Ladies and gentlemen, thank you for standing by, and welcome to Tidewater Year-End 2020 Financial Results. At this time all participants are in listen-only mode. After the speakers' presentation there will be a question-and-answer session. To ask a question during the session you will need to press star one on your telephone keypad. If you require any further assistance please press star zero. Please be advised that today's call is being recorded. I would now like to hand the conference call over to your speaker today, Mr. Joel Vorra, CFO. Please go ahead.
Great. Thank you. Good morning, everybody. Thank you for joining the call. Before passing the call over to Joel MacLeod, our President and CEO, for the review of the quarterly highlights, just want to remind everyone that some comments made today are forward-looking in nature based on our expectations, estimates, and judgments. Some of the statements we express or imply today are subject to risks and uncertainties, which can cause actual results to differ from expectations. Also, we may refer to non-GAAP measures. To know more about our forward-looking statements and non-GAAP measures, please refer to our various financial reports on tidewatermidstream.com or on SEDAR. With that, as usual, I'll pass it over to Joel MacLeod for a review of the quarterly and annual highlights.
Thank you, Joel. Good morning, everyone, and thanks for joining our Q4 2020 conference call. We delivered a record corporate adjusted EBITDA quarter in Q4, where we delivered adjusted EBITDA of CAD 48.8 million. This represents a 22% increase in adjusted EBITDA year-over-year. We continue to see material per share distributable cash flow growth into 2021 with producer activity, increased volumes, increased refined product demand, and also crack spreads and frac spreads being quite strong. Our number one priority remains de-leveraging and free cash flow generation, and we are confident in our ability to achieve our target of 3.25 x- 3.5 x debt to EBITDA with the closing of the Pioneer Pipeline.
This morning, we announced an update to our renewable energy initiatives, as over the past six to 12 months, we have made material progress on numerous fronts and have engaged CIBC and National Bank to help us evaluate our numerous options in funding these projects. We want to be clear that our goal is to de-leverage Tidewater in financing these projects and to also maintain control and material ownership of these projects as they have strong return profiles. Our renewable initiatives give our shareholders significant upside to increasing carbon tax, the new Canadian Clean Fuel Standard, BCLCFS compliance costs, and rents. These initiatives include opportunities in renewable diesel, co-processing, renewable hydrogen, blue hydrogen, renewable natural gas, carbon capture, and various other renewable energy projects.
Our largest renewable energy initiative is our renewable diesel and renewable hydrogen plant at Prince George, which will be a standalone renewables complex with a total capital cost of approximately CAD 225 million. We have received approximately CAD 100 million of grant funding from the B.C. government in the form of BCLCFS credits and do want to thank the B.C. government for all their support. As a result, our net capital contribution would be approximately CAD 125 million, and we do expect the asset to deliver over CAD 75 million of EBITDA on an annualized basis. The consumer use of the produced renewable diesel and renewable hydrogen is expected to reduce carbon intensity and related GHG emissions by approximately 80%-90% and 65%-75%, respectively, versus conventional diesel, which represents the equivalent of removing approximately 70,000-80,000 vehicles from the road annually.
Impressive returns for a renewable energy project where diesel demand in BC remains strong and we continue to see diesel prices in Prince George being as high as anywhere in North America. Want to be clear that we are now evaluating the various options that we have to fund our renewables initiatives with a focus on de-leveraging Tidewater. We also have two other capital projects, including our canola co-processing project, which does come online in Q4 of this year and has been funded 100% with the support of the BC government in the form of BCLCFS credits, where Tidewater's net capital contribution is zero. We were also happy to sign an agreement with the BC government for their support on an FCC co-processing project, which will come online in 2023 and will start in 2022.
The capital spend will start in 2022 with a payout of approximately one year inclusive of the B.C. government support. As we mentioned in our Q3 conference call, the amount of government outreach, stimulus, and support we have seen in recent months and even in the last year is nothing like I have seen in my career. We have received now with executed agreements of over CAD 100 million of support and do expect to see incremental support from governments in the next 60 days-90 days, where we are clearly seen as a leader in clean fuels by the provincial and federal governments. We do also expect to have updates on our blue hydrogen, renewable hydrogen, renewable natural gas, and/or carbon capture initiatives.
We do want to thank the provincial and federal governments for all their time and support to date. We're also seen as a leader in the hydrogen perspective, in business by the provincial and federal governments, as we have existing hydrogen production today at Prince George, and has been operated for 30+ years. We are likely to move forward on the above renewable hydrogen project, subject to financing and a financing plan, and we have existing operating carbon capture reservoirs today, and our acid gas injection wells and related reservoirs at Pipestone and Acheson, and our operating gas storage assets at Brazeau River and Pipestone Gas Storage. Tidewater is positioned extremely well to benefit from renewable energy and clean fuel stimulus. An update on our base business, and to start with Pioneer.
Pioneer Pipeline continues to operate incredibly well, and our partner, TransAlta, has been an incredible partner and the asset continues to perform well. The transaction, the sale of the pipeline is subject to customary conditions for a transaction of this nature, including regulatory approvals by the AUC and the AER. Regulatory approval is anticipated in the second quarter of 2021, and we do expect to close in the second quarter of 2021. In regards to Prince George, another strong quarter in Q4. Total throughput exceeded the refinery's nameplate capacity as we throughput approximately 12,200 bbl a day, and consistent with our third quarter of 2020. Great job by the team and want to thank them for all their efforts. We had for the year 2020, we had the highest refined product sales that the Prince George Refinery has seen in the history. Again, huge accomplishment by our team.
In a COVID year, to have record refined products sales is something, well, we should be very proud of. We expect the strong performance of PG to continue, Prince George to continue into 2021, where crack spreads continue to strengthen. We want to remind investors that a CAD 10 per barrel move in the crack spread would result in north of CAD 30 million of incremental free cash flow to Tidewater on an annualized basis. Demand for diesel continues to exceed our production as a result of large infrastructure projects, including Coastal GasLink, Site C Dam, LNG Canada, and the Trans Mountain Pipeline expansion. Over to Pipestone. Runtimes continue to improve at Pipestone, and the asset continues to perform well. We are seeing consolidation and a significant uptick in activity in both the Montney and Charlie Lake plays, which is great for our terminalling activities and the related gas plant.
The gas plant does remain fully contracted and backstop by two tenure and take-or-pay contracts. On the ESG front, it continues to be a big focus of our company. Obviously, our renewable energy projects further demonstrate our commitment to reducing carbon intensity and GHG and being a leader in clean fuel standards. On another note, in January 2021, the government of Canada's CAD 750 million Emissions Reduction Fund endorsed two small-scale Tidewater projects. Given our goal to eliminate or lower routine venting and methane-rich natural gas, this will result in GHG emission reductions, with the project expected to be online at the end of 2021. 2021 is shaping up to be a transformational year for Tidewater, where we are confident we will deliver shareholder value, given the continued cash flow generation, growth of our base business, and the large-scale renewables initiatives that continue to progress.
We want to be crystal clear that our goal is to deleverage Tidewater while financing and maintaining control over our renewables initiatives and are confident we have multiple paths to do so. It is extremely difficult to find larger-scale renewables projects that are 40% funded by government grants and that also generate material cash flow. We have the ideal cornerstone renewables project to do so in our renewable diesel and renewable hydrogen plant at Prince George. I do want to thank our staff, board, shareholders, credit syndicate partners, and all stakeholders for all of your support. We are looking forward to continuing to deliver strong results for our shareholders into 2021 and remain confident in our ability to deliver debt-adjusted per share free cash flow growth into the future.
I'll pass it back to Mr. Vorra. He can walk you through some of the details around our financial highlights related to 2020 and Q4 2020.
Thanks, Joel. Now we can get into the exciting stuff. I'll give an overview of annualized results year-over-year, 2019 to 2020, and quarter-over-quarter, Q3 to Q4. Obviously, 2020 was characterized for everybody by the impact of COVID, especially in the first and second quarter, where we did see a 10%-15% impact to our annual results or where guidance would have been at the beginning of the year. Year-over-year, when you look at 2019 to 2020, I would consider outperformance from the Prince George Refinery, considering economic shutdowns and commodity volatility. We saw year-over-year, I would characterize 2020 as a success when you look at the numbers, considering what we were faced with.
With that said, didn't quite deliver the distributable cash flow we would have forecasted. We do expect that to improve into 2021 and is our focus to continue and increase distributable cash flow, reduce leverage, reduce borrowing costs and increase related EBITDA and cash flow. With that, quarter-over-quarter, our revenue was in line in Q4 compared to Q3 at around CAD 274 million. Our annual revenue was up significantly, CAD 979 million compared to CAD 692 million in 2019. The 40% increase is mainly attributable to the refinery acquisition. Gross operating margin, adjusted for hedges, was approximately CAD 52 million for Q4 compared to CAD 48 million in Q3, and also an increase in adjusted operating margin percentage of approximately 17%-19%. I think just reflecting a continued recovery in the economy and prices and our overall base business.
Annual adjusted operating margin was approximately CAD 190 million, again, adjusted for hedges versus CAD 122 million in 2019. Again, approximately 17% increase up to 19% in adjusted operating margin year-over-year. Again, a contribution from the refinery. As we continue to see Pipestone improve runtimes and move up to consistent nameplate capacity throughput, we'll continue to see those margins increase slightly. Adjusted EBITDA for Q4, Joel noted, was approximately CAD 48.8 million compared to CAD 47.6 million in the third quarter. Again, continued recovery in prices in the overall economy. We did see some restrictions and lockdowns in December, which slightly impacted the quarter. Again, overall, as those pieces are lifted, we continue to see outperformance in the assets, the refinery specifically.
Annual adjusted EBITDA was approximately CAD 180 million, which would've been the midpoint of our revised guidance once we assessed the impact of COVID and shutdowns compared to CAD 110 million in the prior year. Annual EBITDA margin increased approximately 2% from 16%-18%. We expect that to continue to increase as we move into recovery and I think more of a stable economic outlook. On the distributable cash flow front, probably the most important piece to us, we were CAD 13.5 million in the fourth quarter compared to CAD 10.5 million in the third quarter. Annually, CAD 47 million in 2020 versus CAD 56 million in 2019. The main driver of that being borrowing costs. As we bring in the proceeds from the Pioneer Pipeline, we will save on a cash basis CAD 7 million-CAD 8 million in cash from the reduction in leverage from bringing those proceeds in.
As we continue to increase EBITDA and free cash flow, expect to continue to lower that payout ratio. We have sort of guided to a 20%-25% payout ratio. We do feel that we'll be at the lower end of that range, which would drive higher free cash flow and potential to beat that or come in higher if we continue to see an economic recovery and the refinery continues to perform how it is and we continue to see stable runtimes at Pipestone and some of our other larger assets. Again, to reiterate Joel MacLeod's comments, free cash flow leverage reduction is the number one focus of the company. At the same time, as we move through the economic recovery, we do see the business moving back to where we would have felt our guidance was pre-COVID.
Overall, 2020, obviously a difficult year, but to take the positives out of it, the assets performed well. We have, in my opinion, stress tested the business, and it performed quite well. That being said, still work to do to get to where we need to be on the free cash flow front and leverage reduction. Feels that 2021 is on the right path. I think with that, I'll pass it back to Joel MacLeod, and then I think after that, we can probably open it up to questions.
Thanks, Joel. I think we can open it up to questions.
Okay. At this point, if anybody has a question, please press star one on your telephone keypad. Again, that is star one on your telephone keypad. Your first question comes from Cole Pereira from Stifel. Your line is open.
Good morning, everyone. I just wanted to start by clarifying for the renewable diesel facility that you plan to move forward with the project, but at this point, you're not formally sanctioning it, and you're going to wait until you have a financing plan in place?
You've got it, Cole. We are not formally progressing until we have a financing plan. We've got multiple options, and we plan to evaluate those options here over the next couple of months.
I guess on that note, can you maybe give some color about which financing alternatives you might be thinking about?
I think we probably need a little time. We've seen everything from project financing to separate pure-play ESG entity, from equity ownership to project-level equity ownership, knowing that our main goal is to deleverage Tidewater and also retain control and significant ownership of these projects, given the returns we expect they can generate. Do we have a plan A right now? No. We just have seen significant interest and need CIBC and National to help us evaluate all our options.
Okay, got it. That's helpful. Thanks. As well, with the BC credits, can you just clarify exactly how those would be realized, i.e., over what timeframe?
The grants themselves, on a part three agreement with the B.C. government, there's milestones that need to be achieved, and then you receive a tranche of credit. Our existing canola coprocessing project would be a great example. It comes online here Q4 2021 of this year. It started back in 2018. Even before we owned the refinery, when Husky completed the FEED study, they were allocated BCLCFS credits. You're provided a set number of credits, so if the value moves up, and we have seen values, and if you go to the B.C. government website, you'll see the value of BCLCFS credits from 2018 to, say, more recently in February, have gone from roughly CAD 150 a credit in 2018 through to CAD 437.50, I think is the average transfer that happened here in February.
With the agreement, we're given a set number of credits, and then we're allocated those credits as we hit milestones. Should the value of the credits move up as we've seen, then the grant essentially increases in value with the grant of those credits. Further to that, when the project comes online, our canola coprocessing project comes online this year, and we start producing renewable diesel, every molecule of renewable diesel that we move into British Columbia also generates a BCLCFS credit. That value of a BCLCFS credit has a huge impact to both the capital cost and also the annualized cash flow of that project moving forward as we sell that molecule of renewable diesel into the BC market.
Okay, got it. That's helpful. Thanks. As we think about the capital cost of CAD 220 million prior to the grant, call it EBITDA of CAD 75 million, obviously that's a pretty attractive EBITDA payback. Can you just give some color on what are some of the factors that are getting you to such a low multiple on that, i.e., a quick payback?
Yeah. We probably won't go way down into the weeds, but want you to be aware of the key variables. The number one variable is the carbon intensity of our end product, which we do expect to be, and we were trying to relay the carbon intensity reduction, but it would equate to roughly a 20 carbon intensity, which is that 80%-90% reduction versus conventional diesel. That related carbon intensity is key in determining how many BCLCFS credits we generate every time we sell a molecule of that end product into the market. When we've seen BCLCFS credits move from CAD 150-ish in 2018 to CAD 300-ish a credit, I'd say six months ago, to today in February, large number of BCLCFS credits trading at CAD 435. Just know that's a big driver of the cash flow.
We've tried to be conservative in our numbers. We haven't included the Canadian Clean Fuel Standard credits, which would be incremental as well. Just trying to help educate yourselves and others that the carbon intensity of our fuel is the main driver of the credit component. We would also be paid a Prince George rack diesel price as we're selling that diesel molecule as well. In general, the carbon credit benefit is about 60-ish% of the margin. We can recalculate. I'm just trying to help to give you kind of ballpark components. The diesel itself would be the remaining piece. Happy to jump on a call and give you a little more detail if you like. I hope that was helpful.
Yeah, that was good. I'll turn it back. Thanks for answering my questions.
Thanks, Cole.
Your next question will come from Robert Kwan from RBC Capital Markets. Your line is open.
Great. Good morning. Just want to kind of dig a little bit more into the financing side and understand some of the wording that you're using. No increase in corporate debt, and the number one priority is to delever. Now, is that to delever into that 3x-3.5x range, or is it to delever into the 2.5x-3x long-term range?
Yeah, it's a good question, Robert. I would say ideally, we get down into the two and a half to three-time range, but it'll depend on the terms and our related options. Number one is to deleverage. We do want to be back to 3x debt to EBITDA. With Pioneer closing, as you're well aware, we get to three and a half. With our free cash flow for the year, we feel we get close to 3x . With the renewables initiatives, our goal would be to accelerate that and get to have a path to 3x debt to EBITDA would be a goal of ours. To your point, it could result in even us moving closer down to 2.5x .
Construction, would you be comfortable flexing above that 3.5 x range and then exiting back? Is that whole no increase in corporate debt going to be both an absolute constraining factor and one that you will not allow the EBITDA to go above 3.5 x if you go forward with this?
Yeah. Definitely at 3.75 x-4 x, I would say we'd have a hard guardrail there where we wouldn't want to get to. When we speak to some of the government agencies, and don't want to guarantee this, but if there was a very low coupon government type support, which we will evaluate, then I guess there would be potential during the build that we above 3.5. That is not our number one priority now or our best option, but would hate to say there is no way we will be over 3.5. I think as we get to 3.75 and 3.75 x-4 x, we do not want to be in that range again. Our goal would be to be at 3 x in the next 12 months.
If you did it on a non-recourse project financing basis, would you be excluding that debt then from your calculation?
For now, we would assume, Robert, when we're looking at options that we're consolidating everything up, and even if it was on a non-recourse basis, we'd like to stay under 3.75 in aggregate. We know our shareholders, our board do not want to see our debt levels above 3.75. Ideally, we get down into that 3-time debt-to-EBITDA range.
Got it. Okay. Just looking at your slide deck, just turning overall on the debt side, it looks like the debt reduction exiting 2020 in your 2021 forecast is largely just the Pioneer proceeds coming in. Given the FFO you're generating and dividend being modest, are you building in material CapEx associated with this project even though it hasn't been sanctioned yet? Just, I guess, what's driving free cash flow being flat?
We're trying to be conservative. I'll let Joel jump into the detail, though.
Yeah, I think, Robert Kwan, we haven't formally put out guidance yet. I think you'll see that from us in the next little bit. To answer your question, there'd be some CapEx built into that number just with the new information we've put out to the market. We just want to be careful on providing formal guidance right now, knowing some of the opportunities that are in front of us. Yeah, to answer your question, there would be some CapEx built into that number, but I'm not going to sit here and tell you it's X, Y to this project or that project. Just want to keep it to some ranges for now until we come out with formal 2021 guidance.
Got that. If I can just finish on the payout ratio, the 20%-25%. Joel, you mentioned, sounds like there's a decent chance you'd come at the lower end of that range. Is there an assumption, better than assumption there just on the dividends? I know there's been some talk in the past about a potential increase. Just what are you factoring in as you talk about that payout ratio range and where you think you'd be in the range?
Yeah. When you look at that payout ratio range and you go to the lower end of that range, we're still looking at a greater than 50% increase from 2020. We would be factoring in economic recovery. To your question, I do think there's a decent chance that we can beat that based on what we're seeing today. Is there a dividend increase built into that number? Today, there wouldn't be. Obviously, there's discussions. We're having those discussions at the board level and with shareholders all the time. Not to say that we're not having those discussions or the answer is no, but there wouldn't be an increase built in, but I can't tell you that we haven't evaluated it and that at some point there could be an increase.
We need to show de-leveraging and free cash flow before we come out to the market with a dividend increase.
Understood. Okay. Thank you very much.
Thanks, Robert.
Again, if anybody would like to ask a question, please press star one on your telephone keypad. Your next question comes from Rob Hope from Scotiabank. Your line is open.
Hello, everyone. I have a follow-up question to Robert's question there. Just on the 2021 guidance, even though you're not putting out formal guidance yet, you did say that you're getting kind of back into the original guidance that you gave earlier in 2020, which was, we'll call it CAD 200 million-CAD 220 million. Can you just walk us when you look at 2021, what the key changes you're seeing? I'm assuming Pipestone will have greater availability and volumes. I guess specifically, where you came in on PGR and kind of what your expectations are for 2021.
I would say you hit the two pieces, Rob. When we look at the impact from the shutdowns in Q1, Q2, we look at overall impact to guidance. We're probably in that 10%-15% range. Today when crack spreads held up well at PG, at Prince George, but we did see, obviously, diesel and gasoline demand for a period of time come way off. We are seeing demand and margins at the refinery back to pre-COVID levels. We're seeing probably better run times than we saw pre-COVID at Pipestone. When you look at the gas storage business, I'd say there, we're probably seeing less volatility in gas prices than we saw pre-COVID. That may be one piece that would be down a little, but still it's generally largely contracted, there isn't a ton of volatility in the base cash flows.
The main pieces I think would be we're seeing strength in AECO gas prices. Our more gas-weighted customers seem to be in pretty good shape. We're seeing a recovery in commodities on the frac spread front, on liquids, condensate, crude oil, all positively impacting our customers and their throughput through our facilities. Pipestone, to be able to run at nameplate capacity is going to significantly help those cash flows. Prince George, today, is running pretty near, I wouldn't say the top margins we've seen. They were pretty high at the end of 2019, but running pretty well. Throughput is essentially near or at all-time highs, and lifts are very strong. Those would be the types of things we're factoring into 2021. At the same time, we just want to be careful with OPEC, COVID restrictions.
I'm not sure I would have expected in March 2019 that we'd have restrictions in sorry, March 2020, that we'd be in a lockdown in December 2020. I think we want to be just careful there. Did I answer your question?
Yep. That's great. Turning over to the renewable projects that you were speaking of. I understand that it looks like the key bottleneck right now for an FID is financing. Can you kind of talk us through where you are in the engineering of the process, as well as how long of a build there'd be there and just to better understand the timeline there?
Yep. No problem, Rob. If we look at the project, I would say it's been about a year of evaluation, mainly internal resources, so we haven't allocated significant capital. But we have engaged Haldor Topsøe, who has 80% market share in renewable diesel. I would say we're into FEED today. Our goal would be to be online in early 2023, should we be able to, your point, achieve a financing plan here in the next 60 or so days. We'll be spending the next couple of months to work through our financing plan. Should we get there, then we would move the project forward and do feel that an early 2023 online date is possible, should all go well on the financing front.
All right. Thank you.
Thanks, Rob.
Your next question will come from Curtis Jensen from Robotti & Company. Your line is open.
Hey, fellas, can you hear me all right?
Yep. Curtis, we're good.
Just think about the Pioneer sale again. Watching the back and forth at the Utilities Commission, has your confidence level changed at all in terms of closing this in Q2?
No, I would say we haven't seen any material change or arguments that cause us concern. Obviously, the only concern has been how long it's taken, and we do apologize for that. As far as new material information or concerns that have come through the process, there hasn't been any and remain confident, and I think you'll see our partners and ATCO, through to other involved parties, continue to relay Q2.
If there was some wrinkle in terms of Utilities Commission came back and said something that was unacceptable in terms of the consideration or the terms, is there kind of a plan B, or do you think it's such a remote possibility that you'll just cross that bridge when you come to it if it comes to that?
Yep. We would be high 90 certainty. We're not aware of anything that would cause concern. The good news, I guess, we haven't been spending any time as we're confident we will conclude the process, there would be significant interest on a 15-year take-or-pay asset, even if we did head down that path. We're not. We're confident that we'll close in Q2, happy to answer any other questions.
Just a couple more. Given what's happened to spreads and kind of rates generally, have you kind of identified some areas that were you to close Pioneer in the next quarter, there's some potential for refinancing on attractive terms?
Yeah, as you're well aware, and I'm sure most on the call, the high-yield market's been fairly hot. One piece for us was getting this press release out just so we weren't sitting on any potential material information. We are eager to explore and speak to high-yield investors and explore the potential refinancing of our notes. To your point, we don't want to sit around.
Fairly hot and want to explore those conversations and see if we can achieve attractive rates and attractive cost of capital to refinance our unsecured notes. Our credit syndicate's been phenomenal, so the good news is we're not under any pressure, but we don't want to sit around. If the market's hot, we want to get moving and explore those options, and that's another reason for the press release today is not to be promotional. It's just so we can go and have discussions with high-yield investors as well and see what terms we could potentially refinance our notes.
The last one. Refresh my memory. Does Husky have an earn-out potential based on the performance at Prince George? For 2020, is there a potential earn-out for them? It seems like volumes and crack spreads were pretty good, at least in the last half of the year.
I need to review that agreement, I'm 99% sure, Curtis, that no. I believe the threshold, we'll confirm and come back to you. I think the threshold's CAD 100 million of EBITDA before IFRS adjustments. Yes, we had a great year. Very happy. Our crack spreads would've been near kind of our base, $45-ish for through COVID. Obviously, they've improved significantly now, but I would say 99% or high 90% certainty, we will not have any contingent payments to Husky/Cenovus for 2020. 2021, we're only three months in, but it looks like a much different picture as far as potentially being close to that CAD 100 million of EBITDA number.
I don't want to say I know we're going to have a payment to Husky/Cenovus in 2021, but when you look at the curve on crack spreads into the second half of 2021, the demand we're seeing, we may come close or get there. Again, don't want to be promotional, but I would say there's a much higher risk in 2021 of us having to cut Husky/Cenovus a check than 2020, and that's great news for our shareholders. That would mean we generate CAD 20-CAD 30 more of free cash flow from Prince George than we did in 2020.
I guess, really the last one. We talked a little bit about cash flow, maybe not keeping pace with EBITDA, and I think Joel Vorra kind of said it, a lot of that was interest expense that would presumably go away if you refinance Pioneer. Are there any other pieces to that puzzle as far as, is it either working capital, lease obligations, little things where you might pick up incremental cash flow, converting EBITDA into cash flow?
Yep. I think there's some smaller pieces. I'll let Joel jump in, but definitely interest in financing cost is a big one. The other piece to your point would be some of our lease costs. We have returned railcars here, even in Q1. Not a big material amount, but it will help. It'll help convert that EBITDA through to distributable cash flow. Joel, any other pieces? I think those would be the big ones. The good news is there's no additions coming to those lease costs. You will see that come down. I think the question will be how much. Should the market dislocate, we may potentially use some of the railcars that we are planning to return later on in the year. Nice to have that optionality. Today, we are planning to return so that number will continue to come down.
With renewables through to refined products, through to crude oil, the end of second half of 2021 is shaping up that we could take advantage of some of those opportunities. Joel, anything else in there that you want to let Curtis know that impacts?
No, I think those are the main pieces. The other piece, of course, would just even be EBITDA and general free cash flow from the base business when we started the year with last year around guidance of CAD 200 million and we came in at CAD 180 million. That's all cash flow. We were CAD 10 million less free cash flow in 2020. With that CAD 20 million addition, assuming we had hit guidance, we would've been a 20% increase year-over-year, even with the increased interest cost. You add a Pioneer closing on top of that and CAD 7 million-CAD 10 million in interest savings, we get to a higher number, potentially CAD 20+ million ahead of what 2019 was.
Yeah, Curtis, I think we touched on them, but those are the pieces, and you start to stack them up and you can see a path to material free cash flow generation and percentage increase year-over-year.
All right. Thank you.
Thanks, Curtis.
Again, if anybody would like to ask a question, please press star one on your telephone keypad. Okay. The next question comes from Ed Sollbach from Spartan. Your line is open.
Good day. In terms of financing, what are you looking at? Debt? Debt, I hope, right?
Well, project-level financing, which could be debt or equity or a working interest in the asset. I think we have a lot of work to evaluate our various options. It could range anything from project-level debt, our preference though, and want to be clear, our number one goal is to deleverage Tidewater. In my mind, there will be some sort of equity type of component at a project level. We are not planning to raise equity within Tidewater. I want to be crystal clear there. We have lots of options and interesting parties and have to work through the various options.
Oh, I see. You would sell the equity of the project to another entity?
Potentially. If the economics make sense, yes.
Okay. Yeah. I wouldn't want you to issue a company-level equity at these prices, certainly. Just a big question, in terms of your refinery, it seems like it's a pretty small refinery compared to other refineries that are out there. Can you maybe just kind of summarize the economics of it and how it falls out in the competitive landscape versus other competitors?
For sure. No problem. You're right. I believe if we're not the smallest refinery in Canada, we are definitely bottom decile as far as size goes. 12,000 bbl a day refinery. What we do have at the refinery is conversion units and a reformer, an ISOM unit, an FCC that help us convert 85% of our fuel to spec product. Although our inlet is about 12,000 bbl a day today we're producing between 10,500 and 11,000 bbl a day of spec ultra-low sulfur diesel and gasoline. I would say that's one of the key pieces that gives us a lift on our crack spread. We do, I feel and believe, we have the widest crack spreads in all of North America. The main driver there would be the Prince George diesel price.
If you go to Shell's website and you type in rack prices, you'll see every major Canadian city is listed, including Prince George, and you'll see our rack price on diesel is the highest in Canada, which will also equate to the highest price in North America. The big driver there is BCLCFS, but also some of the large capital projects that are right in our backyard. Today, we cannot keep up with the diesel demand that we are seeing at Prince George. You'd see Vancouver as the highest gasoline price, which is obviously right in our backyard as well. Today, we would see the highest gasoline prices at Prince George that we've seen since we've owned the refinery, before driving season, which has been quite a surprise to us as well.
If you think through the economics, I want to be clear too, we just run light crude for the most part. We don't run any heavy crude. Our feedstock cost, in general, is an Edmonton Light differential price, which today would be roughly WTI less $3 USD a barrel. 90% of our feedstock is priced there. Our end products, if we point you to, which is in public data, the Prince George rack prices, that'll enable you to run your own economics and say, Okay, I see your crack spread is roughly CAD 50 a barrel from the inputs and the outputs. Ed, is that helpful?
Yeah, no, that's good. Basically, you're saying you're the smallest, but you're the highest margin, which just kind of turns economic theory on its head. Why is that price so high there? Diesel is fungible, right? Wouldn't it be trucked in from other places where the price is lower? I don't quite get that.
No problem. There's only two refiners.
One more question. Do you think these high crack spreads remain, or is that a temporary phenomenon?
No problem. Within British Columbia, there are only two refineries. There's Parkland's Burnaby Refinery, roughly 60,000 bbl a day, and then there's ourselves at Prince George at 12,000 bbl a day. The BC market itself is significantly short product. Permitting a new petroleum refinery in British Columbia, I think as most know, is extremely difficult given the environmental regulatory environment. Our main competition would come from Edmonton and then also the Pacific Northwest, Washington State, and down into Northern California. There's next to no infrastructure in BC, especially around Prince George. We control the 1 ,000,000 bbl of storage, the truck, the rail rack, and to get that product into our backyard, into Kitimat, into Prince Rupert, is extremely difficult. It's more a function of the market being short. BC Low Carbon Fuel Standard credits are also a driver of the price.
BC is the only province in all of Canada with BC Low Carbon Fuel Standard credits, so that also drives up the price, and it creates a huge opportunity for us. Those would be the main reasons why does BC have such a high price on the refined product side. Is that helpful?
Yeah. Then do you expect this to last? Secondly, given that it seems to be a very profitable operation, would you have opportunities to expand it?
Do we expect it to last? Yes, we do. We just purchased and closed the refinery in November of 2019. I would say 50% of our time and effort and due diligence was on determining the margin. Will it hold? What risks are out there? You'll see when we press release the acquisition, in our view, after the work we did, we thought that the absolute worst-case scenario, I think, was a CAD 43 crack, and that was before COVID. COVID comes in and hits the refinery four months after we close. Most would expect in all other refineries across North America, they definitely went through their floors. Most were negative at times. On average, I believe crack spreads were zero to CAD 10 a barrel.
To see us through COVID, we definitely were stress-tested in 2020, and maybe we broke 45 for a period of days or maybe one week. In general, you'll see through our results that we held that CAD 45-ish crack, which I think proves our view and historical that that is the floor for British Columbia. I guess other things could happen. I would say there's never 100% guarantee, but COVID is probably the best-stress case scenario we could have for the refinery. Absolutely, we expect cracks to hold. We have been stress-tested, and obviously there's been other refineries that have shut in through California, through Canada, Come By Chance at times. Even through the Midwest and down into the Gulf, and through the forward strip on crack spreads across North America has widened. We think 2021 could be a great year.
We haven't released guidance, but are quite excited with what we'll see at the refinery as far as cash flow generation in 2021.
Okay. Lastly, would you have an opportunity to expand operations at your refinery?
I think our focus right now is a renewable diesel project, which is essentially an expansion, a standalone refinery right next to our refinery at Prince George. That's where we would receive the value of the increasing BCLCFS credits, but also the value of the new Canadian Clean Fuel Standard credits and also the diesel value, which is the highest market in North America. That is our focus right now. Yes, we have been debottlenecking the refinery and I believe if we're not at record throughput, we are darn close. We have been doing very small expansions, and I think to your point, we need to continue to evaluate an expansion at Prince George, but we'd have more work to be done there. Absolutely, it's possible.
Okay. Well, thank you very much, and congratulations.
Thank you, Ed. Thanks for your time.
I have no further questions. Thank you. I turn the call back over for closing remarks.
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Thank you, everyone. This will conclude today's conference call. You may now disconnect.