefly on our Clean Fuels initiative. The opportunity set in this space is very broad. We are specifically focused on downstream biofuels destination terminals. An example of that would be our existing asset at West Colton in California where we are through putting not only renewable diesel, but the low CI ethanol into the California markets.
In addition, we’re focused on feedstock gathering treatment and terminalling opportunities as these refiners transition from traditional refining businesses to things like RD production, renewable diesel production and the infrastructure required to support that, to support bringing in feedstocks from things like vegetable oil are required. And so we’re in the business of supporting that and have very specific discussions, ongoing discussions with potential customers there.
And then finally, there are naturally unintended consequences to policy. One of those being the demand for veg [ph] oil driving crushing facilities and creating a byproduct with the crushing mill and we’re very focused on creating export options for those facilities, and refiners who need that feedstock.
Naturally critical to our success here, like and everything that we do is our partnering with the railroads. And we work closely with them and creating focus and priorities, where we’re collectively to decide and to follow our policy and incentives, drive our development opportunities. And today that includes California, Pac Northwest and minimally Canada. So we look forward to sharing with you successes we have in this space soon.
Dan with that, I’ll pass it back to you.
Dan Borgen
Thank you, Brad. And with that, we’ll open the call up for any additional questions.
Question-and-Answer Session
Operator
[Operator Instructions]. We’ll take our first question from Steve Ferazani with Sidoti.
Steve Ferazani
Morning, everyone. Appreciate all the color on the call. First question is a quick one, that the settlement of the interest rate swap post the end of the quarter. Was there a timing issue with that? Wasn’t it supposed to settle in third quarter if am I mistaken?
Adam Altsuler
Yes. Actually, there’s two. Steve, its Adam. There’s actually been two unwinding. We did one in Q2. And that’s settled. And then we also did one and actually sorry, we did one in Q3 and then we did one in Q4 after the quarter settled as well.
Steve Ferazani
So that’s another one. Okay.
Adam Altsuler
That’s exactly right. The one that we did in Q3 was in July, and that was about $7.7 million of proceeds. And that we use those cash proceeds to pay down debt. The one that we exercise after the end of Q3, which will be reflected in Q4 was for $9 million of proceeds. And those proceeds will be used to pay down debt as well.
Steve Ferazani
Okay, great. When I’m thinking about the distribution, I know that’s a board decision given that we wouldn’t expect to see substantial volume pickups in the next couple of quarters. How are you thinking about the distribution and cash usage, at least in the near term before we see a pickup?
Adam Altsuler
Sure. And we run through several scenarios and do a lot of analysis every quarter when we talked about this with the board. It’s going to really depend on market conditions, our expectations of the future growth of activity at Hardisty and Stroud and in our discussions around the DRU with that customer, which I’ll let Brad speak to you. But he mentioned that we’re very much engaged with that DRU customer. So it’ll be based on all of that information. And we’ll evaluate it with respect to Q4 as well.
Steve Ferazani
When I think about the essentially no volume through Stroud and Casper right now, are there costs associated to operating there? And how do you think about those two markets longer term?
Adam Altsuler
Sure. Yes. And we’ve got our CEO in the room, but I’ll go ahead and answer that. I mean, we do — we have a nomination process. We do kind of go through that as well. And we evaluate the costs associated with projected volumes. And we’ve tried to do the best we could to optimize that. With regard to Q3, I think we’ve done a reasonable job on optimizing that. So that’s probably reflected in the numbers today.
Dan Borgen
There are some costs of both assets to physically maintain capabilities. But to Adam’s point we’ve rationalized those costs. And they’re very small in both locations.
Brad Sanders
Yes. Steve, real quick, this Brad Sanders. As it relates to Casper in particular, we do have relationships with customers that are occupying or attempting to occupy all six tanks and we’ve run two trains this past month through the facility and our plan is to grow that to potentially four trains through the balance of the year.
Steve Ferazani
Okay. It’s helpful. Thank you. In terms of expecting to rebuild volume at Hardisty and certainly it makes sense that you’ll see more activity and more demand into the earlier part or at least later part of the first half of next year. But with Trans Mountain coming and that additional capacity from that expansion. Are you going to have customers seeking shorter term agreements rather than your typical three-year agreements? And how will you deal with that?
Dan Borgen
I think the elephant in the room is the development of TMX. And I think the question is, does it get done? Number one. And then number two, if it does get done. When does it get done? And then number three, what’s the cost of the project? And ultimately, that will lead to tariffs that potentially are uncompetitive relative to Gulf Coast alternatives. Right now, it’s been estimated that tariffs will triple what was originally planned and that only gets you to the West Coast. That doesn’t get you on a boat. And that doesn’t get that boat to where it needs to go. So there’s a lot of uncertainty as relates to the competing pipe alternative. We’ve always dealt with those.
So, we’ll see what the markets like when this supply comes on and incentive, say, we have to move by rail and where the leverage sits. But it mostly points out how critical DRU development is, as a competitive alternative, that sustainable no matter what TMX is doing, no matter what other pipes are doing, simply because of the cost and value advantages it creates. So we’re very purposeful about transitioning as much as possible, if not all of our activity to those longer term, sustainable solutions that drive longer term sustainable contracts with our customers.
Dan Borgen
Steve, as a follow up, Dan here, how are you? As we think about our DRU, just as a fact point, we’ve already moved over 22 million barrels through our DRU platform. And that’s proven the tenacity of the asset that’s on both ends, that’s proved the underlying support of it, the availability of it, the desire for the refining community to take it. So it’s, and be able to blend it to their spec. So it’s a proven system. And that’s why we have aggressive discussions with expanding that with, obviously, our key customers COP as well as others.
So as we’ve made no bones about it, our plan is to convert all of the — all of our Hardisty assets to a DRUbit format and be able to bring all of that over long term, which obviously takes the underlying rail assets of the partnership and extends it at similar levels.
Steve Ferazani
Appreciate the color. Thanks for your time.
Dan Borgen
Thanks Steve.
Operator
Thank you. We’ll take our next question from John [Indiscernible].
Unidentified Analyst
Good morning, gentlemen. Thank you for taking my question. Has to do with the Casper Terminal and the write-downs that you have taken there? And I’m just wondering, is there much remaining book value that’s left? What’s your percentage of the gross asset value going in have you written down? And second part of that is, are there any implications for your distribution given agreement with your lenders?
Adam Altsuler
Sure. Hey, it’s Adam Altsuler here. So with regard to Casper, we historically have tested for impairments to goodwill in July. We did that a couple years ago with Casper. We did, I think it was after Q1 of COVID and March 2020. We wrote down the goodwill associated with Casper. This in particular, this impairment was a result of projections not coming to fruition based on different market conditions. And as a result, we wrote down the intangible and long lived assets. So you’ll see that on the balance sheet with regard to comparable periods. But there is still value on the balance sheet associated with the PP& E and Casper. Keep in mind it’s a operating rail terminal with six tanks. So there’s significant PP&E and still quite a bit of asset value.
But with regard to percentage, I couldn’t tell you that the exact percentage, but to get a large percentage, a good majority of the value has been impaired. And then, with regard to distributions, we evaluate that every quarter. There is no agreement with our lenders with regard to the distributions. Right now, we’re in constant discussions with our lenders. And we’re very much engaged with them with regard to market conditions, and then what’s going on at the company right now. But it’s still up to the board’s discretion to whether or not we make distributions going forward.
Unidentified Analyst
Of course, but I think in the past, there was a time where Casper write-down necessitated a decrease in the distributions, is that not right?
Adam Altsuler
Yes. No, that’s actually incorrect. The impairment is a non-cash impairment. So it doesn’t have an impact on our available cash or distributable cash. So in our credit agreement right now, we don’t have any language that ties, non-cash impairments to our distribution policy. Simply based on the partnership agreement how we view available cash and then our concerns going forward — going kind of requirements for capital going forward.
Unidentified Analyst
Okay, great. Thanks.
Operator
Thank you. We’ll take our next question from Jake Gomolinski with Ellington.
Jake Gomolinski
Hey, good morning. Thanks for taking the question. I guess one question is just around recontracting. Why are you, I guess, where are you at on the contracting, because I think some of the language today was very, very similar on the last call. And I’m curious sort of how things are going on the recontracting front given differentials have gone from $12 over the time to the Hardisty South acquisition to nearly $30 today?
Brad Sanders
Thank you for the question. This is Brad Sanders. So, regarding your first point, the discussion appears to be similar to previous calls, it is, but it is based on mental models that are consistent as to when and why the marketplace will demand our assets. And it has to do simply with the macro story and when the Canadian supply reveals itself and when that Canadian supply is sufficient to be greater than the pipe egress. So we can’t predict that from a exact timing standpoint. That’s impossible to do. The marketplace is very fragmented and we can’t know all things being considered by producers, but directionally, we can deal with facts. We can deal with our customer dialog. We can deal with guidance, that is public information, and deal with smarter people than us who are in that industry as consultants, and see that the outcome is such that supply is growing in the eventual imbalance between supply and demand will occur. So that is happening. We just simply can’t predict when that’s going to happen precisely.
To your second point, the differentials have changed and what I tried to explain earlier and it’s a difficult subject, but the price, remember the Canadian heavy sour is produced, transported to the Gulf Coast and competes with Gulf Coast alternatives. So, the price of Canadian and the differential for Canadian heavy sour at origin is impacted by two things. One is the competing alternatives in the Gulf Coast, and that is what is currently driving the prices lower. And we reference the SPR releases specifically as probably the biggest driver for that, because that release added 180 million barrels of which the majority of it is Canadian sour over the past year into the Gulf Coast market that this heavy sour had to compete with. So that just brought down all values for WCS.
Once the Gulf Coast price goes down then you just adjust for the transportation cost into or up to Hardisty. So until the imbalance at Hardisty is as I described uniquely for Canada if supply is greater than egress only then will Canadian prices do the work to discount to ensure rail costs are in the money and demand for egress by rail occurs. And it’s a difficult subject. I apologize for that. And I apologize for the long winded answer, but happy may be offline to discuss it more at some point.
Dan Borgen
Just to further add, Dan here. Obviously, great question. The historically, as Brad said, the discounts in the Gulf on the delivered basis, historically has been about $2 for a WCS delivered barrel. Today, we’re seeing discounts because of the SPR release in the local market, Gulf market, we’re seeing anywhere from $10 to $15 discounts. So obviously, it has to compete with that. So if the gross spread between the two and what you see top line is call it 30. And there’s a $15 discount in the local market because of SPR release in that market of a heavy sour. Now you’re going to see the net differential of being 15. Right? It was 27, it’s 12. If it’s so, that’s what the rail competes with from a interpipe competes with, from a true net back model, as relates to the SPR release and the discounts that you get.
So like I said, it’s the net spread that matters. And as Brad said, it depends upon, first of all the supply, we’re seeing a portion growing on the pipelines, which is something that we always watch. And so as that happens, that simply means the pipes are full. And it’s got to seek alternative means. And this is where traditional DRUbit right, things that flow in pipe. Our DRUbit barrel is not affected by that. That’s why we’re converting everything to DRUbit and therefore not being subjected to these kinds of these whimsical political manipulation that’s in the marketplace today. But as we see the pipes full, we see demand growing, which we’re seeing today. And we expect to see further of that. And an announced stoppage of the excuse me SPR releases and just the opposite, the administration, the U.S. administration has talked about buying back barrels into that and to replace the SPR, then we’ve not factored that in. But if that occurs, then you’ll see kind of a whipsaw, where you get a premium, should expect a premium in that market not discount.
So all of those things strengthening are, as Brad called it, our mental model or macro model around why these renewal cycles in this what we call demand on event is going to — we feel pretty bullish about. Keep in mind, we’ve been through these cycles two times before on renewal. They’ve always followed the same trend. They’ve always followed the same models that we follow, and growing supply, not enough takeaway, and the blowout spreads and that we see today, we would be in full utilization, based on the facts, historic facts that we’ve seen, had it not been for the items that we’ve mentioned, the political. Wall Street Journal call that a political manipulation of strategic reserves for political gain. So we would — we don’t like any government involvement in free markets. We think the free market should figure it out on their own. And when that occurs, we would — we historically would have been full today. And obviously, that’s when we like to discuss renewal contracts when they come up. Would we have liked for that to be today? Absolutely we would have. But are we panicked by that? Not at all. And we believe that events coming and we’ve got customers at the table right now, knowing that that’s coming and aligning with us and discussions for renewal. Hope that adds some clarity and some color.
Jake Gomolinski
Got it. So you’re saying that the SPR is causing sour to traded at 15 and a local markets sour to be at a, call it $15 discount to sweet. And so you back that out of the $27 discount and you’re still at the $12 that we see on trains that we were in March?
Dan Borgen
Well done. That’s exactly.
Adam Altsuler
That’s exactly right.
Jake Gomolinski
Okay. But then you’re — I mean, just you mentioned that you would be at full utilization if not for the SPR release, but then if not for the SPR release, would we — okay, you think we would still be at like, if not for the SPR release where would we be at WCS. Would it still be at 27? I mean, wouldn’t that also then [Indiscernible] back and forth?
Adam Altsuler
Yes. That’s a great question. So, if I commented that — on the call that we rely on just looking at forward curves, which as I discussed is nothing more than producers and consumers transacting at what each thing value is on a go forward basis. If you look at starting in second quarter of 2023, after the SPR releases have gone away, and the inventory problems have fixed themselves, the marketplace is saying the differential at Hardisty it will be $18 to $20. And as Dan says, when replacement costs or when the global bounces become “normal” again, because SPR is now gone, then our expectation is that values in the Gulf Coast will be somewhere between $0 and $2 discounted not $15 to $20 discounted. And the $18 at — $18 to $20 at Hardisty versus the 0 to 2 at the U.S. Gulf Coast indicates a difference somewhere between $15 and $18, which the marketplace is effectively saying through their actions that we think we’re going to be a crude by rail parity starting in the second quarter of 2023.
Jake Gomolinski
Okay.
Adam Altsuler
So to your point, will the 27 stay? No. The marketplace is saying it will go to 18 to 20.
Jake Gomolinski
Okay.
Dan Borgen
We’ve seen it as high as we’ve seen it in the 30s before, uniquely, but on a conservative basis we’re looking at more of that 18 to 20 just because we can see it on the curves.
Jake Gomolinski
Right. Okay. And at 18 to 21 when you are saying, you’re saying Hardisty would be at full utilization. Is it just Hardisty or is there like where you seeing the whole company? I’m assuming that’s not Casper, Stroud or West Colton?
Dan Borgen
No, the way I would respond to that is if we’re at differentials that incent crude by rail egress options, then we would be the most advantaged asset to participate in that given our location and the design of our facility and our relationship with railroads. But CCR and Stroud, Casper and Stroud both benefit when we move into that cycle, because they uniquely — Casper uniquely is an off take option by rail and by truck. And Stroud is a catchment, a destination that sits in the biggest hub in the world. And we expect that to be advantage and participate when Hardisty is busy, Casper will be busy, and so will Stroud.
Jake Gomolinski
And then one question around the DRU sort of JV and the structure. I mean, I think, in one of the older decks, you had shown that in 2023 you anticipate a lot of is on page 12, a lot — some customers A, 1A, 2B, CDEF [ph] offer starting in 2023. And then if you look at I believe its page 25. I’m curious when your — some presumably those conversations are ongoing now in order to start up in 2023. How do you manage those commercial negotiations given the JV, the Hardisty DRU JV is partially owned by USPG, partially owned by Gibson. The loading terminal of Hardisty is owned by USDP and the unloading facilities at Port Arthur is owned by USPG. From a customer’s perspective, it’s presumably one tariff. How do you split up that tariff across those three things, those three parts of the value chain particularly given different stakeholders, or shareholders or unit holders whatever limited partners in between USPG and USDP.
Dan Borgen
I’ll take a crack at this and then I’ll probably pass it to Brad, but appreciate you diving into the details. I mean when you think about it, I would say, we look at those kind of deals holistically, to make sure the customer is getting the net back — the money for them. We work with railroads on that as well. But there are different groups that support each rate I would say and the volume and the terms. With regard to the partnership, I can speak to the fact that we are always mindful of making sure that it’s fair, and that it’s treated as a kind of a third party transaction. We have a complex committee in place and engaged to do those kinds of things. But with regard to getting to the actual rate at the commercial discussion, and I think it’s really market based
Brad Sanders
Competitive, we have to be sustainable with competing alternatives. So it’s 100% market based regardless of how things are structured.
Dan Borgen
So, Dan, here, let me try. First of all, our stated intent is to convert all of the partnerships underlying assets at Hardisty to a long term DRUbit. And that may include Stroud as well to convert it to a DRUbit hub as well. So that’s our stated intent for all the reasons that we know, right? It’s not haz, its nonflammable. It reduces the carbon intensity by over 30%. It’s just the right thing to do. It gives the refiner and the producer all of what they want. So it’s the real kind of industrial solution here that we like. So, given that both Gibson and USD are committed to doing that.
So there is competitive pressure, if you will, on Dilbit to convert to DRUbit because that’s where we’re heading and that’s where we’re driving. That takes us out of the pipeline, basically comparisons that we find today. Whether TMX gets built whether or not it doesn’t matter, because it’s more sustainable and competitive on a full net back basis. So as we then discuss the commercial terms around that, as we previously did, with the underlying assets on our existing DRUbit deal, it was a long term taking three to five year agreements and converting them to 10 plus year agreements was a positive net back to the partnership for that.
And our commitment is that it would be a, continue to be a positive net back for the partnership for any of the renewals that we do, or the conversion of Dilbit to DRUbit. And so, as we discuss and negotiate with Dilbit customers, we’re open and honest with them, look, you may not have Dilbit capacity remaining at either Hardisty or Stroud, as it relates to, because we’re going to convert that into DRUbit and longer term and more sustainable and more profitable business for both the partnership and USCG and Gibson for that matter. So we’re all on the same page about that. And so, we’d like that if you have a competitive tension. So every time I met Dilbit customer, says another way, every time a Dilbit customer comes to the table, we first look, can we support our DRUbit — continue to support our DRUbit program for the benefit of the Partnership, elongated contracts, and more sustainable revenue for the Partnership. We always weigh that into the commercial discussions, but it’s been — today, it’s been a positive development for the Partnership in terms of both term and both on its term and the commercial viability of that of the commercial agreements. Did that makes sense?
Jake Gomolinski
Totally. I was just trying to better understand that just for purely illustrative purposes for the total dollar per barrel tariff to you for the whole value chain was $15. How do you split that between the DRU facility, the Hardisty Terminal, the Port Arthur Terminal and like I know you mentioned sort of market, but if you — when we look at page 19 of the deck, like there’s no, one doesn’t work without the other, right? There’s no — the DRU facility can’t access it without going through the Hardisty Terminal. And so, like in theory, the Hardisty Terminal has a monopoly on the DRU facility. So just, I don’t know what market means in that sort of scenario. And so how that 15, again, illustrated number would be split across those three legs of the value chain?
Dan Borgen
Yes, it’s great. Again, great question. And obviously, that’s always the challenge between the sponsor and the partnership, right, but our fiduciary responsibility to protect the partnership and to make sure that it’s a positive commercial impact on the partnership, just as we’ve done with the COP agreement. It was a net positive to that. Does it all have to come into consideration and be a fair and balanced? Absolutely. Do we then present that to the conflicts committee who looks at that independently and weighs in on that? That’s kind of the check and balance that we try to use there to make sure that it’s sustainable commercially for both sides. Can I give you more detail around that? I probably can’t. But just as we’ve done historically, it’s been a positive dollar base commercial agreement and term, obviously with the partnerships assets.
Adam Altsuler
And I would say respectfully, that’s our strength as a developer, is that we have strategic alignment with railroads, strategic alignment with terminalling companies where it’s appropriate to support an all in solution. And ultimately, it’s got to be competitive relative to the competing alternative and the story. And it’s got to meet our return thresholds for each one of those pieces of the puzzle and the story.
Dan Borgen
Jake, you’ve got another question.
Jake Gomolinski
Yes. The last question was just, if you had talked about sort of, I think it was 14 to 18 or something in that context of 2023 EBITDA for Hardisty South. I just was curious what your latest thoughts were there. And sort of maybe what — I don’t know if it’s even makes any sense to say what is sort of EBITDA today on a run rate basis given some of the contract expirations? I don’t know if that was baked in earlier this year or not, but what is sort of your — where is that headed right now? Do you have any thoughts around [Indiscernible]?
Adam Altsuler
Jake, this is Adam. It’s a good question. So that, I think that was guidance that we gave when we did the drop down for Hardisty South. I think we haven’t updated that guidance. And I would say considering its 2023 guidance, there’s a lot of factors that have changed, since we issued that with regard to Ukraine, SPR, market volatility around crude oil and discounts in the Gulf. So I’d say, we haven’t given updated guidance on that. I would say, it’s quite fair to say we’ve come off that right now. And that we still expect increased utilization at Hardisty and Hardisty South and the DRU and Stroud around blending opportunities in the first half of next year. So we still are optimistic about cash flow in 2023. But I’d say we’ve probably come off that guidance.
Jake Gomolinski
But why would you come off the guidance if this is only gotten wider even taking into account the [Indiscernible].
Adam Altsuler
Yes. Totally understand what you’re asking. And I totally agree with you. And actually, we do obviously a ton of work around those things. Just timing, timing, when the contracts will get signed.
Jake Gomolinski
Okay, all right. Cool. Thank you very much. Appreciate all the colors.
Dan Borgen
Appreciate. Great questions. Thanks.
Operator
Thank you. We’ll take our next question from Greg [Indiscernible] with Private Investor.
Dan Borgen
Hi, Greg.
Unidentified Analyst
Hey, how you’re doing? Casper, is that some of the better hands that mess up the deal with?
Dan Borgen
Greg. Great question, Greg. Would we consider Casper to be a key component of our transition and growth? Like, I always like to say we’re transitioning from black to brown to base to green. Now, all of that said, it’s got to be long term investment grade counterparties all the things that that we discussed on this call, which was the cornerstone of what’s made it successful through downturns and all of that in the economy. As relates to Casper, would we entertain? Would we look at options? Absolutely, we would. And is it strategic to us in our future growth, as I just mentioned? It is not the most strategic asset that we have for our future growth. Given that, though, we will obviously look to optimize that and we currently have trains running out of there today, and growing demand for that asset. So we liked the market demand model that’s happening. We would be open and look at if it could be in better hands to third parties. Have we had some interest in that? We have and are there ongoing discussions around that? There are. But it would be something that would be, that obviously we weigh that against the value for the partnership as an ongoing asset as well.
Adam Altsuler
Yes. And just as a comment on that, we’re constantly in discussions with customers, existing customers and new customers with regard to commercial developments and potential other alternatives as well.
Unidentified Analyst
This has to do with a tank question. When your limited partners get their K1, you’ve taken a write down of $16 million. I don’t think I was a partner. The last time you took a write down on that. But is that something that flows through? Is the — I mean it’s the reduction of capital I would think that. Do you know how that works?
Adam Altsuler
Yes. It’s different. I mean, it’s different for every unit holder has a different basis. But I would say generally speaking, there are GAAP books and their tax books. And so I have to dig into that a little bit more and then probably get back to you. But it wouldn’t be dollar for dollar obviously, because they’re just different sets of books. But probably and I would imagine it’s probably a positive for unit holders, but I can’t issue tax advice on this call. So I’d have to look into that.
Unidentified Analyst
Now. Let me just ask something that has been taken in my calls, Hardisty South deal. For several years, you’ve always talked about dropping down assets, the general partner dropping down assets that have been derisk. And I don’t know if your board is listening to this call or not, but my impression is Hardisty South was not derisked and your limited partners have taken on $75 million of debt. And there’s been shares that have been granted to the general partner for this to buy this asset. But this assets more risky today than it was in July, or whenever you did it. Could you explain why Hardisty South was a great acquisition for the limited partners at the time and why you didn’t wait until it was derisked?
Dan Borgen
Yes. It’s great question and a great comment. Obviously, Dan here. The intent of the drop down was to try to, one, further simplify our growth for the DRUbit business. Right. So as we expand the DRUbit, the underlying assets with the contracts that we had in place, the partnership would have difficulty supporting the expansion of the DRUbit business to do that. So they needed the underlying support. They needed the underlying rail to do that. We had had several questions from investors about, can we simplify that, can we shift that over to where the partnership can have more of that asset base to support the DRUbit model until obviously, we can at a time in the future start to look to transfer some of the DRUbit business over into the partnership. With the simplest thing be to have the DRUbit business, and all of that under one house? Absolutely it would.
Are we trying to get to that point? Absolutely, we are. So as we looked at transferring Hardisty South into the partnership with sustainable customers that we had, and that we believe will renew in the all the market demand reasons that we said that the partnership will be happy that they have those assets. And again, we’ve tried to always at USD make mid to long term strategic decisions and not be kind of blown by the shorter term wins, given that we’re doing 10 plus year contracts with our commercial customers. So, as we look at that, I mean, I get it. I get the question, and I get the concern. But that was what the driver was of why we felt like it made sense to move that over, have the partnership be able to benefit from the longer term commitment that we’re getting from our DRUbit and as a previous question was, you can’t do one without the other.
So we wanted to put that benefit over to the partnership, which we hope to be able to share some very positive news around that in a shorter term. So hopefully that gives you some color on it. Did we anticipate that there would be continued SPR releases and all of that when we did all of that early in the year? No. Did we — so the impact of that is obviously concerning, and it’s frustrating. But as we’ve said, we do believe that the market demand will come back on and we totally agree with kind of the concern.
Unidentified Analyst
Okay, thanks a lot.
Dan Borgen
You bet.
Unidentified Analyst
Hopefully, we’ll have some good news following this year.
Dan Borgen
You bet. Thank you. Thanks for the questions. Thanks for being ambassador. Any further questions?
Operator
At this time, we have no further questions in queue. I would like to turn the call back to Dan Borgen for any additional or closing remarks.
Dan Borgen
Alright, so we’ve had really great robust questions and really appreciate that. And obviously, thanks so much for everybody being on the call and the support. Obviously, as we say, to just wrap it up, and I’ll just be a bit redundant here. We believe we’re coming into a demand on moment, just as we have as a reminder, as we have before, as a reminder, we’ve been through these renewal cycles before. We generally haven’t missed much on timing, maybe 30 to 60 days, something like that.
When this demand moments come it comes immediately in terms of the phone ringing off the hook literally for capacity that the customers need. Simply because the spreads are in, market demand is on and that’s obviously when we prefer to negotiate and renew mid to long term agreements. Historically, we’ve had customers come in say, hey, look, would you take a discount today to renew? And we’ve looked at the market and made a strategic decision to say, no, we won’t do that, because it’s not the best benefit to the partnership. We will renew that when the market demand is on.
Those facts are aligning similarly. We’ve been through that to two previous cycles. And we have always renewed an extended at or at premiums for at those market demands. All of the facts that we have shared today support that that is coming. Would we have been in that position today? Earlier this year, we absolutely would have been. Had we not had some of the I’ll say the manipulative things that have occurred in the market. So I want us all to remind that, and that’s what keeps us focused on our business, obviously, we’ve got very good in depth discussions going on with customers. Remember, our customers have railcars that are sitting that want to move.
Our customers have product that needs to move, growth initiatives from them, look at what’s happening in Canada, today, we have the bigger ones getting bigger for the most part, consolidating, so every new barrel growth are going to take some synergistic benefits, obviously, of combining those activities, but they’re doing that because they have a growth model and plan. They are going to grow. Every new bar, that they bring on creates a better net back for them, because it absorbs more of the fixed costs. So these are very focused large scale producers in the market that are our customers. And so, their strategic, their long term, these are non declining assets, if you will, producing assets. These are sustainable assets that as they bring them on, they produce kind of flatline till they bring another train of equipment on and another expansion.
So that’s what we like about Canada from a long term barrel perspective versus a shale barrel, who you have to almost replace yourself almost annually there. And obviously, we’re seeing some of that occur, and some of the winds and the headwinds that are blowing against some of the shale production and West Texas production, whereas Canada continues to be a growth and there’s aligned growth and therefore continued development of reserves in that market. Again, our DRUbit business I think it’s proven its sustainability in the market. It’s with over 22 million barrels moved, you wouldn’t have customers like we have, looking at that strategic alternative, to better control their growth, and where their production is going to head and why they’re going to do it.
Are they incentivize a low carbon net back? Absolutely. Why? Because Canada’s pushing for more of a zero tolerance around carbonization in that market. Does this positive benefit to that? Yes. Does the — we just had an independent third party come back and say the condensate return that we provide is the lowest condensate from a carbon intensity standpoint back in the market? Does that play well for the customers in that market that are needing to reduce their carbon intensity? It absolutely does. So is it the right thing from an industrial solution? Not only do we say it, but our customers say it by their commitments and what they’re doing from a political standpoint, from a government standpoint, we’re seeing great support for that.
Not only and I’ll paraphrase it, but I highly place a politician in the local market there said not only does it give us DRUbit network, give us new egress, but it’s developed a new market for our product. So we like where we’re headed. We’d like the market demand that’s coming. We liked the demand for the DRUbit barrel. And we look forward to sharing more about that, and delivering on that in the near term. So we appreciate, obviously, all of our investors we appreciate the support, and we’ll continue to do our jobs to create the best net back that we can for everyone. Thank you.
Operator
That does conclude today’s call. We thank you for your participation. You may disconnect at anytime.
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