M&A Announcement

Oct 7, 2019

Press Release

Ladies and gentlemen, thank you for standing by, and welcome to the Tidewater Midstream and Infrastructure Limited PGR Acquisition Announcement Conference Call. At this time, all participants are in a listen only mode. After the speakers' presentation, there will be a question and answer I would now like to hand the conference over to your speakers today, Joel MacLeod and Joel Vora. Thank you. Mr. Joel Vora, please go ahead, sir. Thank you. Thanks everybody for joining us today on the call. Today with me is Joel McLeod, Tidewater's President and CEO. Before passing the call over to Joel for a review of the acquisition, I just want to remind everyone that some of the comments made today are forward looking in nature based on Tidewater's current expectations, estimates and judgments. Forward looking statements we express today are subject to risks and uncertainties and could cause actual results to differ from expectations. Further, some of the information provided refers to non GAAP measures. For more information about non GAAP measures, you can review our various financial reports available at tugwatermidstream.com or on SEDAR. With that, I'll pass it to Joel McLeod for a review of the acquisition. Thank you, Joel. Good morning, everyone. Wanted to start with a thank you to David Gardner and the entire Husky team because I think both sides will agree this is another win win transaction for both Tidewater and Husky. Husky is a key partner for us including another one of our core areas and we continue to grow our partnership with Husky. Also want to thank our credit syndicate for the support as to fund the acquisition of this size with a 5% to 6.5% cost of capital is almost unheard of for a company of our size and should provide comfort to the market around the quality of the cash flows of the refinery, the value chain addition and the current outperformance of the asset, which is expected to continue. To jump in to the call here, wanted to start by just emphasizing how pleased extremely pleased we are with the acquisition and it's truly once in a career transaction for us and a value chain addition at a price we would never dream we could get the asset at a 2x to 3x cash flow multiple. Being out at the refinery again on Friday and seeing the refinery is running near record throughput at roughly 11,500 barrels a day and continue to see crack spreads at $50 to $60 a barrel at Prince George with diesel cracks on a spot basis near CAD70 a barrel. The asset continues to heavily outperform our forecast and we have not factored in any upside where we continue to see significant upside with the Prince George and area market currently being short about 150,000 barrels a day of refined product. We are utilizing our $44 a barrel crack spread for a $75,000,000 forecast and have seen crack spreads continually achieve $50 to $60 a barrel over the past 18 months. The outperformance of the asset would enable us to deleverage quicker than we are currently forecasting and get us to our 24 month target of roughly 2.5 to 3 times debt to EBITDA. This also includes no upside being factored in, which we will briefly run through here in a bit. We have been clear with our Board that this is a transaction that will likely have initial negative response and may take weeks and or a few quarters of results before we see buy in from what is an extremely challenging Canadian energy market. We want to be crystal clear that the number one reason for the acquisition is the significant amount of cash flow from the asset, which will delever Tidewater and get us back to where we want to be, which was in the 2.5x to 3.5x debt to EBITDA range. Further, the accretion of 50% on an EBITDAcash flow per share basis is material to us and our shareholders and with the outperformance of the refinery, we start to see a clear path to self funding and significant free cash flow into the future. Current outperformance of the asset would drive accelerated deleveraging, which is a key focus for us and message we are receiving from our shareholders. The second and critical reason for the acquisition and it is very real is the addition to the Tidewater value chain. Initially, when we looked at the asset when the process began in early 2019, I would have said it would be a stretch to say that this would be a direct value chain add. But as we continue to spend time with the operations team and process engineers out at Prince George, we continue to hear loud and clear that 45 API crude condensate is the key feedstock for the refinery and optimizes diesel yields and gasoline yields, where the refinery produces 85% diesel and gasoline today. Further, 2 of our largest producer customers at Pipestone are 2 of the largest customers at Prince George and numerous producers have reached out to us since announcing the deal and are eager to look at long term contracts. Maybe just back to the value chain piece, want to be clear that Pipestone produces and today we're in the ramp up phase, but as we get to full ramp up into the end of the year, we expect Pipestone to generate 15,000 barrels a day of 40 API condensate slash crude, which is the ideal feedstock for this 12,000 barrel a day refinery. Prince George is a very real option for Montney Producers in BC and Alberta as it is only a 6 hour truck ride from Pipestone and roughly 4.5 hour truck ride from Dawson, Parkland, Taylor, BC. At a $7 to $9 a barrel truck cost from Pipestone, it is comparable to the current pipeline costs from Taylor at roughly 6 dollars to $7 a barrel, while the 45 API crudecondensate from Pipestone will result in higher diesel and gasoline yields. We will be working to explore longer term fixed fee take or pay tolling contracts and agreements at the refinery, which would also further reduce our volatility of cash flows around the asset. The offtake agreement would be the number 3 critical portion of the arrangement and the transaction and we spent a ton of time on the related offtake agreement. We relate to Husky that in order for us to move forward and having an investment grade offtake with take or pay components around volume and price was absolutely critical for us, and we would not have moved forward if we couldn't achieve the related offtake as messaging this acquisition and transaction is not going to be easy and we felt having an investment grade offtake and an offtake with take or pay provisions around supply and price was critical. There are financial penalties should 90% of the diesel and gasoline supply not be lifted. Based on market pricing, our price is clearly defined as a fixed discount to the Prince George rack price and the discount to the Prince George rack price has not moved by over $0.02 to 0 point certainty on price and volume. The offtake agreement results in 75% of Tidewater's pro form a EBITDA being under take or pay our long term commitments and 50% of our pro form a EBITDA being derived from investment grade counterparties, which we are extremely happy with. Maybe to jump in to a few other pieces. Some of the feedback we received from Friday has been around the historic EBITDA of the asset being roughly $50,000,000 and we would like to just hit this on the head and walk everyone through this. Through this time period 2013 to 2017, there were 2 turnarounds. So the plant was down for just over a month with both of these turnarounds. Further, one operational outage and in some cases, 2 per year were experienced by the refinery. But the most important fact would be the crack spreads. Crack spreads were $40 in 20.13, dollars 40 in 20.14, dollars 41 in 20.15, dollars 35 in 2016, dollars 40 again in 2017. But more recently, with the IMO requirements, low sulfur regulations, we saw $59 cracks in 2018 at Prince George, low 50s at the front end of 2019 and more recently we're closing in back into the $60 range on cracks at Prince George. So our $75,000,000 forecast is based off of $44 crack, which is in our presentation, and we continue see cracks north of $55 a barrel at Prince George. Just to quantify the potential impact, a $10 a barrel improvement in a crack spread on 10,000 barrels a day of diesel and gasoline production, which the refinery does today is approximately $35,000,000 of cash flow or EBITDA. So, it is material to us and would be material to our deleveraging. The vendors, kind of husky, the vendors forecast and other experts continue to forecast IHS included that with IMO, the related low sulfur requirements, we continue to see forecasts of 1 100 2020 2021 2020 2021 only, but the vendor did assign significant value to that and we continue to see forecasts in that range and or higher. But just wanted to be clear that that was a key component of the transaction and Husky did place value on those contingent payments. A big driver of the large diesel crack we're seeing today and have seen over the last 24 months is IMO and low sulfur requirements, also BC being short 150,000 barrels a day, but also pleased to not discount the demand from some of the projects in BC and we saw that firsthand being on-site on Friday. There is a demand pull from the Site C dam construction project to the north from Coastal GasLink from the LNG projects, including LNG Canada and also the potential Trans Mountain construction. So we are seeing increased demand from some very large construction projects in the area. Although we have not built in any upside to our $75,000,000 forecast, we do want to be clear that there from Pipestone into Prince George immediately and the reformer at the refinery does have spare capacity or even 500 barrels a day at a $55 crack would result in roughly $10,000,000 of EBITDA. Blending opportunities at Prince George are material as we have frac feedstock from our brass frac that are ideal for gasoline blending in addition to the ability to add butane blending with limited capital. Prince George Refinery will benefit from IMO as it produces low sulfur diesel and with the ability to blend ethanol, which it does today, biodiesel again does today, and the Prince George team has some great renewable energy projects, including processing canola oil. There are only a few assets in BC that have the ability to take advantage of low carbon fuel standards and Prince George is one that we're extremely excited about. Further, Prince George does have 1,000,000 barrels of tankage that we plan to contract out a portion of and the potential for Trans Mountain to expand could become a key storage hub for Trans Mountain moving forward. Maybe one of the most important pieces to me and the reason we went out to Prince George on Friday rather than taking analyst calls and investor calls myself. I know it's a draw held down the fort was just people. People are a huge part of the acquisition. We are ecstatic to have the entire Prince George team join the Tidewater family and it was key for me to be on-site on Friday to refinery. The runtime at the refinery is top quartile and is due to the Prince George team who continue to do an incredible job. Also want the market to be aware that our Board does have significant downstream experience. With Greta Raymond and Doug Fraser being on our Board, we're both executives or executives at refiners in Petro Canada and Husky and have been instrumental and heavily involved in the transaction. We have also engaged numerous refinery experts through our due diligence process and the resounding feedback is this is a once in a career type of opportunity at the multiple we've paid and the value chain synergies. There has been comments, just wanted to address a few of the comments we heard on Friday, some comments around our cost per barrel of through put and want to be clear after continuing to circle with our refinery experts that this is not relevant. If we're comparing a simple topping refinery and asphalt refinery to a refinery like Prince George that has an FCC, a reformer, a nice aromatization unit cannot compare a simple refinery to a complex refinery with an 85% diesel gasoline yield, but more importantly, cash flow. Comparing a refinery on the Gulf Coast or the East Coast with a $15 or $12 a barrel crack to a BC refinery or even an Edmonton refinery with a 30 dollars 40 dollars 50 dollars plus a barrel crack is not relevant and just want to hit some of those comments on the head where we would suggest and our refinery experts would suggest to focus on cash flow multiples and free cash flow multiples. One other comment we just wanted to address was around inventory. So the refinery historically has ran high inventories. There is 1,000,000 barrels of storage, which is great to have. We do plan to reduce inventory by approximately 25% and potentially more to free up the related working capital and also our related leverage. Some analysts are including the inventory in the purchase price and just want to clarify that you will see the inventory number move down over time as we look to deleverage and also just reduce the working capital crunch related to holding some of that inventory. With ore, I pass it over to Mr. Bora to see if he has any comments. I just want to reiterate that we are extremely pleased with the acquisition and the related outperformance of the asset, and I remain committed to adding materially to my current shareholdings per our July 23 press release, and I'm excited to do so. Thanks again to our shareholders, staff, Board, advisors for all your support as we are fully aware it may take a few quarters for the market to digest this acquisition and we are happy to be available for calls and or in person meetings. So, with that, I'll see if Mr. Bora has any comments and we can open it up to any questions. Yes. No, I think you covered the main pieces, Joel. Happy to open it up to questions. Thank you. Maybe we can just start with the deleveraging profile in the press release. The $810,000,000 pro form a net debt drops by about $100,000,000 by the end of 2020. But of course, that doesn't include any spend on a Pipestone Phase 2 next year. So just wondering if you could walk us through your thoughts on how you might look to fund a Phase 2 expansion while also trying to take down the balance sheet through 2020? No problem, Pat. I think with this acquisition and getting it over the goal line and one would admit at no point here over the last month where we 100 percent certain we were going to be able to get credit syndicate support at 5% to 6.5% interest to get the deal done. So, we'll need a little time, but as we're out at the refinery again on Friday and we continue to see outperformance and the related cash flow, to me it's feeling like we're in a much stronger position to fund Pipestone Phase 2. We do not necessarily have to move to a full blown joint venture and move assets into a joint venture when we realize the related cash flow and have seen proposals from parties to acquire working interest in Pipestone Phase 1 at a premium and also have ownership, small ownership in Pipestone Phase 2. We want to operate and control Pipestone Phase 1 and Phase 2, but there is more and more interest around us selling say a 20% to 30% working interest in Pipestone Phase 1 to fund Pipestone Phase 2. And now with this wall of cash flow, it's something we are going to strongly evaluate here over the coming months. Great. And what about looking at other non core asset sales within the portfolio? Absolutely. We need to remain focused And with the potential outperformance of the asset that we've acquired, it's a great time for us to consider non core asset sales. Again, we haven't spent a pile of time there, but we will over the coming months and we'd love to utilize proceeds or consider proceeds from non core asset sales to help fund a Pipestone Phase 2. We do not have to do anything. We're not required to monetize any assets, but absolutely we will be evaluating options to fund Pipestone Phase 2. Okay. And then just moving over to some of the commercial synergies from the Pipestone stone plant. And just wondering if we can get a bit more color on transporting condensate in from Pipestone to Prince George, boosting the margins and the EBITDA at Prince George, while also helping to improve the netbacks for your Pipestone customers. If you can just walk us through those dynamics? Yes. So cost to move a truck of condensator crude from Pipestone to Prince George, we would be a 6 ish hour truck ride or a $7 to $9 barrel cost, where our tolls on Pembina from Taylor today are in that $6 to $7 a barrel range. So, the incremental cost is not overly material to us, but the related yield improvement is significant, especially when we've got units that can have capacity like our reformer unit today. But where we'd like to head and even some of the initial feedback from some of the producers is to reduce our volatility and our cash flows, commodity exposure and we will be considering longer term contracts with our customers for a tolling arrangement where we could potentially receive, I don't know, dollars 35 to $50 a barrel fee to process their oil and give producers back that diesel or gasoline product when today diesel cracks at Prince George are 70 dollars a barrel, for example. We do not want to promise the market that we know we're going to get there in the next 3 to 6 months. But those discussions have started and there's more interest there than we would have anticipated. So if we could turn Prince George into more of a tolling cash flow structure, our sense is the market would prefer to reduce the volatility of our cash flows. And if we can transform a portion of those cash flows into tolling cash flow, it is something we're going to consider in addition to having barrels of storage on-site, which we can also likely contract out a portion if we wish to do so. Great. Last one from me guys if I could, just on the hedging policy for the asset. What percentage of annual production would you like to lock in going forward? And maybe you could just update us on what crack spread you could actually hedge at today through, say, 2020? Great. So Pat, I would say today we're evaluating. We've received quotes from large trade shops on hedging from our Edmonton light suite or a condensate price at Edmonton all the way through to a Prince George rack price on diesel and gasoline and also at Edmonton. That the issue we have is that the related financial institutions start to take pieces of those crack spreads the closer we get to a Prince George rack price. But if we continue to see diesel cracks move out, we are likely to hedge a portion of the related crack spread. Right now, it's receiving feedback and discussions with our Board. I can't commit to 50% of the related hedge or crack spread being hedged, but we are evaluating it as we speak. When we looked at historic crack spreads even over the last 6, 7 years, we didn't see them go under $35 And even in the past 18 months, it's been a consistent $50 barrel plus crack. So we just want to have some discussions with our key shareholders, our Board and then determine a risk management hedging policy around the asset, but we are evaluating. We definitely look to hedge Edmonton Light for example. We do that today on some of our crude moves. And when we see spot Edmonton Light at a -four differential and yet the forward strip at a -six dollars -seven that's an immediate $2 ish a barrel we can add to our profit. So you will see us hedge components. I think the question will be how much of that entire crack spread do we look to hedge over the next 12, 24, 36 months. To your question, how far out can you hedge? I would say we're definitely 2 years old, but as we start to get 3 4 years out, I'd hate to pound the table and tell you it's not going to be a problem. Okay. That's great, Joel. Thanks a lot. Your next question comes from Robert Kwan with RBC Capital Markets. Please go ahead. Your line is open. Great. Good morning. If I can just come back here to the leverage in that 2.5 to 3, that 24 month target. Is that based on underlying EBITDA of $75,000,000 for Prince George? So to get to end of year 2021, we would see 3x debt to EBITDA, Robert. Where we're saying there is potential to get to 2.5x is when we see the outperformance that we're seeing today and have seen over the last 18 to 24 months. So the 2.5 to 3 times, three times we're comfortable on our $75,000,000 forecast, dollars 2.5 would be based on the outperformance, but 2 we haven't factored in any upside into the asset as well. Got it. And then with that 24 month timeframe, is this how are you looking at that? Is that kind of a goal? Or are you looking at it more as a commitment looking at PGR plus say Pipestone 2, but not or anything else you get into will have to fit within that 2.5 to 3x range going forward? Yes. I mean, we have to be focused today. Pipestone Phase 2 would be our only true capital project and deleveraging is absolutely a focus and that message is well received from our shareholders. So could we commit to be in that 2.5 to 3 times in 24 months? Not at this time, but it is a target that we take very seriously and are working extremely hard to achieve and feel we can. Okay. And then just kind of a couple of smaller things here. Can you just talk about the maintenance CapEx, both what say a normal or a non turnaround year might look like? And then what does a turnaround year look like on the maintenance side? Yes. So over the past 7 years, we've seen years where it's sub $1,000,000 so let's exclude turnaround. So excluding turnaround, sub $1,000,000 but I'd say on average, we'd see $1,000,000 to $2,000,000 a year of maintenance CapEx. We would use $3,000,000 to $4,000,000 in our budgeting just so we have a cushion, but the key piece are those 3 to 4 year turnarounds, which are $30,000,000 to $40,000,000 We've been messaged by Husky and the team on the ground that potentially we can move to 4 years, but we for now are sticking to a conservative 3 year turnaround game plan at $30,000,000 to $40,000,000 expenditure. Okay. And then just last on the debt costs, I assume the base rates are floating. I'm just if that's true, are you looking at anything to hedge out your base rates? Mr. Voro, maybe I'll let you handle that one. Yes, we are, Robert. So, I think that's something we're evaluating daily and even today looking at those pieces again. So, yes, it's probably something that we'll look to lock in. Okay. That's great. Thank you. Thank you. Your next question comes from Brent Watson with Cormark Securities. Please go ahead. Your line is open. Hey, guys. Thanks. It sounds like a pretty clean facility. Just had a question around how decommissioning might show up there, if at all? And what a theoretical decommissioning cost might look like for that plant? Joel, do you want to handle that one? Yes. The decommissioning would be Brent would be close to, say, what we would see at a RAM facility. The footprint of the plant is similar to some of the other facilities. We have overall long term decommissioning and remediation would be in that $55,000,000 to $60,000,000 range. For accounting, we're still working through some pieces, but that likely doesn't end up on the balance sheet given the facilities considered sort of an indefinite asset given those 3 to 4 year turnaround. So but overall full site remediation would be in that 55 to 60 number. And I think just a few other points, Brent. One being, we continue there's ground monitoring wells, there's no material spills, continues to get better. The flow of the minor contamination is away from the river. We spent a pile of time on the environmental side and have a lot of comfort there. The other piece would just be the salvage value of the processing units are significant. They could be relocated to areas like Atchison and we'd be north of $600,000,000 of value related to the processing equipment to take light sweet crude to diesel and gasoline. Great. That's good color. Thanks. Your next question comes from Rob Hope with Scotiabank. Please go ahead. Your line is open. Good morning, everyone. Just 2 broader follow-up questions as most of my answers have been covered off already. But when you look at Prince George as well as the kind of Northeast BC area in general, we've seen a cracker potentially in the area as well as another straddle plant in the frac facility. You seem full up for capital over the next year, but longer term, could we see you move more into the chemical side up in that area? That's a tough one, Rob. Today, I think we need to focus definitely Pipestone Phase 2. The message loud and clear and I agree with our shareholders is focus, deleverage, continue to evaluate Pipestone Phase 2. I guess as you look out 2, 3, 4 years, it'll depend on our cost of capital. We have to ensure it's on strategy as well. I mean, if there was tolling arrangements around those assets similar to I mean, here it doesn't necessarily have tolling arrangements around AEF and butane, but I know Interpipe and Pembina are working towards tolling arrangements around their PDHPP facilities. We would consider those options absolutely. I think given we've got 1,000,000 barrels of storage, we could leverage that piece into helping others in the area and charge related fees. Our rail infrastructure is significant in the area. So I think there's definite synergies in ways we can help versus saying absolutely we'd commit, I don't know, dollars 1,000,000,000 petrochemical facility. I think at this point, it would be a bit of a stretch, but where we would evaluate and it will it would determine based off the opportunity as well. Sorry, yes, I was meaning more on the ancillary side with the storage in the rail. And then actually at TGR, can you just clarify how much rail capacity is there? So, in general, the C and ER, the large pulp and paper mills, chem trade offsets us. There is significant capacity. If you said no, Joel, what's just at Prince George today? They recently did an expansion here in the past 5 or so years. I would say 20 plus cars a day would roughly be the capacity and it's a little higher and we are looking at ways to increase capacity or leverage off of some of the CN yard and some of the other pieces in the area. But if we said in general 20 cars a day, we'd be comfortable with that number. There are our teams in the room, but there's 5 plus racks there as well and they are heavily underutilized. And the most recent rack that was put in is state of the art as far as blending and we are going to look to maximize the use of their $30 plus 1,000,000 rail blending facility. Thank you. Your next question comes from Robert Robertson with RHR Capital. Please go ahead. Your line is open. Good morning, gentlemen. There was mention made that I guess the CEO you John is pledging your shares to buy more of Tidewater. Is that valid? Has it happened yet? If so, what's the status of it? Yes. Unfortunately, we've been in blackout here for 6, 7 months, but kind of my last comment on the conference call absolutely remain committed and that was our July 23 release. So as soon as I'm given the green light from legal counsel and happy to move forward and excited to do so. Okay. On another issue, can you kindly explain the pricing review mechanism for the offtake agreement? The pricing review mechanism, so for the 1st 12 months, so there's a set discount. It's roughly $0.05 a liter for both diesel and gasoline for the 1st 12 months. There will not be a review. Post that, either party can request a review. And if we cannot come to an agreement, an independent arbitrator is assigned to determine that Prince George RAC discount. We spent a pile of time reviewing historical discount sales prices to the Prince George rack price and we did not see it move by more than $0.02 to $0.03 a liter. So we have a lot of comfort that there will not be a significant adjustment and we continue to be inbounded since the announcement on various parties wondering if they can get involved in the offtake. And for now, no, we've got a binding agreement with Husky and happy to have them as a partner. On the margins, can you kindly tell us what was the lowest margin that you've seen at the refinery in the last, let's say, decade? Yes. So 2016 on an annualized basis, you'll see from Slide 20 4 is a $35 a barrel crack, but we did get even into daily cracks and don't hold me to this, but I know we didn't see a number under $25 $26 a barrel on a daily number through the last 6 to 7 years. And even when we did see a daily move, it lasted 2 3 days, not for a month. Slide 24 would outline our crack spread review and the related data back 7 years. Thank you. And what would be your breakeven point? Breakeven on the refinery for us would be I mean on so on the $75,000,000 of EBITDA, we're using a 44 dollars a barrel crack. That is not breakeven. But for us, that is a number we're confident we're going to hit to achieve our $75,000,000 dollars of EBITDA and we are currently seeing cracks north of mid-50s. Yes, I understand that. But where would be your cash flow breakeven? Cash flow breakeven, we can come back to you. I would guess it's in the $20 to 25 dollars a barrel range, but even there, my sense is we'd be cash flow positive. Okay. I'll get back to you on that. Okay. Thank you. Thank you. Your next question here comes from Curtis Jensen with Robotti. Please go ahead. Your line is open. Hey, fellas. Hey, Curtis. Can you give me an example of a refinery operation that's got the sort of long term tolling arrangement that you're talking about in the press release? And would such a thing help insulate the business from crack spread volatility? So step 1, I'm not aware of a refinery with a 5 or 10 year tolling agreement with a producer, but we will reach out to some of our close refiner contacts during the next couple of days as I got to think there's examples of something close. I don't want to say a 10 year agreement where the refiners paid a crack rate, say it's a $44 a barrel fee and then the producer receives the related diesel or gasoline, but we can do some digging and come back to you. Absolutely, we feel it would if we could head in that direction and I'm not saying we are for sure, but want to explore those conversations with our producer counterparties. We do feel it would reduce the volatility of the cash flows. It would be similar to a gas plant where if we know our fee is $1 an Mcf and we produce condensate off the back of the plant that we market similar to refinery. If we know our fee is $44 a barrel to process their oil and then we market their related diesel or gasoline for them. And if it was a 10 year contract, then we know effectively what our margin or crack spread will be for the next 5 to 10 years. I do think there will be some interest for producers not to give us all their volume on those terms, but when the refinery is as small as it is to receive 1,000, 2,000, 3000 barrels a day from an entity that's 100,000 barrels and they get exposure to diesel and gasoline, especially when a diesel crack today is close to $70 a barrel and our forecast is based off of $44 a barrel. If they can see a lift of $5.10 in that case $25 a barrel, I think it's a discussion that parties are open to. Okay. And then I guess the other one, a couple of nitpicks maybe commentary, but you've been banging the drum on sort of delevering and I think your presentations have emphasized the intent to I don't know why I don't know why anybody talks about it because it doesn't seem likely to happen. It doesn't seem like you need you want to deliver or feel like it's important to delever the balance sheet when you seem to have access to capital on relatively attractive terms? So, I mean, to start, we've been messaging these 2 large capital projects, so $100,000,000 TransAlta, our share, $210,000,000 at Pipestone for 2 years. So we've been messaging our debt is going to ramp as we build out these 2 AAA assets, contracted assets into the end of 2019 or I guess September ish of 2019 to want to be clear. We haven't messaged, we couldn't message deleverage until after these assets come online. But I would agree with your comment that we've said once these assets come online, our plan is to deleverage and we'd like to be where we were 2 or so years ago at 2.5 to even one times debt to cash flow 2.5, 3 years ago. And we feel this asset with its current outperformance will enable us to be back in that range in a 24 month timeframe and maybe even quicker. Okay. And then and I'm going to just turn to the stock the share thing for a minute because if I'm remembering correctly from your AGM circular, 2 of your directors don't own any stock at all. Is that still the case, Greta Raymond and Cold Clue, I think his name is? We can confirm. I'd hate to say something and not be accurate there. They're big supporters, but happy to get your response on that question, Curtis. I can speak All right. And then I guess my last thing is just I've always felt like talk is cheap and you got to start walking the walk on your stock purchase or just drop it from the calls and your commentary because you're perpetually in a blackout period doing deals. So the idea that you're going to get in a press release or a commentary and say you really want to buy stock when you know damn well you're going to be blacked out for months going ahead on different deals, it's just disingenuous. So my recommendation is just to drop it. And just if you buy stock, just go out and buy stock. You don't have to be promotional about it. Yes. I don't feel I've been promotional from day 1 when we started the company. I committed $1,000,000 a year. I believe I've hit those targets. Thanks. Your next question comes from Elias Foscolos from Industrial Alliance. Please go ahead. Your line is open. Elias Foscolos from Industrial Alliance, please go ahead. Your line is open. Hi, good morning. One broad question to start with and I want to focus a bit on the optimization of the refinery. Was the idea of putting condensate into the was the idea of putting condensate into the refinery something that you came up with during the due diligence process? Or was this something that as you were looking at it, someone at the refinery tapped you on the shoulder and said, hey, if you do this, we can do that. Yes, I would say it was a combination of both, Elias. We have Board members with downstream experience, but also George Daneker, who I met when he was more at Chevron and Exxon and more recently he was Gibson's Chief Commercial So our question is, okay, walk us through what process units are being underutilized. There isomerization unit, which likes a high C5, C6 feed, which is BRC frac condensate, for example. But then the reformer, which is a big value piece of the refinery, loves a pipestone condensate feed. And the front end of the refinery right into the crude unit also loves the 45 API pipestone feed. So, I would hate to say it was all of us and we're the smartest guys. Stone feed. So, I would hate to say it was all of us and we're the smartest guys in the room. I would say it was a combination of the expertise on the Prince George side, some of our external consultants and a full team effort. Okay. Following up a bit on the tolling arrangement potential, question I'm going ask you again is a bit hypothetical. How much per barrel are you willing to give up to enter into a tolling arrangement? Mean there's a price of course if it doesn't work. Absolutely. And I think that's where we'll be evaluating and having some discussions with producers. We do not have to enter into tolling arrangements, but today would be a great time for us to have those discussions when spot diesel Prince George price is at $0.90 a liter which equates to roughly close to a $70 a barrel crack. Our forecast right now on the $75,000,000 of EBITDA is $44 a barrel crack. So I think most of our shareholders would say if you can lock $44 a barrel crack in $75,000,000 of EBITDA over the next 5 to 10 years do it. And on the producer side, they would see that today they've got potentially $20 plus a barrel upside in having access to diesel off the back of the plant. Okay. Sort of one last question and this is going to relate pretty directly So we're 45 days further on, a little more than So we're 45 days further on, little more than that. Do you think we're 45 days away on Pipestone 2? Yes, yes. I think we're in that range. WTI dependent, but we continue to see significant interest and more cash more cash flow and more options versus having to move towards a joint venture type structure if we wanted to move Pipestone Phase 2. So for me, it feels like this acquisition can help simplify the funding of Pipestone Phase 2. Your next question comes from David McCullough from Fort Washington Investment Advisors. Please go ahead. Your line is open. Hey, guys. Good acquisition. But just a quick question for you. You mentioned a lot about the contract costs and the potential for rail offloading at the refinery. Just to refresh my memory a little bit, would you take rail from Wembley down there? Or would you be looking at like Edmonton to potentially rail into Prince George or somewhere else? Yes. So rail would be unlikely to come from Wembley given our truck cost. I mean we could evaluate it, Dave, but I would say at this point you're more likely to see trucks move into Prince George. But at times, I mean, if condensate prices went to $10 $15 differentials and we have 1,000,000 barrels of storage At Prince George, we would look to put discounted volumes into storage. We have received freight rates and I know with CN their freight rates are confidential. So I'll give you a ballpark rates, but they're the lowest freight rates I've seen on any move. And Husky in the past has asked us to quote freight rates into Prince George and supply like crude by rail, but we would be in $3 to $4 a barrel range on the freight rate from Edmonton Canadian, which is pretty attractive to us as well. Definitely. All right. Thanks. Appreciate that, guys. Thank you, David. Your next question comes from Patrick Kenny with National Bank Financial. Please go ahead. Your line is open. Yes. Quick follow-up, guys. I know the focus of the call is on the acquisition. But while we got you, maybe an update on the base business, just given we've seen frac spreads come down a little bit recently and also had NGTL revise its priority access into storage, which I'm not sure if that would impact your storage margins or not, at least over the near term. But maybe just an update on some of the moving parts for the base business and what gives you confidence in the sustainability of that $130,000,000 run rate EBITDA guidance by starting next year? Yes. I'd say, Pat, overall, our base business would be in line. In no way is it outperforming today, but it would be in line. Our gas storage assets continue to do well and act as a natural hedge when we see these low gas prices and we do see some reduced throughput at some of our facilities. Pipestone coming online as we press release is huge for us and do see potential outperformance as it fully ramps into December and into January, given there continues to be more demand for Pipestone and we're fully contracted at Pipestone. So gas storage going well, Pipestone going well, need some time here to ramp up. But I'd say feel confident that we're in line with our base business, but want to be clear, we're not seeing heavy outperformance in our base business. And I'm showing no further questions in the queue at this time. I will turn the call back over to Mr. Joel McLeod for any closing remarks. No, just want to reiterate how excited we are about the transaction and really more than happy to answer the tough questions. A transaction that will take some time and more than happy to answer the tough questions. So thank you everyone for your time today. And ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.