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Welcome to the HollyFrontier Corporation's First Quarter 2019 Conference Call and Webcast.
Hosting the call today from HollyFrontier is George Damiris, President and Chief Executive Officer. He is joined by Rich Voliva, Executive Vice President and Chief Financial Officer; Jim Stump, Senior Vice President of Refinery Operations; 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, Tamia. Good morning, everyone, and welcome to HollyFrontier Corporation's First Quarter 2019 Earnings Call. This morning we issued a press release announcing results for the quarter ending March 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 statements 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 Damiris.
Thanks, Craig. And good morning, everyone. Today we reported first quarter net income attributable to HollyFrontier shareholders of $253 million or $1.47 per diluted share.
Certain items detailed in our earnings release increased net income by $160 million on an after-tax basis. Excluding these items, net income for the current quarter was $93 million or $0.54 per diluted share versus adjusted net income of $137 million or $0.77 per diluted share for the same period last year.
Adjusted EBITDA for the period was $282 million, $34 million less than the first quarter 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 million despite a very challenging base oil market. Rack Forward adjusted EBITDA was $53 million 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 million and continue to expect long-term synergies of $20 million per year.
Holly Energy Partners reported EBITDA of $94 million for the first quarter compared to $88 million in the first quarter 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 UNEV Pipeline as the arbitrage between Salt Lake City and Las Vegas remained open during majority of the quarter.
During the quarter, we returned $135 million 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 first quarter, 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 and 455,000 barrels per day of crude oil for the second quarter.
I will now turn the call over to Tom for an update on our commercial operations.
Thanks, Jim. For the first quarter 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, $1.62 in the Mid-Con and $2.75 in the Southwest.
In the first quarter 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 8.9 million barrels and ended the quarter at 7.7 million barrels. Current inventories of gasoline are roughly 1 million barrels lower at 6.7 million barrels, well below the 5-year average.
Diesel inventories were relatively static throughout the period. Days supply of gasoline and diesel in the group finished at 29 and 33 days, respectively. First quarter 3-2-1 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 slates during the first quarter. In the Canadian heavy market, first quarter differentials for WCS at Hardisty averaged $12.69, well below the average differential we saw in the fourth quarter of $39.43. Recently, we have seen this differential trade into 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 market 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 average 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 106,000 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 first quarter at $2.57, and currently, we see the same differential trading at $4.16 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.
First quarter consolidated refinery gross margin was $12.74 produced barrels sold, representing a 1% decrease compared to the $12.83 recorded in the first quarter of 2018. This increase was driven by compressed laid-in crude costs in the Mid-Con and Rocky regions, offset by stronger gasoline and diesel cracks in the Southwest. In the first quarter, our rent expense was $39 million.
And with that, I'm going to send it over to Rich.
Thank you, Tom. As George mentioned, the first quarter included a few unusual items. Pretax earnings were positively impacted by a $232 million lower of cost-to-market benefit, which was partially offset by Sonneborn acquisition costs of $13 million and a onetime inventory valuation step-up of $9 million. A table of these items can be found in our press release. We anticipate realizing an additional $13 million to $18 million of Sonneborn-related integration costs throughout the remainder of 2019.
In the first quarter of 2019, cash flow from operations was $217 million, which includes turnaround spending of $79 million. HollyFrontier's stand-alone capital expenditures totaled $53 million for the quarter, and we also funded the Sonneborn acquisition with $663 million of cash on hand.
As of March 31, our total balance sheet -- cash balance stood at $496 million, which is in line with our target cash balance of $500 million. This strong cash position, along with our undrawn $1.35 billion credit facility, puts our total liquidity at over $1.8 billion. As of quarter-end, we had $1 billion of stand-alone debt outstanding and a debt-to-cap ratio of 14%.
During the first quarter, we returned a total of $135 million of cash to shareholders comprised of a $0.33 per share regular dividend totaling $57 million and the repurchase of approximately 1.4 million shares of common stock totaling $78 million.
HEP distributions received by HollyFrontier during the first quarter totaled $37 million, a 2% increase over the same period in 2018. HFC owns $59.6 million HEP Limited Partner units, representing 57% of HEP's LP units and a market value of $1.6 billion as of last night's close.
For the full year of 2019, we continue to expect to spend between $470 million and $510 million for both stand-alone capital and turnarounds at HollyFrontier Refining and Marketing, $40 million to $50 million at our Lubes and Specialty Products business and $30 million to $40 million of capital for HEP.
And with that, Tamia, we're ready to take questions.
[Operator Instructions] Our first question is coming from Brad Heffern with RBC Capital Markets.
Rich, just following on, on your comments there at the end. I guess 2 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 million benefit. And trajectory, yes, obviously, it looks like on the capital side we're going to be a little bit back-end loaded this year. We have a very heavy turnaround schedule in the fourth quarter, so that will also be a big driver of timing of cash flow.
Okay. And then I guess shifting to RINs. Last year, at this time, you guys announced the Cheyenne small refinery exemption. Is there anything to read into you guys not announcing one this time? Or is it -- 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. The 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.
Brad, it's Tom Creery. 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 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, 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.
Our next question is coming from Manav Gupta with Crédit Suisse.
So first of all, you guys have done a very good job on the entire Mid-Con operating system. I mean despite turnarounds at both the refineries the gross margin capture was in line with [ VSX ] and [ Varos ], pretty impressive. 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. Can 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?
Manav, it's Rich. So, yes, obviously, tough quarter. The base oil market remains cyclically very weak. And particularly, we're seeing conditions in the group 3 markets that we haven't arguably ever seen before. We believe the market bottoming here in the first half of '19 with supply additions peaking and the most notable of those being a ramp-up of Exxon's Group II 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 second quarter. So in general, we expect to see the 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 Group III and higher-quality Group II base oils seek better margins in particular over the next few years.
Just a 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 of 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 there 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 start-ups. And as they're being delayed, the pipe -- 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 -- 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 the one?
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.
Our next question is coming from Phil Gresh with JPMorgan.
Just a follow-up on lubes on the Rack Forward. If I look at the EBITDA there, I think you had about 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'd call it a solid quarter there. The big driver here we saw in the first quarter was customer destocking. So this is the exact same phenomenon you saw in the chemical space in late '18 and early 2019 where customers see the prices 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 fourth 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 of demand in March going into April, and we're still optimistic for the full year here.
Okay. And did you reiterate the $285 million Rack Forward EBITDA? I apologize if I missed that.
We did not in the comments, but yes, the $275 million to $300 million range, we'd reiterate that.
$275 million to $300 million. Okay. The second question, just on the cash balances. Rich, you mentioned you're right at your cash balance target of $500 million after completing Sonneborn. Is there a desire to build those cash balances at all to be opportunistic with future M&A? Or would you think it more a cash in, cash out willingness to buybacks with any incremental cash that would be above the $500 million?
Well, I think, Phil, as we've discussed in previous earnings calls, the $500 million is the minimum threshold 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 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're going to continue to focus on optimizing what we currently have, that's improving the reliability of our Refining segment and continuing to integrate our portfolio of lubricants businesses, PCLI, Sonneborn, Red Giant in our legacy Tulsa assets.
Okay. Great. Last quick one. Did you see any residual Canadian crude price benefits in the first quarter 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.
Our next question is coming from Justin Jenkins with Raymond James.
I guess my first question is just a follow-up to Phil's on the cash balance. I think, George, you talked about in the last quarter reevaluating the dividends, and I'm just curious where that stands here.
Justin, it's Rich. So we are evaluating the dividend in light of the additions we've made particularly to our Lubes and Specialty businesses. We're really early in this process, frankly. 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 of over $500 million in the form of buybacks.
Got it. Second question is more macro operational on the product side. 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 UNEV -- or gasoline through the UNEV system, and we will continue to do so.
In the rest of the markets that we operate in, we continue 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.
Our next question is coming from Matthew Blair with Tudor, Pickering, Holt.
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 first and fourth quarter, it's the opposite. So what we saw in the first quarter 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 market 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 second quarter to continue to shift barrels from Salt Lake to Vegas, which again is atypical. But it is a benefit, as you said, both to our UNEV pipeline in HEP as well as our Woods Cross Refinery in HFC.
Terrific. And I guess turning back to the lubes 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 Hengli 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 commodities 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 the 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?
No, Matthew. I don't 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.
Our next question is coming from Neil Mehta with Goldman Sachs.
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 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 that needs to be absorbed. There's also substitution occurring between the various grades of lube oils. So most of these new plants are Group II in the market, as Rich said in his remarks, is trending towards higher-quality lubricants, which is Group II and Group III. And what we expect to happen as this supply comes on is that Group I, 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 II. So there'll 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 and 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 the 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, it 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 in about the $5 per barrel range.
[Operator Instructions] Our next question is coming from Doug Leggate with Bank of America.
Guys, I wonder if I could just prod a little bit on the lubes outlook specifically given that you called out the Exxon start-up because given the base oil market a lot of 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 at the prognosis for demand to absorb additional capacity, how do you see the net balance is playing out? I guess I'm really just trying to understand that your mid-cycle assumptions for lubes EBITDA still stand in light of all these changes that have taken place fairly recently.
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 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 rule of discounted or disadvantaged heavier sour crudes, how does that play into your margin assumptions? One would assume that, that will 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 the margin perspective, we don't think it should have any impact.
Okay. My last one, if I may, just pick up on your comments about the back-end loaded sort of the run 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 changing dynamics potentially going into 2020. 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 that kind of a maximum distillate type of yield going into what is expected to be a fairly robust market? So again, just how you're thinking about the post-turnaround scheduling as you go into 2020.
Yes. 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 VGO. And we'll optimize our plants accordingly, as Tom said earlier, to go max diesel as our LP models dictate as we give them the differentials between gasoline and diesel fuels.
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 and normalized EBITDA for the whole corporation? And I guess would have to go beyond 2020, the IMO effect? And a subquestion 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 you guys? I assume the low is 0. I wondered how high you would go.
Yes. So Paul, on the EBITDA -- I mean, going back to our Analyst Day in 2017, if you go business by business, refining, to your point, I think at that time we called $1.1 billion 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 lubes side, obviously, we've had at 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 kind of what we're guiding this year, $275 million, $300 million 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.
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 wild guess answers here. But to try to frame it up a little bit, raw 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 million 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 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. 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.
We'll let our resident Canadian, Tom Creery, 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 his 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 and Alberta moving forward than it was in the past. So we'll keep our fingers crossed and see what happens.
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 second quarter results with you in August.
Thank you. This does conclude today's teleconference. Please disconnect your lines at this time and have a wonderful day.