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. If you would like to ask a question at that time, please press star one. If at any point your question has been answered, you may remove yourself from the queue by pressing the pound key. When asking a question, we ask that you please pick up your handset to allow optimal sound quality. Lastly, if you should require operator assistance, please press star zero. 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.
Thank you, Shelby. 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, Joshua 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 30th, 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 2nd, 2022.
Any time-sensitive information 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. With that, I'll turn the call over to 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's 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 are fully engaged with our existing customers and potential new customers to renew, extend, or replace those agreements. We are highly confident in the coming 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 led to historical renewals at 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 partnership's Hardisty Terminal.
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 the 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 customer. 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 begin 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. We'll jump back into the recent market and commercial developments. Adam, please go ahead.
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 intangible 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 have been retrospectively recast to include the pre-acquisition results of the Hardisty South Terminal. 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 lower at the Hardisty Terminal due to an unfavorable variance in 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 make-up rate options, the partnership granted to its customers with no similar occurrence in 2021. Revenue was also lower at the Stroud Terminal due to the conclusion of the partnership's terminaling services contracts with the sole customer effective July 1st, 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 of this year. Partially offsetting the increases in operating costs already discussed was a decrease in the partnership's 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. Upon the partnership's acquisition of Hardisty South, the services agreement between the acquired entities with the partnership's sponsor was terminated and a similar agreement was established between those entities and the partnership.
This results in a 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 1st 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 the 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 a 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's interest rate derivatives recognized in the third quarter of 2022 that included the cash proceeds from the settlement of the partnership's interest rate derivative 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 partnership's terminaling agreements was offset by the previously mentioned cash settlement of 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 the 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 30th, the partnership had approximately $5 million of unrestricted cash and cash equivalents, an undrawn borrowing capacity of $53 million on its $275 million senior secured credit facility, s ubject to the partnership's 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. The partnership was in compliance with its financial covenants as of September 30th of this year. The partnership's 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 5x the partnership's 12-month trailing Consolidated EBITDA through December 31st of this year, at which point it will revert back to 4.5x 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 30th. Subsequent to the quarter end, on October 12th, 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 its senior secured credit facility and fund ongoing working capital needs. The partnership simultaneously entered into a new interest rate swap that was made effective as of October 17th.
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 under the partnership's credit agreement. The partnership's senior secured credit facility expires on November 2nd, 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 20th, the partnership declared a quarterly cash distribution of $0.1235 per unit or $0.494 per unit on an annualized basis, the same as the amount distributed in the prior quarter. The distribution is payable on November 14th to unit holders of record at the close of business on November 2nd. 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 are extremely focused on extending or renewing our commercial agreements at 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 like now, like, to turn the call back over to Dan.
Thanks, Adam. Now I'll ask Brad to give us a detailed update on the Western Canadian Select market, recent market events, and an update on our commercial activities. Brad?
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. Secondly, we'll get into the drivers that are unique to the Canadian macro. 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. As these supplies are released in the Gulf Coast, then the heavy sour crudes 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. Both of those events have naturally decreased 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.
Then finally, high natural gas prices and high hydrogen prices, both feedstocks that help with that are required with the upgrading of heavy sour crude are very, very high. That has caused heavy sour crudes globally to discount relative to sweet crudes to take into account the extra cost, the extra burden of upgrading heavy sour crudes. Finally, the critical key driver, the second critical key driver, of course, is the balances unique to Canada itself. As Dan alluded to in his opening remarks, Canadian crude balances are in transition. 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 1 MMbpd below production levels prior to 2020, Canada has responded. Canadian producers have responded aggressively, and supply is currently greater than pre-COVID levels and estimated for the balance of this year and into 2023 to grow materially. 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 what our producing customers are providing in terms of guidance, in terms of production. We also look at what the current curves or what the forward market is telling us.
The forward market is nothing more than a curve that reflects producers and co-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. 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. Then you will see that starting in the second quarter of 2023, the curve on a forward basis shows WCS prices at Hardisty discounting $18-$20 a bbl relative to WTI.
That would indicate that the marketplace is assuming balances later in 2023, starting in second quarter of 2023, that there will be demand for crude by rail egress at that time. There's a lot of factual support related to this supply story, and there's naturally a lot of factual support from a market standpoint reflecting these changes that are occurring up in Canada. As we think about what that means to our business and our assets, I wanna remind our listeners about the industrial logic of both Hardisty and our Stroud asset. 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 originate at Hardisty.
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. 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 to 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 storage. It provides access to Midcontinent and U.S. Gulf Coast refineries.
As a reminder, the majority of WCS that is refined in the U.S. is refined in the Midcontinent. Secondly, the pipelines that service the U.S. Gulf Coast from Cushing have excess pipe capacity and provide advantaged transportation costs should you use the Cushing Hub as your solution. 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 just talked about would be a tailwind for our DRU commercialization efforts. As a reminder, what the key drivers are, what 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 diluent savings that the value chain experiences. It also has to do with the critical railroad partnerships that we have that provide competitive rates to ensure the competitiveness of the solution. The asset's 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. 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 sour refiners in the Gulf Coast, and access to export alternatives that are unique to Port Arthur.
Given these advantages, and again, we're not sensitive to the macro story because these advantages make the solution, the DRUbit by Rail solution advantageous at all times relative to egress alternatives. We are in strong discussions with our existing and potentially new customers, very purposeful discussions and hope to be able to announce something soon on our phase two and maybe more growth supporting this egress solution. Finally, I'd like to comment briefly on our clean fuels initiatives. 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 throughputting not only renewable diesel, but the lowest CI ethanol into the California markets.
In addition, we're focused on feedstock gathering, treatment, and terminaling 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 veg oil are required. We're in the business of supporting that and have very specific discussions, ongoing discussions with potential customers there. Finally, there are naturally unintended consequences to policy. One of those being the demand for veg oil, driving crushing facilities and creating a by-product with the crushing meal. We're very focused on creating export options for those facilities and refiners who need that feedstock.
Naturally critical to our success here, like in everything that we do, is our partnering with the railroads, and we work closely with them in creating focus and priorities, where we're collectively to decide and to follow where policy and incentives drive our development and opportunities. Today, that includes California, Pacific Northwest, and mainly Canada. We look forward to sharing with you successes we have in this space soon. Dan, with that, I'll pass it back to you.
Thank you, Brad. With that, we'll open the call up for any additional questions.
At this time, if you would like to ask a question, please press the star and one on your touch tone phone. You may remove yourself from the queue at any time by pressing star two. Once again, that is star and one to ask a question. We'll take our first question from Steve Ferazani with Sidoti.
Morning, everyone. Appreciate all the color on the call. First question is just a quick one. The settlement of the interest rate swap after the end of the quarter, was there a timing issue with that? Wasn't that supposed to settle in the third quarter, or am I mistaken?
Yeah. Actually, there's two. Hey, Steve, it's Adam.
Yeah.
There's actually been two unwindings. We did one in Q 2 and that settled. Actually, sorry, we did one in Q3, and then we did one in Q4 after the quarter settled as well.
That's another $ 9 million. Okay.
That's exactly right. The one that we did in Q3 was in July, and that was about $7.7 million of proceeds, and we used those cash proceeds to pay down debt. The one that we exercised 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.
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?
Sure. We run through several scenarios and do a lot of analysis every quarter when we talk about this with the board. It's gonna really depend on market conditions, our expectations of the future growth of activity at Hardisty and Stroud, and our discussions around the DRU with that customer, which I'll let Brad speak to. He mentioned that, you know, we're very much engaged with that DRU customer. It'll be based on all of that information, and we'll evaluate it with respect to Q4 as well.
When I think about essentially no volume through Stroud and Casper right now, are there costs associated to operating there? How do you think about those two markets longer term?
Sure. Yeah, we've got our COO in the room, but I'll go ahead and answer that. I mean, we do have a nomination process. We do kinda go through that as well, and we evaluate the costs associated with projected volumes, and we try to do the best we could to optimize that. With regard to Q3, I think we've done a reasonable job on optimizing that. That's probably reflected in the numbers today.
There are some costs at both assets to physically maintain capabilities. To Adam's point, we've rationalized those costs, and they're very small at both locations. Steve, this is Brad Sanders.
Go ahead. Yeah.
Yes, Steve, real quick, this is 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.
Okay. That'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?
Well, I think the elephant in the room is the development of TMX. I think the question is, does it get done? Number one. Then number two, if it does get done, when does it get done? Then number three, what's the cost of the project? 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. There's a lot of uncertainty as it relates to the competing pipeline alternative. We've always dealt with those. We'll see what the market's like when this supply comes on and incentives say we have to move by rail and where the leverage sits.
Mostly points out how critical our DRU development is. As a competitive alternative that's sustainable no matter what TMX is doing, no matter what other pipes are doing, simply because of the cost and value advantages it creates. 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.
You know, Steve, as a follow-up, Dan here. How are you? The you know, as we think about our DRU, just as a fact point, we've already moved over 22 million bbl through our DRU platform. And you know, that's proven the tenacity of the asset that's on both ends. That's proved the underlying support of it, the reliability 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 customer at COP as well as others. And we've made no bones about it.
Our plan is to convert all of our Hardisty assets to a DRUbit format and be able to bring all of that over long term, which obviously, you know, takes the underlying rail assets of the partnership and extends it, you know, at similar levels, so.
Yep. Fair enough. All right. Appreciate the color, everyone. Thanks for your time.
Thank you.
Thanks.
Thank you. We'll take our next question from Jon Leidecker with Burch Partners.
Good morning, gentlemen, and thank you for taking my question. It has to do with the Casper terminal and the write-downs that you have taken there. I'm just wondering, is there much remaining book value that's left, you know, or w hat percentage of the gross asset value going in have you written down? Second part of that, are there any implications for your distribution given agreements with your lenders?
Sure. Hey, it's Adam Altsuler here. With regard to Casper, we historically have tested for impairments to goodwill in July. We did that a couple years ago with Casper. I think it was after Q1 of COVID in March of 2020. We wrote down the goodwill associated with Casper. This, in particular, impairment was a result of projections not coming to fruition based on different market conditions. As a result, we wrote down the intangible and long-lived assets. 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 at Casper. Keep in mind, it's an operating rail terminal with six tanks.
There's significant PP&E and you know, still quite a bit of asset value. With regard to percentage, I couldn't tell you the exact percentage, but a good, a large percentage, a good majority of the value has been impaired. With regard to distributions, you know, 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 what's going on at the company right now. It's still up to the board's discretion to whether or not we make distributions going forward.
Of course. I think in the past, there was a time where a Casper write-down necessitated a decrease in the distributions. Is that not right?
Yeah. No, that's actually incorrect. It's the impairment is a non-cash impairment, so it doesn't have an impact on our available cash or distributable cash. 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 going concerns going forth, our kind of requirements for capital going forward.
Okay, great. Thanks.
Thank you. We'll take our next question from Jake Gomolinski with Ellington.
Hey, good morning. Hey, morning. Thanks for taking the question. I guess one question is just around recontracting. Why are you, I guess, where are you at on recontracting? 'Cause I think some of the language today was very, very similar to on the last call. I'm curious sort of how things are going on the recontracting front, given differentials have gone from $12 at the time of the Hardisty South acquisition to nearly $30 today.
Thank you for the question. This is Brad Sanders. Regarding your first point that 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. 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. We can't predict that from an exact timing standpoint. That's impossible to do. The marketplace is very fragmented, and we can't know all things being considered by producers.
Directionally, we can deal with facts, we can deal with our customer dialogue, 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 and the eventual imbalance between supply and demand will occur. That is happening. We just simply can't predict when that's going to happen precisely. To your second point, the differentials have changed. 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. The price of Canadian, 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. We reference the SPR releases specifically as probably the biggest driver for that, because that release added 180 million bbl, 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. 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. Until the imbalance at Hardisty is, as I described uniquely for Canada, 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.
It's a difficult subject. I apologize for that, and I apologize for the long-winded answer, but happy maybe offline to discuss it more at some point.
Yeah, just to further add, Dan here. Obviously, great question. You know, historically, as Brad said, the discounts in the Gulf on a 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- $15 discounts. Obviously it has to compete with that. 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 gonna see the net differential of being $15, right? If it's $27, it's $12.
That's what the rail competes with from a and/or pipe competes with from a true net back model as it relates to the SPR release and the discounts that you get. You know, like I say, it's always the net spread that matters. As Brad said, it depends upon, first of all, the supply. We're seeing apportionment growing on the pipelines, which is something that we always watch. As that happens, that simply means the pipes are full, and it's got to seek alternative means. This is for traditional dilbit, right? Things that flow in pipe. Our DRUbit barrel is not affected by that.
That's why we're converting everything to our DRUbit and therefore not being subject to these kind of you know, 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 you know, an announced stoppage of the 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. 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.
All of those things strengthening, you know, our, as Brad called it, our mental model or our macro model around why these renewal cycles, in this what we call demand on event is gonna, 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 model that we follow and, you know, growing supply, not enough takeaway, and the blowout spreads that we see today.
We would be in full utilization based upon the facts, historic facts that we've seen, had it not been for the items that we've mentioned, the political, you know, Wall Street Journal called it a political manipulation of strategic reserves for political gain. You know, we don't like any government involvement in free markets. We think the free market should figure it out on their own. When that occurs, we historically would have been full today. 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. Are we panicked by that? Not at all. We believe that event's coming. We've got customers at the table right now knowing that that's coming and aligning with us in discussions for renewal. Hope that adds some clarity as to color.
Got it. You're saying that the SPR is causing sour to trade at a $15 in a local market, sour to be at a, call it $15 discount to sweet. You back that out of the $27 discount, and you're still at the $12 difference that we see on screens or that you had, that we were in March.
Yes. Well, well done. That's exactly it.
That's exactly right.
Okay. I mean, just you mentioned that you would be at full utilization if not for the SPR release. If not for the SPR release, would we be at full utilization? You think we would still be at full utilization. Like, if not for the SPR release, where would we be at on a WCS diff? Would it still be at $27? I mean, wouldn't that also then send the WCS diff back to $12?
That's a great question. 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 thinks the 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 will be $18-$20. As Dan says, when replacement costs or when the global balances become "normal" again because SPR is now gone, then our expectation is that values in the Gulf Coast will be somewhere between $0-$2 discounted, not $15-$20 discounted.
The $18-$20 at Hardisty versus the $0-$2 at the U.S. Gulf Coast indicates a difference somewhere between $15-$18, which the marketplace is effectively saying through their actions that we think we're gonna be at crude by rail parity starting in the second quarter of 2023. To your point, will the $27 stay? No. The marketplace is saying it will go to $18-$20.
Okay.
Now we've seen, you know, we've seen it as high as, you know, we've seen it in the $30s before, uniquely. You know, on a conservative basis, we're looking at, you know, more of that $18-$20 just because we can see it on the curves.
Right. Okay. That $18-$20, when you're saying Hardisty would be at full utilization, is it just Hardisty or is there like, or were you saying the whole company?
Yeah. What I—
I'm assuming that's not Casper, Stroud, or West Colton.
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 our design of our facility and our relationship with the railroads. Casper and Stroud both benefit when we move into that cycle because Casper uniquely is an offtake option by rail and by truck, and Stroud is a catcher's mitt, a destination that sits in the biggest hub in the world, and we expect that to be advantaged and participate. When Hardisty's busy, Casper will be busy, and so will Stroud.
Okay. One question around the DRU sort of JV and the structure. I mean, I think in one of the older decks, you had sort of shown that in 2023 you would anticipate a lot of, I think it's on page 12, so a lot of some customers, A1, A2, B, C, D, E, F, all sort of starting in 2023. If we look at, I believe it's page 25, I'm curious when you're, you know, so 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 USDG, partially owned by Gibson.
The loading terminal at Hardisty is owned by USDP, and the unloading facility at Port Arthur is owned by USDG. From the customer's perspective, it's presumably one tariff. How do you split out that tariff across those three things, those three parts of the value chain, particularly given you have different stakeholders or shareholders or unitholders, whatever, limited partners in between USDG and USDP?
I'll take a crack at this, and then I'll probably pass it to Brad. You know, appreciate you diving into the details. I mean, you know, 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 there, you know, that's in the money for them. We work with railroads on that as well. There are different groups that support each, you know, rate, I would say, and the volume and the terms. With regard to the partnership, I can speak to the fact that, you know, 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 conflicts committee in place and engaged to do those kind of things. With regard to getting to the actual rate, that's a commercial discussion, and I think it's really based on—
It's market-based.
Yeah, it's market-based.
Competitive. We have to be sustainable with competing alternatives, so it's 100% market-based, regardless of how things are structured.
Dan here. Let me try. First of all, our stated intent is to convert all of the, I'll call the partnership's underlying assets at Hardisty to a long-term DRUbit. That may include Stroud as well, to convert it to a DRUbit hub as well. That's our stated intent for all the reasons that we know, right? You know, it's non-haz, it's non-flammable, 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. It's the real kind of industrial solution here that we like. Given that, both Gibson and USD are committed to doing that.
There is competitive pressure, if you will, on dilbit, right, to convert to DRUbit because that's where we're headed, 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. 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, you know, taking three- to five-year agreements and converting them to 10+ year agreements was a positive net back to the partnership for that.
Our commitment is that it would 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. As we discuss and negotiate with dilbit customers, you know, we're open and honest with them about, "Look, you may not have dilbit capacity remaining at either Hardisty or Stroud as it relates to." Because we're gonna convert that into DRUbit in longer term and more sustainable and more profitable business for both the partnership and USDG. Gibson for that matter. We're all on the same page about that. You know, we like that, if you will, the competitive tension. Every time a dilbit customer say this 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, you know, to date, it's been a positive development for the partnership in terms of both term and both, you know, on its face term and the commercial viability of the commercial agreements, if that makes sense.
Totally. I guess what I was just trying to better understand if just for purely illustrative purposes, if the s ort of total dollar per barrel tariff to you for the whole value chain is $15, how do you split that between the DRU facility, the Hardisty terminal, and the Port Arthur terminal? Like, I know you mentioned sort of market, but when we look at page 19 of the deck, like there's no. You know, one doesn't work without the other, right? There's no— The DRU facility can't access at all.
That's right.
C an't access it without going through the Hardisty terminal. Like in theory, the Hardisty terminal has a monopoly on the DRU facility. I don't know what market means in that sort of scenario, and so how tha$t 15, again, illustrative number would be split across those three legs of the value chain.
Yeah. It's great. Again, great question. Obviously that's always the challenge between the sponsor and the partnership, right? Our fiduciary responsibility is 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 fair and balanced? Absolutely. Do we then present that to the conflicts committee who looks at that independently and weighs in on that? You know, that's how that's kind of the check and balance that we try to use there to make sure that it's you know sustainable commercially for both sides. You know, can I give you more detail around that?
I probably can't. Just as we've done historically, it's been a positive dollar-based commercial agreement and term, obviously, with the partnership's assets.
I would say respectfully.
And then the last—
That respectfully, that's our strength as a developer, is that we have strategic alignment with railroads, strategic alignment with terminaling companies where it's appropriate to support an all-in solution. Ultimately, it's got to be competitive relative to the competing alternative end of story, and it's got to meet our return thresholds for each one of those pieces of the puzzle.
That's right.
End of story.
Jake, you had another question?
Yes. My last question was just, if you had talked about sort of, I think it was $14-$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 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 or, you know, earlier this year or not, but where is your head at now? Given the previous thoughts around 2023.
Yeah. Jake, this is Adam. It's a good question. That I think that was guidance that we gave when we did the dropdown for Hardisty South. You know, I think we haven't updated that guidance. I would say, you know, considering it's 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. I'd say we haven't given updated guidance on that. I would say it's probably fair to say we've come off that, right now, and that we, you know, 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. We still are optimistic about cash flow in 2023, but I'd say we've probably come off that guidance.
Why would you have come off the guidance if the diff has only gotten wider, even taking into account the sour discount due to the SPR.
Yeah. Totally understand what you're asking, and then I totally agree with you. Actually we do obviously a ton of work around those things. Just timing when the contracts will get signed.
Okay. All right. Cool. Thank you very much. Appreciate all the
Appreciate it. Great questions. Thanks.
Thank you. We'll take our next question from Greg Bennett. I'm sorry. He's a private investor.
Hey, Greg.
Hi, Greg.
Hey. How you doing? Casper, is that something to be in better hands, that asset that you would remain [audio distortion]?
Yeah. Great question.
Better value.
You know, yeah. Great question, Gregg. Would we consider Casper to be a key component of our transitioning growth? You know, like I always like to say, we're transitioning from black to brown to beige to green. Now, all of that said, it's got to be long-term, investment-grade counterparties, you know, all the things that we've discussed on this call, which is the cornerstone of what's made it successful through the downturns and all of that in the economy. As it relates to Casper, would we entertain, would we look at options? Absolutely, we would. 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, you know, that, and we currently have trains running out of there today and growing demand for that asset. We like 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. You know, and are there ongoing discussions around that? There are. But it would be something that would be, you know, that obviously we'd weigh that against, you know, the value for the partnership, as an ongoing asset as well.
Yeah. 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.
This has to do with a tax question. When your limited partners get their K-1, you've taken a write-down of $60 million. I don't think I was a partner the last time you took a write-down on that. Is that something that flows through? I mean, it's a reduction of capital, I would think there. Do you know how that works?
Yeah. You know, it's different. I mean, it's different for every unit holder that has different basis. I would say generally speaking, there are GAAP books and their tax books. I'd have to dig into that a little bit more and probably get back to you. It wouldn't be dollar for dollar, you know, obviously, because they're just different sets of books. Probably in the end, I would imagine it's probably a positive for unit holders. I can't issue tax advice on this call, so I'd have to look into that.
No. All right. Let me just ask something that has been kicking in my crawl since the Hardisty South deal. For several years, you've always talked about dropping down assets, the general partner dropping down assets that have been de-risked. I don't know if your board's listening to this call or not, but my impression is Hardisty South was not de-risked. 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. This asset's 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 de-risked?
Yeah. That's a great question and a great comment. Obviously, the intent of the dropdown was to try to further simplify our growth for the DRUbit business, right? 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, right, to do that, right? 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. Would 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. As we looked at transferring Hardisty South into the partnership with sustainable, you know, customers that we had and that we believe will renew for all the market demand reasons that we said, that the partnership will be happy that they have those assets.
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, you know, 10+ year contracts with our commercial customers. As we look at that, I mean, I get it. I get the concern. 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. You know, as previous question was, you can't do one without the other, right?
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 the shorter term. Hopefully that gives you some color on it. Did we anticipate that there'd be continued SPR releases and all of that when we did all of that early in the year? No. You know, the impact of that is, you know, obviously concerning and it's frustrating. As we've said, we do believe that the market demand will come back on and, you know, we totally agree with kind of the concern.
Okay, thanks a lot.
You bet.
Hopefully, we'll have some good news before the end of the year.
Thank you. Thanks for the questions. Thanks for being an investor. Are there any further questions?
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.
All right. We've had really great robust questions and really appreciate that. Obviously, thanks so much for everybody being on the call and the support. Obviously, as we've stated, just to wrap it up, I'll just be a bit redundant here. We believe we're coming into a demanding 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 30-60 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, the market demand is on, and that's obviously when we prefer to negotiate and renew mid to long-term agreements. You know, historically, we've had customers come in and say, "Hey, look, would you take a discount today to renew?" We've looked at the market and made a strategic decision to say, "No, we won't do that because it's not in 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 two previous cycles, and we have always renewed and extended at or at premiums for those market demands. All of the facts that we have shared today support 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. You know, 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 rail cars that are sitting that wanna 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. Every new barrel growth, they're gonna take some synergistic benefits, obviously, of combining those, you know, those activities. They're doing that because they have a growth model in plan. They're gonna grow. Every new barrel that they bring on creates a better netback for them because it absorbs more of the fixed cost. These are very focused large scale producers in the market that are our customers. They're strategic, they're 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.
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. Obviously we're seeing some of that occur and some of the wins and the headwinds that are blowing against, you know, 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. You know, again, our DRUbit business, you know, I think it's proven its sustainability in the market.
It's you know, with over 22 million bbl moved, you wouldn't have customers like we have looking at that strategic alternative to better control their growth and where their production is gonna head and why they're going to do it. Are they incented by the low carbon netback? Absolutely. Why? Because Canada is pushing for more of a zero tolerance around carbonization in that market. Does this positively benefit to that? Yes. 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. 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 can paraphrase it, but a highly placed 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." You know, we like where we're headed. We like the market demand that's coming. We like the demand for the DRUbit barrel, and we look forward to sharing more about that and delivering on that in the near term. We appreciate obviously all of our investors. We appreciate, you know, the support, and we'll continue to do our jobs to create the best netback that we can for everyone. Thank you.
This does conclude today's call. We thank you for your participation. You may disconnect at any time.