HFC
#Sure.
In the Permian, we are seeing the rig count in the production levels increasing.
I don't think there's any secret there.
A lot of that is in the counties that are right around our Artesia and Wilmington refineries.
We are pleased to see that increased production.
That presents opportunities for both our refinery in Artesia, New Mexico as well as HEP that participate in the midstream business around those assets.
Having said that, there's a lot of pipeline capacity to the Permian to the Gulf Coast, where it's going to take a significant continued increase of production to fill up those pipelines to lead to widening crude differentials between Midland and say Cushing or the Gulf Coast.
Sure.
<UNK>, directionally, the incremental crudes from the shale production there are lighter, but one of the reasons why we are pleased with this project that we're going to be doing during the turnaround to emulate those recycle streams and allow us to increase our ability to run lighter crudes.
There's no question there's going to be, need to be some solutions to placing these higher gravity crude into existing pipeline infrastructure, and again, this is one area where we hope that HEP will be actively participating.
Anything else on the Permian, <UNK>, or is that good.
Okay.
Scoop and stack, we're not experts in that area.
We see it secondarily to the movement of that crude to Cushing.
From what we see and know, scoop and stack is another, much smaller, player in the Permian, but comparable to Permian, where, again, production is very active.
And again, the incremental barrel tends to be lighter than your typical 42 gravity WTI.
On the Uinta Basin, we're seeing some signs of production there by smaller producers.
Larger producers like New Field have other plays they are focused on.
But you see smaller producers picking up the slack and it's very early in that pickup.
It's one of the last basins that we anticipate production increasing, but for producers that don't have positions in the other plays like the Permian and scoop and stack, we're seeing interest in producing those barrels.
It's a much lower risk play in [ENO].
The crude is there.
It is just a matter of financing the wells and having a market like us to produce it in.
That project is on hold for now.
We continue to work with engineering and cost estimate.
We're still optimistic about that project.
It's going to be a good one for potential octane and tier III solutions, but it's not something that we need for either.
It's just an opportunity investment for us to further decrease our gasoline sulfur for TFC and make more octane.
But again, we can lead tier III and produce our octane without that project.
Sure.
I think a couple things on that, <UNK>.
We have some initiatives that are based on or driven towards the OpEx, just the dollars perspective.
We have some fixed costs that we need to drop out of the system, maintenance being the biggest one, but we also have a series of other smaller targeted cost-reduction efforts, water consumption being one I can highlight.
But the biggest opportunity we have in the Rockies is getting throughput up.
That's been our biggest challenge in Cheyenne.
That refinery is rated at 50,000 barrels per day.
It's actually 52,000, but it's tough for us to run at that crude capacity.
The downstream is not matched up to that rate.
But there's no reason we shouldn't be able to run the facility in the high 40,000s: 47,000, 48,000.
We have reliability initiatives in place to go get that and that constraints in coke handling and sulfur handling that we're addressing as well.
The models not only increase the throughput, but also increase the percentage of WCS in front of that facility, which fits to your gross margin question.
But when you look at gross margin, that is our biggest facility to influence it is on the fluid side of the equation.
The product market is what the product market is.
The big lever to increasing our WCS percentage in that fluid side, that's Cheyenne.
Yes, we've guided 350,000 to 360,000 for the first quarter.
Again, it's impacted by some turnaround, the biggest one being Navajo where we have a 45-day outage that looks like we need about every unit in the refinery down in various stages and then we have a 17-day outage at El Dorado, which will impact crude rates there appreciably.
As far as builds, they're basically at the same level where they were last year.
The good news is the build is less this year from last year, not significantly less, but less nonetheless.
And on the build side, I think there's definitely some questions on demand.
I don't think that demand has decreased as much as some of the reports would indicate.
And when I see that demand decreasing 4%, that sounds very high to me.
Which suggests there might be some weather issues in the data or perhaps some issues with export data and how that calculates into a demand number.
I still think that the majority of the build in refined products, especially gasoline, is more supply driven.
And I think we have more maintenance planned this year than perhaps last year and hopefully with this turnaround coming up, that will decrease inventory levels and some of the inventory level will go up in advance of those turnarounds so that and as we did it at Navajo, they're [dance] about turnaround there, we built inventory so that we could supply our customers during downtime.
No, no.
There is no economic run cuts.
As you know, we have a pretty good product market location product but are net short product and with the incremental barrel coming from somewhere else.
We typically run our plants full-out.
The last time we got an economic run cut was about a year ago now, it was about 5,000 a day and it lasted for about a week.
So, no harm in the increase.
But again, the reason the numbers might be low is we have, again, the turnarounds at Navajo.
It's 45 days, significantly half of the quarter, Navajo is going to be at significantly reduced rates.
Again, El Dorado is going to down for 17 days.
When the vacuum tower, the fluid tower goes down with it.
And then we have the 12 to week former that we mentioned.
That downtime occurred in the fourth quarter and still into the first quarter.
And then one of the questions the <UNK> asked that I forgot to address was Woods Cross.
There are issues with the Salt Lake City pipeline.
That's the major supply pipeline into all the refineries in Salt Lake.
So, we are running at reduced rates there, roughly in the ballpark of 30,000 to 31,000 barrels a day versus our high-30,000s that we've run since the turnaround.
This was the Woods Cross expansion turnaround.
Yes, <UNK>, on the first question, what I would tell you is that because this non-GAAP, non-audited results that we see in Suncor did not break the valve and we cannot give an exact number, but we will tell you that, yes, we are very comfortable with the previous guidance and the $150 million number you mentioned, again, on a non-GAAP, non-audited basis looks very close to exactly what we were expecting and what the actual results were.
As to the margins, I'll let <UNK> or <UNK>, maybe Tom, comment.
Hello, <UNK>.
It's <UNK>.
I think on the base oil side, the year started off a little bit soft, not unexpected seasonally and downstream of that, finished product margins remain strong.
So we, again, to <UNK>'s point, feel very confident in our numbers and our guidance around PCLI.
Yes, I think we're planning an analyst day meeting later this year, probably in December.
I think 2017 is going to be very focused on integrating and making the improvements we anticipate and capturing the synergies with PCLI.
We are still going to be looking for other opportunities, but our primary focus, again, is going to be on PCLI.
That's obviously a huge acquisition for us.
We think there's tremendous potential to integrate that with Tulsa and to use that platform for growth.
There are other opportunities that we're looking at, both in refining and for HEP, especially in the Permian.
But, by far and away, our biggest priority is PCLI this year.
The biggest structural change in the Rockies is on the crude side again.
It's a $50 crude, there's obviously more production.
Then there's the $100 crude.
You see that across the entire domestic sector, but you especially feel it in the Rockies.
We've seen significant contractions or narrowing of crude differentials there and that's the biggest change in the second half of last year is that the crude that we've typically enjoyed at Cheyenne, especially at Woods Cross, has narrowed significantly in the last few months.
I think that it will continue until, again, production increases.
And that's going to be driven by crude price.
I think we're on a day-to-day basis here, working to get the permits and permissions we need to get in there and do the work.
I think the work is well-defined what needs to get done.
But it's really just the upfront work that needs to get done to clear the way for the fix.
Go ahead, Ed.
I think the fee optimization is not exclusively the wax crude gas oil.
I think there's also feedstock from Tulsa, since we're a third-party feedstock, it would all be conducive to making more group III versus group II.
I think we should give us a little time and check about towards the end of the year to see some of that coming through.
Again, putting odds on things like this is very difficult to do.
I would put the odds are greater than 50% and less than 100%, so I think in the midpoint, 75%.
I think there's no question there's a lot of people on the other side of this, but the people that are on the other side of this are frankly the people that are realizing unintended windfall profits from this.
So, but we still believe we have right on our side, whatever the intents of the RFX to generate winners and losers to this magnitude.
Again, to generate profit centers that were never intended to exist.
And I would just add to that, Ed, that as <UNK> mentioned in the open, while the new chair of the EPA, Mr.
Pruitt, is not likely to be a radical, our experience having worked with him as the Attorney General in Oklahoma with our ownership of the refinery there is that he is of sound mind and a critical thinker and one that is certainly at least willing to understand both sides and our view, as <UNK> said, is that there is a better than 50/50 chance that we get some movement there.
Don't know until it's done, but again, our view is a better than average chance.
I guess one last thought on this one, Ed.
The flaws in the RFS could never be better illustrated than what we've seen since the election.
We're infiltrating over dollar and right now, they're trading for less than $0.50.
There is no fundamental change in supply/demand balance for RINs.
So again, it just highlights the speculation and how subject to manipulation the RINs market is and how the misalignment between the points of obligation and the point of bonding is causing this market to be highly distorted and it needs to be fixed.
That's one of the reasons why we like PCLI deal.
That, again, in combination with Tulsa, it gives us scale to basically have a full third leg to our growth story here.
We think there's opportunities in the M&A arena for lubes just like there are, again, like you said, on the refining MLP side.
We're, again, very early in the stages of tapping into that deal flow, but we see deals of various sizes in the lubricant space that would be nice bolt-ons to PCLI.
We don't have any specifics to share at this time, but we're encouraged by what we're seeing this early in the game and getting into that deal flow.
I think, <UNK>, we'd prefer to think of it as changing the product plate rather than volume expansion.
The facility makes 15,000 or 16,000 barrels per day of base oil.
And right now, it's about 20% group III and 80% group II, so we're actually II plus type of material.
Again, very early stages of what we could do with the feedstock optimization strategy.
But, we think there's potential to increase group III production by a few thousand barrels per day, and again, every barrel that is converted from group II to group III has an $80 per barrel uplift.
We think we can get this done with no to minimal investment.
We might need to make some pre-treating type investments, but we're talking something in the order of $5 million to $10 million.
But, again, very early stages of quantifying both the potential and any potential costs associated with doing that.
Sure.
Thanks.
On the tax side, certainly prior to our PCLI acquisition, HollyFrontier is the definition of a full US taxpayer.
We have been so and, certainly through the early part of this decade, paid a tremendous amount of US tax.
If you get a reduction to 25% or 30% or 20% all of that would be incrementally very positive for us.
On the PCLI side, we do have a few structures that does help us with taxes there, but for the most part, again, a huge gain to us if we do get a change and that would be great.
But, again, much the same with our comments on border adjustment.
I think our tax department view is that, even if you get the consensus of something that gets taxed, at the very, very earliest, we'd be talking about back half of 2018 and perhaps later before you see something that's implemented.
But, we'll keep our fingers crossed, certainly, on that one.
In terms of use of the free cash flow, we would love to have that problem and have it start as soon as the second quarter, but really no change there.
I mean, we've deferred some discretionary opportunity growth CapEx projects that we think are very high return and I think that would be the first and those tend to be 1.5- to 2-year paybacks.
Hopeful, look at, I think share repurchase would be the next leg we'd look at because that's really been a preferred method versus the special dividends or such that we looked at earlier just after our merger.
I'm certain <UNK> looks forward to that problem and hope it begins the day that I leave.
No, that's definitely something that we're looking at, <UNK>.
We do have our hands a little bit busy like we've talked about right this minute with PCLI and closing the year's financial statements.
But, we will definitely be looking at this.
There's a lot of tax implications here that we need to really get into the details.
As you know, the devil's in the details on that type of thing.
But we think it is something that could be potentially be good for both HEP and HFC as the GP.
I would not say that.
I think if it's something that's going to be good, I think that's something we can figure out this year.
If it is good for both sides, then I think it'll be something that potentially could be done this year.
No guarantees, but again, I would think sooner rather than later on that.
That is your third question, <UNK>.
Just saying.
Well I just saw your quarter side set here, so I wanted to let you know.
Yes.
I think the conversion to JV is it's not limited to us or to refining in general.
As you know, the issue with JV is that if, even if both parties consensus is perfectly aligned at the beginning, over time, they can tend to drift and become misaligned.
I think the Motiva venture is a good case study in that one.
So again, initial alignment is difficult and then maintaining alignment over time is again difficult.
But having said all that, <UNK>, never say never.
If there are enough incentives to enter a JV, especially on a refining JV, where perhaps we'd bring something to the table from a marketing or supply perspective or operational perspective, gives us trading opportunities, sure, we would look at it.
But going in, we would be with a very cautious eye.
I think for the full year, <UNK>, it was about $90 million, $95 million.
And for the fourth quarter, it was about $28 million.
Sure.
At the highest level, we agree with your statement.
We are not pleased with where we are here.
We are not meeting the objectives that we set up in our business improvement plan.
But having said that, at the risk of sounding like I'm making excuses, extenuating circumstances on some of our downtime.
For example, the Tulsa reformer that we highlighted in the prepared remarks, the issue with that downtime is primarily associated with the original conversion of that unit to a CCR that was done prior to HollyFrontier even taking ownership in that facility and it's taken basically 10 years for that design flaw to show up and it's basically some support rings and caps internal for the reactor that's failed and basically, the eternals to the reactor altered and move that point.
But, having said that, we are fully focused on operational improvements, we've made significant investments in people and in our efforts to improve reliability, especially in utility systems.
We have got a team of 10 to 15 people here in Dallas at the corporate level lending assistance to the plants to improve their reliability across the board.
One of the best examples I think I can highlight is our BMI program, where we've identified various pieces of pipe that had it not been for this program could have failed and could've led not only to downtime, but significant safety events in that facility.
I think we're not going to get into a whole lot of detail here.
We'll start sharing more of that information as we report our financials.
But at a high level, this is a very fixed cost driven business, as refining tends to be in general.
Especially so in the differentiated high-margin business in that we have a lot of pretty big sales in R&D staff associated with PCLI.
Beyond the plant level, there is also fixed cost associated with those capabilities.
I think it's less sensitive to changes in crude price than refined products definitely are.
It sensitive, but much less so, and I would say that also, it tends to be more lagged than we find products typically are.
Hello, <UNK>.
It's <UNK>.
So, we've been on the ground for about three weeks now and credit to our accounting department, they've also been trying to wrap up a 10-K, so it's really premature to go there.
We will have some detail and we will report this as a separate segment for the first quarter and I expect this will also evolve with time.
PCLI costs are in corporate and RINs for the fourth quarter, <UNK>.
$75 million.
$75 million and the full-year was $240 million.
All our refineries can meet the tier III requirements.
We had our last plant was Navajo and we have our prime G units just completed there.
And it is ready to start up if we need it.
Those other two plants are the smaller plants, Woods Cross and Cheyenne, and both of those have small refinery exemptions to push out the compliance until 2020.
Thanks, everyone.
We appreciate you taking the time this morning to join us.
If you have any follow-up questions, as always, Craig and I will be available all day.
Thank you very much.
