Tidewater Midstream and Infrastructure Ltd.

Good afternoon, ladies and gentlemen, and welcome to the Tidewater Midstream and Tidewater Renewables year-end financial results. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. This call is being recorded on Thursday, March 9, 2023. I would now like to turn the conference over to Mr. Scott Bowman. Please go ahead.

Thank you, operator, and welcome everyone to Tidewater Midstream and Tidewater Renewables combined fourth quarter results conference call. I'm Scott Bowman, Tidewater's Director of Capital Markets, and on the call with me today are Rob Coclo, Tidewater Midstream and Tidewater Renewables Interim CEO, Brian Newmarsh, Tidewater Midstream's Chief Financial Officer, Doug Beamer, Tidewater Midstream's VP of Corporate Finance. Brent Booth, Tidewater's Executive Vice President of Downstream Marketing. Rob McNeil, Tidewater's Downstream Director of Engineering. And also joining on the call, we have Tidewater Renewables Chief Financial Officer, Ray Kwan. Before passing the call over to Rob to review some highlights, I just wanted to quickly remind everybody that some of the comments made today may be forward-looking in nature or and are based on Tidewater's current expectations, estimates, judgments, and projections. Forward-looking statements we may express or imply today are subject to risk and uncertainties, which can cause actual results to differ from expectations. Further, some of the information provided refers to non-GAAP measures. To know more about these forward-looking statements and non-GAAP measures, please see Tidewater Midstream and Tidewater Renewables financial reports which are available at tidewatermidstream.com, tidewater-renewables.com, and on CDAR. And with that, I'll pass it off to Rob to discuss some of the highlights for the quarter.

Thanks, Scott. Good morning, and thank you for joining our Q4 2022 conference call. This is the first call that I've had the privilege of hosting since taking on the role as interim CEO for both Tidewater Midstream and Tidewater Renewables. and that goes back to the end of November of 2022. Well, it's only been a few months in the seat. I did serve on the Tidewater Midstream Board since 2017, so I'm very familiar with the business and the assets and the team. As I've settled into the role, I've established clear near-term strategic priorities, and that's increasing shareholder value and ensuring that Tidewater Renewables successfully commissions its renewable diesel plants. I recognize that to date shareholders have not benefited from the growth that Tidewater Midstream has been delivering. We believe that our company trades at a material discount to the sum of the value of our assets, especially relative to midstream peers. We also do not believe that this discount will fix itself. While we've implemented a program of disciplined capital allocation, I've also kicked off a review of our asset base and we'll be evaluating alternatives that could unlock this value that we see. My second priority, as I mentioned, is the successful commissioning of Tidewater's renewable HDRD complex, which will be Canada's first renewable diesel plant. As we announced this morning, this project is facing an increase to its capital costs as we deal with the logistical, labor, and inflationary pressures that pretty much all major projects seem to be facing within the industry. The project's now over 90% complete, and we're down to a very modest amount of capital to be spent that I'd consider at risk, which gives us a high degree of confidence in this $342 million capital cost figure. The project economics also continue to look strong, with an estimated run rate of EBITDA of 80 to 90 million per year. And we're working with our lenders to ensure that we continue to have capacity to fund our project through startup. We're seeing a very strong market for both BC LCFS credits and the federal CFR credits that this project will generate. For the first half of 2023, we expect to receive proceeds of approximately $53 million from the sale of Part 3 BC LCFS credits that are under executed agreements. Now, focusing on the results that we delivered in Q4, I think the numbers speak for themselves. Consolidated full-year EBITDA of approximately $250 million at the high end of our guidance range, and deconsolidated maintenance capital of $41.5, which is at the low end of our guidance range. Within the midstream business, last year we completed major planned turnarounds at our Pipestone, Ram River, and Brazzo natural gas processing plants. The turnarounds were completed safely and largely within expected timelines. These facilities are now processing volumes at their expected capacity, and we've seen a steady incline in corporate processing volumes with the turnarounds behind us. As we discussed throughout 2022, we saw very strong refining margins at our Prince George refinery. That played a significant role in driving our consolidated full-year EBITDA of approximately $250 million. This is an asset that benefits from the fact that it serves a region with a significant amount of industrial demand for refined products and realizes some of the highest refining margins in North America. Our refinery is scheduled for its four-year planned turnaround during the second quarter of 2023. And over the last 12 months, our local Prince George team, supported by a specialized turnaround team, has been working on the planning, procurement, and scheduling of the turnaround. We expect to be up and running mid-May as we flip into summer driving season, and we see increased industrial demand following spring breakup. On the tidewater renewables front, in addition to the HDRD complex work, the team has been advancing our first renewable diesel natural gas project, which is located in southern Alberta. This is an integrated project with our partner Rimrock Cattle Company and has a 20-year off-take agreement with Fortis. Renewables has an exciting pipeline of opportunities and continues to see substantial support on the government and regulatory front. Now, I'd like to turn it over now to Tidewater Midstream's Chief Financial Officer, Brian Newmarsh, to walk through some of our financial results.

Thanks. As Rob mentioned, this is a strong year from an EBITDA perspective. Consolidated 2022 adjusted EBITDA of $250 million was a 19% increase over the previous year, and full-year consolidated distributable cash flow was approximately $75 million, representing a 12% increase over 2021. I'm very focused on distributable cash flow as this provides us with the cash to pay our dividends, pay down debt, or invest in profitable growth projects. Over the last year, we have significantly improved our balance sheet and reduced Tidewater Midstream's leverage, addressed near-term debt maturities, and simplified our balance sheet. The financing transaction that we closed in the third quarter, coupled with our financial results, have brought us within our targeted 2.5 to 3-time debt-to-EBITDA leverage target. Despite leverage levels now within our targeted range, we're still exposed to the rising interest rate environment. This is leading us to take a conservative approach on how we finance future growth opportunities and has led to a delay in catalyzing major growth initiatives within the midstream business. During the fourth quarter, Tidewater Midstream realized a $55 million non-cash impairment that equates to an approximately 3.5% reduction in the $1.6 billion book value of our property, plant, and equipment on our balance sheet. This reduction ties to the carrying value of minor, non-core assets outside our major gathering and processing hubs that have minimal fee-for-service revenue associated with them. The second quarter turnaround at the Prince George Refinery will contribute to a moderate year-over-year increase in our maintenance capital budget that we forecast to be in the $55 to $65 million range as announced in this morning's press release. This investment is part of our scheduled four-year turnaround planned at our refinery. and will help bring total throughput back above nameplate capacity of 12,000 barrels per day. We have timed the turnaround to coincide with the seasonal spring breakup that temporarily reduces industrial refined product demand in the region. Operations are scheduled to be back online with more than enough time to capture the increased demand from the summer driving season and the broader increase in industrial activity we continue to see within the region that leads to some of the highest refining margins on the continent. With our refinery turnaround scheduled for the second quarter, we have pared back near-term growth capital to maintain our leverage levels. We continue to evaluate longer-term growth opportunities, such as our Pipestone Phase 2 project, but are looking to partnerships to ensure we have the appropriate funding mechanisms to profitably support these initiatives. Lastly, we've been working on extending the maturity of our credit facility that's currently scheduled for August 2024, and we expect to have the maturity extended out until 2026 in the near term. This extension will push our debt maturities to three years and enhances our financial flexibility and the durability of our balance sheet. I will now pass the call over to Raekwon Tidewater Renewables Chief Financial Officer to walk through the renewables results.

Thanks, Brian. Tidewater Renewables reported fourth quarter adjusted EBITDA of $16.7 million and distributable cash flow of $9.4 million. Full-year performance yielded adjusted EBITDA of $62.4 million, well ahead of the $48 million forecast at year-end 2021, and distributable cash flow of $38.1 million. Our annual performance was underpinned by realized hedging gains from our coprocessing feedstocks, canola and FCC coprocessing, and growth in our feedstock collection business. Total capital expenditures, including maintenance capital for the fourth quarter of 2022, were $76.8 million compared to $58.2 million in the third quarter of this year. For the year, total capital expenditures, including maintenance capital, were $244.6 million. 2022 capital relates largely to the construction of the HDRD complex, but also includes the commissioning of the FCC and Canola coprocessing projects, the engineering design of the R&G facility, and the expansion of our renewable feedstock collection business. These expenditures were partially offset by funds received from the sale of BC LCFS credits awarded by the BC government for achieving milestones under the Renewable Diesel Project Part 3 Agreement, which totaled $10.6 million in the fourth quarter and $33 million for 2022. In the first half of 2023, we plan to concentrate our capital program on the construction and commissioning of the HDRD complex and supporting the planned turnaround of our renewable fuel assets at the Prince George Refinery. Regarding Tidewater Renewables' financial position, we ended the year with total net debt of $211 million, up from $124 million in the third quarter of this year. As Rob mentioned, with the announced cost increase for the HDRD complex, we expect to fund the remaining project costs through the sale of BCLCFS credits and with the support of our capital providers, among other sources. For the HDRD complex, our startup plan involves a gradual and measured increase in production, translating to a 75% to 80% utilization rate in the second half of 2023. Based on this utilization, second half 2023 adjusted EBITDA guidance for Tidewater renewables is expected to range between $50 to $60 million, inclusive of $35 to $45 million of second half adjusted EBITDA contributed by the HDRD complex. At this point, I'll turn it over back to Rob to wrap things up.

Thanks, Ray. I'll just wrap up by thanking our hardworking staff for delivering on a record year in 2022 and for safely progressing our HDRD complex to near completion. I strongly believe that our focus on disciplined capital allocation and cost controls, as well as our asset-based review, will soon deliver results to shareholders. Now, before we open it up to the line to questions, I want to remind listeners that me and my team are available for questions that you have at any time. You can find contact information for the team at the bottom of the press release. And with that, we can turn it back to the operator for the Q&A period.

Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star followed by the one on your touch-tone phone. You will hear a three-tone prompt acknowledging your request. Questions will be taken in the order received. Should you wish to cancel your request, please press the star followed by the two. If you are using a speakerphone, please lift the handset before pressing any keys. The first question is from Ko Pereira from STIPO. Please ask your question.

Hi. Good morning, everyone. On the asset disposition front, can you maybe talk a little bit about what you think might be on the block and maybe give some sort of indication about the scale you might be thinking about?

Hey, cool. Thanks. I mean, I don't think we want to speculate what it may lead to. Right now, it's a review. So we're looking at all of our assets and how the market may value those and how we value them internally. So, you know, I would say we're not limiting it. So it is, you know, open to all of our assets. But, you know, speculating as to where that may lead, I think, is just probably a step too far.

Yeah, fair enough. And Rob, you talked about some past the shareholder value. How do you think about, you know, increasing the dividend to be more in line with some of your peers in the infrastructure space as well?

Yeah, look, I think there's a number of different ways that we can sort of unlock some of the value that we've got here. As you probably have seen, I think I've been maybe a little repetitive. We are very focused on our cash flow generation. So, you know, that goes to cost controls. It goes to where we spend our growth capital or lack thereof. So, yeah, it's definitely on the table. Obviously, we've got some near-term issues both on renewables as well as midstream, specifically, obviously, the HDRD project, which is... you know, front and center here. But then we've also got the turnaround at Prince George. But, you know, I'd remind you that that's sort of once every four years. So it absorbs a fair bit of capital, but we'll be looking at all of those options as soon as we complete the turnaround and the HDRD, which really is a couple of months away.

Got it. And on the capital cost increase for the renewable diesel facility, Can you maybe give a bit more detail as to what drove this? I mean, I think we can all appreciate the current environment, but it's a pretty big increase right before coming into service and no real indication three months ago.

Yeah, I feel the same. I think the reasons aren't really simple, but they can be traced back largely to increases in quantities of materials, but also everything from piping to fabrication. When you have a larger increase in quantities, you have more labor. Obviously, we've also seen labor costs increasing, but all of those things seem to accelerate in November and December. Um, and you know, it's not that unusual with, with these projects where, you know, you get to the end of the line and that's where some of these, uh, additional costs come into, come to light. Uh, I think if you want to trace the origins of it, uh, you know, I, it, we should have seen more engineering done at the front end. Um, and that's really a function of being, as you said, this is the first renewable diesel plant in the country. Um, so it's not like you can take, uh, pieces of units and strap them together and estimate a cost. It's more complicated than that, and engineers just don't have a history with it. When that last estimate came out in November, from what I can tell, it was right when things were really accelerating on that front. It was a challenging time to be putting out an estimate, I think, in retrospect. but anyway, we're pretty confident where we are right now, and we're down to a fairly small amount of capital that's sort of at risk, so hopefully all of that's behind us.

Got it, and then just one more quick one from me. On the renewables front, for the first half of 2023, I mean, should we be expecting a similar EBITDA contribution as the last two quarters, or is there going to be some commissioning costs? Like, how should we think about that?

Hey, Cole, it's Ray here. Yeah, it's certainly not going to be as robust as the second half, just given the fact that we have HDRD kind of ramping up through the second half. So as you saw in our disclosure, like our thinking is that the HDRD project actually starts producing diesel towards the end of May. and then slowly ramps up thereafter. So really it's just going to be reflective for the first half this year, really just our base EBITDA generation. So anywhere between kind of that $40 to $50 million that we're forecasting for the first half.

Okay, great.

That's all for me. Thanks. I'll turn it back.

Thank you.

Once again, please press floor one should you wish to ask a question. Your next question is from Patrick Kenny from National Bank Financial. Please ask your question.

Thank you. Good morning. Maybe just on the renewed focus here on cash flow conversion. Looks like de-cash as a percentage of EBITDA was about 30% last year, same as 21%. You have the turnaround at PGR coming up here in Q2. Looks like that pushes up maintenance capex by $20 million or so year over year. Lease payments don't appear to be coming down from the run rate there of $45 to $50 million. Maybe you can just walk us through your thoughts as to what other line items might be helping to improve your cash flow conversion over the near term.

It's Brian here. I appreciate the question. I think you pointed out the line items. When we think about what's transpired over the last 12 months in terms of turnaround activity and what we have on tap for the first half of the year, these are events that we need to get behind us from a maintenance capital perspective to ensure that all our facilities are running at nameplate capacity and contribute the EBITDA that we expect them to. As we look into the second half of the year and having these events behind us, I think you do see a step change in that distributable cash flow We talked about the financing that we did in the summer that closed. It obviously reduced our debt levels by about $85 to $90 million. So that reduces the overall debt burden, or debt at the time. Unfortunately, that debt is all floating-based interest rates, so there is a bit of an uptick in overall interest expenses as a result of the increase in rates here. But I think the step change you will see as we look out to the second half of 2023 and into 2024 our clean quarters and clean years with reduced maintenance capital. And then, of course, we will benefit from the cash, not just EBITDA, coming out of the HDRD plan.

Yeah, and I'd add, you know, if we're looking down the line even further and out to a free cash flow number, we're going to be very, very focused on our growth capex. And that's, you know, a real... We're going to be minimizing the number of projects that are being chased around here And again, that's going to drive that cash to the bottom line.

Okay, got it. That's helpful. So more of a free cash flow improvement as opposed to just distributable cash flow, it sounds like. That's right. Okay. Yeah. And then I guess on the Pipestone 2 expansion, it looks like you're still evaluating that project. But I guess just given this latest 30% overrun on the HTRD, can you comment on where the latest cost estimate for Pipestone 2 might be at today versus the previous $300 million market? And maybe just remind us if any of the inflationary pressures can be recovered through customer contracts to perhaps maintain that six times build multiple on the project.

Yeah, sure. So let me just differentiate a little bit on those two construction projects. HDRD is first of its kind. So you've got, you know, engineering is new. You've got some, you know, some fairly funky catalysts and some interesting metallurgy involved, as opposed to looking at phase two of Pipestone, which is really a replica of phase one. So, you know, any of the any of the question marks that we went through on phase one are now behind us. And basically the engineering and construction are just going to be a lot simpler. So it makes us very comfortable in terms of our capital budget on phase two. And yes, we are still, you know, evaluating and working through things. And, you know, part of our structured process here is, you know, talking to partners as well as, you know, potential buyers. So maybe, Brian, do you have something to add?

Yeah, just to add to that, I think when we provided the update capital cost path, that was in the summer. And I think there has been give and takes. First of all, bulk commodities kind of were screaming higher at that time of the year. We have seen a pullback in the actual underlying commodity prices for steel and whatnot itself, probably somewhat offset by labor. So we think that capital cost estimate remains intact from a high-level perspective. And then I know it's been kind of a bit of a prolonged story on catalyzing this Pipestone Phase 2, but we need to be really honest about, as I said, kind of capital costs, where those are kind of coming in, and the fact that our cost of capital has increased given what interest rates have done. So we just want to make sure that we're catalyzing projects that are truly profitable before we execute them just for the sake of getting them done. And as Rob mentioned, the Sharpen focus on capital allocation and generating free cash flow to the business.

It looks like that project still has potential. You referenced partnerships, asset sales and other sources of funding for the HDRD. I just want to confirm, is the incremental $82 million of funding expected to come from renewables, asset sales only and partnerships or perhaps you know, other areas within the midstream portfolio with proceeds potentially being dropped down to renewables? And then, you know, how might this impact your 69% ownership of renewables when all is said and done?

Yeah, I mean, the reality is, you know, we're not prepared right now to outline exactly how we're going to proceed there. We, as Tidewater Midstream, are still very... engaged with the project and think very highly of the HCRD project. So, you know, we are looking at all options is the message. But, you know, speculating about what ownership is going to end up being, you know, in the near term, you know, it's just, again, a little, a bridge too far.

Okay. So all options on the table, sounds like. Okay. That's great. I'll leave it there and jump back in the queue. Thanks, Rob.

Okay.

Thank you.

Your next question is from Robert Cattelier from CIBC Capital Markets. Please ask your question.

Hi, good afternoon. I just wanted to follow up on the funding question there. I want to make sure, first of all, I have the facts right. We're looking at it the right way on the HCRD facility, specifically trying to narrow down the quantum of what type of funding is needed. So I believe you have $97.1 million left to spend according to the MD&A. I think you mentioned $53 million worth of credits that you can monetize, and I think there's $77 million of debt capacity on the facility. So with those two items, I'm just wondering what level of additional sources of funding do you think you need?

Hey, Rob. It's Ray here. So, you know, just to add on to the capital there, you know, so our forecast that we think for 2023 in terms of total capex, including maintenance capital, it's probably in that $130 to $140 million range. So it accounts for HDRD, but also spending on the FCC coprocessing as well as, you know, our capital for maintenance for the PGR turnaround as well, too. So that has to be accounted in there. In addition to that, we do have some feedstock purchases that needs to be accounted in terms of the startup and commissioning of our facility as well as to operate the HDRD facility. But overall, in terms of from a funding perspective-wise, we could see from a gap perspective-wise, it could be up to $50 million in terms of the funding gap that we're looking at.

Okay, so it's really, yeah, so it's the other items. It's the working capital for feedstock, et cetera, as well as the other projects that are underway. Okay, and just looking at just the state of the market for the credits. So, you know, a couple things have changed. Obviously, we have the Inflation Reduction Act in the U.S. and the whole Buy America situation. So just give an updated view on the credit market, and you're clearly still monetizing credits, but how does the Inflation Reduction Act in the U.S. and Parkland's decision not to build a settlement refinery change your outlook on the credit market?

Yeah, Rob, it's Rob.

I mean, the credit market, as Rob probably most participants can see is really strong. Frankly, it's stronger than we anticipated, both on the LCFS front as well as the CFR front. Now, that has not really anything to do with the IRA, but clearly in certain areas, there will be more attractive markets in the U.S. because of the Inflation Reduction Act. So we've been talking to governments and so have our colleagues at much larger companies and explaining to particular federal governments that it probably is a very good time to step up if you don't want to lose projects to the United States. Having said that, we actually have one or two projects in the U.S. that we are looking at. So we're fairly flexible as well. We can we can go across the border very easily. Nonetheless, we look at each project on its own merits and its own economics. And so when we look at the HDRD and the credits that are going to be generated out of that, as well as the part three credits that we've received on the build side, to get a three times build multiple on a major project is still super attractive. So each project will be analyzed in its own way. I can't speak to Parkland's decision. I don't know what they're going to do in the States, but it is certainly an interesting data point for our governments to be looking at.

Okay, thank you.

Thank you. Your next question is from Justin Strong from Scotiabank. Please ask your question.

hey uh guys thanks for taking my call so just a quick uh follow-up on the cost escalation it sounds like it's um you characterize it as a function of price and volume of components or maybe under kind of expected before is that fair yeah justin that is fair it's um

You know, I think it was the additional quantities that really drove some of the later cost increases. But, yeah, they both obviously impacted. I mean, everybody's been impacted by, you know, inflationary forces, especially over the last year from Ukraine and COVID, et cetera. And I think that we obviously experienced that, but we also experienced the... added uncertainty out of the gate from our engineering contractors with regard to a new type of project, frankly.

Great. And then, so you just kind of mentioned that you're minimizing the types of projects that you'd be pursuing in the future. Previously, you did kind of cast a wide net of you know, various different either clean fuels or carbon capture and storage. So you've cast Widen out there. Can you give us an idea of what projects you're looking at less now or if it's more just like a more stringent screen across the board?

Yeah, again, I guess I want to differentiate between renewables and midstream. So renewables is a – is clearly going to be a bit more of a growthy vehicle. There's a large pipeline of opportunities there and we continue to kind of prime the pump on those opportunities and digging into what the economics are. So there is a little bit more project work, let's call it future project work on the renewable side. And that's just a nature of, we're going to be spinning off 140, $150 million of cash of EBITDA in that business It is a larger scale renewables company that's going to have the capability of funding its own projects. That's different than the midstream side. The midstream side, a lot of projects get looked at. I couldn't categorize which ones we won't be looking at and which ones we will be, but CCUS obviously has a part to play, and we are a carbon tax-paying entity, so we look at things as they relate to savings on the midstream side. But in general, we'll be a lot more disciplined when it comes to understanding the EBITDA that comes out of projects. risking that heavily and making sure there's a great deal of certainty. Again, everything will be traded off against generating cash flow to shareholders. So it's going to have to be very solid projects that get funded.

That's great. And just kind of lastly on that, are there any learnings or anything you've taken from this HDRD process that... You know, has changed your thinking around the RNG, the current one or future ones? Yes, is there any kind of different thinking going on there? Any more caution or would you not call it similar enough?

There are learnings, absolutely. I mean, even in a good project, you'd hope to have lots of learnings. With regard to RNG, it's a really simple process. I mean, the complexity around the RNG is getting all of the pieces together, getting that high-quality offtake, getting the feedstock, getting your CI score, like all of the, frankly, more of the commercial side of things. We're pretty comfortable and we're not under construction now on the R&G side, so we actually have quite a bit of time. Our team has been looking at a lot of the European projects and we just have a lot more comfort with that construction project. It's vastly smaller. It's a simpler process. But there are definitely projects that have similar levels of complexity of the HDRD that we're still very interested in. And, you know, we're in discussions on SAF on various fronts. And, you know, I think what we've learned is pretty clear when it comes to engineering side. Obviously, like I said, the first project's the toughest one to get over. But from, you know, engineering contractor side and from contractors themselves, We learned a lot from that process, but in general, we will not kick off a complex project like that without doing a lot more engineering up front. And that's one of the, you know, I think one of the changes we'll see around here is, you know, having those costs buttoned down in the very beginning. It's worth spending the extra dollars and the extra time up front on all projects, whether it's a gas plant or whether it's a, you know, a complex refinery.

Great. And so maybe just to summarize that, it sounds like a lot of the cost kind of runs come from the more specialty kind of pieces of equipment and catalyst that, you know, aren't as available or, you know, you guys haven't engineered around before and the RNG project is simpler and, you know, more in the wheelhouse of the experience of your engineers. Is that fair?

Yeah, I mean, simply the process is just a lot more simple. You know, you're letting biology do a lot of the work for you in the RNG side of things.

Yeah, anaerobic digestion has been around for quite some time. That's great.

That's all for me. Thanks. Thank you.

Thank you.

Once again, that is star one. Should you wish to ask a question? The next question is from Robert Kwon from RBC Capital Markets. Please ask your question.

Great. Good morning. If I can start with Tidewater Midstream here. And you've got the statement that you're focusing on maximizing cash flow generation. I just wanted to confirm, are you looking at just operating cash flow or are you talking about maximizing free cash flow? And if it's the latter term, What does that mean then for the Pipestone expansion? Does that basically mean you're going to be looking at structures, partnerships and the like that would minimize if not eliminate any CapEx?

Yeah, I'd say that's fair. And we're looking at, you know, ultimately at free cash flow, you know, once it has to trickle down, you know, all the way to free cash flow. We're just looking at opportunities around phase two. Again, we think the economics are excellent and we are pretty comfortable on the cost side of things. Again, as I mentioned before, this is a replica of phase one. I think that side of it, the economics are very attractive. It's not a cash flow issue as much as it is really a large project. Given the size of our company and the CapEx requirements for Phase 2 just in general, even with the economics being excellent, it's a big project for the size of our company to do it on our own.

Okay. If I can turn to renewables here, and I want to make sure I'm understanding the disclosure and the numbers. Okay. It looks like you ended the year with debt to EBITDA of 3.9 times. The covenant's at four and a half times. You've got another 97 million left to spend and 50 some odd million of credits are put differently. You also talked about your funding gap being about $50 million. So I get this in quarterly timing. Is there something that you need to do to fit all of this in underneath the covenant, whether that's getting a waiver or otherwise?

Yeah, thanks, Robert. It's great here. So you're right there. We'll be working with our lenders to, you know, to basically work through the in terms of looking for a covenant relief here over the next two quarters until the startup of the renewable diesel facility. And to be fair. Well, just highlight that, you know, once this renewable diesel facility actually starts up, we'll be adding close to 80 to 100 million of EBITDA associated with this project. So, you know, our net debt to annualized adjusted EBITDA will fall sharply. So, like, we'll be less than, let's call it, two times in 2024 at that time frame once we start up our HDRD facility. So, know to your point we are working with our lenders and you know just for a temporary covenant relief for this year but you know once the project starts up i mean we'll be um hopefully in better better footing i think overall from a financial point of view got that um and then my last question is just on the guidance you've given for renewables for the second half of the year so you've got

HDRD of 35 to 45 million. And then you've got corporate EBITDA of 50 to 60 million inclusive of HDRD. So that implies, you know, call it about $15 million from the rest of the business. How does that square up given that's roughly the quarterly run rate? And I know, you know, things are doing a bit better and you've got some realized gains on hedges. Let's just go back to the 40 million annual guidance at the IPO. Is there something coming off here? fairly materially and in the base business?

Oh, there isn't. I mean, I think it's just for us is from a base business perspective wise. I mean, we still have the FCC coprocessing, the canola coprocessing, our ecodine, our feedstock collection business is actually outperforming, I think, from our point of view. So I think from a base perspective wise, we're just being conservative in terms of how we're forecasting for the second half of this year. Okay.

If I can just go back to an earlier question then, is there any reason, at least based on where you're seeing the market dynamics right now, that you would be materially different and call it the $16 to $17 million quarterly EBITDA run rate on the base business?

Yeah. I mean, we should be higher than that, like in terms of our base business, at least meeting that, you know, $20 million over the second half here.

So, So the base business goes to 20.

So that's like 40 for the base business. And we're adding HD. Basically. Exactly. Like you said, it sounds like the corporate EBITDA guidance for the second half is very conservative.

It is. And it's just us assuming that a very steady and measured ramp up in terms of the HD already complex. So we start off again, like late May in terms of a startup. And then we don't reach that.

know full capacity or at least 90 of uh utilization until september so it's actually pretty conservative from our point of view no no i understand that but the 50 to 60 is inclusive of that 35 to 45 on the hdrd so the residual in that is the base business which is like less than a quarter's worth of ebit uh and we're talking about two quarters okay but it's the base business basically

It's the base business. You shouldn't change.

It's still $20 million for the second half. To be clear, $20 million a quarter? No, no, no. It's $20 million for the second half.

So $40 million annualized for the base business.

And how does that square up then versus the $16.7 million? I know you're doing well, but...

Like, how much outperformance are you currently getting, then, to get you to... I think you're getting $6.7 million of outperformance in the quarter?

Like, currently? You mean? Sorry. Like, it's so... Like, the one thing that I'll say is that, you know, for the second half this year, yeah, we are assuming just the base business. And so we're not assuming any... realized hedges from our, you know, feedstock in terms of, and as well as we're assuming a conservative canola coprocessing as well as FCC coprocessing. And that's net of basically G&A and operating expenses associated with that. So, you know, again, just to reiterate, our base business, it's still $40 million that we're forecasting here and You know, compared to last year, last year we've had really strong kind of hedges that basically supported that $60 million of EBITDA that we generated last year. But for this year, it's just being conservative in terms of what we're forecasting. Okay. That's great. Thank you.

And, Robert, happy to take it offline as well, too. Sounds good. Thanks.

Thank you. Your next question is from Devin Schilling from PI Financial.

Please ask your question.

Hi, guys. You guys talk about an offtake agreement here on the renewable diesel side. Can you guys maybe elaborate a bit on the economics? Is this a fixed price contract or variable based on a set margin? And also, is the credit embedded in the sale?

So on this deal, it's with an investment-grade party. And so where we're selling this is basically into the U.S. So essentially, the credits are attached with the volumes there. And the benefit of having this offtake is really just increased cash flow or quicker pay in terms of when we sell a renewable diesel attached with the credits effectively.

Okay, and sorry, you said it's selling into the U.S. market?

Yes. Okay, no, that's helpful. And then maybe if you guys can just provide a bit of an update on your feedstock requirements, I guess what's all been secured thus far for 2023 production as well as 2024. Sure.

We are going to be starting up with canola product just to keep the complexity of things down. So, again, we're hoping that the ramp-up happens quite quickly, and once that does, we'll start differentiating our feedstock a little bit and trying to get some lower costs there. As we've talked about in the past, particularly with the UCO market and with tallow and things like that, we think we'd be able to bring our feedstock costs down. We're not budgeting for any of that, so all the numbers that Ray's mentioned are just using a proper canola feedstock. We have our own business, Clex UCO. We've got relationships with a number of other larger UCO players in the tallow market as well. We're looking forward to... you know, starting to differentiate that feedstock because it will have a pretty dramatic impact on our, you know, positively on our cash flow generation out of HDRD.

Okay, great. No, that's everything for me. Thanks, guys.

Once again, ladies and gentlemen, that is star one. Should you wish to ask a question? There are no further questions at this time. Please proceed.

All right. That concludes our call. We appreciate everyone's time for dialing in. The team is available if there's further questions. And again, thank you for your time and your interest.

Thank you.

Thank you, ladies and gentlemen. The conference has now ended. Thank you all for participating.