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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Ladies and gentlemen, thank you for standing by, and welcome to Tidewater Year-End 2020 Financial Results. [Operator Instructions] Please be advised that today's conference 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, I 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 about -- 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 $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 #1 priority remains deleveraging and free cash flow generation, and we are confident in our ability to achieve our target of 3.25 to 3.5x 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 6 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 deleverage 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 standards, BC-LCFS compliance costs and rents. These initiatives include opportunities in renewable diesel, coprocessing, 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 $225 million. We have received approximately $100 million of grant funding from the BC government in the form of BC-LCFS credits and do want to thank the BC government for all their support. As a result, our net capital contribution would be approximately $125 million, and we do expect the asset to deliver over $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% to 90% and 65% to 75%, respectively, versus conventional diesel, which represents the equivalent of removing approximately 70,000 to 80,000 vehicles from the road annually, impressive returns for a renewable energy project, where diesel demand in BC remain 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 deleveraging Tidewater. We also have 2 other capital projects, including our canola coprocessing project, which does come online Q4 this year and has been funded 100% with the support of the BC government in the form of BC-LCFS credits, where Tidewater's net capital contribution is 0. We were also happy to sign an agreement with the BC government for their support on an FCC coprocessing project, which will come online in 2023 and will start in 2022. The capital spend will start in 2022 with the payout of approximately 1 year inclusive of the BC government's support. As we mentioned in our Q3 conference call, the amount of government outreach stimulation 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 $100 million of support and do expect to see incremental support from governments in the next 60 to 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 our carbon capture initiatives. We do want to thank the provincial and federal governments for all their time and support to date, where we are also seen as a leader in the hydrogen perspective and business by the provincial and federal governments as we have existing hydrogen production today at Prince George and has been operated for 30-plus years. And 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 in our asset gas injection wells and related reservoirs at Pipestone and Atchison and our operating gas storage assets at Brazeau River and Pipestone Gas Storage. Again, 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 barrels 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. So again, huge accomplishment by our team in a COVID year to have record refined products sales, it's something 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 $10 per barrel move in the crack spread would result in north of $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, run times 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 Place, which is great for our terminaling activities and the related gas plant. The gas plant does remain fully contracted and backstopped by 2 10-year 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 in GHG and being a leader in clean fuel standards. On another note, in January 2021, the government of Canada's $750 million emissions reduction fund endorsed 2 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. And 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, and 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. So I'll give an overview of annualized results year-over-year, 2019 to 2020, and then also quarter-over-quarter Q3 to Q4. Obviously, 2020 was characterized, I think, for everybody by the impact of COVID, especially in the first and second quarter, where we did see a 10% to 15% impact to our annual results or where guidance would have been at the beginning of the year. But 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, but with that said, didn't quite deliver the distributable cash flow we would have forecasted, we do expect that to improve into 2021. And as our focus to continue and increase distributable cash flow, reduce leverage, reduce borrowing costs and increase related EBITDA and cash flow. But with that, quarter-over-quarter, our revenue was in line in Q4 compared to Q3 at around $274 million. Our annual revenue was up significantly, $979 million compared to $692 million in 2019. The 40-ish percent increase is mainly attributable to the refinery acquisition. Gross operating margin adjusted for hedges was approximately $52 million for Q4 compared to $48 million in Q3. And also an increase in adjusted operating margin percentage of approximately 17% to 19%, and I think just reflecting a continued recovery in the economy and prices and our overall base business. Annual adjusted operating margin was approximately $190 million, again, adjusted for hedges, versus $122 million in 2019, and, again, approximately 17% to 19% -- 17% increase up to 19% in adjusted operating margin year-over-year, again, a contribution from the refinery. And as we continue to see Pipestone improve run times and move up to consistent nameplate capacity throughput, we'll continue to see those margins increase slightly. Adjusted EBITDA for Q4, you all noted was approximately $48.8 million compared to $47.6 million in the third quarter, again, continued recovery in prices and the overall economy. We did see -- we did see some restrictions and lockdowns in December, which slightly impacted the quarter. But again, overall, as those pieces are lifted, we continue to see outperformance in the assets, the refinery specifically. Annual adjusted EBITDA was approximately $180 million, which would have been the midpoint of our guidance -- of our revised guidance once we assess the impacts of COVID and shutdowns compared to $110 million in the prior year. And again, annual EBITDA margin increased approximately 2% from 16% to 18%. And again, we expect that to continue to increase as we move into recovery and more of -- I think, more of a stable economic outlook. On the distributable cash flow front, probably the most important piece to us. We were $13.5 million in the fourth quarter compared to $10.5 million in the third quarter. Again, annually, $47 million in 2020 versus $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, $7 million to $8 million in cash from the reduction and leverage from bringing those proceeds in. And 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% to 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 run times at Pipestone and some of our other larger assets. Again, to reiterate Joel MacLeod's comments, free cash flow leverage reduction is the #1 focus of the company. And, at the same time, we do see -- 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. So overall, 2020, a bit of a -- 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 that performed quite well. But that being said, still work to do to get to where we need to be on the free cash flow front and leverage reduction, but it 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.
[Operator Instructions] Your first question comes from Cole Pereira from Stifel.
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.
So 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. But do we have a Plan A right now? No, we just have seen significant interest and need CIBC and National Bank to help us evaluate all our options.
Okay. Got it. That's helpful. As well, with the BC credit, can you just clarify exactly how those would be realized, i.e., over what time frame?
So the grants themselves, on a Part 3 agreement with the BC government, there's milestones that need to be achieved and then you'll receive a tranche of credit. So our existing canola coprocessing project would be a great example. So it comes online here in Q4 2021 of this year. It started back in 2018. And as -- so even before we own the refinery. When Husky completed the FEED study, they were allocated BC-LCFS credits. You've provided a set number of credits. So if the value moves up, and we have seen values, and if you go to the BC government website, you'll see the value of BC-LCFS credits from 2018 to, say, more recently in February, have gone from roughly $150 a credit in 2018 through to $430, $750, I think, is the average transfer that happened here in February. But with the agreement, we're giving a set number of credits, and then we're allocated those credits as we hit milestones. So 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 BC-LCFS credit. So that value of BC-LCFS 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. And so I mean, as we think about the capital cost of $220 million prior to the grant, call it, EBITDA of $75 million, obviously, that's a pretty attractive EBITDA payback. So I guess, I mean, 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?
Yes. I mean, we probably won't go way down into the weeds, but want you to be aware of the key variables. So the #1 variable is the carbon intensity of our end product, which we do expect to be in, and we are trying to relay the carbon intensity reduction, but it would equate to roughly a 20 carbon intensity, which is that 80% to 90% reduction versus conventional diesel. So that related carbon intensity is key in determining how many BC-LCFS credits we generate every time we sell a molecule of that end product into the market. And when we've seen BC-LCFS credits move from $150-ish in 2018 to $300-ish of credit, I'd say, 6 months ago to today, in February, a large number of BC-LCFS credits trading at $435. Just know that's a big driver of the cash flow. We've tried to be conservative in our numbers, and we haven't included the Canadian clean fuel standard credits, which would be incremental as well. But just trying to help educate yourselves and others that the carbon intensity of our fuel is the main driver of the credit component. Then we would also be paid a Prince George rack diesel price as we're selling that diesel molecule as well. So in general, the the carbon credit benefit is about 60-ish percent of the margin. We can recalculate. I'm just trying to help to give you kind of ballpark components and then the diesel itself would be the remaining piece. But happy to jump on a call and give you a little more detail, if you like. I hope that was helpful.
Your next question will come from Robert Kwan from RBC Capital Markets.
I just want to kind of dig a little bit more into the financing side and understand some of the wording that you're using. So no increase in corporate debt and the #1 priority is to delever. Now is that to delever into that 3 to 3.5x range? Or is it to delever into the 2.5 to 3x long-term range?
Yes it's a good question, Robert. I would say, ideally we get down into the 2.5 to 3x range, but it will depend on the terms and are related options. #1 is to deleverage. So we do want to be back 2 or 3x debt-to-EBITDA with Pioneer closing. As you're well aware, we get to 3.5x. With our free cash flow for the year, we feel we get close to 3x. But 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. But to your point, it could result in even us moving closer down to 2.5x.
And would you -- during the multiyear construction, would you be comfortable flexing above that 3.5x range and then exiting back? Or is that whole -- no increase in corporate debt going to be of an absolute constraining factor and one that you will not allow debt-to-EBITDA to go about 3.5x if you go forward with us?
I'm definitely at 3.75 to 4.0x. 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 [Audio Gap] above 3.5x. That is not our #1 priority now or our best option. But would hate to say, there is no way we will be over 3.5x. I think as we get to 3.75x and a 3.75x to 4x, we do not want to be in that range again. And our goal would be to be at 3x in the next 12 months.
If you did it on a nonrecourse 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 nonrecourse basis, we'd like to stay under 3.75x in aggregate. We know our shareholders, our Board do not want to see our debt levels above 3.75x. And ideally, we get down into that 3x debt-to-EBITDA range.
Okay. I'm just looking at your slide deck, just turning overall on the debt side, it looks like the debt reduction exiting 2020 and your 2021 forecast is largely just the Pioneer proceeds coming in. Given the FFO you're generating and the dividend being modest, are you building in material CapEx associated with this project, even though it hasn't been sanctioned yet or just, I guess, what's driving free cash flow being flat?
We're trying to be conservative. I'll let Joel jump into the details though.
Yes. I think, Robert, we haven't formally put out guidance yet. I think you'll see that from us in the next little bit. But there would be some -- 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. But yes, to answer your question, there would be some CapEx built in to that number, but I'm not going to sit here and tell you it's XY to this project or that project. But just want to be -- just want to keep it to some ranges for now until we come out with formal 2021 guidance.
Got it. And if I can just finish on the payout ratio, the 20% to 25%. And Joel, you mentioned, it sounds like there's a decent chance you'd kind of at the lower end of that range. Is there an assumption -- that an assumption there just on the dividends? And 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?
Yes. 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. So we would be factoring in economic recovery. But to your question, I do think there's a decent chance that we can beat that based on what we're seeing today. But 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. So 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 at some point, there could be an increase. But we need to show deleveraging and free cash flow before we come out to the market with a dividend increase.
[Operator Instructions] Your next question comes from Rob Hope from Scotiabank.
Have a follow-up question to Robert's question there. Just on the 2021 guidance, even though you're not putting out formal guidance that you did say that you're getting kind of back into the original guidance that you gave in that '20 -- earlier in 2020, which was, we'll call it, $200 million to $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 in volumes. And then, I guess, specifically, where you came in on PGR, and kind of what your expectations are for 2021?
Yes. I would say you hit the 2 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% to 15% range. And today, where you see -- when you see -- I mean, frac 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. But 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. So that may be one piece that would be down a little, but still it's generally largely contracted. So there isn't a ton of volatility in the base cash flows. But 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. And then Pipestone to be able to run at nameplate capacity is going to significantly help those cash flows. And then Prince George, today, is running pretty near, I wouldn't say the top margins we've seen that were pretty high at the end of 2019, but running pretty well and then throughput is essentially near or at all-time highs and lifts are very strong. So those would be the types of things we're factoring into 2021. But 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. So I think we want to be just careful there. But did I answer your question?
Yes. That's great. And then turning over to the renewal projects that you were speaking of. So I understand that it looks like the key bottleneck right now for an FID is financing. But 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 be there? And kind of just to better understand kind of the time line there?
Yes. No problem, Rob. So if we look at the project, I would say it's about -- been about a year of evaluation, mainly internal resources. So we haven't allocated significant capital, but we have engaged Haldor Topsoe, who has 80% market share in renewable diesel. So I would say we're into feed today. Our goal would be to be online in early 2023 should we be able to, to your point, achieve a financing plan here in the next 60 or so days. So we'll be spending the next couple of months to work through our financing plan, and 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.
Your next question will come from Curtis Jensen from Robotti & Company.
Can you hear me all right?
Yes. Curtis, we're good.
Just thinking about the Pioneer sale again. I mean watching the back and forth at the Utilities Commission, I mean, 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. But as far as new material information or concerns that have come through the process, there hasn't been any, and we remain confident. And I think you'll see our partners and ATCO through the other involved parties continue to relay Q2.
I mean 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, I mean, is there kind of a plan B? Or is that -- do you think it's such a remote possibility that you'll just cross that bridge when you come to -- if it comes to that?
Yes. We would be high 90 certainty. Again, 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, but there would be significant interest on a 15-year take-or-pay asset, even if we did head down that path, but we're not. We're confident that we'll close in Q2. And happy to answer any other questions.
Just a couple more. I mean given what's happened to spreads and kind of rates generally, are there -- you kind of identified some areas that -- were you able to close Pioneer this -- in the next quarter, there's some potential for refinancing on attractive terms?
Yes. So as you're well aware, and I'm sure most on the call, the high-yield market has been fairly hot. One piece for us was getting this press release out just so we didn't -- we weren't sitting on any potential material information. So we are eager to explore and speak to high-yield investors and explore the potential refinancing of our notes. And to your point, we don't want to sit around. The market feels 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 has been phenomenal. So the good news is, we're not on a -- under any pressure, but we don't want to sit around. If the market is 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.
And then the last one, I guess, I mean, refresh my memory, was there -- does Husky have an earn-out potential based on the performance at Prince George? For 2020, is any of that -- or is there a potential earn-out for them based on -- it seems like volumes and crack spreads were pretty good, at least in the last half of the year and...
Good question. I need to review that agreement, but I'm 99% sure, Curtis, that no. And I believe the threshold, we can -- we will confirm and come back to you. I think the threshold is $100 million of EBITDA before IFRS adjustments. So yes, we had a great year, very happy. Our frac -- our crack spreads would have been near kind of our base $45-ish for through COVID. Obviously, they've improved significantly now. But I would say a 99% or high 90 certainty, we will not have any contingent payments to Husky/Cenovus for 2020, 2021, I mean, we're only 3 months in, but it looks like a much different picture as far as potentially being close to that $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, I 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 as that would mean we'd generate $20 million to $30 million more of free cash flow from Price George than we did in 2020.
And 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 a lot of that was interest expense that presumably go away if you get refinanced Pioneer? And are there any other pieces to that puzzle as far as -- is it either working capital, lease obligations, little things that -- where you might pick up incremental cash flow, converting EBITDA into cash flow?
Yes. 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 do -- we have returned railcars here even in Q1, not a big material amount, but it will help. It will help convert that EBITDA through to distributable cash flow. And Joel, any other piece? I think those would be the big ones. There's -- 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. And then should the market dislocate, we may potentially use some of the railcars that we are planning to return later on in the year. So nice to have that optionality. Today, we are planning to return so that number will continue to come down. But 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. But 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 around -- last year around guidance of $200 million, and we came in at $180 million, that's all cash flow. So we were $10 million less free cash flow in 2020, with that $20 million [Audio Gap]assuming we had hit guidance, we would have been a 20% increase year-over-year, even with the increased interest costs. So then you add a Pioneer closing on top of that and $7 million to $10 million in interest savings, then we get to a higher number, potentially $20-plus million ahead of what 2019 was. So yes, Curtis, I think we touched on it, but those are the pieces. And you start to stack them up, and you can see a path to material free cash flow generation, a percentage increase year-over-year.
[Operator Instructions] Your next question comes from [ Ed Saloba ] from [ Spartan ].
So in terms of financing, what are you looking at debt or -- debt, I hope, right?
A profitable 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, but it could range anything for project level debt. Our preference still and want to be, say, our #1 goal is to deleverage Tidewater. So 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. But we have lots of options and interesting parties and have to work through the various options.
Oh, I see. So you would sell the equity of the project to another entity?
Potentially, if the economics make sense. Yes.
Okay. Okay. Yes. I wouldn't want you to issue the company level equity at these prices, certainly. And 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. So 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. So you're right. I believe if we're not the smallest refinery in Canada, we are definitely bottom decile as far as size goes, so 12,000 barrel a day refinery. But what we do have at the refinery is conversion units in a reformer, an isom unit and FCC that help us convert 85% of our fuel to spec product. So although our inlet is about 12,000 barrels a day today, today, we're producing between 10,500 and 11,000 barrels a day of spec ultra-low sulfur diesel and gasoline. So I would say that's one of the key pieces that gives us a lift on our crack spread, and we do -- I feel and believe we have the widest crack spreads in all the North America. The main driver there would be the Prince George diesel price. If you go to -- you don't need to log in. 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 BC-LCFS, but also some of the large capital projects that are right in our backyard. And today, we cannot keep up with the diesel demand that we are seeing at Prince George. Then you'd see Vancouver as the highest gasoline price, which is obviously within -- right in our backyard as well. And 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. So 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. So our feedstock cost in general is an Edmonton light differential price, which, today, would be roughly WTI less USD 3 a barrel. So 90% of our feedstock, our feedstock is priced there. And then our end products that we point you to, which is in public data, the Prince George rack prices, that will enable you to run your own economics and say, "okay, I see your crack spread is roughly $50 a barrel from the inputs and the outputs." Is that helpful?
Yes. No, that's good. So you -- basically, you're saying you're the smallest, but you're the highest margin, which is kind of turns economic theory on its head. But like -- and why is that price so high there? Like oil is -- diesel is fungible, right? Could -- wouldn't it be trucked in from other places where the price is lower? I don't quite get that. And yes, one more question. And do you think these high crack spreads remain or is that a temporary phenomenon?
No problem. So within British Columbia, there's only 2 refineries. There's Parkland Burnaby Refinery, roughly 60,000 barrels a day, and then there's ourselves at Prince George at 12,000 barrels a day. So the BC market itself is significantly short product and permitting a new petroleum refinery in British Columbia, I think, as most know, is extremely difficult given the environmental regulatory environment. So our main competition would come from Edmonton, and then also the Pacific Northwest, Washington State and down into Northern California. But there's next to no infrastructure in BC, especially around Prince George. We control the 1 million barrels of storage, the truck, the rail rack and to get that product into our backyard, into Kitimat, into Prince Rupert, is extremely difficult. So it's more a function of the market being short. BC low-carbon fuel standard credits are also a driver of the price. It's the only -- where BC is the only province in all of Canada with low-carbon fuel standard credits. So that also drives up the price, and it creates a huge opportunity for us. But that -- those would be the main reasons why does BC have such a high price on the refined product side. Is that helpful?
Yes. And then do you expect this to last? Or -- and secondly, are there -- given that it seems to be a very profitable operation, would you have opportunities to expand it?
So do we expect it to last? Yes, we do. We just purchased and closed the refinery in November of '19. And 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? And 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 $43 crack, and that was before COVID. So COVID comes in and hits the refinery 4 months after we close. We -- most would expect in all other refineries across North America, they definitely went through their floors, most were negative at times. And on average, I believe crack spreads were kind of 0 to $10 a barrel. But to see us through COVID, we definitely were stress test in 2020. And and maybe we broke $45 for a period of days or maybe 1 week. But in general, you'll see through our results that we held that $45-ish Canadian 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 a COVID is probably the best stress case scenario we could have for the refinery. So absolutely, we expect cracks to hold. We have been stress tested. And then obviously, there's been other refineries that have shut in through California, through Canada, come by chance at times. But even through the Midwest and down into the Gulf, and you'll see the forward strip on crack spreads across North America has widened. So 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. And then lastly, would you have an opportunity to expand operations at your refinery?
Yes. I think our focus right now is the renewable diesel project, which is essentially an expansion, a stand-alone refinery right next to our refinery at Prince George. And that's where we would receive the value of the increasing BC-LCFS 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. So that is our focus right now. But yes, we have been debottlenecking the refinery, and I believe if we're not at record throughput, we are darn close. So 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. But absolutely, it's possible.
I have no further questions in queue. 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.