Gibson Energy Inc

TSX:GEI

Earnings Call Transcript 2020-Q4

[Operator]

Good morning, ladies and gentlemen. Welcome to Gibson Energy's Fourth Quarter and Full Year 2020 Conference Call. Please be advised that this call is being recorded. I would now like to turn the meeting over to Mr. Mark Chyc-Cies, Vice President, Strategy, Planning and Investor Relations. Mr. Chyc-Cies, please go ahead.

[Mark Chyc-Cies]

Thank you, operator. Good morning, and thank you for joining us on this conference call discussing our fourth quarter and full year 2020 operational and financial results. On the call this morning from Gibson Energy are Steve Spaulding, President and Chief Executive Officer; and Sean Brown, Chief Financial Officer. Listeners are reminded that today's call refers to non-GAAP measures and forward-looking information. Descriptions and qualifications of such measures and information are set out in our continuous disclosure documents available on SEDAR. Now I'd like to turn the call over to Steve.

[Steven R. Spaulding, President, CEO & Director]

Thanks, Mark. Good morning, everyone, and thank you for joining us today. In a very challenging year for our industry, I believe our strategy, which is built around our core terminals on high-quality cash flows and maintaining a very strong balance sheet, prove resilient. As you can see from our 2020 financial results, infrastructure segment profit, $374 million was in the upper half of the outlook range we gave in 2019.That was pre-COVID, which speaks to the stability and visibility we have in our business. In 2020, infrastructure segment profit was a $60 million increase from 2019 on a comparable basis, 20% growth year-on-year. With the tanks we placed in service at the end of 2020, and the DRU expected to enter service on budget and on schedule midyear, we have the visibility for further growth this year.It's the strength of our infrastructure business that makes our dividend so solid. Our payout of 66% was below our target range of 70% to 80%. Perhaps more importantly, our infrastructure only payout was 75%. The Board and management see the value of modest, stable dividend growth. In a year where many North American midstreamers cut or pause dividend growth, we were very pleased to again increase our dividend by 1% -- $0.01 per share per quarter or about 3%.On the marketing side of the business, we were in the middle of our $80 million to $120 million run rate. That said, it was a tale of 2 halves. In the first half of the year, we saw significant volatility. Our marketing organization was able to move decisively and lock in very meaningful gains. In the second half, it was a very challenging environment. And it looks like 2021 is shaping up to be the inverse. The challenging environment has persisted, with very few opportunities available today. I can tell you -- I can't tell you when or where the market is going to shift. But looking back over just the last few years, we can see how quickly it can change. Also, marketing outperformance tends to be quite lumpy. With a small number of events driving a good portion of the year's P&L.And in that context, we expect marketing performance to improve at some point through the year. But as we always say, delivering our strategy is not dependent on marketing earnings. One area where we've seen noticeable improvement, coming into 2021, is on our commercial discussions. On the tankage front, we are in numerous conversations with customers for tankage of both Hardisty and Edmonton. One of the drivers for tankage at Edmonton is TMX. Discussions on the DRU have also moved forward. Clarity on KXL has helped. We're currently talking to multiple producers and multiple refiners. That said, it's a complicated set of agreements and will take time. Shifting gears to another area where we made significant progress in 2020, advancing our sustainability and ESG initiatives. ESG is very important to Gibson. We want to ensure that we embed ESG into all areas of our business to position ourselves as a sustainability and ESG leader. It's the right thing to do and the smart thing to do.While the core values of ESG have always been a part of Gibson, we started our formal ESG journey in 2020, with the release of our inaugural sustainability report. We also made our first submission to CDP climate change questionnaire, and we were very pleased to receive an A- score. We are 1 of 7 oil and gas companies in North America to receive this distinction and also ranked in the top 10 globally.For any initiative to be successful, you need to have the right governance in place to ingrain it into your existing business practices. Our Board established a dedicated sustainability in the ESG committee. It is chaired by Judy Cotte, an expert on ESG in responsible investment, and we have benefited greatly from her experience on our ESG journey thus far. We've also ingrained sustainability in ESG in our strategy process and in evaluating all of our commercial projects. And we've made ourselves accountable with a meaningful proportion of our short-term incentives tied to ESG-related metrics.On the environmental side, clearly, a major focus is on admissions. We believe our carbon footprint is already best-in-class in the North American midstream space. This is both on an admissions per dollar revenue basis, and a per barrel-throughput basis. We continue to advance opportunities to reduce our emissions footprint. For example, at Moose Jaw, in 2019, we expanded the facility by 30%. And by utilizing new heat exchangers, we reduced emission intensity by about 25%, and we've identified additional projects that could reduce our emissions. Within the social pillar, our efforts to date have been concentrated on community giving and diversity and inclusion. In 2020, Gibson made a real commitment to a cause I personally feel very strongly about. With a 5-year partnership with Trellis and the donation of $1 million, we are very much making a difference in the mental health of youth in our communities. This is the largest financial donation in Gibson's history, and Gibson employees have committed to dedicating a significant number of volunteer hours.On diversity and inclusion, women currently comprise 37% of the workforce and 30% of employees at the Vice President level. Our Board is 1/3 women. We took positive steps in 2020. This would include the addition of 2 women to our Board and putting programs in place to attract and retain women to Gibson and to ensure equal representation through the recruitment process.In 2021, expect to see us continue our ESG journey. Our near-term focus will be set on Sustainability and ESG targets, which we are in the latter stages before [indiscernible]. We will also continue to expand our disclosure, and we'll publish a TCFD-aligned report during the year. Sustainability in ESG continues to evolve very rapidly, and we will very much seek to maintain our existing leadership position. Let me conclude by returning where we see the business today. I would stress that our strategy was designed to succeed in any environment. That strategy has not changed, and its effectiveness has proven again in 2020. Our infrastructure business demonstrated its resilience despite the impact of COVID. Infrastructure grew 20% in 2020, and it will grow again this year and into the future. Discussions for tankage at the DRU have advanced. We feel very comfortable in our ability to deploy $150 million to $200 million per year without sacrificing returns. And our balance sheet is very strong. We are fully funded and our dividend remains very well underpinned by our stable, long-term infrastructure cash flows. We will remain conservative in our approach to our business.I will now pass the call over to Sean, who will walk us through our financial results in more detail. Sean?

[Sean M. Brown, Senior VP & CFO]

Thanks, Steve. As Steve mentioned, our business had a strong year. Notwithstanding COVID, we were still above our budget for the year on both an adjusted EBITDA and distributable cash flow basis. One of the main drivers was our infrastructure segment, which was in the top half of our outlook range. Segment profit for the year was $374 million, including $93 million in the fourth quarter. I would note that the annual figure is a $60 million or nearly 20% increase on a comparable basis. This was largely driven by a full year contribution from the 4 tanks or 2 million barrels we brought into service in late 2019 at the top of the hill. But also by our ability to add some incremental revenues at Hardisty through the year. And this is despite weakness from the relatively small variable component of our infrastructure segment, our conventional pipelines in small terminals in Canada and the U.S. These businesses were certainly impacted by COVID and have yet to recover, remaining roughly 40% below where we initially thought they would be.Comparing the fourth quarter to the third quarter of 2020, we are very much in line. The 3 tanks or 1.5 million barrels we brought into service in the fourth quarter provided only a partial contribution, and we'll see their full benefit in the first quarter of 2021. As a result, we still very much expect to be right at or around the $100 million per quarter run rate for infrastructure we had previously discussed coming into 2021. Marketing adjusted EBITDA of $104 million and segment profit of $95 million for the full year put us in the middle of our long-term run rate.As Steve mentioned, that was driven by a strong start and then a very challenging environment towards the end of the year. In the fourth quarter, adjusted EBITDA was negative $4 million and segment profit was negative $9 million. The strong start to the year was in part due to the volatility we saw during the onset of COVID, with one of the largest factors being the availability of time based opportunities given the steep contango in the futures curve, whereas opportunities in the crude marketing business were very limited in the back half of the year.On the refined product side, road asphalt had a fairly strong year, in line with 2019. Though other key products such as roofing flux and distillates had positive margin but were down year-over-year. In response to the current environment, where drilling fluid demand remains fairly weak and asphalt demand is seasonally lower, we are also looking to capture seasonal opportunities on certain refined products. In any year, within our refined products business, seasonal optimization opportunities may exist, and we, at times, participate needs by storing some of our products in the winter months and selling in the summer months.This year will be no different. And the impact of this is to push out some revenues from the fourth quarter of 2020 and the first quarter of 2021 into the second and perhaps third quarters of 2021, albeit for higher margins. And characterizing our fourth quarter results, I think it's also very important to note that to the extent that marketing is not performing at levels that it has historically, it's reflective of the fact that the opportunities that they were able to find were not sufficient to fully offset the ITP commitments they have in place rather than because we made the wrong market calls or took on high-risk positions that went sideways. These ITPs are generally flat through the year where earnings can be lumpy or seasonal.We also very much recognize the noise created by having both a segment profit and adjusted EBITDA measure. We've been looking at reporting a single measure to be accountable to, so we think it makes the most sense to start reporting that with the first quarter rather than making the adjustment in the fourth quarter. In reviewing peer disclosures and thinking about what is most appropriate for our business, we are leaning to something akin to adjusted EBITDA as that removes the noise created by unrealized hedging gains and losses and focuses on the economic value generated in the period. I would caution that it's something we're still working through, with a formal decision to be made in conjunction with our Q1 2021 results.Shifting to our outlook for marketing. As Steve said, it remains a very challenging environment. And absent a change in that environment, it will be a fairly challenging quarter for the crude marketing business, given the very limited opportunities. Combine that with our outlook for refined products, where we continue to see reduced product demand due to the pandemic, our outlook on an adjusted EBITDA basis for the quarter is around breakeven. That being said, we do expect to see a recovery throughout the year, especially on the refined product side as end-use normalizes with a more fulsome economic recovery given the rollout of the vaccine, though differentials are likely to stay narrow on a historical basis. And as has always been our approach, if we are setting reasonable expectations, then we need to consider that absent a meaningful change in the environment relatively soon, there's certainly the potential to be at the low end or potentially even below our $80 million to $120 million run rate in 2021. As Steve said, marketing is lumpy. We could certainly see a couple of events that get us comfortably back into that range quite quickly. And that's certainly what history has shown us. But at this time, we can't say we have clear line of sight to that.And to speak to what weakness in our marketing business could mean for our strategy, I said it on the last call, but I think it is very much worth repeating. I could not be more clear than to say that we do not rely on our marketing business to fund our capital, fund our dividend or support our leverage. We are very deliberate in designing a framework that anticipated eventual volatility in a variable part of our business. For that reason, in addition to our overall leverage target being conservative relative to peers, despite the cash flows from our infrastructure business being amongst the highest quality, our financial governing principles include measures for maintaining infrastructure only leverage at or below 4x, as well as not paying out more than 100% of our infrastructure only cash flows. e currently are and very much see ourselves continuing to remain within both measures, with quite a bit of headroom on our infrastructure only payout. Obviously, corporate level measures matter, but it's really the infrastructure only measures that we fundamentally run our business around, given the variability and the marketing business is not within our control. As a result, and very much by design, even with the moderation in contribution from our marketing business, we remain in a very strong financial position, including being fully funded for all of our anticipated capital. Given the strategy we have in place and our conservative financial governing principles, we are comfortable living at the lower end or even below our long-term marketing run rate and in no way will change our marketing strategy, or risk tolerance to chase earnings.Finishing up the discussion of the results, let me quickly work down to distributable cash flow. G&A of $33 million in 2020 was below our normalized run rate, largely due to COVID-related items, with the fourth quarter very much in line with the third quarter. Lower interest costs were one of the key wins in 2020, with a decrease of $10 million from 2019. Refinancing our debt over the past 18 months has been a major focus, reducing our run rate interest cost by over $20 million per year.For context, that represents that 7% of distributable cash flow, and our weighted average coupon on our notes would be, by far, the lowest within our Canadian midsized peer group at just over 3%, while at the same time having the second longest weighted average center. Replacement capital of $23 million in 2020 was slightly below 2019 as a result of deferring certain discretionary work to this year given the impact of COVID and a focus on cost. Taxes in 2020 were comparable with 2019, with a recovery in the current quarter related to an adjustment booked for the Alberta job creation tax cut. These payments were slightly lower in 2020 than 2019. We've been very much looking to reduce our lease costs and would expect that in 2021, these lease costs could decrease further. These factors resulted in distributable cash flow in 2020 being fairly comparable to 2019. The largest dynamic here is the growth in infrastructure largely offset the decrease in marketing, and the interest savings and lower lease costs also helped to close the gap. The fourth quarter was $11 million lower than the third quarter of 2020 due to the decrease in marketing contribution. And on a trailing 12-month basis, rolling off a stronger quarter, with the fourth quarter of 2019 having been $22 million higher than the fourth quarter of 2020, due to the weaker contribution from marketing in the current quarter, our payout ratio increased modestly to 66% but is still well below our 70% to 80% target range. Similarly, our debt-to-adjusted EBITDA was relatively flat at 2.8x, which remains below our 3 to 3.5x target.Speaking to our financial position, our approach will continue to be in favor of remaining conservative, including maintaining a fully funded position for all our capital, and being proactive in having significant available committed liquidity. At the end of the year, we are only $60 million drawn on our $750 million credit facility with about $54 million of cash on the balance sheet or effectively undrawn on a net basis. We also have $115 million of unutilized capacity on our $150 million bilateral demand facilities, so very significant liquidity. With years of running room given our 66% payout ratio and $200 million capital program.In terms of being proactive, in 2020, we completed our transition to a fully investment-grade capital structure with the issuance of a $250 million hybrid to fund the redemption of our $100 million convertible debentures. We are very pleased to be able to replace a potentially dilutive convert with a nondilutive, longer-tenor hybrid while maintaining the same 5.25% coupon. Also, we were able to ensure that the redemption was nondilutive to the limited use of our NCIB in December.With these actions, we came into 2021 with significant available liquidity. And as our upsizing our credit facility in February 2020 showed, you can never be too proactive in maintaining liquidity. It's when you need it that the price goes up and availability goes down as many issuers saw during the onset of COVID. In summary, the business had a good year in a very challenging environment. Our infrastructure segment had a very strong year and marketing was within our long-term run rate expectation.The current environment for marketing is challenging. While that will change in time, the more important point is that we simply don't rely on it in order to execute on our strategy. We very much believe that our business offers a strong total return proposition to investors with visibility to continued high-quality investment opportunities in our infrastructure segment, resulting in attractive distributable cash flow per share growth, which supports a meaningful growing dividend, all while maintaining a very strong balance sheet and financial position.At this point, I will turn the call over to the operator to open it up for questions.

[Operator]

[Operator Instructions] Our first question comes from Jeremy Tonet with JPMorgan.

[Jeremy Bryan Tonet, Senior Analyst]

I just wanted to start off with regards to marketing outlook and how that impacts, I guess, capital allocation philosophy as you guys see it right now. Does the softer marketing outlook right now kind of impact how you think about buybacks, the pace of buybacks or is that really kind of more tied to growth CapEx in general and just the level of money you're spending, the balance of it would be put towards buybacks? Just wondering the whole capital allocation plus -- between buybacks -- growth CapEx and dividend growth works out right now.

[Steven R. Spaulding, President, CEO & Director]

Sean, can you take that?

[Sean M. Brown, Senior VP & CFO]

Yes, absolutely. Thanks, Jeremy. So I mean, our capital allocation philosophy really hasn't changed. And as a refresher for everyone on the call, bias towards funding growth capital to the extent that we're deploying at that 5 to 7 build multiple under long-term contracts with investment-grade counterparties. That will absolutely remain our priority. Also remaining fully funded and within our financial governing principles to the extent that there's excess cash flow, and you would have seen it in conjunction with the results here and that's primarily from infrastructure. Then we certainly have a bias towards modest annual dividend increases over time with infrastructure segment profit going up 20% on a year-over-year basis. Again, you saw that with the modest dividend increase that we announced this year.Notwithstanding a challenging environment because of COVID. We have been clear that to the extent that we have excess cash flow, and it's primarily from marketing then we would very much buy share buybacks. And so Jeremy, you're absolutely right. The marketing outlook does impact our ability or our desire to do share buybacks in the first half of the year, certainly. We would like to see some measure of recovery in that marketing business before we look at that more fulsomely as we think of it the back half of the year.And the other part is all the factors you mentioned aren't necessarily mutually exclusive. If you think about the capital spend we have, it is more front-end loaded this year. So again, we'd like to get through the bulk of that capital spend in the first half of the year as well and see some measure of recovery in the marketing business. And then I think you would see us look at a buyback program or reinstituting a buyback program more fully, probably closer to the back half of the year.

[Jeremy Bryan Tonet, Senior Analyst]

Got it. Understood. That's helpful. And pivoting over to the DRU here, the potential for expansion. I was just wondering, granted is very complicated contract structure there that you all can assign. But any thoughts you could provide on when this might kind of come to fruition, potential expansions? Is this kind of this year or next year event or later dated? Just trying to get more feeling on when you think that could come together.

[Steven R. Spaulding, President, CEO & Director]

Thank you, Jeremy. We're very excited about our Phase I with Conoco. That first $50,000 is underpinned by a 10-year take-or-pay. So this is our first -- really the first DRU, commercial DRU, in Canada, and we think it's a real opportunity. I think clarity around KXL certainly helps and discussions have picked up with -- as we continue to talk to multiple producers and refiners. So you have the U.S. pool and now that KXL is kind of cleared up, the feedstocks in Mexico -- coming from Venezuela and Mexico continue to decline. So those U.S. refineries need that heavy crude oil produced by Canada. And likewise, the Canadian producers want that U.S. market. And so we think that this is a real opportunity for them, and discussions continue to heat up. But I would say it would be later in the year, probably a -- I would say, a fourth quarter -- third -- late third or fourth quarter if we're able to do it this year, Jeremy.

[Jeremy Bryan Tonet, Senior Analyst]

Got it. That's helpful. And then just one last one, if I could. I think at points in the past, you've discussed 2 to 4 tanks something that you guys would target in the long term. I'm just wondering how you think about that right now given everything we've gone through it COVID in the cycle, do you see that rate still achievable? Or just any updated thoughts there would be helpful.

[Steven R. Spaulding, President, CEO & Director]

Well, I would say COVID kind of put a pause on things. But as the year started this year, commercial negotiations are really heated up, both at Edmonton and at Hardisty. In fact, at Hardisty, we did sign a short-term agreement with one of the oil sands producers. And we are going to actually move marketing tank that we -- our first marketing tank that we leased to marketing, we're going to lease that to that producer. And we see several other opportunities. We have a we have probably 4 different customers that are wanting tanks at Hardisty. And then at Edmonton, we're getting very close designing a construction signing agreements to start doing initial engineering work on building tanks there. So those discussions are really starting to pick up, and they're associated with TMX and other opportunities at Edmonton, Jeremy. So I would say that 2 to 4 tanks a year is still very viable. And we see pretty good line of sight over that over the next 3 to 4 years.

[Operator]

Our next question comes from Ben Pham with BMO.

[Benjamin Pham, Analyst]

I wanted to follow-up on the Edmonton opportunity in particular. And you mentioned TMX is a driver. You mentioned other opportunities. Can you expand on these other opportunities and then on TransMountain, is expectation that in the past, you've seen producers wanting the storage ahead of time and you lease it on a spot basis before the pipeline is actually in service.

[Steven R. Spaulding, President, CEO & Director]

So yes. So on tanks at Edmonton, obviously, TMX is driving that. And we have a mainline connection into TransMountain, and there are several customers there. The other driver is really what producers are saying is synergies between those 2 markets and -- Edmonton and Hardisty and the ability for them to swap barrels back and forth. And optimize their netbacks is really driving some of the other talks, Ben. As far as -- I don't know that we need to build anything early. I think kind of timing-wise. To have tanks ready, we'll need to contract them later this year to have tanks ready on the current time line for TMX.

[Benjamin Pham, Analyst]

Okay. So we should think about in service of potential tanks, more aligning with that late 2022 service and in the past, discussed spot revenues, that sounds like it was more of just -- you completed tanks early than expected?

[Steven R. Spaulding, President, CEO & Director]

Correct. Correct. Yes. And then you're only talking about 1 or 2 months, generally, Ben, when we do that.

[Benjamin Pham, Analyst]

Okay. And maybe switch to marketing side of things. And can I appreciate the language around not relying on it, and there's opportunity to buyback stock in the second half and potentially see a recovery. But what are your thoughts about just going to be looking at overall exposure strategically moving at lower -- you got 20% EBITDA today, is -- are you open to moving 10%, whether it's less fixed commitments, selling Moose Jaw? I know you're probably not going to get a great price on that today, but you haven't been against selling assets at 5x EBITDA in the past. So any sort of context on where you want marketing to be long term? Is that -- any thought on any changes there?

[Steven R. Spaulding, President, CEO & Director]

I think when we came out on our strategy in 2018, at that time, we came out with a $60 million $80 million kind of run rate on a long-term run rate. And there was quite a bit of volatility in the market over the last couple of years. And we've moved that, I think, the $80 million to $120 million. And last year, last year, we came right in the mid range. If things continue to tighten up on the differential between WCS and WTI on a long-term basis, that will put -- that does increase our feedstock at Moose Jaw and reduce our crack spread. So we may in the long term, have to move that down some, but we're always going to make maybe $60 million to $100 million long term, but we don't know yet. But right now, we're still at that $80 million to $120 million, and we feel comfortable over the next couple of years in that $80 million to $120 million, Ben.

[Sean M. Brown, Senior VP & CFO]

Ben, the only thing I'd add to that, too, is that if you structurally move down your ability to generate margin out of that business, that not only impacts in more challenging times like right now, but that would also impact our ability to achieve outsized results in both 2018 and 2019. And so I think that's something to remember that if you structurally change the business, in the periods when the market presents opportunities like we certainly have seen up until recently, then you permanently probably impair your ability to get those outsized results, at least to the same quantum. So that's also the offset to a strategic decision, as you would note there.

[Operator]

Our next question comes from Rob Hope with Scotiabank.

[Robert Hope, Analyst]

Two questions. The first one is just on the 2021 outlook for infrastructure. So good to see that you reiterated that $100 million a quarter until the DRU shows up. But can we delve a little bit further to what that assumes on the other infrastructure side? Does that assume that the U.S. pipes kind of stay where they were at in Q4? Does that kind of assume a pick up back to more kind of budgeted levels.

[Steven R. Spaulding, President, CEO & Director]

Sean?

[Sean M. Brown, Senior VP & CFO]

Yes. Thanks, Rob. I mean, it would assume a very, very modest pickup. I mean, I think it's important to highlight that really the core of our infrastructure business is truly our tankage business. So that's going to drive the vast, vast majority of that, and that's what's driving our confidence in reiterating the $100 million. It really is having a full quarter contribution from the 3 tanks or 1.5 million barrels that we have in service. It does assume a very, very modest improvement over Q4 levels at both the U.S. and in Canada. But again, very modest. And overall, I wouldn't say that's a significant swing factor.

[Robert Hope, Analyst]

All right. And then can we maybe discuss a little bit further that the commentary on the short-term tankage contract that you have with the oil sands customer in Hardisty. How long of a contract is that right now? And then could you also see just you leasing out that marketing tank to the customer on a longer-term basis and then build another marketing tank?

[Steven R. Spaulding, President, CEO & Director]

We never really go into exact details of contracts. But it's -- but we feel comfortable that, that will become a long-term tank to that customer. And we actually feel that customer will probably -- we'll build several tanks for that customer over the next couple of years with their plans as they've discussed. So we're feeling pretty comfortable at Hardisty to continue to build tankage going out into the future.

[Operator]

Our next question comes from Patrick Kenny with National Bank Financial.

[Patrick Kenny, Managing Director]

Just as we think about refinery utilization levels you are continuing to recover throughout the year. I guess, on the one hand, it might increase throughput at terminals. But on the other hand, it might keep demand for Canadian crude and differential is quite narrow. So just wondering if you could help triangulate a net headwind or a net tailwind for your overall business as refinery runs continue to normalize?

[Steven R. Spaulding, President, CEO & Director]

One of the things that refinery runs do continue to normalize, that will increase distillate pricing. And that -- and as U.S. drilling starts to pick up, now that we're over $60 right at or above -- $60 crude, we do think the U.S. will start drilling. So with that higher distillate price and higher crack spread across distillate, we think our drilling fluid market will pick up across the year. As far as -- I mean, that's probably the biggest driver. The other thing is what's going to happen with DAPL? What's going to happen with Line 5? Those could have impacts on the differentials between WCS and WTI and does have an impact on our feedstock price into the facility.

[Patrick Kenny, Managing Director]

Okay. And then my next question just here on the broader theme of industry consolidation, both on the upstream front and also more recently in the midstream space, I guess is a way to crystallize value here in a low-growth environment. Is this flattish production trends change the way you think at all about delivering total return to shareholders in the form of steady organic growth as opposed to pursuing more strategic partnerships with other midstreamers or perhaps even looking more at M&A even if it's on a financially neutral basis, but just increase the overall size of the company?

[Steven R. Spaulding, President, CEO & Director]

Well, I mean, this year, we've announced that we're going to spend another up to $200 million in capital, which will allow us to continue to deploy and get -- continue to grow our infrastructure earnings. Last year, we had a 20% growth in infrastructure earnings. We're going to put on 3 tanks. And we put on 3 tanks in November. The DRU is coming on. So we're feeling comfortable continuing just the growth in the business and the status quo is a good strategy. Obviously, we'll look for opportunities to improve the total return to our shareholders. Because at the end of the day, that's the most important thing is that total return to our shareholders. Sean, do you want to comment any more on that?

[Sean M. Brown, Senior VP & CFO]

No. I think you hit it, Steve., Pat, as Steve said, we still have very much have conviction in our strategy. We have visibility to growth. We feel confident with our financial position. And so as we've always said, something like M&A is something we're not necessarily averse to, but I mean, the bar is so incredibly high, given the visibility that we have, there's just nothing that has cleared that hurdle. So we certainly don't see a need for M&A. As Steve said, we've got confidence in our strategy and the visibility we have around it.

[Operator]

Next question comes from Robert Catellier with CIBC Capital Markets.

[Robert Catellier]

And thank you for your comments this morning. I'll just start by saying that I would be supportive of your change to reporting adjusted EBITDA in an effort to remove the hedging noise. At this point, most of my questions have been answered but maybe just one on the carbon tax front. So if carbon taxes are, in fact, raised as envisioned. How would you account for this item in project economics because it does have a bit of controversy and could be subject to change. So -- and with that, does it make any projects more or less likely there to reach up [ by the year ], in your opinion?

[Steven R. Spaulding, President, CEO & Director]

So we're certainly putting it in our project economics, Robert. What is the height of that? We don't really know. But we're definitely putting that carbon tax in our economics. Most of our business, as you know, is the tankage business, where we really don't have any carbon. So one of the things when we released our CDP report is our company is by far best-in-class when it comes to CO2 emissions on a per barrel basis or even on a per revenue basis. And that's because of the -- just the tankage business itself isn't. So the one place that we do have -- the 2 places we do have carbon tax, one is at Moose Jaw, and that would certainly increase our expenses at Moose Jaw.And then the other is on the DRU itself. And that would certainly impact the economics of DRU to our customers. But at Moose Jaw, we have -- we're excited about a project there that we think will reduce our carbon emissions by about 25% there. And that has a very positive rate of return. And we're looking to move forward with that project very soon.

[Robert Catellier]

Okay. That's helpful. And then just want to offer an opportunity if you have any updates to volunteer on what the Cenovus-Husky merger might need for the Hardisty position and contract renewals?

[Steven R. Spaulding, President, CEO & Director]

Cenovus is a very important customer of ours. We're -- we think this is a great opportunity for them in synergies. We think that we can provide a lot of that synergy. We have best-in-class connectivity, probably far better than any of the other terminals. And we have the ability to really provide them blending opportunities to capture some of those synergies that they have out there. Robert, we're not really -- right now, Hardisty has the Husky terminal is full and economics to probably build new tankage and take from us would be very challenging.

[Operator]

Our next question comes from Linda Ezergailis with TD Securities. [Operator Instructions]

[Linda Ezergailis, Research Analyst]

Recognizing that the weather is sometimes even more challenging to predict in the capital markets, I'm wondering if you can just give us a sense of what you think the potential implications for the unfortunate cold snap is in the Southern U.S., is there any effect on your business? How might that change how you approach that business prospectively, either capturing more connectivity opportunities, adding resilience to your business for your customers? Or might that create some challenges that might make you rethink the opportunities there long term?

[Steven R. Spaulding, President, CEO & Director]

So, yes, the cold snap in the U.S. Obviously, in the Permian Basin, it did almost shut in all that production for about 5 days. And I was talking to my U.S. ops person yesterday and all that production is back online. But it was a 5-day event kind of for the U.S. production. So I don't know that has any real long-term impact to our strategy in the U.S., which is a very small, small piece of our business.And right now, there's very little drilling activity, but talking to our producers, that's about to start to pick up as the year goes on. Right now, on the U.S., I would say we've pulled back on what we're going to spend in the U.S. until things really kind of fundamentally change in the Delaware Basin there.

[Linda Ezergailis, Research Analyst]

Okay. And maybe just as a follow-up in terms of capital allocation. Again, a strategic question on some of the consolidation we're seeing with maybe just a bit more thought if we can get from you on as producers consolidate and midstreamers consolidate, how important do you think scale is and bundled services as well in your offerings to your customers? Might producers want to seek more bundled services from midstreamers and how might that influence your competitive positioning versus some of the more discrete services that you provide currently?

[Steven R. Spaulding, President, CEO & Director]

As far as bundled services, probably that's one of those opportunities that we're talking about there at Edmonton as far as building a tank is really starting to bundle the service in between Hardisty and Edmonton, and those 2 major hubs in Canada. And how do we use the 2 facilities to really help enhance our producer net back, especially as they consolidate and they get new streams. How do we work together to help them maximize their netbacks on their crude oil? I'll let Sean talk about just pure size and the other question, Sean?

[Sean M. Brown, Senior VP & CFO]

Yes. Thanks, Steve. Yes. No, Linda, I think we've been always very clear. I understand the benefits of being larger. Pre us getting investment grade, that probably would have been, at least from a capital markets perspective, one of the more important because size is certainly a criteria for the rating agencies.With our current size, from a capital markets perspective, as we've always said, what we're very focused on is delivering a total return to our shareholders. So think of that as being growth for us yield over time. The challenge is you get larger and larger, it's more difficult to achieve that growth. I think Steve spoke about our confidence in being able to deliver on the growth certainly over the next 3 to 5 years here, consistent with what we have historically. But to the extent that we were to get larger just for the sake of getting larger, that would make that more difficult.So given our focus on delivering total return to shareholders and certainly on a per share basis, again, getting bigger just for the sake of being bigger is not necessarily a focus for us. Now if there's something strategic, or we got bigger through something directly on strategy, such as building additional tanks or phases of the DRU, that's absolutely something that we would be interested in. But again, just getting bigger for the sake of getting bigger is not a real focus for us.

[Operator]

Our next question comes from Robert Kwan with RBC Capital Markets.

[Robert Michael Kwan, MD & Energy Infrastructure Analyst]

I'd like to come back to some comments you made earlier on the call around capital allocation. And specifically, if things improve, maybe you look at share buybacks in the second half. But you also talked about what sounds like a pretty significant ramp-up in commercial discussions around new growth that may come together, call it, later this year. So when you think about your funding and your funding slide shows, I think the ability to self-fund in the $300 million to $350 million range per year. Do you see that then as being kind of the optimistic case for capital spending for 2022, if you're thinking about putting money out the door in the second half around buybacks?

[Sean M. Brown, Senior VP & CFO]

I can start on the buyback one. And then maybe, Steve, you can touch upon sort of the growth outlook for next year. That buyback comment they made, Robert, was in the context of our current capital plan for this year and assuming a consistent capital plan for next year. Obviously, and as I -- I think the start of the question I gave, mentioned that our focus from a capital allocation will always be on growth capital to the extent that, that growth capital is being deployed towards projects that have characteristics like we typically deploy. So to the extent that our capital gets flexed up through the back half of this year, and we have visibility to having higher capital through next year, then absolutely, that would be the focus from a capital allocation perspective above share buybacks. Just given the return we see that and the long-term value, we see that delivering to our shareholders. Steve, do you want to touch on the sort of growth aspect of that?

[Steven R. Spaulding, President, CEO & Director]

Yes. And then on the capital side, obviously, since we haven't signed any agreements, we're not going to -- we kind of know our funding plan for the next 6 -- to the midyear. And if we are able to sign agreements that would be back half lated the new capital. But I would say, right now, we're kind of in that $150 million to $200 million range. And then if we get a DRU, if we sign a DRU, it pushes us up into that right or at $300 million range if we're able to sign a DRU, Robert. And so we could definitely see that kind of -- we see that progressing over the next 3 to 5 years.

[Robert Michael Kwan, MD & Energy Infrastructure Analyst]

That makes sense. Just to break down, the CapEx. You noted that roughly half, if I'm reading it right, of this year's CapEx, you're putting in the bucket of beneficial to ESG. Are you considering the DRU is [ being ] in that? And can you just talk about that? Or if it's not, just can you talk and elaborate on what the nature of some of the other projects are?

[Steven R. Spaulding, President, CEO & Director]

Yes. So I will talk a little bit about that. First, the DRU, we've done quite extensive research on just how is this negative or positive? And one of the things is the DRUs is separating the condensate from the crude oil. That exact thing will happen on the U.S. Gulf Coast as it was refined out. So with that, you got to think that's kind of net neutral. The actual CO2 there. And then with removing that 30% to 35% condensate, you're not having to transport that on pipe down, and you're not having to transport that going down to states, but you're also saving that barrel coming back up. And so we see that as a -- actually, the savings is twice or about 150% more than the actual CO2 footprint of the DRU itself.So on a North American basis, we see that in Phase I and Phase II admissions, probably about 150% savings on a North American basis. So it does have a significant. Now the other one is at Moose Jaw, and I kind of talked about that project. And then there's others that we're looking at at Edmonton, we're looking at a pretty significant spend that's really in that renewable space.

[Robert Michael Kwan, MD & Energy Infrastructure Analyst]

Got it. Okay. And if I can just finish question of your tanks and contracting. I know you've got a lot of newer tanks. But have you had any recontracts expire? And can you talk about what recontracting pricing trends have been, not you, but others had expressed that given some of those tanks were built in the past. And if you think about it from a avoided cost pricing, there actually was upward pressure on rates. Is that something you're seeing or expecting with future tank contract rollovers?

[Steven R. Spaulding, President, CEO & Director]

So we've only had one contract expire really over the last 1.5 years, and that contract just rolled into a evergreen kind of contract. We've got a couple of contracts coming up in the latter part of this year, and we're currently in contract negotiations there. And right now, it appears that it's -- the recontracting will be right at or maybe a little bit above the existing rates for those tanks.

[Robert Michael Kwan, MD & Energy Infrastructure Analyst]

I'm just wondering because when there's -- like if you're talking about signing additional commercial agreements? Or maybe is this just how you're dealing with existing customers and trying to favor them. But if you've got others who want new tanks, who are willing to pay returns based on today's capital costs, should that provide reasonable uplift then on the pricing?

[Steven R. Spaulding, President, CEO & Director]

We've got more and more capital efficient, right, at building tanks. And I think some of that -- some of the labor costs that went down for tankage. So I would say -- I don't think -- steel cost has went up. But -- so I would say still in that -- as these expiring, we're seeing some of the rates go up, but some of these were 5-year agreements, Robert. And in those 5-year agreements, there hasn't been a significant change across there.Obviously, when the 10-year agreements start to expire, we will -- there will be a potential to raise some rates. But all of our tanks have an escalator on them. So that's one of the reasons why you're not seeing the rates go up any kind of significant amount. It's because they all have annual escalators on them.

[Operator]

Our next question comes from Andrew Kuske with Crédit Suisse.

[Andrew M. Kuske]

I guess it was a broader question as it relates to the market environment. And when we see TransMountain done and Line 3 gets done, does that play right into your wheelhouse with tank positioning? And I ask the question part is, do you see the market environment becoming a bit more dynamic with additional egress?

[Steven R. Spaulding, President, CEO & Director]

I don't know about dynamic. I think that we see a lot more interplay between our Edmonton and our Hardisty assets. And the dynamics between those, as you get a greater market pool to the Pacific, where everything else in the past have been just drawn into the U.S. Gulf Coast and Midwest. I think that creates potentially some excess capacity, which really generally reduces volatility in the market. So -- go ahead.

[Andrew M. Kuske]

No, sorry, sorry, continue.

[Steven R. Spaulding, President, CEO & Director]

No, no, I'm good.

[Andrew M. Kuske]

And I guess just a different question. When you think about just the DRU economics right now. With egress issues looking to be ending, what's the tone of conversations? And I ask the question in part because there's clearly the benefit of higher commodity prices, but then there's also the detriment of higher commodity prices as it relates to diluent costs.

[Steven R. Spaulding, President, CEO & Director]

So with the DRU, I mean, one of the big -- the U.S. refiners are still a little leary because that crack spread is still pretty tight in the states, and their economics have been pretty challenged over a year. So they're pretty leary in the U.S. to enter any really long-term contracts right now. And then with the producers, I think there's a couple of things going on there. One is, they want to see it run. So they want to see the DRU run. They want to see and prove it out that it does work. And then the other piece there is their balance sheets have been weakened by COVID. They're strengthening now, but their balance sheets were weakened by COVID.So I think it's just an overall strengthening of our customers will help with it. And I think proving out the actual operation will help. As far as condensate pricing, as long as we're still importing from the states, there's still going to be a pretty good-sized differential between Canadian condensate pricing and in condensate on the U.S. Gulf Coast. So that diff is going to remain wide.

[Operator]

Our next question comes from Matt Taylor with Tudor Pickering, Holt & Company.

[Matthew Taylor, Director of Midstream Research]

Yes. Just a quick one for me here. It's on the gathering pipes. It looks like revenue and volumes dropped quarter-over-quarter. I was just wondering if there's any competitive pressures you're seeing there? Or -- I would have expected it to be slowly trending up. So any color there would be helpful.

[Steven R. Spaulding, President, CEO & Director]

Yes. I don't think there was any competitive pressure there. I think that was just total -- people aren't drilling. And for crude oil right now, the drill rigs had stopped, so you're just seeing decline. Just kind of natural decline month-on-month. So as the producers do start to deploy those drilling rigs again, we'll see that reverse.

[Operator]

Our next question comes from Chris Tillett with Barclays.

[Christopher Cox, Director & Equity Research Analyst]

Most of my questions have been asked by this point. But I guess, maybe just one quick one, if I could. Sort of retrospectively, I appreciate the comments around your buyback philosophy, particularly as it relates to performance in the marketing business. But if I could just look at the fourth quarter of 2020, I think you guys did close to about $20 million in buybacks, and that was obviously not the strongest quarter there for marketing. So just trying to kind of marry the decision-making process last quarter with sort of what you're anticipating moving forward, if you could help us sort of sort that out?

[Sean M. Brown, Senior VP & CFO]

Yes. Thanks, Chris. I mean the buyback in December was very much in conjunction with the early redemption of our convertible debentures. So as a reminder, we had those convertible debentures for an extended period of time, those are trading well into the money. Given our absolute focus on per share metrics here, we'd investigated different options where we could try and mitigate the dilution from those convertible debentures. With some of the pressure we saw at the end of the year, the -- our shares begin to trade-in and around that conversion price we opportunistically called those debentures for early redemption in an effort to try given our liquidity and in an effort to try and mitigate the dilution. As it's a 30-day call period, during that period, the shares sort of vacillated in around the conversion price. And so what that NCIB really we executed on there was to try to the extent that those shares actually did convert into equity as opposed to being cash settled, we wanted to try and mitigate some of the dilution there because over time, we would have wanted to have bought back those shares. What actually ended up playing out is of our -- just under $100 million of notional amount but 95% of it cash settled. So call it, $4-ish million actually equity settled. The buyback at that time was in anticipation of potentially a bit more of that than that actually being equity-settled. So really, the buyback activity is there were more in relation to our the early redemption of our converter of debentures as opposed to a longer-term call on our capital allocation vis-à-vis marketing performance.

[Christopher Cox, Director & Equity Research Analyst]

Okay. Yes. That's helpful. And I appreciate the color then. So then basically, something more not technical, I guess, but certainly not something that you would think would repeat this year.

[Sean M. Brown, Senior VP & CFO]

No, no, that's absolutely right. I mean, as I spoke to in my prepared remarks, thankfully, we now have a very -- a much more simple capital structure, fully investment grade. So opportunities like that and the refinancing of our notes that we've done over the past 18 months have largely been done. So no, I wouldn't expect that. I would expect, as I said earlier that to the extent that we utilize the NCIB, that will be in conjunction with an improvement in our outlook for marketing and somewhat dependent on our outlook for growth capital. Again, if that flex is up, that could impact our ability to utilize it, as I indicated on -- in one of the answers previously.

[Operator]

There are no further questions. I would like to hand the call back to Mark.

[Mark Chyc-Cies]

Thanks, operator. And let me take this opportunity to thank everybody for joining us for our 2020 fourth quarter and full year conference call. Again, I'd like to note that we have made certain supplementary information available on our website, gibsonenergy.com.If you have any further questions, please reach out at [e-mail]. Thanks for joining us. Thanks for your support of Gibson, and have a great day. Thanks.

[Operator]

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