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Welcome to HollyFrontier Corporation's Fourth Quarter 2019 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; and Tom Creery, President, Refining and Marketing. [Operator Instructions] Please note that this conference is being recorded.
It is now my pleasure to turn the floor over to Craig Biery, Director, Investor Relations. Craig, you may begin.
Thank you, James. Good morning, everyone, and welcome to HollyFrontier Corporation's fourth quarter 2019 earnings call.
This morning, we issued a press release announcing results for the quarter ending December 31, 2019. If you would like a copy of the press release, 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 to be intended -- are 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 press release 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.
Thanks, Craig. Good morning, everyone. Today, we reported fourth quarter net income attributable to HollyFrontier shareholders of $61 million or $0.37 per diluted share. Fourth quarter results reflect special items that collectively decreased net income by $17 million. Excluding these items, net income for the fourth quarter was $78 million or $0.48 per diluted share versus adjusted net income of $394 million or $2.25 per diluted share for the same period of 2018.
Adjusted EBITDA for the period was $263 million, a decrease of $378 million compared to the fourth quarter of 2018. This decrease in earnings was driven by heavy planned refinery maintenance, coupled with lower product margins and crude differentials.
The Refining segment reported adjusted EBITDA of $172 million compared to $583 million for the fourth quarter of 2018. Consolidated refinery gross margin was $13.58 per produced barrel, a 39% decrease compared to the $22.17 for the same period last year. Our Lubricants and Specialty Products business reported EBITDA of $35 million compared to a negative $4 million in the fourth quarter of 2018. Rack Forward EBITDA was $61 million, representing a 14% EBITDA margin. Full year Rack Forward adjusted EBITDA was $230 million, representing a 12% EBITDA margin.
In 2020, we remain constructive on global demand for finished and specialty products and expect gradual improvement in Rack Back EBITDA from strengthening base oil markets as demand for premium base oils increases and against limited capacity growth. Full year Rack Forward EBITDA is expected in the range of $250 million to $275 million with an EBITDA margin of 11% to 16% of sales.
Holly Energy Partners reported EBITDA of $88 million for the fourth quarter compared to $90 million in the fourth quarter of last year. HEP EBITDA was impacted by lower volumes due to heavy planned maintenance across HFC's refining system. Looking forward, we expect to bring in our Cushing Connect JV project on schedule and on budget.
HEP expects to maintain its quarterly cash distribution of $0.6725 throughout 2020, while generating a coverage ratio of 1.0x for the full year of 2020.
During the quarter, we announced and paid a dividend of $0.35 per share, totaling $57 million and repurchased $61 million of HFC common stock. Our strong cash generation for the full year 2019 allowed us to return $758 million in cash to shareholders through dividends and share repurchases.
In November of 2019, we announced our new renewable diesel unit project at the Navajo Refinery. We are in the early construction process and anticipate commissioning during the first quarter of 2022. The RDU will have production capacity of 125 million gallons per year and allow HFC to process soybean oil and other renewable feedstocks into renewable diesel. This investment will provide HollyFrontier the opportunity to provide high-quality, low carbon fuels for our customers, while substantially mitigating our annual RIN purchase obligation. The project is attractive for 3 reasons: it mitigates our exposure to RINs; it is expected to generate an approximate 30% IRR; and has a favorable ESG profile as it reduces greenhouse gas emissions attributable to middle distillates.
Looking to 2020, we expect that demand for gasoline and diesel will strengthen into the driving season, margins for finished lubricants will remain strong, and the base oil market will improve as existing capacity absorbs growing demand for premium base oils.
As most of you are likely aware, I rejoined HollyFrontier as its CEO effective January 1 of this year. I've maintained close contact with the company and its management team as a Director of both HFC and HEP during the past 4 years, and I'm fortunate to have the chance to join this management team in a leadership role. Obviously, there are differences both inside and outside the company since I was last its CEO, most notably, our investment in the finished lubricants business via PCLI, Sonneborn and Red Giant. These are good businesses and, together with our Group I lubricants business in Tulsa, provide a growing platform for participation in a more differentiated specialties market. The decline in base oils margin over the past couple of years has provided a headwind for this segment, but our product offerings are strong, and I anticipate growth in earnings and value coming out of our HF LSP business. More broadly, I expect to execute a corporate strategy that emphasizes continuing operational improvement within our manufacturing operations; capital discipline and return of capital to shareholders; investment in our renewables business to create scale and advantage within feedstock selection and processing; continued growth of our midstream business, particularly in applications where we're able to integrate midstream services presently provided by third-parties.
I believe we have attractive organic opportunities to generate growth at HollyFrontier. But these will compete with our goal of providing strong cash returns to shareholders as we consider capital allocation.
So now I'll turn the call over to Tom for an update on our commercial operations.
Thanks, Mike.
For the fourth quarter of 2019, we ran 381,000 barrels per day of crude oil, composed of 38% Permian, 17% WCS and black wax crude oil. Overall, lower throughput volume was primarily due to planned turnarounds at our El Dorado, Cheyenne and Woods Cross Refinery.
Our average laid-in crude cost was under WTI by $2.71 on the Rockies, $0.24 in the mid and over WTI by $2.33 in the Southwest.
For the fourth quarter of 2019, we ended the year with gasoline inventories at high levels and gasoline cracks at low levels in most of our markets.
In the Magellan system, we ended the quarter at 9.8 million barrels, roughly 3.2 million barrels higher than the third quarter of 2019.
Diesel inventories ended the quarter at 6.9 million barrels, some 800,000 barrels lower than third quarter levels.
Days supply of both gasoline and diesel in the group finished at 33 and 43 days, respectively.
Fourth quarter 3-2-1 cracks in the Mid-Con were $14.57, $27.90 in the Southwest and $28.36 in the Rockies.
Crude differentials widened across the heavy barrels during the fourth quarter. In the Canadian market, fourth quarter differentials for WCS at Hardisty ended the year at a $20.20 discount. Recently, we have seen this differential compressed to the $18 range due to concerns around economic growth around the coronavirus and lower overall flat crude price.
The levels of apportionment on the Enbridge system remain high. And in March, we were announced that apportionment would be 43% for heavy crude oils. We continue to be able to purchase and deliver adequate volumes of price advantaged heavy crude oil from Canada to meet our refining needs.
Midland differentials averaged the quarter at $0.65 over Cushing, and we see the same differential trading at similar levels for the remainder of the year.
Canadian heavy and sour runs averaged 52,000 barrels per day at our plants in the Mid-Con and Rockies. This was below normal levels as both El Dorado and Cheyenne were down for planned maintenance in this period.
We refined approximately 143,000 barrels per day of Permian crude in our refining system, composed of 85,000 barrels per day at the Navajo complex and 58,000 barrels per day by the Centurion pipeline at our El Dorado refinery.
Our RINs expense for the quarter was $31 million. For the full year 2019, we ran 428,000 barrels per day compared to 432,000 barrels per day for 2018. Our consolidated operating expense per throughput barrel was $6.54 for 2019 compared to $6.24 in 2018 driven primarily by heavy maintenance.
Looking to 2020, we have a turnaround scheduled in September at our Mississauga base oil plant. With our light planned maintenance schedule, we anticipate running healthy utilization rates across the refining system with improved operating expenses in all of our regions. We expect to run between 425,000 and 435,000 barrels per day for the quarter -- first quarter of 2020.
And with that, let me turn the call over to Rich.
Thank you, Tom.
As Mike mentioned, the fourth quarter included a few unusual items. Pretax earnings were negatively impacted by a lower of cost or market charge of $31 million, and Sonneborn integration costs of $4 million, which were partially offset by an $18 million gain on the reinstitution of the biodiesel blenders tax credit for the years 2018 and 2019. The table of these items can be found on our press release.
Cash flow from operations was $137 million in the fourth quarter and over $1.5 billion for the full year, which included turnaround spending of $166 million and $318 million, respectively.
HollyFrontier stand-alone capital expenditures totaled $92 million for the quarter and $264 million for the full year 2019.
During the fourth quarter, we returned a total of $116 million of cash to shareholders, comprised of a $0.35 per share regular dividend totaling $57 million and share repurchase totaling $61 million. For the full year 2019, HollyFrontier paid $225 million of regular dividends and spent $533 million repurchasing approximately 11 million shares of common stock for a total cash return of $758 million.
As of December 31, our total cash balance stood at $885 million, which is above our target cash balance of $500 million. This strong cash position, along with our undrawn $1.35 billion credit facility, puts our total liquidity over $2.2 billion.
As of December 31, we have $1 billion of stand-alone debt outstanding and a debt-to-capital ratio of 14%.
HEP distributions received by HollyFrontier during the fourth quarter totaled $38 million. HollyFrontier owns 59.6 million HEP limited partner units, representing 57% of HEP's LP units with a market value of $1.4 billion as of last night's close.
With respect to capital spending in 2020, we expect to spend between $270 million and $300 million for capital at HollyFrontier refining and marketing; $130 million to $150 million in renewables; $40 million to $60 million at HollyFrontier Lubricants and Specialty Products; and $125 million to $150 million for turnarounds and catalysts.
With respect to the RDU, or renewable diesel unit, we expect to realize the majority of this year's spending in the second half of 2020 and the balance of the capital in 2021.
At HEP, we expect to spend $8 million to $12 million for maintenance capital; $45 million to $50 million for expansion capital, which includes our investment in the Cushion Connect joint venture; and $5 million to $7 million for refinery processing unit turnarounds.
And with that, James, we're ready to take questions.
[Operator Instructions] And our first question comes from the line of Brad Heffern from RBC Capital Markets.
Mike, I appreciate the comments earlier about the strategy going forward with you back in the CEO seat. I noticed that you didn't mention M&A at all, so I was wondering if you could talk through your thoughts on the strategy going forward, whether we're likely to see more lubes M&A and then maybe if you could talk about the relatively large number of assets that seem to be on the market in your region and how you feel about a new refining acquisition.
I'll start out with lubricants. I do see opportunities within the lubricants and specialty space, particularly for bolt-on acquisitions that fill out product offerings and geographic market opportunities. As to significant manufacturing of base oil, I think that's less likely for us.
Moving on to the refineries within the market, I think those are sort of a case-by-case basis, but what we see internally is that there's tremendous opportunity for organic improvement and significantly in the renewable diesel space and renewable fuels. So I think our attention is going to be focused toward those areas that I called out and opportunistically in terms of external refining M&A.
Okay. And then on the renewable diesel front, I guess, can you talk about the advantages that you have at the Navajo facility, either in terms of location or feedstock? And then is this just the start of a broader push into renewable diesel, and we'll potentially see more units being constructed?
You bet, Brad. I'm going to ask Tom Creery to answer that question as he's leading the renewables effort.
To answer the first part, Navajo presents us with some great advantages that we're willing to take advantage of at this point in time. And mostly, it revolves around the infrastructure of being able to use the refinery assets in terms of utilities, people. From a location standpoint, we've got lots of land, the ability to build rail facilities. We've got the permits already. So from an environmental, governmental standpoint, from a city and town standpoint, everybody is excited about this project as we are. And it just -- it was a good fit for us to start the renewable diesel effort at that location.
In terms of future expansions, still early days as far as we're concerned. We're sort of getting our -- we've just broken ground on our -- on the first one, and it's -- and we're looking over the tips of our skis to see what else is on the horizon. But it's just probably a little bit too early at this point in time to make any major comments about expansion into that business. Having said that, we are excited about it, and we see a great deal of opportunity within it.
Yes, if I can elaborate, Brad. We view this as a business and not a project. And so I think you can read between the lines. We're going to be reasonably aggressive in looking for additional opportunities.
Our next question comes from the line of Manav Gupta from Crédit Suisse.
Quick question. Looking at the turnaround expense guidance you issued, it appears it's almost 50% lower than what you ended up spending in 2019. So should we assume 2020 would be a year of much lower turnarounds for your refining system?
Yes, Manav, that's correct. It's Rich. We've got really one significant turnaround at our Mississauga base oil facility, which is scheduled for the fourth quarter. And then we do have some spending getting ready for 2021 as well as some catalyst change, so...
A quick follow-up here. When we're looking at the Southwest margins, what you have issued for the month of January, they look particularly strong. And I'm trying to understand, is it your best cost leverage? What's driving such strength in the West Coast margins? And should we expect you to capture most of them because you have no turnaround at Navajo in 1Q?
Yes, Manav. It's Tom. You're correct. We are taking advantage, especially in the Phoenix market, with the situation that we saw in the fourth quarter on the West Coast, where there were some refinery problems. We saw very high crack spreads for gasoline and diesel in the Phoenix market. And because of turnarounds in the first quarter for some of the Southwest refiners, we are seeing those differentials continue into January and early February at this point in time. We'll have to see what happens for the rest of the quarter. But right now, it's pretty good on that aspect.
The other big factor is that we geared up volume at our Orla truck stop to supply diesel into the drilling in the Permian Basin. And probably in the fourth quarter and into the first quarter, we got higher volumes there than we had seen prior to. That's probably our best -- one of our best netbacks on diesel, as you can well imagine. So that was a contributing factor as well.
Our next question comes from the line of Roger Read with Wells Fargo.
Mike, welcome back. Good to have you.
Thank you, Roger.
I'd like to carry on a little bit more with the second question from Brad and your answer on refining a greater internal focus. I was just curious, what do you think the best internal opportunities are? And from our perspective, how should we be thinking about measuring that? Is it -- I mean, I generally think of it as an uptime issue or a lower OpEx, but I was just curious how you're approaching it.
Right. So one of the great internal opportunities that we have is exactly that. It's uptime. It's reliability. And so we're going to be spending obsessive focus on that and some internal investment as well to make for more robust facilities. Beyond that, and I think we'll probably get to it, but Tier 3 presents octane-related opportunities that I know you're all aware of. As people post treat their gasoline, the octane premium has grown, and we're seeing opportunities within the markets that we serve. So I think probably between reliability and octane, that encompasses a lot of the internal opportunity for investment.
And should we consider that within the CapEx guidance, the $270 million to $300 million for refining, plus whatever turnaround expense might be kind of targeted that direction?
Yes, that's correct.
Okay. And then kind of the second question here on an OpEx front. Natural gas is about as cheap as it's been. Just curious if there are any ways you can take advantage of that other than just sort of a straight line. It's $1 cheaper than a year ago, so that's worth something to you in terms of the OpEx thought process.
So Roger, yes. This is Rich. Yes, it's $1 cheaper than last year. Additionally, I think we've finally fully anniversaried a very bad set of natural gas hedges that we had put on 4 or 5 years ago, so we should get a little bit better benefit than just the straight tailwind. They'll be in the order of $10 million to $20 million a year.
Our next question comes from the line of Paul Cheng with Scotiabank.
And Mike, welcome back. Long time no talk.
Thank you. Yes.
Mike, just curious, then. I mean I think, at least that for the last 10-plus years, you guys have been talking about uptime and reliability as a focus and as an opportunity, but that always seems to be the case. So just curious that when you're doing the internal review and looking at what is the root cause of the underperformance or at least not the consistent performance of your refining operation, is it hardware? Is it culture? Is it people or just a combination of all and what we need if you've been trying for the last 10 years without winning that significant success? I mean, why should we believe that this time is going to be better? What initiative you're going to be put in place that to ensure it's going to work this time?
Well, that's the center of the target, Paul, that's for sure. Listen, here, here's the deal. Refining, reliability and safety and environmental impact are core to any refining manufacturer, ourselves included. And those last 2 or 3 percentage points of utilization and availability are incredibly valuable, particularly during high-margin seasons. So that lost opportunity hurts badly, particularly when self-induced.
What I would tell you is, your question is what's different, and I understand that this is going to be a show-me market. I don't expect people to pencil it in to forward models until we demonstrate it. But we are aggressively pursuing and then implementing an operational excellence program across our fleet of refineries. That's different from the way we operated in the past, which was on a more decentralized basis. We've invested in a lot more talent centrally to assist our operations. And we're putting capital into these businesses on a more aggressive basis to effectively add robustness to refining process. So we have a focused and structured program. I believe that's different from what we've had in the past, and we're going to pursue it like a religion.
Mike, on the renewable business, since that is -- the economic to entry that I think is solely driven by the government mandate, so how big is the business that you will feel comfortable if there's opportunity? I mean how big do you want it to be as a percentage of your overall business?
Yes. Look, I think Tom said it properly that we're going to walk before we run. But I could be very comfortable in having 2 or 3 such plants of 100 million gallons a year. And as percentage of overall production capacity, Paul, I think you appreciate, it's small. That might be 30,000, 40,000 barrels out of 400,000, but it addresses a growing need, yes, supported by government programs necessarily, but also with some other attractive attributes that, I think, particularly, our host refining facilities can be very synergistic with as compared to greenfield investment in this space. So we're excited about it. It's new. It's a growth vector, if you will. But I don't expect it will be anywhere the size of our petroleum refining operations, certainly within the next few years.
And for the current plant you're building that they are using the soybean or the other plant-based feedstock, would they have the capacity or capability to also use the end movements or the waste oil or cooking oil, that kind feedstock?
Paul, it's Tom Creery. Yes, we're going to have flexibility to run a variety of different fuels. We've looked at soybean to begin with, but that doesn't exclude distiller corn oil, tallow and other things as well. I think a big key in these renewable diesel plants is fuel flexibility, and we're certainly going to build towards that to be able to take advantage and remain competitive in the marketplace.
So Tom, so they will also be able to process the animal fat, those kind of waste, right? Is that...
Yes, we're currently looking at tallow right now, and we haven't looked at some of the other ones such as hog fat or things like that. We're just sticking with the beef products for right now.
Paul, for years, we've made a living by optimizing crude slates. We see this as very similar. We need to pre invest -- or we need to invest in pretreatment and metallurgy in order to give us that flexibility, but that's the goal. It's just to be able to optimize among a whole variety of different feeds according to price and what are called CI indexes.
A final question for me. Mike, one of your competitor, I think, that recently that they did something pretty interesting. They did a wholesale refinery like you. And they just did a joint venture on refine -- on the retail store with another operator in California. So is that some kind of business or that opportunity that you guys may look into in your local market? Or that is there any opportunity to do something like that?
Paul, I don't know if that's unique to California. It doesn't sound like it is. Obviously, we're not present in that market. But I'd say, real investment in retail is probably less likely for us, but JV in terms of supply and getting closer to end-use markets is attractive, but not something we currently have an offer.
Our next question comes from the line of Theresa Chen with Barclays.
And welcome back, Mike.
Thank you, Theresa.
So following up on the discussion of renewable diesel, I guess, kind of taking Paul's question and cutting it a different way. As you put together your plans for this project and getting into this market, can you help us quantify what your framework is for the supply and demand balance for the next, call it, like, 1 to 2 years? And how sustainable do you think the margins are?
Theresa, it's Tom. I think for the next 1 to 2 years, if you just look at the California demand at this point in time and you look at the plants that are actually going to come on stream and be able to produce into that market, there's going to be a shortage of renewable diesel into that market. After that, there's a lot of different factors that are going to come into play, whether or not other states adopt an LCFS model, such as Washington, Oregon, what's happening in the Canadian and also the international market as well. So there's a lot of question marks. But as far as we're concerned or what we're looking at, we think that early entrants to market is key. We're going to be on stream relatively quickly as compared to some of our other peers. And we're going to be able to capture some of those early day economics and then just move forward and be able to sell and have the capability to sell into the markets that are going to give us the highest netback. But going forward, when you see things like renewable jet as well as renewable diesel, there seems to be a lot more demand out there than there is supply at this point in time.
And will your facility also be creating renewable naphtha as a by-product?
We will. It's not large volumes, as you can well imagine. And we haven't made a decision as what we're going to do with that renewable diesel, whether to sell it outside the refinery or use it internally and capture the benefits thereof.
Got it. And my follow-up question is related to the base oil market. Mike, related to your comments about how it's going to improve as existing capacity absorbs growing demand for premium base oil. The line of sight that you have in terms of time line and just what inning we're at currently. Can you give us some color on that?
Theresa, it's Rich. So yes, we are expecting improvement year-over-year. We continue to believe that we saw the true seasonally adjusted trough in supply/demand in the base oil market in the spring of 2019 as normal. We saw seasonal weakness in late December and early January, and this was compounded by the timing of the Chinese New Year. But I'm happy to say we've seen a nice rebound in base oil prices and cracks, really, in the last few weeks, so call it, early February. But we're expecting this, to your point about baseball analogies, this is probably the bottom of the first inning. So we have a ways to go here. But again, we are expecting year-over-year improvement.
Our next question comes from the line of Neil Mehta with Goldman Sachs.
Mike, welcome back. It's great to spend time with you again and wish George well here in his next phase in retirement.
Mike, I guess the first question for you here would be just going through your 2020 capital spend budget. I know you guys read it out on the call, but could you just take us through with a little more granularity, go segment by segment? What are the important moving pieces and kind of flush it out for us?
Sure, Neil. It's Rich.
Neil, thanks. Go ahead, Rich.
So as we've said, $270 million to about $300 million within the refining business. To some of the earlier discussion, that's primarily reliability, safety and environmental spending. The renewable diesel unit, we obviously talked about, that will be about $130 million to $150 million this year. At HEP, then, the majority of the spend there will be related to the Cushing Connect joint venture. And then I mentioned turnarounds and catalyst before, call it, 1/3 of that or so is going to be the Mississauga turnaround. 1/3 of that is pre spending. We have a very heavy year in 2021, so it's getting ready for that. And then, call it, 1/3 of that is catalyst.
Okay. All right. That's helpful. And then the follow-up is, just want to talk about these 3 small refinery exemptions that were struck down in a court ruling recently. Can you talk about what that means for HollyFrontier, but at a bigger picture level, what that means for the RINs market on a go-forward basis? And is there a risk that we're going to be talking about higher RINs prices on a go-forward basis?
Neil, it's Rich again. So yes, as you mentioned, on the 24th of January, the Tenth Circuit handed down a decision which vacated the SREs for 3 refineries which included our Cheyenne and Woods Cross plants for the year of 2016. We believe the decision is wrong. The renewal fuel standard holds that refineries can apply for an SRE at any time, and the EPA should be able to grant them at any time without any regard to whether a refinery has received an exemption each year since the beginning of the program. The EPA also correctly applied the standard in granting SREs, which is disproportionate economic hardship. So we expect to appeal for en banc hearing, and we urge the EPA to do so as well.
So Neil, to your point on the broader market, look, on its face, this decision only applies to the Tenth Circuit. However, the national implications are pretty clear, and there's no realistic way this could or would be applicable only within a few states. Obviously, if EPA is worried they can't make up the lost volumes for SREs, they showed they can do that with the 2020 RVO, which unfairly penalizes the industry if SREs are no longer granted to refineries that did not have continuous exemptions. And we also urge the EPA to look at that reallocation of forecasted SREs in 2020.
So in broad comment, look, Neil, the RFS is really poorly constructed, and it serves as a tax on consumers and jobs. The SREs have helped a lot, while having absolutely no impact on the amount of biofuel produced in the U.S. So we're expecting and urge the EPA to take some corrective action here to avoid some of the implications you're probably worried about.
Yes. No, it's helpful. It just strikes me that this is going to become a topic that we put away for a while that has the risk of reemerging as a focus topic. So appreciate it.
Yes, that's a fair comment. It's not just 3 refiners in 1 particular year, obviously. This has broad-reaching consequences. And I believe that we, as an industry, will be working hard legally and through advocacy to get to a little more sane solution.
Our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt.
Great. And Mike, welcome back.
Thanks, Matt.
Just -- maybe just to continue on Neil's question there. What happens to that -- to those 2016 RINs? Do you have to take a reserve and pay those back? Could you just walk us through kind of the financial implications here?
Sure. Matt, it's Rich. So what I can tell you is that what we booked for those 2016 RINs was a little under $60 million. To your question, to be honest, we have absolutely no idea what happens to these RINs. Obviously, there are no 2016 RINs in existence anymore. We don't know -- the EPA -- this was remanded back to the EPA for corrective action, but we have no idea what that action would look like. And the reality is, obviously, we don't think this is going to stand up anyways. So at this point, there's no accounting or financial implication, and we'll just have to stay tuned.
Yes, it's a bit of -- what's the value of 2016 Super Bowl tickets? I mean, I don't know. This is going to be an interesting process to watch this unfold.
Sounds good. And then, Rich, did you have a pretty big working capital benefit in 2019, maybe like a $250 million tailwind? Can you hold things where they are in 2020? Or would you expect a reversal?
Yes, Matthew. So yes, we had a little over $300 million of working capital benefit in 2020. I would expect we can hold the vast majority of that, probably not all of it. There was a little bit of inventory that we're able to pull and probably running a little bit below operating targets by the end of the year. So a little bit might need to go back in the tanks, but a lot of that came out of our lubricants business, where we had very high working capital, really, throughout 2018. And we expect to hold that gain.
Our next question comes from the line of Doug Leggate from Bank of America.
And Mike, let me add my welcome back to you also. It's great to -- good to have you back on the seat. I got 2 questions, if I may. The first is use of cash. You've obviously had a very strong balance sheet for quite a long time. It gives you a lot of options. I'm just curious how you think about that. Obviously, the lubes' expansion on the last several years has been one potential use of cash going forward, but you've also been active with your buyback program. So I'm just curious, how do you think about your balance sheet and how you might exploit where the share price is currently?
Yes. So the share price has fallen a bit recently, obviously, with most of the rest of the industry. We're looking forward at a fairly high CapEx year and growth within our renewables business. So those are competing uses of capital. Doug, with that said, our formula is pretty explicit in that we expect to grow the dividend annually and substantively. And the remainder really will be a combination of share repurchase and growth investment. And the 2 have to compete with each other. That's really not different in terms of priority than the company has had through the last few years. So I don't think that it's a meaningfully different capital allocation strategy. What might be different is probably our view of internal opportunity versus external opportunity, and I think that the internal needs and opportunities are simply greater.
Okay. I -- but what -- [ I'll wait for them to set up ], please. My last question -- or my second question really is, really, more about just your point about the recent sector performance. And I was reflecting back on the Analyst Day from 2017, you're obviously running the chair at that time. But when your announcement to leave was made in December 2015, the share price was about 10% higher and Holly has underperformed pretty much all of your refining peers, despite that pullback. So I guess my question is, what can you do differently? What are you thinking about that? What is the investment case in your mind for Holly? And if I can add a last piece to that. A flat share price for best part of 8 years is not -- in a market, which is less than 4% energy, is there any consideration that Holly could be a participant in consolidation, but as a seller rather than a buyer? I'll leave it there.
Okay. Well, that's a lot of questions, Doug, and we'll take it head on. First off, Holly Frontier was one of the great beneficiaries of inland crude differentials. And we made a heck of a lot of money in monetizing those differentials for the direct benefit of our shareholders. A lot of that money was paid out in cash, not necessarily in share repurchase. And as such, I wouldn't expect it to affect share price on an ongoing basis. Beyond that, we have put a good deal of money into a lubricants business that I think will have very substantial value to us, as we rationalize it and improve it going forward. Clearly, the base oils margin has been a headwind for us. We expect that we'll get through that and demonstrate the value of what we purchased.
As to what the investment cases for HollyFrontier, it really is around our portfolio of businesses, which we see as having substantial sum of the parts value. And I know it's on us to demonstrate that value. And we expect to do that.
Finally, your question was, effectively, are we part of industry consolidation? And what I would say is this. We're a public company. We're responsive to our shareholders. Our purpose is to make it expensive and valuable. And our Board will respond as they need to, but we're not selling the company, and our purpose is to grow it and build it.
[Operator Instructions] Our next question comes from the line of Phil Gresh with JPMorgan.
A couple of quick questions. First, just coming back to the Rack Forward outlook of $250 million to $275 million of EBITDA. How should we think about that progressing through the year? And I'm specifically asking this because, obviously, the macroeconomic situation with China and all that is a bit in flux. So are you expecting more of a 2H weighted kind of recovery there? Or just any thoughts.
Phil, it's Rich. So seasonally, we'd expect the second and third quarters, maybe late in the first quarter to be the bulk or the best time of the year, call it, 60%, 70% of the earnings. Keep in mind that we do have a turnaround in our Mississauga facility in the fourth quarter of 2020. Look, it's a big priority for us in the next few years to move our Rack Forward business, so it's less dependent on our own base oil production. And we can minimize these kinds of impacts, but we're not quite there yet. So that will exacerbate the fourth quarter.
And then, Phil, to your point, look, we're closely watching the China situation, but I don't think we have any particular insight. We haven't seen any demand impact, yet, but it's admittedly early days.
Okay, understood. My second question, I guess, as a follow-up to some of the other ones. But if I go back to the Analyst Day a while back, and I believe there was a long-term guidance that throughput could be 450,000 to 470,000 barrels a day, the CapEx could be $5.50 a barrel, and it was $6.50 this year. So obviously, you've highlighted a couple of the things you're doing there. But I mean is that something we should be still thinking about as the bogies for throughput and OpEx? This year is supposed to be a lower maintenance year, and the first quarter is still below the 450,000 to 470,000. Maybe there's some seasonality to that, but just any thoughts on those targets.
Look, I think those targets are still valid. The nameplate capacity of these plants has been crept up. And while the first quarter is a little lower, it reflects some lingering maintenance from turnaround season last year. But the opportunity that was laid out in 2017 in the Analyst Day, I think, is very much valid. The OpEx is probably higher as progression through time. But no, I see those as good targets for us.
Okay. Last question just for Rich. With the spending on the renewable diesel facility this year, the high level of turnarounds that you highlighted for 2021 and the cash on the balance sheet, is any of that cash being maintained above the normal $500 million just because of these upcoming events? Or would you -- is there a willingness to use buybacks as a value creation tool to -- and draw down that cash closer to the $500 million as we look through 2020?
Yes, Phil. I think in the first half of the year, that's a very fair comment, right? A lot of our spend this year is going to be back-half loaded, and then we've got a heavy turnaround season in the first half of '21. So I'd expect we'll probably run a little more cash in the first half of 2020. However, as Mike said, look, we're going to continue to use the buyback when we have excess cash to create value. So we -- that's not been shut off. We're just trying to manage the ship correctly over the next 12 to 24 months.
Our next question comes from the line of Paul Sankey with Mizuho.
I actually was going to ask about the cash balance which Phil very eloquently just did. So slightly had my take -- question taken away from me, but Mike, welcome back. You know that if Rich softens up at all on the subject of RINs, you can always bring back Doug Aron, right? So you've always got that tool up your sleeve. Actually, given the cash balance question was asked, I did want to -- is there any perspective on how this dreadful RIN subject might change in the case of a surprise election outcome? I know it's already so involved that it's almost impossible to second guess. But I just wondered if there was one side or the other that might or not might be better for how that might resolve itself going forward.
Well, let's put that right. That's fast there. You've got -- is one administration preferable to the other? I think we have seen both parties participate in this creation of the renewables fuel structure, if you will. And I don't know that it matters that much. Clearly, there's pressure toward carbon reduction and pressure toward a strong agricultural lobby.
So we're trying to be responsive to that.
On the other side of it, our industry and we are providing very low cost, high-capability fuels that really run this country, so there has to be balance. I think, despite election rhetoric, there will be balance. And occasionally, we see this thing pop out like squeezing on a balloon, the Tenth Circuit Court. It has to find a stable place in order for the industry to function, and our purpose is to have a strong voice in that. I wish I could tell you where it's going, but I can't. It obviously is impactful to our company and our shareholders, and we're working it hard.
And our next question comes from the line of Chris Sighinolfi from Jefferies.
Rich, if I could circle back to LSP for a moment. I know your forecast for Rack Forward is an EBITDA forecast, but I did notice a pretty healthy step-up or it seemed like maybe a reallocation of just depreciation between Rack Forward, Rack Back in the quarter versus prior quarters. Just a point of clarification if I missed something in terms of either asset allocation. Or I guess, simplistically, what occurred there?
Bear with me one second, Chris, I'm just pulling the number out. So yes, I think you had kind of a one-off issue in the fourth quarter. I would expect that to revert. And yes, to -- call it, the $12 million to $15 million level in depreciation for the Rack Forward business. The big driver there in the fourth quarter was some environmental accrual, which was part of purchase accounting at our Sonneborn entity, so that would be the big difference of the third to the fourth quarter.
Okay. Yes, I noticed that the total level had remained roughly flat, so it seems like an allocation. I figured it was something on the accounting front. I guess sticking on this with a quick follow-up is just you noted earlier, inventory declines across LSP was one of the contributors to working capital benefit in '19. I'm just curious as an update on where we stood. I know you gave some forecast for Sonneborn synergy and ultimate Rack Forward contribution. Any update on that would be great.
Yes. So I think, look, our long-term view is that this is still a $275 million to $300 million business. The difference, I think, Chris, to your point versus where we're at in 2020 is the Mississauga turnaround, which I already mentioned. And second, look, we've got some opportunity to take expense out of this business still, and we're going to -- we plan to work that over the next 12 to 24 months. The last piece, to your point, is on Sonneborn synergies. We're at a run rate right now, call it, $12 million to $13 million versus, is what you'll recall, what we guided at $20 million a year. The next $8 million or so will probably become a little bit slower, so call it over the next 12 to 18 months, and that's really the optimization around intermediate streams between Petrolia, Tulsa and Mississauga. We've done some of that really out of the Tulsa plant already, and we're going to keep working that going forward.
Is the full attainment of that number, Rich, just -- is it predicated on just a normal operating framework where you're not seeing meaningful turnaround activity?
Yes.
And there are no further questions at this time. I'd like to turn the call back over to Craig Biery for closing remarks.
Thanks, everyone. We appreciate you taking the time to join us on today's call. If you have any follow-up questions, as always, reach out to Investor Relations. Otherwise, we look forward to sharing our first quarter results with you in May.
And this does conclude today's teleconference. Please disconnect your lines at this time, and have a wonderful day.