Tidewater Midstream and Infrastructure Ltd. (TWM) Earnings Call Transcript & Summary

Ladies and gentlemen, thank you for standing by, and welcome to the Tidewater Midstream and Infrastructure Year-End 2019 Earnings Results. [Operator Instructions] And please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Joel Vorra, CFO. Thank you. Please go ahead.

Thank you. Hello, everybody. On the call with me today, as usual, is Joel MacLeod, Tidewater's President and CEO. Before passing over to Joel to give an overview of the quarterly highlights, I just want to remind you that some of the comments made today are forward-looking in nature based on our expectations, estimates and judgments. Forward-looking statements we express today are subject to risks and uncertainties that may cause actual results to differ from expectations. Further, some of the information talked about today are non-GAAP measures. And to know more about these forward-looking statements and non-GAAP measures, please refer to our various financial reports, which are available on our website at tidewatermidstream.com or on SEDAR. With that, I'll pass the call over to Joel MacLeod for an overview of the quarter and 2019 year.

Thanks, Joel. Good morning, everyone, and thanks for joining our year-end 2019 conference call. Looking at our share price over the last few weeks and even months has been extremely frustrating and want all our shareholders to know we are working harder than ever and we are very confident in our ability to: number one, deleverage; two, double our EBITDA per share year-over-year 2019 to 2020; and three, which is becoming more paramount to us and our shareholders, which is to deliver shareholder value in 2020. We are taking the severe downturn in the energy industry very seriously. Low commodity prices, and more specifically, WTI crude oil prices below $40 have been a key risk since inception that we have identified. We have been focused on growing and acquiring defensive assets that do well in a low-commodity environment, while also materially improving our customers and contracts. These defensive assets include our gas storage assets, which are contracted to over 5 investment-grade counterparties, our Pioneer Pipeline, and more recently, our Prince George Refinery, which also has a 5-year offtake with an investment-grade counterparty. Approximately 50% of our cash flow is now derived from investment-grade counterparties, which is critical in an extremely challenging energy environment. The Prince George Refinery is now our largest defensive asset and continues to deliver adjusted EBITDA of over $75 million even at WTI priced in the 30s. The announcement of the sale of the Pioneer Pipeline today reiterates our focus on our #1 priority of deleveraging, and we expect to achieve our forecasted adjusted EBITDA range of $200 million to $220 million for 2020. Exit net debt to adjusted EBITDA for 2020 pro forma the Pioneer Pipeline sale is expected to be approximately 3x. I'm not aware of another company with an approximate $1 billion enterprise value that will reduce their debt levels by almost 2 turns while growing EBITDA and cash flow per share by approximately 100% from 2019 to 2020. Our #1 priority, following on delivering shareholder value in 2020, is to deleverage. We are confident in our ability to bring our debt-to-EBITDA down to 2.5x to 3x over the next 12 to 18 months. Our contracted cash flows continue to account for over 70% of our EBITDA, with approximately 50% of our EBITDA coming from investment-grade counterparties. We are pleased to announce the sale of the Pioneer Pipeline today for $138 million of proceeds, where we do expect to replace the EBITDA with other commercial arrangements, including gas storage, and are eager to grow our partnership with both TC Energy and TransAlta. Commercial terms are expected to have similar contract points as the 15-year take-or-pay. Given some of the research notes that have gone out today, we just wanted to clarify that total proceeds are $138 million to Tidewater, while lost EBITDA is minimal with a downside scenario of approximately $3 million on the EBITDA front and an upside scenario of being even slightly net positive on the EBITDA front after the disposition. I also wanted to clarify that no additional capital is required by Tidewater. That said, we do lose a key take-or-pay contract with an incredible counterparty and partner in TransAlta that are looking at incremental contracts with similar term. Working with TransAlta over the past 3 years has been an absolute pleasure, and we wish to thank Brett, Dawn and the entire TransAlta team for all their support and look forward to growing our partnership and supplying them with low carbon-intensive Alberta-based natural gas. We also wish to thank TC Energy and their entire team, as they were an absolute pleasure to work with. And as Albertans and Canadians, we greatly appreciate their efforts in pushing for market access across Alberta and North America for Canadian resources. I also want to thank Toby, Reed, Vanni, Scott and our team for all their efforts on a transformational transaction that couldn't have been better timing, given the turmoil in the market today. Continue to work through a few other small noncore asset dispositions, which will further deleverage Tidewater and also focus Tidewater on our larger core contracted assets. Counterparty risk has been a daily discussion this week and I want to reiterate that our 50% of our EBITDA is from investment-grade counterparties, with Husky being our largest customer on the 5-year offtake at Prince George. We have 2 investment-grade counterparties at Pipestone. We have over 5 investment-grade counterparties in our growing natural gas storage business. We have an investment-grade counterparty at Brazeau and an investment-grade customer at Ram River. Our NGL, crude oil and ethane counterparties are almost all investment-grade. We also want to reiterate that over 70% of our EBITDA is derived from take-or-pay contracts and long-term agreements. One key positive of the dramatic drop in crude price has been the reaction of AECO natural gas prices, which has -- have moved up materially and are currently around $1.90 an Mcf for the remainder of 2020 and are in contango. Our smaller natural gas weighted producers and customers have not seen natural gas prices at these levels for a while, and it is very helpful to our customers and our gas processing business unit. The natural gas volatility is also very helpful to our natural gas storage business. As all are likely aware as well, our Prince George Refinery remains hungry for low-priced oil supply, and our underutilized 1 million barrels of storage at Prince George is positioned well to take advantage of contango in the current market. Back to our Q4 results. Our Q4 was in line to a slight beat, where we delivered our best quarter since inception at $40 million of adjusted EBITDA and an approximate 90% increase over Q4 2018. We do expect to see continued EBITDA per share growth through 2020 with the ramp-up of Pipestone in Q1 and are guiding $200 million to $220 million of adjusted EBITDA in 2020, with debt-to-EBITDA of approximately 3x at the end of 2020 and 2.5 to 3x debt-to-EBITDA in 12 to 18 months pro forma the Pioneer disposition. Prince George continues to outperform, and we look forward to delivering our first full quarter of Prince George results in Q1. There has been a lot of market chatter over the last few weeks that we have significant commodity exposure and Prince George cracks could collapse. We continue to see Prince George cracks exceed our forecasted $44 per barrel crack even at USD 30 WTI, and Prince George continues to demonstrate it is a critical diversified cash flow stream that continues to help accelerate our deleveraging. While deleveraging remains our focus, we continue to see several downstream-related projects that are under 24-month payouts. Capital expenditures are currently planned to be minimal in 2020, as we focus on deleveraging, but do want our shareholders to be aware that we have a significant inventory of 50-plus percent rate of return projects. At Pipestone, we began processing natural gas and natural gas liquids in mid-September 2019. Throughput continues to increase, with December 2019 averaging over 50 million cubic feet a day and the first 45 days of 2020 averaging throughput of approximately 65 million cubic feet a day. The Pipestone plant experienced operational issues during fourth quarter commissioning and was restricted due to third-party pipeline infrastructure, which is expected to be fully completed at the end of the first quarter of 2020 here in a couple of weeks. We expect to increase throughput to near full capacity by the end of first quarter of 2020. The Pipestone Gas Plant is fully contracted with no space currently available. On the ESG front, we believe we are becoming a leader within the oil and gas sector. As with our integrated network of infrastructure assets, we are well positioned to be an important part of this evolution, including distribution of clean natural gas to TransAlta's coal-fired power-generating stations that are converting to natural gas. Further, Prince George Refinery is one of the only refineries and assets in Western Canada that can utilize renewables. Canola oil, biodiesel and ethanol can be utilized at the refinery to help reduce our carbon footprint along with several other green initiatives. Our recently established -- we recently established an Environmental, Social and Governance Committee comprised of myself; Mr. Vorra, our CFO; our Chief Legal Officer, Mr. Barva; our VP, HSE&R, Scott McLean, to our efforts in measuring and reporting on our ESG metrics and improving our ESG performance. We are also excited to announce that we plan to expand our Board of Directors with the addition of Mr. Michael Salamon, and Mr. Neil McCarron of Birch Hill Energy (sic) [ Equity ] Partners. Birch Hill has been a strong supporter of Tidewater since early 2018 and currently holds approximately 22% of Tidewater's issued and outstanding common shares. Birch Hill is a leading Canadian mid-market private equity firm with approximately $5 billion in capital under management and a 25-year history of driving growth and delivering returns to investors. Great to have support from a large capital provider with a strong track record in an extremely challenging energy environment and look forward to working with Michael and Neil. Our focus over the next 6 to 12 months continues to be to harvest the related cash flow from our large capital projects in the Prince George Refinery acquisition. We plan to deploy minimal growth capital in 2020, but want our shareholders to be aware, we are building a significant inventory of capital projects with sub-2-year payouts. As discussed within our Q3 release, we have decided to delay the expansion of the Pipestone Phase 2 plant until further notice and focus on deleveraging over the next 6 to 12 months. We are committed to reducing overall leverage through 2020 back to our historical levels at 2.5x debt-to-EBITDA over the next 12 to 18 months. Oil and gas and small-cap continues to be heavily out of favor by the public markets, yet midstream and infrastructure-contracted cash flow continues to see strong interest from private capital, and I want to assure our shareholders that this continues to be the case and we remain laser-focused on creating and maximizing value for our shareholders in 2020. Our 2 large capital projects are complete, and our largest acquisition continues to outperform where our free cash flow yield will be top decile across all industries and is supported by contracted cash flow and investment-grade customers. We have made an application to the TSX for our first normal course issuer bid after strong support from our shareholders to do so. We will ensure we stay within our guardrails on net debt-to-EBITDA of approximately 3x, debt-to-EBITDA into the end of 2020 in 2.5x to 3x over the next 12 to 18 months. That said, our proceeds from our Pioneer sale today are almost equal to our market cap. And our projected adjusted EBITDA per share in 2020 exceeds our current share price. So we do have several levers to generate shareholder value in 2020 and are also evaluating buying back our unsecured term debt and/or convertible debentures at a discount. I'll pass it back to Mr. Vorra, and he can walk you through some of the details around the financial side of our year-end results. We want to thank all our shareholders, employees, customers, stakeholders, partners for all the support in these challenging times. Thank you.

Thanks, Joel. A comprehensive summary. I'll give a brief overview of the financial highlights, and then we can open it up to everyone for questions. Starting off with top line revenue. We had revenue of $266 million for the quarter, approximately an 80% increase over the prior quarter and 110% increase from the prior year. This was mainly driven by the acquisition of the Prince George Refinery and having a full quarter of the assets we completed in our 2019 capital program being mainly the Pipestone Gas Plant and Gas Storage. Gross operating margin was approximately $44 million or a 60% increase from the prior quarter and a 40% increase from the prior year, again, mainly driven by new assets coming online and the acquisition of the Prince George Refinery. Operating margin was approximately 17%, which is consistent with prior quarters, taking into account realized gains and losses from our risk management program on derivative contracts. EBITDA. Adjusted EBITDA for the fourth quarter was a record for Tidewater at $40 million, representing an approximate 57% increase from the prior quarter and a 42% increase year-over-year. Q4 2019 EBITDA per share growth was approximately 90% increase from the same quarter in 2018, again, mainly a result of new assets coming online in the fourth quarter, and we expect those assets to continue to perform through 2020. Payout ratio. We've always tried to maintain a conservative payout ratio forecast to be under 20% for 2020. Q4 was approximately 19% payout ratio with distributable cash flow of approximately $17.4 million and $56.3 million for the year. As we are focused on applying excess free cash flow to reduce leverage, we would expect to maintain a conservative payout ratio. With that, I think we can open it up to questions from participants on the call.

[Operator Instructions] The first question is from Patrick Kenny with National Bank Financial.

Just from a business continuity perspective here, how are you guys managing this exponential trend of people working from home, avoiding large gatherings? What sort of operational plan are you guys looking to put in place, both in the field and at your corporate office just to ensure sustainability of the business?

Hi, Pat. So we had our Board meeting yesterday, and we have now a firmly approved plan in place related to COVID-19 coronavirus. Just realize it is evolving day by day, and I'm sure it is for most companies in town. To go through all the details, I'd probably not be the best person to do so. I mean we're happy to have a call off the line. But I think just for our shareholders to know, we definitely have a clear plan. Even industry -- even our 2 partners, we talked about today, and TC Energy and TransAlta have been very helpful. Industries talking with each other. Nonessential travel, we haven't formally determined to not allow our staff to do that, but we have even seen quarantine of certain contractors that have come from other countries. We've had no cases. There's no reason to panic. But it is something we're sending out daily updates to our staff, and we feel we're well prepared. But happy to take any questions off-line, if you like.

Yes, Pat, we've looked at minimum staffing levels at all our facilities. We've looked at IT bandwidth and what the network can handle from people working at home. So we spent a fair bit of time going through those worst case scenarios and what would happen if we had to make a shift. So we spent a bunch of time there. And like Joel said, we've got a formal plan approved.

Okay. Great. Maybe back to our mainstream business items. Just wanted to confirm the expected timing of closing the sale of the Pioneer Pipeline. When does NGTL expect to have regulatory approvals in hand and so on? And then also maybe just a bit more color on how we should be modeling in the ramp-up or the backfill of the $10 million of lost EBITDA over the next few quarters or a couple of years?

For sure, I think we want to be careful to commit to a time, Pat. You'll see in our revised corporate presentation, even in some of our documents today, we're hopeful that we can close by year-end, but would hate to commit to that. So I think there's a range in the process there, and we'll continue to keep the market updated. As far as the backfill, it's not -- it doesn't have an effective date where I feel we have -- able to backfill, and the dollar amount is not overly material. So in my view, there's not a need to backfill. When we close, we should have commercial agreements in place to replace the majority and potentially all the EBITDA. So you won't see an impact to EBITDA up to close. And then at close, we would expect to have the commercial agreements in place that would cover. But I think we'll continue to keep the market updated if anything changes on that front. Joel, anything you want to add?

No.

And just to clarify, maybe, like, how much of the $10 million of EBITDA that's being replaced by the new commercial arrangements is actually coming in from NGTL or NGTL customers and how much is associated with the expectation for higher utilization at BRC or the frac?

For now, given we're not through the PSA, Pat, I think we'd prefer to defer walking through the components on the $7 million to $10 million. Know that there is a component related to Gas Storage and there's also components related to the Brazeau River Complex. But happy to provide more details here over the coming months.

Okay. Great. And then maybe last one from me and then I'll jump back in the queue. But can we just get an update maybe on your outlook for your crude oil infrastructure business, specifically the crude by rail activity after some larger producers, I guess, have suspended their crude by rail programs? I think you guys had previously hit a run rate of $10 million of EBITDA or so. Just wondering how we should be thinking about those contributions through 2020 and maybe into 2021?

Yes, no problem, Pat. So the one piece we have now that we didn't have before is our crude oil tankage at Prince George and up to 1 million barrels of storage there. So when we see the price move down, we have even done test runs on offloading crude by rail at Prince George. Again, we're not forecasting a big ramp in our crude oil infrastructure, but we definitely have more tools in the toolbox. And then we have contracted cash flow related to those rail movements. So in general, we'd say we expect that to continue. Is there some upside? Absolutely. But we don't want to get ahead of ourselves. And we hate to say it, too, but the lower a crude goes, the more upside we'd have on our crude oil infrastructure and our tankage at Prince George. But at this time, we'd want to just message that base flat, $10 million, which we're confident we can achieve.

Okay. Great. And sorry, I lied. One last question, cleanup. Any crack spread hedges through 2020 or 2021?

Yes, we have some small pieces on and we continue to add. The issue we have with the Prince George crack is it's not 100% correlated and you cannot get a hedge that's 100% efficient. You can't hedge on screen a Prince George crack. Yes, it's correlated to Edmonton, it's correlated to NYMEX, ultra-low-sulfur diesel and RBOB. So we do not want to get into a situation, and you're more aware of those than I, where we have a dirty hedge on and we're on the wrong side of the transaction. The great thing about Prince George is it's a small refinery in a small market and it is relatively dislocated. We're seeing real demand pull from Site C dam with 2,000 to 4,000 folks working up at Fort St. John, Coastal GasLink as we get through the protesting, and we are even seeing some of that demand, not large, but starting to see pull there. So we've got potentially 4, a $10 billion project in Site C dam, Coastal GasLink, LNG Canada, $40-plus billion right in our backyard, and then TransMountain, we're hopeful gets going here as well. So we've got 3 of the largest capital projects in all of Canada right in our backyard. So we're not overly concerned about demand in the area. And it's only 10,500 barrels a day of both diesel and gasoline. Joel, is there anything you want to add to that?

No, I think good summary.

The next question is from Robert Catellier with CIBC Capital Markets.

I just wanted to follow up on the agreement to sell Pioneer and the independent agreements with NGTL. In addition to storage, what is the nature of the other service agreements with NGTL? What services would you be providing in addition to storage?

So Rob, again, given we're still working through the definitive agreements, and I apologize, we want to -- we're a little hesitant to get into the details. Gas Storage, you've got it as a piece, processing at Brazeau River is definitely a piece and then working to continue to supply TransAlta gas longer term is also a piece. But we'd hate to get into the details at this point in time, and also the regulatory process needs to work its way through as well. But we're happy to give an update as we have more details. But right now, our partners and we would prefer to just sit tight.

Okay. And then moving on to customer activity levels. Obviously, you pointed to the stronger gas price, which may have been overlooked here. But in the -- on balance, everybody is cutting their capital spending budgets, and we'd expect that to continue for some time. So what have you heard from customers in and around your plans? And what sort of feel do you have in terms of what the declines might be after breakup?

It's a good point. I think it's still pretty early, Rob. On the gas side, even, I think, Q4 -- maybe Q4 was -- saw a little more activity than we would anticipate. But we saw strong gas prices in Q4. Ram River was near record throughput. Brazeau was near record throughput. Some of that is driven by our Pioneer Pipeline, but we do have customers that do want to drill, and most of them would be private and larger that want to drill around Braz and potentially even Ram at $1.80, $1.90, $2 gas definitely. So I would say where there's gas plays that are ready to go and even gas behind pipe, we wouldn't expect to see a significant decline. If gas and Cal 2020 continues to hold that at $1.90, we wouldn't expect to see material declines around Ram River and Braz. We typically plan for $1-ish gas through the summer. But right now, producers and most of the producers we're talking to are looking to lock in prices so that they could continue to either drill a little bit or hold their production flat. Where there could be exposure would be -- we don't have any assets in heavy oil country, but high water cut, high op costs with heavy differentials, we don't have any assets in those areas, but there you would see shut-ins at $30 WTI. A lot of discussions about shut-ins. None -- we don't have really any. We don't have any heavy oil assets. Maybe Seal would be one asset, which is just tiny immaterial, where there's definitely heavy oil there, but 2 Seals near record highs as well right now. So Pipestone itself fully contracted. So that would be our biggest gas processing asset, but again, it's fully contracted 90% with take-or-pays. So for the near term, there's no concern, but absolutely, we have to monitor our customers. We have to even continue to analyze their type curves, their cash flows and figure out how we can help them. We don't see any immediate pain there, but into the fall and borrowing base reviews, yes, we want to get a sense for potentially where their credit facilities could be cut and the related impact, but also how we can help them.

Okay. You touched on something else here of interest. Obviously, I don't think you have too much trouble getting feedstock for PGR, should be a big inventory build, but there could be a change in production plans. Is there going to be, as far as you can tell, any indication of a change in how you source feedstock, i.e., any potential negative impact to the crack just from the changing supply dynamics?

If the one good thing, again, in -- we'll have in a small refinery is all we need to feed the refinery is 12,000 barrels a day of light sweet crude, so within BC, most -- almost all our feedstock today comes out of Fort St. John and down the Pembina Western Pipeline system. Pembina has been a great partner there. And we've got ample supply in the Montney on condensate and crude, and then even in the Pipestone, which we have seen some volumes being trucked from that Pipestone area into Taylor and down. And we've also sent a few of our own trucks direct from Pipestone into Prince George. So today, I would say there isn't a concern. And given operating cost for the Montney, and 80% to 90% of our volumes out of Montney are around $10 to $15 a barrel, even at $30 WTI, producers are in the money and want to flow their volumes. They're cash flow positive. I'm not saying they're going to ramp up drilling, but we're very unlikely to see big shut-ins on light sweet crude. One-off costs are in that $10-ish to $15 a barrel range. But we have -- and we've been working on ensuring we have flexibility. So absolutely, we've been railing in small volumes. I wouldn't say there's a huge benefit, but we want to be ready. Even if we saw a dislocation in a U.S. market and we can rail volumes up to Prince George, that's something we want to be ready to do. Same thing we've done on the demand side. We have railed refined product in some markets outside of British Columbia, just so we're ready. In the event BC had a pandemic and everyone wanted to stay home, we are ready to send volumes into other markets. I would say that's highly unlikely, and when we see massive new demand around Prince George today with some very large capital projects, but we want to be ready. And the message from our shareholders is we want to be ready in the event something unforeseeable happens.

Last question for me just on the financial side. Assuming you do close Pioneer as envisioned, what's the plan for the proceeds? Is that targeted towards a second line -- lien terminal loan?

Yes. So we've started those discussions, Rob, and welcome, I think, feedback from our shareholders, partners, advisers, even understanding, if we could acquire some of our unsecured notes at a discount. I think yesterday, it felt like there may have been an opportunity, but now that we have this public news in the market, I would hate to say, we know we can buy some of our unsecured notes or convertible debentures at a discount. So over the coming weeks, months, we're going to explore our best way to reduce our leverage. So number one would be reducing our leverage through our credit facility, but also some of our higher cost of capital, including our ATB second lien note, and continue to have inbounds from various parties, understanding how they can be involved on the credit side. Number one, though, would be delever, delever, delever. And I just want to clarify that. We do have an NCIB in place, but highly unlikely to deploy significant capital to the NCIB. Our focus will be on deleveraging.

The next question is from Robert Kwan with RBC Capital Markets.

If I can just come back to the transaction. And I know within replacing the lost EBITDA, you don't want to get too much into the details. I'm just wondering, though, as you look at the different buckets in aggregate, how much of the replacement do you see as being contractual and really kind of locking that in and how much of that is more volumetric or assumption-driven?

It's a good question, Rob. And again, it will be -- it's hard for -- I hate dodging questions, but it's hard for us to give specifics, but want to be upfront. The key piece would be we will not have a 15-year take-or-pay contract moving forward. We don't want to hide that. But we are confident, even a lot of our gas storage contracts today can go out, I think, on average, we're 6 plus years, but can go out 10. And maybe I'll let Mr. Vorra jump in at the end. But I want to be clear, we're not going to have a firm 15-year take-or-pay, but we're going to have likely a gas storage piece and a couple of other pieces with similar term on a 15-year basis. But Joel, is there anything there you want to add?

No, I think it's a good question. I agree, Joel, it's hard to get into it. Obviously, the goal is to replace as much with contracted cash flow as possible, and we think we're going to be able to do that. But again, without -- it's tough to get too far into it when we're sort of in the middle of those discussions.

Okay. Let me put it this way. Maybe this is kind of coming off the last comment. Is there a potential as you look at the different scenarios to -- a reasonable scenario to fully replace that amount with some amount of contract and recognizing it may not be 15-year take-or-pay, but it could be 3-, 4-, 5-year type deals, but under contract versus relying on some sort of interruptible or volumetric level?

Absolutely. Even our existing gas storage deals that we continue to see volatility, we could have a 6- or a 10-year gas storage deal that could make up all or a large chunk of the $7 million to $10 million we plan to make up. I think we've got multiple levers there and we're just working through the details.

Okay. Turning to the proceeds from the transaction. So the $138 million, I think you made it abundantly clear that, number one, use of proceeds is reducing leverage. With the NCIB out there, do you feel, though, that there is an amount within that $138 million that you could deploy? Or is it really put the NCIB in place, reduce the leverage and see how the year progresses, whether that's good storage or otherwise? Like is it something where we could see some amount of activity in the NCIB in the near term? Or is it more likely you've got to wait until you get deeper in the year and see how the year is shaping up to hit that target?

It's been a real busy last 30 days. So our goal was -- a message from our shareholders and even our Board was just work to get it in place. So we made the application. The amount we're going to allocate, Robert, I'd just say right now, we don't have a number. We're going to have a follow-up Board meeting to discuss it. But we're talking $1 million to $5 million max initially. I want to be clear, I mean, depending on price in those discussions, but also realize, we do think we're going to be able to close 1 or 2 other noncore dispositions for very small nonmaterial amounts, which would also give us a little bit of capital that we may consider on the NCIB. Otherwise, the majority of the proceeds are going to paying down debt. But we need to continue to have some discussions with our shareholders and our Board members. And I think we can give a little more clarity, but I want to be clear, we don't expect to buy back 5% or 10% of our stock here in the near term.

Understood. If -- maybe to just finish on volumes at the BRC. I know you made some general volumetric comments. But volumes were steady in the fourth quarter versus third quarter. I'm just wondering if you've got some commentary as to what you've seen so far here in 2020? And the other thing, I guess, with the NGL year coming up, what's the expectation for BRC volumes kind of through the remainder of the year and into early next year?

Yes. Brazeau has had a nice uptick from stronger gas prices and also the Pioneer Pipeline. I'd say we expect to hold current levels and don't want to get ahead of ourselves. I think this crude move down and natural gas move up has really only been here for a week and even less than a week. So I think we need a little more time, talk to our customers, see if they are hedging and hedging into a drilling program. I think that may be getting ahead of ourselves. I think most companies and entities are kind of on a holding pattern to see where things shake out, but we do have 1 or 2 customers that have told us for years, if we can help them achieve $1.80, $1.90 gas price, they're happy to drill wells and bring us a significant amount of gas into the Brazeau River Complex and also into the Pioneer Pipeline. But for now, I'd say expect roughly flat, Rob, but there's definitely some upside, and we'll probably be able to give clarity here in the next couple of months. On the frac, that's been one of our biggest wins at small scale, not necessarily material. But for us, to build that fractionation facility, I think, almost 3 to 4 years ago now. And last year, we were full in that capacity, and we expect the same here in 2020. So a big win for us and an asset that's done well for us. Today, again, we're not spending capital, but that would be a piece should we get through this next little bit and continue to see outperformance from Prince George and a few of our other assets. We have more cash than we anticipate, capital around expanding frac. So it's something that we at least want to be ready for.

And when you say expect to be full on the frac in 2020, given we're kind of 2 weeks away from the NGL you're starting, are those -- is that -- are there still loose ends feeding into that? Or is it pretty much all signed out?

Well, I would say we're 90% contracted, as we speak. And even last year, I'd want to look at a press release from last year around NGL contract season. But we signed some longer-term deals and brought in 2 investment-grade counterparties last year. And my sense is we have next to no space to give, but would hate to say we're 100% perfect and wrapped up. Would the crude move down? There's been, I know, a lot of discussions with some producers, and they're even trying to figure out their volumes in their drilling programs. But confident in being at 90% full and wrapped up. I think the question is, do we exceed what we did last year, which I think we were at 95-ish percent. So somewhere between 90% and 100% depending on here the next 30 days or so.

[Operator Instructions] The next question is from [ John Clark ], a private investor.

Congratulations, everybody, on your higher yield on the PGR refinery. I noted 42% gasoline, 46% diesel, 88%. Can you hear me?

Yes, we can, [ John ].

Right. I noted on Slide 11 of your presentation, the reference to the Montney condensate. I'm wondering, does that need to be desalted?

Right now, no. I'd want to check with our operations staff on the ground. And I believe we would run it through our desalter, but we don't see significant salt in the Montney condensate. But part of all -- I believe all our crude runs through the desalter and can absolutely get you an answer. I'm sure you've got a technical background, so I don't want to try and argue a technical capability for the refinery. But continue with your questions, [ John ].

Yes, the thought is to increase your inputs about 12,000 barrels a day by running some of the condensate to the cat fractionator. And I guess the other question would be, is your heavy fuel oil sulfur under 0.5%?

So our heavy fuel, our vacuum tower bottoms are about 1.4% or 1.5% sulfur. We have been able to blend those off and sell them into 0.5% fuel oil markets, which has been a nice win for us. When we picked up the asset, they were selling into a 3.5% HSFO market. And as you would know, that market has been heavily hit with IMO 2020. And today, we're moving that product into more of a 0.5 market, which has been a nice move. And then we've also sold those volumes into crude streams at times when it's made sense for some of our partners.

Wonderful. I guess, you would back out Boundary Lake crude. And that gets me, I guess, to a question, what would be a typical Montney condensate load to your refinery?

So kind of density-wise, sort of sulfur-wise, [ John ]?

Just volume.

Volume. So Montney production would be about 7,000 to 8,000 barrels a day. Our Boundary Lake would be about 1,000 barrels a day or 10% of our production that's feeding the Prince George Refinery.

Yes. It would seem appropriate to get rid of Boundary Lake and replace it with Montney.

Yes, although it is priced at times. Today, differentials aren't as wide as they were. But we would -- we had been getting close to a p-sour pricing on Boundary Lake as sulfur is a little higher. We're kind of 0.7%, 0.8% sulfur on Boundary Lake. So at times, it is definitely a lower cost feedstock, and we still see a similar distillate yield in our Boundary Lake production. But today, I would agree with you. When we have similar, less price differentials between a p-sour and a light sweet, we're better to run a Montney crude.

I'm not familiar with your layout. But the question, the cat cracker propylenes and butylenes, are they blended to gasoline? Or do you react -- do you upgrade them?

So that's, again, Husky had the asset, didn't allocate a lot of capital, noncore asset, great partner. But that's a project that we're starting to look at. Again, we're not allocating large capital today, but that would be a piece that gets me and our team real excited. We have, to your point, propylene, even isooctane, isobutane in our current LPG stream, but we sell that as kind of a mix into end markets, where if we could work to either convert some of those molecules to alkylates or isooctane, high-octane, and blend that into our gasoline pool, it will be a huge home run for us. But again, we're told by the market today to minimize capital, but we're starting to inventory some of these great ideas. And happy to have a call off-line, and you could even give us some of your insight on potential other projects.

I'm showing no further questions at this time. I'll turn the call back to the presenters for any closing remarks.

Just a big thank you. Again, to reiterate the support, awful tough times, challenging market and a real appreciation to all our shareholders, our staff, our customers. And thanks, everyone, for their time today. Thank you.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.