Welcome to the HollyFrontier Corporation’s First Quarter 2021 Conference Call and Webcast. Hosting the call today from HollyFrontier is Mike Jennings, President and Chief Executive Officer. He is joined by Rich Voliva, Executive Vice President and Chief Financial Officer; Tim Go, Executive Vice President and Chief Operating Officer; Tom Creery, President, Refining and Marketing; and Bruce Lerner, President, HollyFrontier Lubricants and Specialties. At this time, all participants have been placed in a listen-only mode and the floor will be open for your questions, following the presentation. [Operator Instructions] Please note that this conference is being recorded. It is now my pleasure to turn the floor over to Craig Biery, Vice President, Investor Relations. Craig, you may begin.
Thank you, Julie. Good morning, everyone, and welcome to HollyFrontier Corporation’s first quarter 2021 earnings call. This morning, we issued a press release announcing results for the quarter ending March 31, 2021. Yesterday afternoon, we issued a press release announcing our acquisition of Shell’s Puget Sound refinery.
If you would like a copy of the press releases and the acquisition investor presentation on the Puget Sound refinery, you may find one on our website at hollyfrontier.com.
Before we proceed with remarks, please note the safe harbor disclosure statement in today’s press release. In summary, it says, statements made regarding management expectations, judgments or predictions are forward-looking statements. These statements are intended to be covered under the safe harbor provisions of federal security laws. There are many factors that could cause results to differ from expectations, including those noted in our SEC filings. The call also may include discussion of non-GAAP measures. Please see the earnings press release and acquisition investor presentation for reconciliations to GAAP financial measures. Also, please note any time-sensitive information provided on today’s call may no longer be accurate at the time of any webcast replay or rereading of the transcript. And with that, I’ll turn the call over to Mike Jennings.
Great. Thanks, Craig. Good morning, everyone. Today, we reported first quarter net income attributable to HollyFrontier shareholders of $148 million or $0.90 per diluted share. These results reflect special items that collectively increased net income by $234 million.
Excluding these items, adjusted net loss for the first quarter was a negative $85 million or negative $0.53 per diluted share versus adjusted net income of $87 million or $0.53 per diluted share for the same period in 2020. Adjusted EBITDA for the period was $47 million, a decrease of $221 million compared to the first quarter of 2020. The Refining segment reported adjusted EBITDA of negative $66 million compared to $176 million for the first quarter of 2020, and consolidated refinery gross margin was $8 per produced barrel, a 28% decrease compared to the same period in last year. This decrease was primarily due to lower realized product margins coupled with compressed crude differentials.
First quarter margins were also impacted by winter storm Uri, which increased natural gas costs by approximately $65 million across our refining system.
First quarter crude throughput was approximately 348,000 barrels per day, slightly below our guidance of 350,000 to 380,000. We recently completed planned turnaround work at our Tulsa and Woods Cross refineries and have no scheduled maintenance until the fall. Strong finished product and base oil margins drove a record financial quarter for our Lubricants and Specialty Products business. Reported EBITDA was $87 million compared to $32 million in the first quarter of last year and included $8 million for restructuring charges.
Excluding the $8 million of restructuring charges in lubricants and specialties, adjusted EBITDA was $95 million. Rack Forward adjusted EBITDA was $88 million, representing an 18% adjusted EBITDA margin.
For the full year of 2021, we expect to earn between $230 million and $270 million of adjusted EBITDA in the Rack Forward portion of this business.
Within the Rack Back segment, we expect base oil margins to temper from current spot market levels but expect they will continue to be higher in the past three years. Holly Energy Partners reported EBITDA of $96 million for the first quarter compared to $64 million in the first quarter of last year.
During the quarter, refined product volumes improved, and we are optimistic for continued improvement in refined product demand in our markets as we head into the summer driving season.
We are excited to announce that yesterday HollyFrontier entered into an agreement to acquire Shell’s Puget Sound refinery for a purchase price of $350 million plus hydrocarbon inventory to be valued at closing with an estimated current value of $150 million to $180 million. This purchase price represents an attractive acquisition multiple of 1.5 to 2 times EBITDA net of inventory, based on the refinery’s historical financial performance. The Puget Sound refinery is a high conversion, 149,000 barrel per day capacity plant located in Anacortes, Washington. It is well positioned in the premium Pacific Northwest product market and has advantaged access to both, Canadian crude via the Trans Mountain Pipeline as well as Alaska North Slope supply. Puget Sound has an outstanding environmental, health and safety track record and has been well capitalized through the past 10 years.
We are committed to continuing the site’s track record of responsible operations and we look forward to welcoming Puget Sound’s highly skilled workforce to the HollyFrontier family. Financially, Puget Sound refinery has a history of consistent earnings and free cash flow, averaging $235 million of annual EBITDA and $75 million of free cash flow between 2015-2019, again, an attractive 1.5 to 2.0 times EBITDA multiple net of inventory for this well capitalized and very well operated refinery.
We expect the acquisition will be immediately accretive to earnings per share and free cash flow. Financing for the acquisition will come from a combination of one year suspension of our regular dividend as well as cash on hand.
Additionally, we’re evaluating opportunities for an asset drop down to Holly Energy Partners. This transaction is currently subject to regulatory clearance and other customary closing conditions and is expected to close in the fourth quarter of 2021. A copy of the acquisition press release and accompanying slide deck can be accessed on our website under the Investor Relations, Events and Presentations tab.
So, with that, let me turn the call over to Rich.
Thank you, Mike.
As previously mentioned, the first quarter included a few unusual items. Pretax earnings were positively impacted by a lower of cost or market adjustment of $200 million and a $52 million gain on a tariff settlement, which were partially offset by severance costs of $8 million related to restructuring in our Lubricants and Specialties segment, as well as charges related to the Cheyenne Refinery conversion to renewable diesel production, including decommissioning charges of $8 million, LIFO inventory liquidation cost of $1 million and severance charges totaling approximately $500,000. A table of these items can be found in our earnings press release. Cash flow from operations was $62 million in the first quarter, which included $25 million of turnaround spending and $14 million of working capital gains. HollyFrontier’s standalone capital expenditures totaled $117 million for the quarter.
As of March 31, 2021, our total liquidity stood at approximately $2.5 billion, comprised of a standalone cash balance of over $1.1 billion, along with our undrawn $1.35 billion unsecured credit facility.
As of March 31st, we have $1.75 billion of stand-alone debt outstanding, a debt-to-cap ratio of 25% and a net debt-to-cap ratio of 8%. Last week, we successfully completed an extension of our $1.35 billion revolving credit facility, which now matures in April of 2026. We anticipate recovering between $50 million and $60 million in cash tax benefit in 2021 under the CARES Act, and in the first quarter, we recovered $21 million of estimated tax payments made during 2020.
During the first quarter, we declared and paid a dividend of $0.35 per share totaling $58 million.
As Mike mentioned, as part of the acquisition financing of the Puget Sound refinery, the HollyFrontier Board of Directors approved a one-year suspension of the regular quarterly dividend, effective with the dividend to be declared for the first quarter of 2021. It is expected to resume the dividend after such time. HEP distributions received by HFC during the first quarter totaled $22 million. HollyFrontier owns 59.6 million HEP limited partner units, representing 57% of HEP’s LP units with a market value of over $1.2 billion as of last night’s close.
Turning to forward-looking guidance. Within our Refining segment, for the second quarter of 2021, we expect to run between 400,000 and 420,000 barrels of crude per day. With respect to capital spending, we are increasing our capital guidance, specifically in our Renewables segment based on updated project cost estimates.
Our total Renewables project spend is now expected between $800 million and $900 million, and importantly, these projects remain on schedule. Specific to calendar 2021, we now expect to spend between $625 million to $675 million in renewables versus our prior guidance of $520 million to $550 million. The rest of our 2021 capital budget is unchanged. Still expect to spend between $190 million to $220 million for capital at HollyFrontier refining and marketing, $40 million to $50 million Lubricants and Specialty Products, and $320 million to $350 million for turnarounds and catalysts. At HEP, we expect to spend $14 million to $18 million for maintenance capital, $30 million to $35 million for expansion capital, which includes our investments in the Cushing Connect joint venture, and $5 million to $8 million in refinery processing unit turnarounds.
As a reminder, beginning in the fourth quarter of 2020, activities associated with the conversion of HollyFrontier’s Cheyenne Refinery to renewable diesel production, along with the construction of renewable diesel and pretreatment units in Artesia, New Mexico, are reported in HollyFrontier’s Corporate and Other segment.
For fiscal year 2021, we continue to expect Corporate segment operating expenses to be in the range of $100 million to $120 million which includes decommissioning and severance costs related to the Cheyenne Refinery conversion in the range of $20 million to $30 million. With that, Julie, we’re ready to take questions.
The floor is now open for questions. [Operator Instructions] Your first question comes from Manav Gupta with Credit Suisse.
So, the price obviously doesn’t look a problem as far as the refinery is concerned. But, one of the key questions we have been getting since last night is the last guy who bought a refinery on the West Coast from Shell was also hoping to make $350 million, and it did not go down that way.
So, I’m just trying to understand what due diligence have you done to make sure that this EBITDA is realizable and what would you like to say to the bears who are basically out there saying buying West Coast assets from Shell doesn’t really work out well?
Thank you for your question. And as a starting point, the current owner and an operator of that facility has run it really very well and capitalized as well. It’s a premium asset in a premium market, and we’re feeling that we are getting a very good price on it.
We’re not going to comment as to other buyers and other transactions. In this particular one, we’re paying less than $3,000 of capacity barrel for a high complexity refinery in a great market.
Going past that, it creates big opportunities for our Company. And I’ll just kind of bang through them. And we will certainly elaborate and expect to spend some time on this call discussing it.
First, we’re going to benefit from relative advantage of operations in Washington versus California. With a refinery that has a heavy gasoline yield.
Second, we bring additional feedstock benefit to this refinery versus our existing relationships with crude suppliers and a Trans Mountain expansion.
Third, we’re engaging a commercial foothold in another LCFS state, which adds opportunity for our renewables business. Fourth, we’re adding diversification to our portfolio, which at present is fairly heavily dependent on regional crude differentials. And finally, as I’ve said, we’re adding an asset that has scale, great operations, well capitalized at an attractive purchase price.
And a follow-up question here. Rack Forward, even higher than your guidance. Clearly, you have turned this business around.
I think last quarter also, you were indicating that there was a price lag because of which you couldn’t realize the full benefit.
So, a little bit of outlook on the Rack Forward, because at 1Q rate, you could actually even beat your annual guidance, which looked a little difficult earlier in the year, but clearly, things have really -- are looking strong on the Rack Forward front.
So, if you could comment on that market a little?
So for the short term, which involves probably the balance of this year, we see conditions continuing to be similar as the first quarter. Maybe as COVID relief comes along with vaccinations and people come out of turnarounds and refineries pick up steam on fuel side, there’ll be a little more supply in the market. But, overall dynamics right now look to be similar in going forward as they were in the first quarter.
The next question comes from Matthew Blair with Tudor Pickering Holt.
In regards to acquisition, do you see this as a shift in your overall strategy, where down the road, you’d like to acquire even more PADD V assets, or to kind of view this as like a onetime opportunistic deal that you just kind of passed up?
So, in terms of our strategy, I don’t see us in California, if that is your question. And following this acquisition, I think we’ll have enough concentration within Puget Sound, but this would be a onetime opportunity for us. With that said, we see PADD Vs attractive and particularly the Pacific Northwest as being attractive. And there are a few reasons for that, but it is advantaged geography in terms of crude supply. It also has advantages in respect of operating environment and operating cost versus the remainder of PADD V.
So, effectively, we want to be in the north part of PADD V and believe will benefit from what’s going on in California.
Got it. And then, could you talk about the RIN exposure at the refinery? How much internal blending can it do? And then, also, just with Washington recently passing the LCFS program, what’s your outlook there? And what would you do if conditions became just pretty weak on the West Coast, right, with decreasing renewable diesel and increasing electrification? Where is the outlet for West Coast refineries?
Hey Matthew, it’s Rich.
So, with respect to RINs, the plant has historically exported, call it, 15% of its transportation fuels, gasoline and diesel and can blend about that quantum at the rack there.
So, call RIN -- call our exposure here, 60% or so. I’d point out that this has a -- plant has a relatively low diesel cut, and that’s went into our thinking.
As you look at PADD 5 in general, and the closures that have been announced versus what we’re seeing in renewable diesel, we’d expect the diesel market that’s in balance and the gasoline market that’s actually short.
So, we feel like this plant is really well positioned. And frankly, our company when you consider our renewable diesel investments are really well positioned vis-à-vis that outlook.
Your next question comes from Theresa Chen with Barclays.
Mike, I was hoping you could dig in a little further on your comment about having that commercial foothold in an LCFS state since the Washington state Assembly has passed that greenfield standard legislation. What does this mean for your existing projects? What kind of commercial synergies can you derive there?
So immediately, it will be small because our commercial relationships are directed toward California, but there’s going to be clearly a knock-on benefit in terms of demand for renewable diesel. And as we get up to speed in marketing light oils, liquid products in Washington, we’ll have the opportunity to arbitrage between those two markets.
And so, that’s really where that comment comes from.
Got it. And Rich, in relation to the uptick on the project spending, can you talk about what’s driving that? And at this point, what is there left to do on the execution side?
Theresa, this is Tom Creery, and I’ll make a few comments in response to your question. The cost for the renewable diesel project has gone up due to a variety of different factors.
We have changed the scope a little bit as we have moved forward with this project. And in doing so, we’ve encouraged more construction costs and metallurgy costs with the idea of being is that we have to metal up to be able to run alternative feedstocks that have lower CI.
So, this is an economic play. It’s also a longevity play as we move through the marketplace with renewable diesel. And we’re not hanging our hat on one particular feedstock that being soybean oil.
So, that’s part of it. We’ve also seen some COVID effects in terms of construction costs have been going up, as well as raw material costs such as steel. We’ve seen those prices going up. We’ve seen a little bit of delay in the delivery of some parts and vessels from overseas locations. And what we’ve tried to do is as previously said, is to stay within our schedule because we’re trying to capture that DTC prize at the end of the day, which is worth a lot of money to us in the long run.
So, schedule is very important to us.
So, we’re having to balance some of the schedule versus the increased costs. And that’s where some -- most, if not all of the costs are coming from at this point in time.
In terms of future spending, we have ordered or have on order most of the equipment, very high percentage.
I think, we probably have a very little left to do.
So, most of those costs are already locked in and set and are included in our new numbers. We’ve made allowance for some construction cost increases in our new numbers. And that’s probably where the bulk of our risk is going to be as we go forward is in terms of construction cost. And there, again, the impact of that would be weather, COVID, such things like that.
Your next question is coming from Ryan Todd with Simmons Energy.
Following up on the acquisition, can you walk through the decision to suspend the dividend? How are you thinking about that from a balance sheet exposure point of view? Was it necessary or just cautious on your part? And if earnings over the next couple of quarters ended up more supportive than expected, is there any sensitivity on the length of the suspension?
Hey Ryan, it’s Rich. Look, I would call that’s cautious for sure. We see, obviously, a tremendous opportunity here, but it comes in the midst of financing and other grade opportunity in Renewables as well as a really heavy maintenance year in our Refining business. And these investments all have to be viewed in the context of our long-standing commitment to an investment-grade credit rating.
So with that in mind, we feel it’s prudent to invest a year’s worth of dividends to ensure our balance sheet through 2021.
We are not doing this lightly. We view the dividend as our primary vehicle of cash return. And in our industry and at HollyFrontier, cash return is an essential part of the investment thesis. To your point, we intend to return the dividend at previous rate in a year, I think if things go better than we’re expecting, could be earlier than that. Last thing I’ll say on this is, as you recall, in November of 2019, we articulated a plan to grow our dividend.
We haven’t forgotten about that. And we strongly believe that Puget Sound and the build-out of our renewables business is going to enhance our ability to do that going forward.
All right. Thanks, Rich. And maybe one additional and following up on some of your comments earlier, Mike. I mean, with getting a foothold in an LCFS state there in Washington, there’s a benefit that may come, but there’s also a potential obligation burden down the line under the standard. I mean how do you think about the obligatory burden, if you kind of -- if you look 5, 10 years down the line? And is there any possibility that you could ever convert in accordance to an RD facility, or is that nowhere in the plans?
So, few questions, and I’m going to try to hit them one at a time. The foothold in the LCFS state is opportunity for us because we think that the renewable diesel molecules will flow. And we’ll be out there actively marketing product.
So, that is an opportunity, as I previously spoke.
As to whether it’s just an opportunity or also an obligation or a burden, I think we look to the California market, which Washington is trying to link to.
Now, recognize, this legislation just passed. But trying to link to California, in California, the consumer is effectively taking 100% of burden of LCFS.
So, we don’t see that encroaching significantly into our refining economics.
Third point would be, as we may, this is a gasoline maker. It does have diesel and jet, but the diesel yield is relatively low on this plant.
So, we think it is regionally well positioned because of that. And finally, as to the legislation itself and the opportunity to convert, what I’d say is the legislation is modified by need for in-state production of renewable fuels or lower CI fuels. And at the same time, they’re very cautious about permitting new emissions.
And so, that impacts both our ability and Anacortes to do something with renewable diesel, but also the ability for this LCFS to roll forward in the emissions manner.
So, that’s a question mark. And I think we’ll play that out through time as to what the states really intend with respect to local production opportunities versus the permitting of associated emissions.
Your next question is coming from Paul Cheng with Scotiabank.
I just want to go back, Rich on the dividend suspension. Is that a purely an internal decision or that is a suggestion from the rating agency also? So, just trying to understand that the background behind why you guys decided to suspend it. Because it does look like your balance sheet is strong or not, even with the increasing the renewable CapEx spending that you should be able to handle it, without the suspension.
So, no, this is a decision we made before speaking with the agencies. Like, this was made out of an abundance of caution, and I think you’d agree that’s consistent with how we’ve run our balance sheet historically.
We have obviously since spoken with the agencies.
We’re not expecting any changes to the ratings. And in the long run, this is objectively positive from a credit perspective.
So, no, this was done from an abundance of caution, nothing more than that.
All right. And the second question is two parts, maybe separate. One is that, do you have a CapEx spend and expectation for the Puget Sound for 2022 and forward on the average cycle also? And also, I think this is for Mike.
You guys have never been in the western state, [ph] this is a totally step out, and it’s a very progressive pace.
And so, I guess that the pushback we got from people is that how can you feel comfortable about the long-term regulatory and political environment given how progressive the state over there has been?
Paul, let me hit your capital question. I’ll hand it to Mike.
I think consistent with what you’ve seen historically, we’d expect to spend $30 million to $50 million a year in sustaining capital. Obviously, turnarounds are similar to what we would see elsewhere.
The first one that’s scheduled is 2024.
So, that speaks to the capital. Tim, do you have anything else on that.
I was just going to say, we’ve got some numbers in the PowerPoint slides that we posted last night. OpEx is about $5.55 a barrel. And then what I would basically tell you is, the asset is a high quality asset, as Mike mentioned before, highly competitive, not just in the PADD V region but also in the whole Washington area.
So Paul, your second question, I think, was a point that isn’t Kansas anymore worthy. And we fully understand.
First, this refinery has operated and has been operating in the Washington state for a very long time.
So, the real questions really are around the progressive agenda and what happens going forward to limit our ability to operate and make money. And our viewpoint on that is really kind of two or threefold. But first, that California is going to be more progressive. It is also a higher operating cost jurisdiction in terms of OpEx and CapEx and lesser in respect of crude economics. We believe we’re relatively advantaged, and that usually creates opportunity within the refining business.
Beyond that, we’re going to have to be good stewards, just like any other operator, and we’ll also be opportunistic, blending what we see as opportunities created by LCFS and other such things against the reality of a more progressive or otherwise demand destroying hydrocarbon agenda.
Beyond that, I think there’s a cap and trade legislation that recently passed. The impact on us will be about 6% reduction in greenhouse gas emissions. And we feel like we can address that through energy efficiency investments and operating procedure at the plant.
So, the more elaborate answer is, we’re looking hard at this. We believe we understand it. We’ve studied it through due diligence, and we’re prepared.
Mike, can I sneak in one final question?
On the renewable diesel project, budget increased. Since you announced it only about a year ago, you already raised it a couple of times.
So, when we look back in hindsight, have you learned anything that in terms of what may be the process when you budget and FID, the project that need to change in order to avoid this cost increase or overrun?
So Paul, we’ve increased onetime.
Our previous advice was that we were looking towards the high end of the range, not through this period. And in respect of your question or your point, learnings are threefold. One is that we chose to add scope to these projects as things have evolved to take advantage of lower CI, better feedstock economics. We think those are intelligent decisions and warranted by the increase in project return.
Second, had we known then what we know now in respect of trying to execute projects in a COVID environment with people working from home, supply chains constricted, et cetera, yes, we would have added more contingency. And that’s a lot of what we’re seeing in addition to the scope change around feedstock. The final bit was, I think, as announced, we wanted to get in front of this in terms of capturing blender’s tax credit. And in so doing, final investment decision was made relatively early. And on one hand, we can take strikes for that; and on the other hand, we’re going to make money relative to blender’s tax credit.
So, that was a reason to decision that we made, and it led to scope evolution that wasn’t firmly tacked down when we announced the project.
You our next question is coming from Phil Gresh with JP Morgan.
With respect to the mid-cycle EBITDA guidance for Puget Sound of $150 million to $200 million, could you share what 2020 was and how you think 2021 is evolving?
Hey Phil, it’s Rich.
So, 2021 was a loss. I don’t have the number in front of me, but we’ll get back to you on that. I will say that at today’s crack, plant is clearly running at that mid-cycle number or better.
You’ve seen those levels really probably since early March in the Pacific Northwest.
Okay. Got it.
On the renewable diesel side, could you just elaborate a bit on your plans for start up? Exactly, when you expect to start-up and how you expect that process to go? I mean, some other facilities have had some teething issues with start-up.
You’re talking about battling up to run alternative feedstock.
So, what progress are you making there to be sure that you will be able to capture these blender’s tax credits in 2022?
Well, Phil, this is Tom.
Some of the things that we’ve done in terms of start-up, let me first say that what we’ve done is we’ve already secured some feedstock at this point in time.
So, we’re getting ahead of the ball at this point in time to get feedstocks in place to hit our scheduled start-up.
In terms of the actual start-up itself, I think we’re learning some lessons from those who have come before us. And in dealing with our suppliers and technology, we’re using their knowledge and information to make changes at the refineries or the RDU plants to accommodate this as well as putting in some other failsafe devices at the refinery.
So, we’re definitely in the learning mode. We’ve also moved people around internally to take advantage of hydro trading knowledge, so that we’re not putting new people into new positions.
We’re doing the same with hydrogen plants.
We’re doing cross training.
So, internal people are getting as much knowledge from within on how to operate the units. And then, we’re using external sources and other alternatives to help us with these new units as they come on as well as, like I said before, learning from those who went before us and what happened there.
Okay, got it.
And Phil, this is Tim. What I would just say is, as Tom mentioned, we are working closely with our technology licenser who is also involved in some of the projects that are preceding us. They are helping us with lessons learned and helping us beef-up our start-up procedures and our processes so that we can be successful as we train and prepare for starting.
Okay. Rich, last question.
As we look ahead to 2022 or future spending, can you just remind us how to think about normalized CapEx, layering in Puget Sound as well as, I guess, the residual renewable spend that will bleed over into 2022, just some kind of framework for ‘22 and beyond?
So Phil, on the sustaining level rate, we typically, call it, $375 million for the corporation mid-cycle sustaining. And as always, I emphasize, there’s a lot of volatility around that number with the timing of turnarounds. Puget Sound sustaining capital should be in that $30 million to $50 million range, and we’ll obviously have a turnaround every five years or so as well.
So, I think that $375 million probably moves to call it $425 million as a rounded number. To your second point on renewables CapEx, there will be some bleed over of -- in the ‘22. Right now, we’d expect somewhere between $75 million and $150 million. It’s going to depend a lot on timing of invoices. What we’re looking at here, obviously, is most of the spend is going to come and most of the work is going to come in the second half of the year.
So, we’re having a little bit of a hard time figuring if the invoice is going to show up in December of ‘21 or January of ‘22. But, that’s what’s the play here.
Okay. And that should be a lower turnaround year?
Any ballpark on that?
I don’t have that number in front of me now. But, I believe the only thing we have scheduled is partial turnaround at Woods Cross in ‘22.
Your next question is coming from Neil Mehta.
Good morning, team. I want to go back to the dividend. I’m still struggling on this point. Rich, was your point that given rating agency conversations, Holly was likely on track to suspend the dividend either way, given market conditions, and therefore, this wasn’t related to funding the transaction, or was this a decision to suspend the dividend because it was a conscious decision to invest in this growth asset?
No, Neil, this was a conscious decision to suspend the dividend out of an abundance of caution while making the investment in Puget Sound. It’s directly related to this acquisition. Again, done out of caution and before we talked to the agencies, right.
We expect no action from them.
And so, just for you to spend some more time on this point, because the investor community continues to push return of capital to shareholders. And that’s one of the things that’s made Holly special over the years with the introduction of the special dividend and the outsized return of capital, particularly during the stronger margin environment. How do you get comfortable that prioritizing growth was the right thing to do versus returning capital to shareholders over the next year?
So, I think -- the reality is our return of capital in 2021 was going to be restricted to the dividend given what we had from capital spending perspective. And I think we -- I hope we’ve been pretty clear that the opportunity for our shareholders within the growth that we were going to see in the cash flow, ergo, the cash returns in 2022, 2023 and beyond. That thesis is absolutely still intact. If anything, I think it’s more powerful today. To your point, we have a period of investment here through 2021, which gets us to higher cash returns in ‘22 and beyond.
The other thing I would add, if I can, is that the engine that drives return of cash to shareholders is obviously return on capital employed. And we believe that through renewables and through this investment, we take return on capital employed substantially higher. Obviously, we had some concern about balance sheet stress.
One of the, I would say, criticisms of HollyFrontier by the agencies is size. And they, because of scale and lack of diversity, tend to want to run us at different metrics than our larger peers in respect of retaining the investment-grade rating.
So, we maybe have a little less wiggle room per unit of debt to cap. But end of the day, this is about driving cash returns on our business that can ultimately be provided to our shareholders. And we feel like it’s the right decision, given the high-return of the investment.
Mike, if I could just press you on that. Was there a cheaper way or an alternative way that you could have funded this, either maybe asset sales or elsewhere without having to press on the dividend?
The cheaper way is obviously debt. And our concern is that that ultimately increases our overall cost of capital by increasing our cost of debt and by introducing volatility into our equity.
So, we believe that this reduces our cost of capital.
Your next question is coming from Jason Gabelman with Cowen.
I wanted to ask on the financials you disclosed on Puget Sound. Are the RIN costs -- is that fully burdened within those disclosed financials? And where would -- what would, I guess, the RIN cost be today above where maybe it is in those financials just based on where RIN prices are right now? And I have a follow-up. Thanks.
Jason, it’s Rich. Yes, those historic financials fully reflect the cost of RINs. I don’t have a number for today.
Okay. Any way to ballpark it? I mean, aren’t we talking $1, $2, $3 a barrel, just...
Right. If we can blend or export 30-plus-percent of the product and the RINS are obviously publicly quoted at well-known blend rates, right, you could probably do the math based on your expectation of RIN prices going forward.
It’s effectively 60% of the product slate of fuels make, as Rich said. And the question is, is how much do we capture by crack spread uplift due to high RIN price. And that’s obviously a $64,000 question in today’s market. But, the past is fully burdened and the plant, as Rich said, is nicely profitable on this -- in the spot market today.
Right. Got it. That’s helpful. And then, my second question is just on the opportunity cost on investing in this asset versus maybe doing something in the energy transition space that’s more aligned with peers. Can you just discuss, one, are you now limited in your optionality of investing in opportunities that better future-proof business? And, are you worried that as we move forward and there’s likely increasing concern around the terminal value of the refining business that the business can be valued even lower than where it is today, as you’ve expanded your refining footprint? Thanks.
Jason, that’s a good question. And right now, the shiny new object is clearly renewables. But, I think we have to take a step back and say what is powering this economy through the next 10 years. And we’ll talk about terminal values later. But, the fact is, the gasoline, diesel and jet fuels provided from petroleum hydrocarbons are the major mover of people and equipment around this economy. And other fuels are making inroads, and we’re participating in some of those, we think, at high returns. But we see a pretty bright future for petroleum here in the foreseeable future. And we’re obviously willing to invest in it. It’s a part of our core business. It’s what we do well. And we think that despite the headlines, the numbers would argue that a lot of money can be made in petroleum responsibly operated for a good period of time.
And your next question comes from Doug Leggate with Bank of America.
Hey Mike, I really appreciate the voice of reason on that last comment, we all remember the only petroleum 20 years ago.
So, thank you for that insight today. I have two quick questions, if I may. One is related specifically -- I guess, both related to Puget Sound. The environmental liability that comes with refineries, is Shell holding on to that or are you guys taking that on? Can you put any characterization around that? And if I may also ask, how competitive this process was, or was that under right negotiation?
I’ll answer the first -- the second question first. It was a direct negotiation. We were chosen through an organized process. And then, the second answer is frankly tied up in certain confidentiality. But, I will tell you that it’s an asset purchase, and we are not taking full liability for the past.
Okay. I appreciate. My follow-up is you mentioned briefly the potential for an MLP drop down. I wonder if you could elaborate on any notional numbers of what product it look like.
Doug, it’s Rich. Yes, I think there’s some logical assets that we’ll evaluate here in the second quarter, truck rack and the marine dock, namely.
I think at a high level, we see probably $50 million to $75 million total range of a drop-down potential there.
Okay. That’s really helpful. Can I follow Paul Cheng and go for a third?
Like throwing your buddy under the bus.
I’m sorry, Paul. I apologize publicly for that.
So, in the deck you put out last night, and this is kind of a not terribly nice question. I just want to try to understand what’s going on here. There’s one item in there for growth capital. And it’s not obvious what that was to eliminate it from our go-forward free cash flow estimates, because, obviously, at each of the crude throughput level, didn’t really [Technical Difficulty] any change.
So, do you have any insight as to what that growth capital was and assures that [Technical Difficulty] disappear going forward?
Doug, this is Tim. What I would just tell you is, as Puget Sound has gone through their typical turnaround cycles, they have, of course, identified incremental growth projects that continue to increase yield primarily, as well as product qualities.
We’re very pleased with the flexibility that Puget Sound has to blend gasoline. They can make car gasoline, they can make gasoline that can supply in Canada, they can supply in Alaska. Those types of growth projects have increased the flexibility of Puget Sound’s portfolio to be able to position themselves for those future options that a lot of you folks have asked about on the call today.
As the landscape changes and as the ability to place product becomes changed, as a result of regulations, these growth projects give them flexibility moving forward.
Now, we have not assumed any growth projects specifically going forward in our investment analysis. But of course, as that comes forward, we will evaluate them and consider them on a case-by-case basis.
They spent fairly heavily on crude flexibility, as many did in the Pacific Northwest, targeting receipt of namely Bakken barrels by any variety of means. Not all those investments are currently in the money. But, there was $60 million, $80 million spent in anticipation of those sorts of deliveries in terms of things like crude desalters and receiving facilities and basic crude infrastructure.
So, obviously, that wouldn’t carry forward. The facility is really well capitalized. It’s made its compliance investments. And frankly, the regulatory environment is going to make it tough to do much from a growth perspective.
So, I think we can expect that.
Your next question is coming from Matthew Blair with Tudor Pickering Holt.
Hi. Thanks. Two quick follow-ups here. One, is there a logistics EBITDA associated with the refinery? And if so, would you expect to eventually drop that into HEP? And then two, can you provide any specifics on just the actual product yield of the refinery? Thanks.
Hey Matthew, it’s Rich.
So, on the logistics side, if you go back to that, we do see potential here within that -- within the total that we’ve guided.
So yes, I think, there’s room for a $50 million to $75 million drop down in here if it makes sense for everybody. I’d point you to slide 8 on the deck we put out last night, has detail on historic product mix.
I think that would be reflective of what we would expect going forward as well.
In addition, Matt, to the gasoline and diesel and jet yields there, I’ll just point out, they make anode grade coke and they make specialty [indiscernible] chemicals as well.
So, those premium products just enhance the base product portfolio.
And there are no more questions. I’ll turn the call back over to you, Craig.
Yes. Thank you, operator. We’ll finish up here and obviously follow-up individually with investors and analysts. But it’s just in our wrap up, I would say that with respect to the quarter, it was a solid quarter, obviously affected by storm Uri to the extent of sort of $65 million of OpEx.
Our product markets are well in recovery and demand is now allowing us to run full with the margins that you’re seeing on the screen.
So, we’re pleased with what we’re seeing, recovery wise, reopening wise and demand wise. The lubricants business is really hitting on all cylinders. It’s right markets and right geography. And what I mean by that is, our market really covers a lot of these commodities that are being produced and in short supply, such as lumber, and deep into the Canadian sort of commodity markets. Also, we weren’t affected by the storms and others were.
So, we really are doing quite well, both in our base oil business and in our finished products business. But obviously, what’s in front of us right now is Puget Sound, Puget Sound and Puget Sound. And we’ve got a lot of focus on it.
We’re really excited about it. It was important to enough to us to do that deal and maintain our investment-grade credit rating that we’re willing to do something we really didn’t want to do with respect to our dividend. But we think it’s right for the long-term and right for the value creation of the Company.
So with that, we’ll wrap up, and thank you very much for your participation.
Thank you. This does conclude today’s teleconference. Please disconnect your lines at this time. Have a wonderful day.