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Welcome to the HollyFrontier Corporation's First Quarter 2020 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, Polly. Good morning, everyone, and welcome to HollyFrontier Corporation's First Quarter 2020 Earnings Call. This morning, we issued a press release announcing results for the quarter ending March 31, 2020. 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 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 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. Before the team and I share our usual discussion of business updates and our quarterly results, let me first begin saying that I hope you and your families are staying healthy and safe during this unprecedented time. The COVID-19 pandemic has struck a hard blow on the economy, our company and our families. With this situation, given the potential to create distraction, I want to express my gratitude to our employees who have stepped up and delivered in a very safe and consistent and professional way during this period.
The impact of COVID-19 on the global macro economy has created unprecedented destruction of demand as well as lack of forward visibility for many of the transportation fuels, lubricants and specialty products and the associated transportation and terminal services that we provide. We expect a strong recovery of demand for all these essential products in the long run. There's little visibility on the timing for or the extent of this recovery in the near term.
In response to the COVID-19 pandemic and with the health and safety of our employees as our top priority, we took several actions, including limiting on-site staff at all of our facilities to essential operational personnel only, implementing a work from home policy for certain employees and restricting travel unless approved by senior leadership. We will continue to monitor COVID-19 developments and the dynamic environment to properly address these policies going forward.
I'll now get into the details of our first quarter results. Today, we reported first quarter net loss attributable to HollyFrontier shareholders of $305 million or a negative $1.88 per diluted share. First quarter results reflect special items that collectively decreased net income by $391 million. Excluding these items, net income for the first quarter was $87 million or $0.53 per diluted share versus adjusted net income of $93 million or $0.54 a share for the same period in 2019.
Adjusted EBITDA for the period was $269 million, a decrease of $13 million compared to the first quarter of 2019. This decrease in earnings was driven by lower product margins and crude differentials.
The Refining segment had adjusted EBITDA of $176 million compared to $193 million for the first quarter of 2019. Consolidated refinery gross margin was $11.32 per produced barrel, an 11% decrease compared to the same period last year.
Our Lubricants and Specialty Products business reported EBITDA of $32 million compared to $11 million in the first quarter of 2019. Rack Forward EBITDA was $77 million, representing a 16% EBITDA margin and our strongest quarter-to-date since the acquisitions of PCLI, Sonneborn and Red Giant Oil. During our strong first quarter, we have -- despite our strong first quarter, we have withdrawn 2020 guidance for the Rack Forward business. Within our industrial and passenger car related end markets, beginning late in the first quarter, demand dropped substantially, while in our personal care end markets, demand is running slightly below normal.
We expect industrial end market demand to rebound with the broader economy. And within the Rack Back portion, we expect base oil demand to rebound with the reopening of its primary transportation-related end markets. Similar to our Refining segment, we intend to match production to market demand.
Holly Energy Partners reported EBITDA of $64 million for the first quarter compared to $94 million in the first quarter of last year. The first quarter included nonrecurring loss on early extinguishment of debt of $26 million related to HEP's previously outstanding 6% notes due 2024.
In view of both the short-term impact from COVID-19 as well as our expectations for the future, HEP reduced its quarterly distribution to $0.35 per unit, representing a new policy focused on funding all capital expenditures and distributions within cash flow, improving distributable cash flow coverage to 1.3x or greater and reducing leverage to 3.0 to 3.5x EBITDA. As we continue to navigate the COVID-19 pandemic, our top priority remains the health and safety of our employees, communities and contractors. We are committed to delivering safe and reliable operations during this challenging environment.
We believe our disciplined approach to capital allocation led by our strong balance sheet and liquidity position will help to position HollyFrontier for long-term success.
And now I'll turn the call over to Tom for an update on our commercial operations.
Thanks, Mike. For the first quarter of 2020, we ran 436,000 barrels per day of crude oil, including 35% Permian and 22% WCS and black wax crude. Our laid-in crude cost was under WTI by $6.87 in the Rockies and $0.99 in the Mid-Con and over WTI by $2.04 in the Southwest.
We ended the first quarter of 2020 with gasoline inventories remaining at high levels and gas crack at low levels in many of our markets. In the Magellan system, we ended the quarter at 10.6 million barrels, roughly 800,000 barrels higher than fourth quarter levels. Diesel inventories ended the quarter at 6.5 million barrels, roughly flat with 2019 year-end inventories. First quarter 3-2-1 cracks in the Mid-Con were $10.66, $23.62 in the Southwest and $17.29 for the Rockies.
In the Canadian heavy market, first quarter differentials at Hardisty averaged at a price of $20.73. Recently, we have seen this differential compressed through to $5 range due to overall flat crude price. Midland differentials ended the first quarter -- average for the first quarter at $0.85 over Cushing. And currently for the June market, that index is trading at $2.75 over Cushing. Canadian heavy and sour runs averaged 76,000 barrels per day at our plants in the Mid-Con and Rocky regions. We refined approximately 153,000 barrels per day of Permian crude in our refining system, composed of 107,000 barrels per day at the Navajo complex and 46,000 barrels per day by the Centurion pipeline at our El Dorado Refinery. Our RINs expense in the quarter was $41 million.
In response to the demand destruction associated with the COVID-19, we have reduced run rates at all our refineries by an average of 30%. Run rates have and will continue to be based on demand for products as well as feedstock inventory blends. Crude oil availability has not been a problem so far, so we remain a little short and buy additional volumes of crude oil as required.
On the demand side, we experienced low levels during the last couple of weeks in March and through the first part of April. Since then, we believe demand has picked up for gasoline in all of our markets. Jet fuel demand drops have been severe, and we continue to minimize the production of jet fuel. Diesel has been the least affected up until this point, and we have benefited from spring agriculture demand associated with the planting season.
For the second quarter of 2020, we expect to run between 300,000 and 340,000 barrels per day of crude oil based on the market demand for these transportation fuels. Currently, the primary determinants of demand are the various government orders and guidance restricting and discouraging most forms of travel. We intend to match refinery production with demand and adjust with the market.
And with that, I'll turn the call over to Rich.
Thank you, Tom. As Mike mentioned, the first quarter included a few unusual items. Pretax earnings were negatively impacted by a lower of cost or market charge of $561 million, HollyFrontier's $15 million pro rata share of Holly Energy Partners' loss on its early extinguishment of debt and Sonneborn integration costs of approximately $1 million. A table of these items can be found in our press release. Cash flow from operations was $190 million in the first quarter, including turnaround spending of $39 million and $65 million of working capital costs. HollyFrontier's stand-alone capital expenditures totaled $65 million for the quarter.
In the second quarter, we expect to consume between $100 million and $300 million of working capital based primarily on the impact of falling crude and product prices as well as reducing refinery throughput to match demand. These mechanics are not unusual but they may be larger than a typical quarter, and we expect to recover this working capital as commodity prices and demand for product normalizes.
During the first quarter, we declared and paid a $0.35 dividend per share, totaling $57 million. We did not repurchase any shares in the first quarter and do not intend to repurchase shares until market conditions and visibility improve.
As of March 31, 2020, our total liquidity stood over $2.2 billion, comprised of a stand-alone cash balance of $890 million, along with our undrawn $1.35 billion unsecured credit facility. As of March 31, we have $1 billion of stand-alone debt outstanding, a debt-to-cap ratio of 14% and a net debt-to-cap ratio of 1%. Our earliest stand-alone debt maturity is 1 -- our $1 billion of senior notes due in 2026, which are rated investment-grade by S&P, Moody's and Fitch.
Interest expense was $22.6 million for the 3 months ended March 31, 2020, compared to $36.6 million for the 3 months of the prior period. This decrease was primarily due to a $9.8 million unrealized gain in our refinery catalyst financing program.
HEP distributions received by HollyFrontier during the first quarter totaled $38 million. HFC owns 59.6 million HEP limited partner units, representing 57% of HEP's LP units at a market value of approximately $825 million as of last night’s close.
We have reduced the range of our 2020 consolidated capital budget to $525 million to $625 million from the previous $623 million to $729 million, and we remain committed to our 2 major strategic investments in 2020, the Artesia Renewable Diesel unit and our Cushing Connect joint venture. We now expect to spend between $222 million and $251 million for stand-alone capital at HollyFrontier Refining and Marketing, $130 million to $150 million in renewables, $30 million to $45 million in HollyFrontier lubes and specialties and $85 million to $110 million for turnaround and catalyst. At HEP, our capital budget remains unchanged at $59 million to $60 million.
We are continuing to evaluate additional ways to reduce cash costs, including operating and SG&A expenses as well as incremental capital spending reductions. We will continue to monitor COVID-19 developments and make further changes as circumstances dictate.
And with that, Polly, we're ready to take questions.
[Operator Instructions] Our first question is coming with -- from the line of Brad Heffern with RBC.
[Technical Difficulty]
Can you hear me now?
Yes, sir.
Okay. There we go. I was hoping we could start on LSP. So in the first quarter, the Rack Back results looked a little weaker than the crack slick and then the Rack Forward results look stronger. So can you walk through any dynamics there?
And then additionally, I appreciate the comments you gave on demand going forward. Do you have any thoughts on margin at this point? Is the Rack Forward holding in relatively strongly? And then, I guess, how does the Rack Back look just given the low flat price dynamics?
Sure, Brad. So there's a few things in there. In the first quarter, we saw very good demand and good sales growth, frankly, in the Rack Forward side of the business. On the Rack Back side, obviously, as the bottom fell out of the crude market that pulled feedstock prices down with it and it widened benchmark margins. The reality was in the -- probably the last month of the quarter, there was no actual buyer on the other side of those margins. There was no demand, that's sort of evaporated, and that's continued into April. So the margins look good on paper. They weren't real. It's probably the simplest way to say that.
As we've gone into the second quarter, obviously, we've retracted our guidance on Rack Forward. If you look at our Rack Forward business, it's basically, 20% is consumer products or consumer staples, and that demand has held in very well. The other 80% is really industrial or passenger car end markets, and that demand has fallen off, as you'd expect. And there, that we have very, very little visibility on when that's going to come back. That's going to be very economy driven and hence, we’ve pulled our guidance.
On the base oil side of the business in the second quarter, similar, right? Most of those products end up in the car or a truck. And as miles driven have gone down, demand has gone down. That will rebound as people start driving again. But in the long run, that will be fine, but the path back from here is hard to call.
Okay. And then I guess switching over to refining. We've seen a lot of shut-in announcements at this point. I'm curious if you could talk about the impact of that on the system and particularly in the Rockies.
Brad, it's Tom. Yes, we've seen some of those shut-ins as well. As you are more than aware, we buy all our crude on 30-day contracts. So as we move through this month, we really haven't experienced a lot of interruptions in supply. It's hard to say what's going to happen going forward. We've tended to mitigate some of this by carrying a little higher inventory of crude oil at various locations and tankage. That's got the benefit of supplying us with some contango profits, but it also gives us a little bit of comfort if one of our producers does come up short, then we can use those barrels to supplement runs at the refinery if they're economic.
And our next question comes from the line of Paul Cheng with Scotiabank.
A couple of questions. My -- how the COVID-19 -- I know that, I mean, right now, everyone focused short-term on liquidity, preservation of the balance sheet. But if we look past -- at some point it will pass, after this event, is there in any shape or form that change your view how you're going to operate in terms of your operating parameter as well as the leverage ratio in order?
Yes. Paul, I think your question is one of how we operate longer term, how we recover into increasing demand. Yes, certainly, in the near term...
I think my question is that once that we recover, if we're looking at the way how you run your company, will that change before and after COVID-19? So let's say, if we're looking at the -- what will be the comfortable cash balance that you would want to keep on the balance sheet? What is your leverage ratio? How are you going to run your company? And how you view the M&A market? Is any shape or form that this event has changed your longer term way to look at the business?
Yes. I got the question now, Paul, being balance sheet centric and capital allocation centric. The answer is not really. We have, for a long time, run with a fairly conservative balance sheet, recognizing the commodity business and the working capital and capital-intensive business that we're in. We believe that's the right strategy in terms of the way we manage our leverage. Looking forward, clearly in the near term, we're going to be limiting capital investment into the refineries. One of those is a practical driver in just being able to get work done in the plants during this environment. And the other is a question mark in terms of the recovering demand and how quickly that will come.
So I think you'll probably see a little less capital in terms of growth capital going into our plants. But as it pertains to the balance sheet that we maintain, the liquidity reserves, capital allocation, and then obviously, part of that is return of cash to shareholders, I haven't seen anything through this that changes our philosophy. Execution in the near term is clearly going to be one of conserving cash. But longer term, I think we've built this business to be robust through cycles. This is obviously a very dramatic cycle, and then I won't tell you that we anticipated it, but we do run with a conservative balance sheet because of the nature of our business.
My second question is that you have one of the strongest balance sheet. Your net debt is very small. And there's a number of assets now that being put on the market and one would argue that the best time to buy is when everyone is distressed. So from your standpoint, will the M&A be at the front of the consideration for the [ rig ] asset or that preservation of balance sheet is going to override that?
I'm afraid I'm going to have to answer both, Paul. We obviously are much more interested in assets when the price is lower, but we're going to be careful about it because this is a time when capital is dear. And so the return parameters are going to have to be that much better for us. But to say that we've excluded focus on acquisitions would be inaccurate. It's just a high standard.
And your next question comes from Ryan Todd with Simmons.
Maybe if I could follow-up a little bit on that, some of your comments on the flexibility on the capital side. I mean, can you talk about additional flexibility that you might have in the 2020 budget, if necessary? And thoughts and implications beyond that for 2021, which I believe, is expected to be a higher turnaround season next year. Do deferrals from this year push into next year? And how much flexibility should we think over the next 12 to 18 months as we think through your budget?
So I think realistically, we've probably got some more wiggle room in the 2020 budget, and we'll keep looking at -- it's not stuff we would prefer to cut, but we're going to adjust with the circumstances is just the reality of it. As you look in 2021, yes, we -- look, we have a big turnaround year coming next year. This -- now is the time you're planning these and evaluating. So the team has done a really good job of continuing to look and see what might be deferrable, and we'll continue to work that over really the next 6 months. This is -- it's the delicate balance of trying to preserve cash and you want to take care of the assets, which is obviously important to us. So nonetheless, '21 will be a big turnaround year for us. How big? We'll see if we can manage around that.
Good. And then maybe can you talk in your -- I appreciate the comments on distillate holding in the gasoline shown a little bit of a bounce here. I mean can you talk about how you see the various supply-demand drivers right now for gasoline versus diesel in your various markets and how you see those playing out over the next couple of quarters?
Yes. Sure, Ryan. I guess we're a little bit more bullish on gasoline than we are on the distillate side of the barrel for the following reasons. As the stay in place gets lifted, you see more people driving around in their cars. We certainly see that in Dallas, and that's helping spur gasoline demand. To that effect, we've probably seen, in most of our areas, probably a 10% to 15% increase in gasoline demand in the areas that we operate in, excluding the Denver region, which is a bit of a special place at this point in time.
On the distillate side, we're showing a little concern on the distillate as inventories continue to grow, and we believe that's primarily not due to demand destruction, but it's due to the jet being repurposed or rerefining being put back into the diesel pool. So as you well know, there's not a lot of airplanes in the skies these days, but there is a lot of jet being ending up in the diesel pool. So we're a little more -- like I said, we're a little bit more bullish on gasoline. We should see increases go as these restrictions are lifted in diesel. The next little while is going to be very important, and it might be a little more slow climb to get back to normality on the diesel barrels at this point in time, given what we know.
I mean the one thing about diesel that will be interesting to watch relative to jet fuel is as crude rates start to come up, the diesel hydrotreating capacity isn't going to grow with it in terms of being able to handle more kerosene and turn that jet back into road diesel. Our company produces very little jet fuel, so we think we're pretty well positioned, but there may be growing barrels of jet in tankage as things go forward if people try to increase crude rates to meet gasoline demand.
And your next question comes from the line of Theresa Chen with Barclays.
Following up on the discussion of gasoline demand, Tom, when you were talking about the 10% to 15% recent increase. So in terms of the fall off from demand, like, call it, last year, what was like the depth of the trough? And where are we relative to that?
Yes, that's a tough -- it's really hard to say, Theresa, because every market is a little bit different. I think in the Mid-Con, it was a little bit less than some of the other areas. I think the industry did a very good job of keeping that supply-demand in balance, so we didn't see as much erosion there.
I did mention the Denver market. Denver, we saw a pretty precipitous drop in demand there. It's starting to come back now, but that precipitous drop ended up with extremely low prices for finished gasoline at the rack in Denver. The other markets weren't so bad as well. And the Woods Cross market in Salt Lake City has been pretty well, and it continues to be that way in terms of demand. So although it's a smaller market, it doesn't seem to be as harder hit. So very diverse and it's kind of hard to put a number straight across the board and saying how much we've lost.
But the geography we serve tends to be opening more quickly than some of the coastal geographies. So we see that as a positive, but it's a tough call in terms of the pace or otherwise the trajectory.
Got it. And then on the feedstock side, so there's been a lot of discussion about the benefits of contango to refinery. And given your exposure to WTI-linked crude, can you provide some sensitivities around that? Or what kind of benefit you might expect to recognize in second quarter related to this factor alone?
Yes, sure. Well, as you know, we make money off contango 2 ways. I guess we're buying prompt crude that's lower than future price. So by the time it gets into the refinery and the curve staying the same, we get a higher price that way, plus it gives us the ability to actually, as I mentioned before, storing barrels and roll them on the NYMEX and capture a profit that way. That's always a nice little bonus as compared to when we're in backwardation, and it tends to…
[Audio Gap]
So it does help with our crack spreads going forward on the domestic barrels that do have that pricing component in them.
And your next question comes from the line of Neil Mehta with Goldman Sachs.
First question was on the refining side. A little bit better in capture than we expected in the Rockies in the first quarter, just any quick thoughts on gross margins there? And anything unusual that you would call out? And thoughts on how much to carry forward?
Yes. Neil, the capture rate, we did benefit by -- in the first quarter with having a WCS differential fairly wide. As we mentioned, that certainly helped us in terms of capture rate. And as I mentioned, Salt Lake was a very good market. Very high gasoline and premium differentials coupled with a very strong distillate market, which was helped influenced as well by some refining problems on the West Coast. So whatever we moved into Las Vegas was giving us a pretty good price, too. And versus the fourth quarter, we ran without a lot of maintenance, and that helped our capture rate as well.
Okay. That's helpful. Follow-up is for you, Mike. You've reestablished yourself in the role here for a couple of months now relative to our last check out a few months ago. Do you want to just give us a lay of the land as you see it from a strategic perspective as a returning CEO what you think is working, where are there opportunities for improvement and lay out where you are on your strategic road map?
Yes. Fair enough. What I would say is that the broader strategy isn't different than what I articulated on our year-end call. Obviously, we've had a bit of a bump in the road called COVID and we have had to go into crisis management mode, quite frankly. What I would comment on that is that the most important dimensions that I identified on the previous call were that of refinery reliability, safety, environmental performance and good use of capital.
During this period of COVID and of essential personnel only and such, our plant performance has been just spectacular. And I think it's demonstrated an employee focus, management focus on the fundamentals and on the things that are really most important to operating successfully. So I'm really pleased about that. We've gotten better traction more quickly than I would have expected.
On some of the broader strategic front in terms of where is the company going and how quickly, I think right now, we're responding to the challenge of COVID, of meeting demand as it comes back to us, of reducing capital spending, reducing operating spending because of the obvious.
So those are what I'd call crisis responses and things that we need to do in the very near term. But longer term, in terms of having a refining company, lubricants transportation that is very effective in the marketplace, generating high returns on the capital we choose to invest and operating well and leanly, those priorities still very much exist.
As I spoke previously, our head is not in the sand with respect to the growth of our business and acquisitions. I think the market is fairly illiquid right now. But there are assets out that will be sold within probably the next 12 months. So I hope that addresses your question. Obviously, there's a lot here and much of it induced by the COVID crisis. But most importantly, the fundamentals of our business and day-to-day operations have been quite good and safe during that period.
And your next question comes from the line of Chris Sighinolfi with Jefferies.
Mike, I was just curious, could you -- obviously, appreciate all the color about what you've done at the Refining side to manage lower throughput, manage fixed cost absorption, manage the cash flows of the business. I was just curious -- I know, obviously, I feel like I know less about the operations of the base oil business and LSP in general. Is the approach there similar? Or is there something fundamentally different about running lower operating rates at the base oil facilities and lubricants facilities versus the refining operations?
Yes. So the base oil and lubricants facilities are largely hydrotreating operations. They're going to be demand driven in terms of throughput, just as refining is. The ability to turn down those assets is similar. You'll often hear in the refining space 60%, 65% turn down rates before things get operationally difficult. Those numbers might be more toward 50% in lubricants hydrotreating facilities.
But the key is, in terms of our focus operationally, safety, obviously, and strategically is on the market side. We need to be effective in the marketplace. And those things in terms of growing the Rack Forward business and the margins in that business are the most important strategic priorities to the Lubricants business.
Okay. That's very helpful. That's exactly what I was looking for. And then I guess maybe to take a follow-on from Paul's earlier question about the learnings off this process and things you might do differently. I'm just curious, a lot of people seem to be focused on, sort of, certainly a recovery in activity, a recovery in demand. But I guess recognizing that may not be a linear progression, that we may go into sort of a secondary or tertiary wave of what we've recently faced, are there things that you've learned from sort of the initial COVID response that we might see you guys do differently if we get back up towards more of a normal operating rate and then face the secondary situation where we have to shut things down aggressively again?
Yes. I think Tom kind of spoke to it implicitly just a bit earlier, but underbuying crude with the notion that we're linked to Cushing in many instances and otherwise to storage opportunities, having the flexibility to meet demand and work into demand without having to dispose barrels in distress, that's key in terms of volumetric management.
The focus at the plants, I think, has been obvious. We're going to need to get contractors back in to do maintenance. But the learnings are -- some are we're still digesting, quite frankly. But others, particularly how well we have operated at the site level during this period, yes, we're going to gain from that and try to extrapolate that into the future. So that's probably the most important thing. And the management of our inventories and our production around market signals is also going to be really important if we have kind of an erratic or otherwise volatile recovery of demand.
Okay. Perfect. One final one for me and perhaps for Rich. On the HEP side, totally understand what was done with the distribution there. And I understand it from an HEP perspective. I was curious if you could talk about it from an HFC perspective. I don't know the right way to think about it, but when I think about distributions received from the MLP, underpinning historically, 70-plus percent of the HFC dividend, now it's obviously about half that number. Can you just talk about how you thought about that cash flow stream? And what maybe the plans are for it once you reach the leverage targets that you've stipulated for the HEP vehicle?
Sure, Chris. So I think if you're in HFC issues in this situation, you're balancing exactly what you're highlighting, the cash flow to HFC stand-alone against the reality of consolidated leverage and trying to manage the balance sheet from HFC's perspective. On balance in the current environment, we think HFC should be happy about this decision. It’s a lead to deleveraging at HEP and by extension in HFC.
Look, to your point, though, yes, looks at the cash flow that we missed, and we'll manage accordingly in the meantime. It just goes into the broader points, Mike, and we've all been trying to make about trying to be very careful with our spend right now.
[Operator Instructions] And your next question comes from the line of Phil Gresh with JPMorgan.
I had a follow-up question on lubes. Rich, you're talking about how things played out in March versus earlier for the quarter. And I recognize that it's too difficult to have visibility to the full year. But maybe just a little bit more color on the actual financial performance in March and April, just to help us think through at least what 2Q might be looking like, whether it's volume or EBITDA? And just maybe any other color around actions on the cost side in lubes that can partially offset any of this, just so we can have a better understanding.
Yes. Phil, the data I've got that's handy here is really on volume that speaks to what you're talking about. On the industrial side of our business, for the month of April, we're looking at sales that are down 50% to 60% year-over-year, and that's on the volume side.
On the consumer-oriented side, if you will, primarily the legacy Sonneborn businesses, you're talking about down 5% to 10%. So very different perspective. Base oil was going to look a lot more like the 40% to 60% in the finish side. And then to that point, so we just don't have visibility more than a couple of weeks in front of our face right now. So calling that arc is impossible.
Sure. I guess I just more wondering like in March and April, were you seeing negative EBITDA across the entire lubes business? Or any kind of metric we could at least start with?
Yes. So I'm not going to go into monthly financials.
Okay. Fair enough. My broader question would just be about how do you think differentials are going to play out here? You made some opening remarks about Cushing, Midlands and WCS, but with production now just starting to roll over here pretty hard with the shut-ins, do you have a strong view of where differentials might go in the second half of the year?
That's a tough call, too. We've seen some pretty dramatic changes, not only in frac price but in differentials. And I think to put it in perspective, I think earlier this week, we saw WCS and Cushing almost trading at parity with domestic sweet, which doesn't make a lot of sense. But based on availability and market conditions, it happens.
So going forward, I would say we need time to normalize in the markets, and there's going to be a lot of jumping around, but they will normalize and get back. Long term, we still probably see a Midland barrel trading over a Cushing barrel as exports start to come out of the Gulf Coast again. That's how we truly believe. And then we see when WCS going back to a transportation basis and quality to get it into the Cushing market or the Gulf Coast. So that's going to take some time, and it's going to be a slow process, but it's going to happen. And I suspect probably by the third and fourth quarter, you'll see some return to that normalcy, and we'll get a lot of these knee jerks out of the market.
And just on the Brent-WTI spread, the last time crude production rolled over Brent-TI went to near 0 back in 2016. So I guess I was just wondering if you think that might be possible again until crude production starts to rebound?
Yes, it's hard to tell -- Brent's a physical market and WTI is a financial market, and that's one of the big things that we saw during this COVID-19 OPEC situation. There's been a huge delink between a physical and a paper barrel. So comparing it to prior years, I don't know if it's going to be the same case going forward. When you look at the forward curve, it's still getting back to historical numbers on Brent-TI at around that $4 mark. And so that's where we would expect it to be, and it's there now. So...
And your next question comes from Matthew Blair with TPH.
I think it was Tom mentioned that refiners are moving jet into the diesel pool. What year do you expect jet demand to return to 2019 levels? And does this impact your thinking on the renewable diesel project?
There, again, a tough question. I don't think we're going to see jet demand rebound until probably sometime next year to 2019 levels. I just can't imagine that it's going to happen this year. A, I don't think people are very anxious to get on an airplane. And when they do, I don't know what kind of shape the airlines are going to be in or if they're going to have retired some flights and not running as many options as they did going forward.
So jet is a real concern going forward. Mike did say as distillate -- as diesel demand goes up and crude rate goes up, the DHT capacity will be taken away to just run diesel off the crude or diesel off the crude stills. So that's going to push more jet back into the market. So that's -- the airlines have got a tough goal ahead of them as far as I'm concerned, and that level of that is personal and not corporate viewpoint.
The RD project….
Yes.
Yes. I don't think that swings with jet fuel demand, honestly. It's a more unique market than that and really is geared toward a low-carbon fuel standard market, in jurisdictions that are putting that in place, California being the obvious. But the lack of jet demand doesn't really, in our minds, interplay with our RD business.
Got it. Okay. And then ethanol RINs have moved a little higher here. I think they're currently around $0.37. In Q1, they averaged $0.24. How does this big drop in gasoline demand impact your ability to meet these RFS obligations?
Right. So for 2020, our obligation has been conveyed to us as a percentage of gasoline sales. That's kind of how that works. The EPA figures a volumetric obligation, translates that into a percentage. So the fact that gasoline sales are lower doesn't correlate to a higher percentage blending value obligation. That's fixed for the 2020 year. As to the RIN cost or the RIN value, with gasoline prices low and ethanol prices relatively high, it -- frankly, it costs you more money to blend that ethanol into the barrel. And I think that's really what the RIN price reflects today.
And we do have other questions.
This is Kalei Akamine from Bank of America Merrill Lynch. My first question is on operations. So cracks have improved here off the lows pretty appreciably. I'm wondering how you guys are planning to operate into an improved demand environment, understanding that those cracks are because of lower runs. And I guess what's on my mind is when you look at the DOE data, it shows very low gasoline yield as a percent of production. So I'm wondering if the first move would be to normalize gasoline yields rather than to increase crude runs.
Yes. When we have a driver in terms of margin to improve gasoline yields, we do that, and we can do that relatively quickly. That swing, as you probably know, is a percentage point or 2 or maybe 3 at the high side of total throughput or total produced volumes. Beyond that, we're going to be opportunistic but also pretty measured about the gasoline demand that's out there so that we don't swamp the markets or nearby markets with our own barrels. As you know, we serve a geography that tends to have fairly low population density and kind of smaller markets, if you will. So we just need to be disciplined and balanced about how aggressively we produce into the growth.
Now with that said, gasoline demand has been very inelastic for the last, what, 2 months, right? We've had imposed restrictions placed upon us. I think that flips to elastic demand. The stuff is cheap. And it's one of the things that people can do fairly inexpensively to get out, frankly, and enjoy life a bit. So I think you're going to have the cooped up scenario as we look into June, in particular, and then people will be consuming a lot more gasoline at what are very attractive prices.
And we do have another audio question.
Yes. This is Jason Gabelman from Cowen. I guess I had a couple of questions. First, on the competitive position of the company as a whole. I mean you guys have obviously benefited the past few years, particularly from wide inland crude differentials that seems to be going away. I think you guys kind of said you expect $4 Brent to TI diff. So how do you view the competitive footprint of the business in light of changing inland crude differentials, maybe in a very structural way? And what are you guys doing to kind of make sure you stay competitive relative to peers?
Well, as a starting point, I don't think we're willing to roll over and say that crude differentials are dead. Certainly, during this current period of very low demand and shut-ins, there are days on which every barrel price is the same at Cushing. Tom was suggesting that WCS was pricing with sweet crude. That's unnatural and won't continue into the future in our view.
But with lower flat price, I think your point is well made that crude differentials tend to be more narrow with lower nominal crude prices. So what do we do as a business? Well, obviously, competitively, we've got to work on cost structure, throughput utilization and capital allocation. So we have levers available to us. I won't tell you that they're anywhere near as easy as buying cheaper crude, but those are the things that we're working on. And we're certainly not going to roll over because of the loss of a few dollars of crude differential.
Got it. Okay. And then my follow-up is just on some of these inland niche markets that you serve. Are you seeing any margin erosion or maybe higher inventory builds in those markets because you have players from outside those markets moving product into the primary markets you serve? Specifically, I'm thinking about some of these Gulf Coast guys where maybe exports have fallen off and maybe instead of reducing runs, they’re moving -- they're just flipping product from the export market into more U.S. inland markets. Any color on that you’re seeing, that would be great.
Yes. That's -- Jason, that's a typical occurrence that we always watch. Sometimes the [ ARBs ] are from the Gulf Coast, and there's a variety of pipelines coming up. So we're paying attention to that all the time. So we see a little bit of that happening at when the [ ARB ] is there. And when the [ ARB ] isn't, we're not seeing it as a dumping ground per se in the group anyways. The other markets, it's a little harder to get product in there on an instantaneous basis. Either you have to have pipeline space or you have to wait 30 days to get it there. So there's a lead lag effect in a lot of those other markets that's hard to take advantage of and as you say, put additional or excess barrels into those markets.
And the [ ARBs ] generally flows through this process as well. So the pressure in terms of the price drivers really aren't there. Our markets are largely trading at a discount to the screen. Which means that if you have Gulf Coast barrels and an ability to go up to Colonial pipeline, you probably elect that over some of these inland markets.
We do have another audio question.
This is Manav. A quick question on the Rockies part. The capture came in much stronger than expected. Can you help us understand what were the factors that drove a stronger capture versus some of your own benchmarks?
.
Sure. The main factor, as we previously stated, was probably volumetric. In the Rockies, we had a very good crude run rate in the first quarter versus the fourth quarter of 2019, and we also did see some benefit from crude pricing through WCS differentials of [ RSD ].
Okay. The second question is you're very close to the entire Cushing situation. So in terms of how are you seeing the storage build up over there? And what's the capacity left over there? And is there a chance you max out storage in Cushing?
Yes. We see probably that there's a little bit of room left in Cushing. When I mean a little bit, I'm not talking a lot here, probably less than 10 million barrels. The flows into Cushing have probably been lower in the past couple of weeks than what we thought was going to happen earlier in the month of April. So I think the general consensus is that Cushing is not a big danger spot or as high a danger spot as it was previously in getting coal and not being a repository for crude. That, however, could change very rapidly, given other factors in the marketplace. But at this point in time, from a HollyFrontier standpoint, we're not worried about Cushing filling up as much as we were 2 or 3 weeks ago.
And the last question is you lowered your CapEx about 15%, but you didn't actually postpone any major projects. I'm just trying to understand how this was achieved, lowering the CapEx by 15% without actually changing anything on the major project side?
So Manav, if you look at our capital spend, right, less than $200 million of what was originally, call it, a $625 million to $725 million budget was “major projects”. There are a lot of projects in there of $2 million, $5 million, $10 million, $15 million that can be canceled or deferred, and that's where the vast majority of these dollars came from.
You do have a follow-up question from the line of Chris Sighinolfi with Jefferies.
I just have one quick one. Rich, I missed it in your prepared remarks, but the offset item in your interest expense in the first quarter, could you just walk me through that again, the driver, what it was and maybe just a bit of explanation?
Sure, Chris. So that's unrealized. So we do finance some of our refinery catalyst really platinum, and you can go ahead and pull platinum price up on the screen. Platinum dropped precipitously really in March and April. So we took an unrealized gain on that financing, which runs through interest on the income statement.
Is that something, Rich, that's going to reverse in subsequent periods and you're going to reflect a higher than sort of average run rate interest expense in some future period?
Depending on your platinum price call, yes. If you think platinum is going up, yes. If you think it's going to continue to go down, no.
Okay. Okay. And can you remind me the amount of that?
It was right around $10 million.
And at this time, there are no further audio questions, sir. And I can turn the conference back over to you for your 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 second quarter results with you in August.
And thank you. This does conclude today's teleconference. Please disconnect your lines at this time, and have a wonderful day.