Welcome to the HollyFrontier Corporation's First Quarter 2019 Conference Call and Webcast. Hosting the call today from HollyFrontier is George Damaris, President and Chief Executive Officer. He is joined by Rich Boliva, Executive Vice President and Chief Financial Officer Jim Stomp, Senior Vice President of Refinery Operations and Tom Creery, President, Refining and Marketing. Please note that this conference is being recorded. It is now my pleasure to turn the floor over to Craig Burey, Director, Investor Relations.
Craig, you may begin.
Thank you, Tamiya. Good morning, everyone, and welcome to HollyFrontier Corporation's Q1 2019 earnings call. This morning, we issued a press release announcing results for the quarter March 31, 2019. If you would like a copy of the press release, you may find 1 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 George Dameris.
Thanks, Craig, and good morning, everyone. Today, we reported 1st quarter net income attributable to HollyFrontier shareholders of $253,000,000 or $1.47 per diluted share. Certain items detailed in our earnings release increased net income by $160,000,000 on an after tax basis. Excluding these items, net income for the current quarter was $93,000,000 or $0.54 per diluted share versus adjusted net income of $137,000,000 or $0.77 per diluted share for the same period last year. Adjusted EBITDA for the period was $282,000,000 $34,000,000 less than the Q1 of 2018, principally driven by maintenance in our refining and marketing segment and weaker base oil margins in our lubricants business, which were partially offset by stronger earnings at HEP and 2 months of contributions from our Sonneborn acquisition.
Our Lubricants and Specialty Products business reported adjusted EBITDA of $20,000,000 despite a very challenging base oil market. Rack Forward adjusted EBITDA was $53,000,000 for the quarter and adjusted EBITDA margin was 12% of sales. Our integration of Sonneborn is going well. And as of May 1, we have achieved run rate synergies of $7,000,000 and continue to expect long term synergies of $20,000,000 per year. HOLLY Energy Partners reported EBITDA of $94,000,000 for the Q1 compared to $88,000,000 in the Q1 of last year.
Overall pipeline volumes increased 5% year over year driven by record volumes on our crude gathering system of 157,000 barrels per day. We also experienced strong third party spot shipments on the UNEP pipeline as arbitrage between Salt Lake City and Las Vegas remained open during majority of the quarter. During the quarter, we returned $135,000,000 of cash to shareholders through regular dividends and share repurchases. Our focus remains on improving reliability and by extension both unit and absolute costs across our refining system. With the rebound in the gasoline market and no major planned downtime until September, we believe we are well positioned for strong financial performance heading into the summer driving season.
Now I'll turn the call over to Jim for an update on our operations.
Thank you, George. For the Q1,
our crude throughput was 400,000 barrels per day at the midpoint of our guidance of 395,000 to 405,000 barrels per day. Crude throughput was impacted by our Tulsa East turnaround and unplanned maintenance at El Dorado, both of which have since been completed. Operating expense per throughput barrel was $5.24 in the Southwest, $6.30 in the Mid Con and $10.07 in the Rockies. Due to the extended turnaround at Tulsa, we expect to run between 445,000,455,000 barrels per day of crude oil for the 2nd quarter. I will now turn the call over to Tom for an update on our commercial operations.
Thanks, Jim. For the Q1 of 2019, we ran 400,000 barrels of crude oil composed of 42% Permian and 20% WCS and black wax crude oil. Our average laid in crude cost was under WTI by $4.46 in the Rockies, dollars 1.62 in the Mid Con and $2.75 in the Southwest. In the Q1 of 2019, we started the year with high gasoline inventories and low gasoline cracks on the product side and decreasing crude differentials on both Canadian and Permian crude oils. Over the course of the quarter, the markets have improved and we are optimistic for the remainder of the year as product fundamentals continue improving and gasoline and distillate inventories remain at reduced levels.
Gasoline inventories in the Magellan system started the year at 8,900,000 barrels and ended the quarter at 7,700,000 barrels. Current Diesel inventories were relatively static throughout the period. Days supply of gasoline and diesel in the group finished at 2933 days, respectively. 1st quarter 321 cracks in the Mid Con were $14.74 $19.15 in the Southwest and $15.51 for the Rockies. Crude differentials compressed across heavy and sour plates during the Q1.
In the Canadian heavy market, 1st quarter differentials for WCS at Hardisty averaged $12.69 well below the average differential we saw in the Q4 of $39.43 Recently, we have seen this differential trade in the $13 range as the Alberta government quota system has reduced the volume of crude output. Despite mandated quotas, the levels of apportionment on the Enbridge system remain high. The forward market for WCS has been widening as the markets foresees incremental crude to be produced as well as the impact of IMO 2020 later in the year. We continue to be able to purchase and deliver adequate volumes of price advantaged crude from Canada to meet our refining needs. Canadian heavy and sour runs averaged 65,000 barrels per day at our plants in the Mid Con and Rocky regions.
We refined approximately 171,000 barrels a day of Permian crude in our refining system composed of 106 1,000 barrels a day at the Navajo Complex and 59,000 barrels per day delivered by the Centurion pipeline at the El Dorado refinery. Midland differentials averaged in the Q1 at $2.57 and currently we see the same differential trading at 4.16 dollars below Cushing due to new pipeline capacity coming on later than originally expected. We anticipate this differential to remain wide into the summer months and then revert to tighter levels later in the year as additional pipeline capacity comes on stream. 1st quarter consolidated refinery gross margin was $12.74 produced barrels sold, representing a 1% decrease compared to the $12.83 recorded in the Q1 of 2018. This increase was driven by compressed late in crude costs in the Mid Con and Rocky regions, offset by stronger gasoline and diesel cracks in the Southwest.
In the Q1, our rent expense was $39,000,000 And with that, I'm going to send it over to Rich.
Thank you, Tom. As George mentioned, the Q1 included a few unusual items. Pretax earnings were positively impacted by a 2 $32,000,000 lower of cost to market benefit, which was partially offset by Sonneborn acquisition costs of $13,000,000 and a one time inventory evaluation step up of $9,000,000 The table of these items can be found in our press release. We anticipate realizing an additional $13,000,000 to $18,000,000 of Sonneborn related integration costs throughout the remainder of 2019. In the Q1 of 2019, cash flow from operations was $217,000,000 which includes turnaround spending of $79,000,000 HollyFrontier's standalone capital expenditures totaled $53,000,000 for the quarter and we also funded the Sonneborn acquisition with $663,000,000 of cash on hand.
As of
March 31, our total balance sheet cash balance stood at $496,000,000 which is in line with our target cash balance of $500,000,000 This strong cash position along with our undrawn 1 point $35,000,000,000 credit facility puts our total liquidity at over $1,800,000,000 As of quarter end, we had a $1,000,000,000 of standalone outstanding and a debt to cap ratio of 14%. During the Q1, we returned a total of $135,000,000 of cash to shareholders, comprised of a $0.33 per share regular dividend totaling $57,000,000 and the repurchase of approximately 1,400,000 shares of common stock totaling $78,000,000 HEP distributions received by HollyFrontier during the Q1 totaled $37,000,000 a 2% increase over the same period in 2018. HFC owns 59,600,000 HEP limited partner units, representing 57% of HEP's LP units and a market value of $1,600,000,000 as the blast lines close. For the full year of 2019, we continue to expect to spend between $470,000,000 $510,000,000 for both standalone capital and turnarounds at HollyFrontier Refining and Marketing, $40,000,000 to $50,000,000 at our Lubes and Specialty Products business and $30,000,000 to $40,000,000 of capital for HEP. And with that, Tamina, we're ready to take questions.
The
floor is now open for Thank you. Our first question is coming from Brad Heffern with RBC Capital Markets.
Good morning, everyone. Good morning, Brad. Rich, just following on your comments there at the end, I guess, two things. Can you give, what the working capital impact was during the quarter? And then additionally, the CapEx number for the quarter seems relatively light relative to the full year budget.
So can you talk about the trajectory there?
Yes, Brad. So working capital in the quarter was about $64,000,000 benefit. And trajectory, yes, obviously, it looks like on capital side, we're going to be a little back end loaded this year. We have a very heavy turnaround schedule in the Q4, so that will also be a big driver of timing of cash flow.
Okay, thanks. Then I guess shifting to RINs. Last year at this time you guys announced the Cheyenne small refinery exemption. There anything to read into you guys not announcing 1 this time or has it just not come in yet?
Yes. I just think it's simply a matter of timing, Brad. As you know, the government's been shut down on and off a little bit here recently. We expect small refinery exemptions to continue to be granted consistent with the recent practice under the Trump administration. We expect them to be granted because it's the law is confirmed by several court cases and because we take Administrator Wheeler's word during his confirmation hearings that he is committed to continuing to uphold the law.
Okay. And then finally, I was just looking at the Southwest crude runs. Last couple of quarters, you guys have run a lot more sour and a lot less sweet. I know that those are very, very similar crude grades out there. But I was wondering if you're seeing anything in terms of the light crude quality, in terms of API gravity or anything else that's causing you to shift more towards the sour barrels?
Thanks.
Hi, Brad, it's Tom Creek. Probably what we're seeing in the Permian these days is we're getting into a 3 tiered system on WTI. We're starting to see WTI regular, WTI light and WTI condensate for a lack of a better word. And what we're going to see is those grades are going to start to trade at different levels. I think we've probably seen the highest grade, which is over $60,000,000 traded at $1.50 below WTI.
Primarily, where we do business in the Delaware Basin, we see a lot more light crudes coming on stream and not as many of the sour crudes. And I think that's probably why you've seen some price inversion of late is that the sour crude is being bid up, because it's being used to blend down those lighter grades to get back to that WTI normal basis. So going forward, we're probably seeing more of the lighter crudes coming into the system.
Thanks.
Our next question is coming from Manav Gupta with Credit Suisse.
Hey, guys. So first of all, you guys have done a very good job on the entire MidCon operating system. I mean, despite turnarounds at both the refineries, the gross margin capture was in line with VFX and Vero, so pretty impressive. And I wanted to focus a little bit on one part of the business, which is not working as well as all of us would have hoped for. And you mentioned this on your opening comments when you said very challenging base oil markets.
You elaborate a little bit on that topic? And when can we expect to see a trough condition and then reversal in the base oil markets?
Hey Manav, it's Rich. So yes, obviously tough quarter. The base oil market remains cyclically very weak and in particular we're seeing conditions in the Group 3 market that we haven't arguably ever seen before. We believe the market bottoming here in the first half of twenty nineteen with supply additions peaking and the most notable of those being the ramp up of Exxon's Group 2 plant in Rotterdam right now. Specific to our business, we saw sequential improvement with the absence of a turnaround.
This was somewhat hampered by weather related maintenance we had at Mississauga, which has bled into the Q2. So in general, we expect to see a continued slow improvement for the remainder of the year. But really in the long run, what we expect to see is demand growth absorb these capacity additions, similar to conditions you'd see in any cyclical business, frankly. The secular trend remains the higher performance lubricants in all end markets. And so we expect to see our Group 3 and higher quality Group 2 base oils seek better margins in particular over the next few years.
Thanks for those comments, Richard. Quick follow-up is you are using a lot of Permian crude. We are seeing that this being volatile, but rewidened here a little. Just wanted to if you could get a few give us some idea what is causing the rewidening? Is there a delay in some pipeline?
Was it production? Is it crude quality issues? Any color you could give us on what's driving the rewidening of the differentials here in the Permian?
Yes, Manav, it's Tom Creery. What we're seeing is just the differential is trading around as far as we can tell around pipeline startups. And as they're being delayed, the differential widens and as they advance their schedule, it narrows. We don't have a great line of sight to seeing how many new wells are being brought in and completed, but that's but from what we see, a lot of it is being driven around that pipeline news in the Permian.
Which pipeline is this, sir?
Which pipeline? I'm sorry? Yes.
Which pipeline is
this 1? The 3 big pipelines coming on for the remainder of the year is Epic Enterprise and Gray Oak. So those are the ones that are getting all the news at this point in time.
Okay. Thank you so much guys for taking my questions.
You're welcome. Thanks Mohan.
Our next question is coming from Phil Gresh with JPMorgan.
Yes. Hi, good morning. Just a follow-up on lubes on the Rack Forward. If I look at the EBITDA there and I think you had what 2 months of Sonneborn in there. So I just wanted to understand because it looks like the EBITDA was down year over year on Rack Forward?
Yes. Phil, it's Rich. So it was I think we call it a solid quarter there. The big driver here we saw in the Q1 was customer destocking. So this is the exact same phenomenon you saw in the chemical space in late 2018 early 2019, where customers see the price of their ultimate raw material falling and they're going to destock their own inventory, expecting to buy cheaper inputs later.
So we all saw the bottom fall out of the oil market in the 4th quarter and we in turn saw very weak demand in several of our markets in January, February. This was particularly impactful to our legacy Tulsa business. So really looking forward then, we've seen a nice acceleration in demand in March going into April, and we're still optimistic for the full year here.
Okay. And did you reiterate the $285,000,000 RAC Forward EBITDA? I apologize if I missed that.
We did not in comments, but yes, the $275,000,000 to $300,000,000 range, we'd reiterate that.
$275,000,000 $300,000 Okay. Second question just on the cash balances. Rich, you mentioned you're right at your cash balance target of $500,000,000 dollars after completing Sonneborn. Is there a desire to build those cash balances at all to be opportunistic with future M and A? Or would you think of more cash in cash out willingness to buybacks with any incremental cash that would be above the $500,000,000
Well, I think Phil, as we've discussed in previous earnings calls, the $500,000,000 is the minimum threshold that we like to keep to operate the company. Then once we get above those levels, we start looking at the competition for cash between share repurchases and any acquisition opportunities that we see available to us.
And how does that environment look today to you?
Well, as we've previously discussed, we'd love to continue to grow our company because as our industry continues to consolidate, we believe scale will become increasingly more important. But having said that, we're not going to add scale simply for scale sake. We're going to continue to be value oriented in our approach to acquisitions. We don't see value in the midstream space as we've discussed previously, primarily due to the amount of private equity capital chasing deals in that sector. I think similarly in the refining space as much as we'd like to add a refinery to our portfolio, we believe the bid ask spread is wide there due to the recent profitability of the sector and the anticipation of IMO 2020 and its expected impact on refining profitability.
We continue to see the best opportunities in the lubricant space. But in the meantime, until we get something more definitive, we are going to continue to focus on optimizing what we currently have. That's improving the reliability of our refining segment and continue to integrate our portfolio of lubricants businesses, PCLI, Sonneborn, Red Giant and our legacy Tulsa assets.
Okay, great. Last quick one. Did you see any residual Canadian crude price benefits in the Q1 from late 4Q purchases? I know some others have talked about that.
Yes, we have. Just given the in transit time on the Canadian pipelines, we saw some of that drag over into January.
Got it. Okay. Thank you.
Thanks, Phil.
Our next question is coming from Justin Jenkins with Raymond James.
Great. Thanks. Good morning, everybody. I guess my first question is just a follow-up to Phil's on the cash balance. I think George, you talked about maybe last quarter reevaluating the dividend and just curious where that stands here.
Hey, Justin, it's Rich. So we are evaluating the dividend in light of the additions we've made particularly to our lubes and specialties businesses. We're really early in this process, frankly. And I think we're going to have a better idea as we integrate Sonneborn over the next couple of quarters. So to George's point, I think certainly in the near term, we'd expect to continue to return excess cash over $500,000,000 in the form of buybacks.
Got it. Thanks, Rich. Second question is more macro operational on the product side. I'm just curious where we stand today in terms of the split between MAX gasoline and MAX diesel and how you think that plays out throughout the summer months and maybe in the lead up time of 2020?
Right. Justin, it's Tom. It kind of goes region by region. We don't have a consistent plan because we're going to try and maximize earnings here. What we're currently seeing is we're seeing extremely high differentials in the Phoenix Southwest area.
So in our Navajo complex right now, we are maximizing gasoline and we will continue to do so until we see that break. A lot of it is driven by operating problems on the West Coast. So it's tightening supply back into the Phoenix market. And like I say, we're seeing really high margins there as well as into the Las Vegas market. George mentioned we were moving a lot of crude through the U.
N. Or gasoline through the U. N. E. V.
System and we will continue to do so. And the rest of the markets that we operate in, we've continued to maximize diesel because it's getting a higher crack back to us and we'll continue to do that. But we do watch it very closely and make alterations to our refining systems as market conditions dictate.
Got it. Very helpful. Thanks guys.
Thank you. Thanks Justin.
Our next question is coming from Matthew Blair with Tudor, Pickering, Holt.
Hey, good morning, everyone. It sounds like this Las Vegas arb was pretty helpful for your midstream in Q1. Could you comment on whether that's persisting into Q2? And does that also present some refining upside at your Woods Cross plant?
Yes. Matthew, that arbitrage between Salt Lake City and Las Vegas is typically very seasonal. In the summer, Salt Lake typically trades above Vegas and in the winter, I. E. The 1st and fourth quarter, it's the opposite.
So what we saw in the Q1 is very typical to what we typically see. But to your question, because of the West Coast operating problems that Tom just mentioned, the Vegas markets that is typically supplied from the West Coast, That supply is not as readily available. So that's opening up the arbitrage even as we enter the Q2 to continue to ship barrels from Salt Lake to Vegas, which again is atypical, but it is a benefit, as you said, both to our UNEP pipeline in AGP as well as to our Woods Cross Refinery in HFC.
Terrific. And I guess turning back to the lube side, you mentioned the ongoing ramp of the Exxon plant is perhaps oversupplying the market. I believe there's also a fairly large plant in China from Hengly Petroleum that is just about to start up in mid May or so. So I guess, do you view that as just another headwind on your commodity side of your lubricants business for the rest of the year?
Yes, Matthew, I think
yes, I mean long story short, we see sort of supply additions peaking here in the first half. To your point, it's hard to call it a day. And so then what we would expect from here is this will be trough here in the first half and then we'll see demand basically absorb the supply over the next few years and margins rebound.
Great. And last one, your balance sheet is pretty safe here. Is there any thought to perhaps levering up a little bit, buying back some additional shares before IMO tailwinds kick in next year? Thanks.
No, I think we'd intend to lever up. We'll plan to use this excess cash to repurchase shares if we don't have a better use for it. Great.
Thank you.
Our next question is coming from Neil Mehta with Goldman Sachs.
Hey, thank you. I guess the first question going back to the lubes business is, George, how do you think about the weakness, whether it is a cyclical point or a structural point? And I'm guessing the view is that it is cyclical and the demand will ultimately eat into the oversupply. But as we think about the full cycle returns on the investments that you made in the acquisitions, want to get your sense of your conviction level that those were the right decisions?
Yes. Let's think about this business in 2 segments really here, the Rack Back and the Rack Forward that we typically discuss. And there's no question there's weakness on the Rack Back side. Rich talked about the additional capacity coming on both in Rotterdam and in other regions of the world. So there's 2 things happening there.
It's obviously adding supply, but it's not just a matter of additional supply needs to be absorbed. There's also substitution occurring between the various grades of lube oils. So most of these new plants are Group 2 in the market, as Rich said in his remarks, is trending towards higher quality lubricants, which is Group 2 and Group 3. And what we expect to happen as this supply comes on is that Group 1, which is primarily the base oil that's used in Asia and to a certain extent in Europe that will be substituted by this increased supply of Group 2. So there will be a lot of substitution going on to absorb that capacity as well as continued growth overall for base oils in general.
And then there's the Rack Forward section of the business, which again, that's where our primary focus is for growth, to continue on capitalizing on our technology and know how within Sonneborn and PCLI to grow that business in downstream
markets. I appreciate that. And the follow-up is just on the crude markets. Brent WTI in particular, there's a really rich debate in the investment community about what the normal level is for Brent WTI. Just curious what the team's view is as you think about where transportation economics will ultimately take the spread in kind of a more mid cycle type of environment?
Yes. I mean, as you know, it's been in the $8 to $9 range for most of this year. I think we would all agree that that's probably on the high end of where it should be. As we all know, the Permian pipelines are coming soon at the end of this year to bring more barrels from the Permian to the Gulf Coast. We think that will put downward pressure on the Brent WTI spread.
But our view is it still should be in the $5 per barrel range, plus or minus. The way that we typically look at that, we break it into 2 components. What's the Brent to WTI Houston differential going to be? That's been typically running in about the $2 per barrel range recently. I think directionally that will widen out as there's more barrels coming into Houston from the Permian.
Those Permian barrels are going to have to find new and different markets than where it's currently going to absorb the additional supply that's hitting Houston. And then what's the Houston to Cushing differential going to be? I think that's going to be very much a function of transportation economics, which is going to be roughly in the $3 per barrel range. As those pipelines fill, could be higher. If and when new capacity is added from the inland markets to the Gulf Coast, it could be lower.
But bottom line is we expect long term for that differential to be at about the $5 per barrel range.
That's great. Thanks,
Our next question is coming from Doug Leggate with Bank of America.
Thanks. Good morning, everybody. Can you hear me okay?
Sure, Doug. You're good.
Sorry, I wasn't sure if my headset was operating correctly. Guys, I wonder if I could just prod a little bit on the lubes outlook, specifically given that you called out the Exxon startup because given the base oil market, a large part of it, as you pointed out, George, is Asia. They did also sanction another very large lubes project just in the last month or so, which is sort of probably 2 or 3 years away. So as you look out to the prognosis for demand to absorb that additional capacity, How do you see the net balances playing out? I guess I'm really just trying to understand if your mid cycle assumptions for Loop's EBITDA still stand in light of all these changes that have taken place fairly recently?
Hey, Doug, this is Rich. So yes, long story short, our mid cycle assumptions still stand. I think you can look at and we would look at Exxon's willingness to spend that kind of money on another project at this point in the cycle as an endorsement of the fact that demand is going to grow here and there will be a need for that capacity. Ergo, margins are going to get better.
If I could just add to that, the IMO role of discounted or disadvantaged heavier sour crudes, how does that play into your margin assumption? One would assume that that would be incrementally more favorable.
Yes. I don't see IMO having a major impact on base oil margins, Doug. I think directionally IMO should increase the demand and price of VGO to the extent that VGO replaces bunker fuel in the marine market. But we always think of the base oil profitability as a margin over VGO. So directionally, we think it would raise the pricing structure across the base oil and lube oil market.
But as far as a margin perspective, we don't think it should have any impact.
Okay. Thank you. My last one, if I may, just pick up on your comments about the back end loaded turnaround schedule. I'm just curious about again, it's kind of an IMO related question. Obviously, a lot of folks are talking about preparing for the change in dynamics potentially going into 20 20.
Coming out of your turnarounds, how would you see would you see any meaningful shift in your relative product yield and perhaps even your operating sort of MO as it relates to staying with a kind of a maximum distillate type of yield going into what is expected to be a fairly robust market. So again, just how are you thinking about the post turnaround scheduling as you go into 2020? And I'll leave it there. Thanks.
The short answer, Doug, is we don't see any material differences in the capabilities or the way we operate our plants pre or post turnaround. Directionally, as you're saying, IMO will increase the demand for diesel fuel and to a certain extent BGO and we'll optimize our plans accordingly to, as Tom said earlier, to go max diesel as our LP models dictate as we give them the differentials between gasoline and diesel fuels.
Understood. I appreciate you getting on this morning guys. Thank you.
Thanks, Doug.
Our next question is coming from Paul Sankey with Mizuho.
If I could just try
and pull this all together, but ultimately you have what might be an impossible question to answer. Can you give us a mid cycle or normalized EBITDA the whole corporation? And I guess, would have to go beyond the IMO effect. And the sub question would be, are you seeing any IMO effects as of now? And then if you could try, if possible, to get towards that future number.
And then to make it even more impossible, could you give us guidance on a range for how much acquisitions might comprise for you guys? I assume the low is 0. I wondered how high you would go. Thanks.
So, Paul, on EBITDA, I mean, going back to our Analyst Day in 2017, if you go business by business, refining to your point, I think at the time we called $1,100,000,000 of mid cycle EBITDA. We'd expect that to improve, thanks to IMO, but your guess is as good as mine, frankly, on quantifying that improvement. On the lube side, obviously, we've added Sonneborn most importantly as well as Red Giant. And to our discussion with Doug earlier, we'd expect the Rack Back to still be more or less breakeven in the long run. So I think you get to sort of a kind of what we're guiding this year, dollars 275,000,000 $300,000,000 of mid cycle EBITDA.
HEP continues to grow slowly, so a couple of years of growth there. I think at a high level that'd be sort of mid cycle EBITDA per business.
Yes. Yes, great. Thanks.
And I'll try the IMO 2020 effect. I mean it's still too early. We're not seeing any of that impact now. What that's going to do to our diesel cracks and potentially our gas cracks, It's kind of one of those who knows type of wise ass answers here. But to try to frame it up a little bit, round numbers, we make about 200,000 barrels a day of diesel fuel.
Every dollar per barrel impact on the crack is going to be nominally $70,000,000 per year to us. The most common number I've heard for the impact of IMO 2020 is probably in the $5 per barrel range. I've heard numbers as crazy as $20 per barrel. We tend to stick to the consensus type of number of 5. So you can go from there on that.
As far as acquisitions, that's difficult to impossible to call. As I said earlier, we'd love to continue to grow our company. We're not going to grow just for growth sake. It's got to be value oriented. I mean, you've seen what we've done in the recent past.
I think we're pretty proud of what we've done. I would probably predict that we won't be doing as many acquisitions going forward as we have the last 2. But again, it all depends on the opportunities that present themselves and the price expectations of the sellers.
Well, that's very helpful answers. Thank you very much indeed. The follow-up is the new premier of Alberta, I assume, is well, he's immediately got into action with some oil positive moves here. I don't know if you just would add your perspective on the political change there.
Thank you. We'll let our resident Canadian, Tom Curie, answer that one.
I'm kind of biased a little bit on this one, but I think it's going to be it's definitely a different outlook for the province of Alberta going forward. The new Premier is more attuned to the oil industry and the building of pipelines as opposed to its predecessor. Time will tell. Politicians don't always get through what they say they're going to get through. But I think it's better off from what we see here, at least from a personal standpoint, it's probably better off for the oil industry in Alberta moving forward than it was in the past.
So we'll keep our fingers crossed and see what
happens. Great.
Thank you.
Thanks, Paul.
There are no further questions. I will turn the floor back over to Craig for any 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 Q2 results with you in August.
Thank you. This does conclude today's teleconference. Please disconnect your line at this time and have a wonderful day.