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Northern Tier Energy LP (NYSE:NTI)

Q2 2014 Earnings Call

August 05, 2014 12:30 pm ET

Executives

Paul Anderson - Vice President of Investor Relations and Business Development for Northern Tier Energy GP LLC

David L. Lamp - Chief Executive Officer of Northern Tier Energy GP LLC, President of Northern Tier Energy GP LLC and Director of Northern Tier Energy GP LLC

David Bonczek - Chief Financial Officer of Northern Tier Energy GP LLC and Executive Vice President of Northern Tier Energy GP LLC

Analysts

Edward Westlake - Crédit Suisse AG, Research Division

Paul Y. Cheng - Barclays Capital, Research Division

Mohit Bhardwaj - Citigroup Inc, Research Division

Jason Smith - BofA Merrill Lynch, Research Division

Jeffrey A. Dietert - Simmons & Company International, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Second Quarter Northern Tier Energy Earnings Conference Call. My name is Kim, and I will be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today, Mr. Paul Anderson, Vice President of Investor Relations. Please proceed.

Paul Anderson

Thank you, Kim, Good morning. I'd like to thank you for taking the time to listen in today and for your continued interest in Northern Tier. My name is Paul Anderson, I'm Northern Tier's Vice President of Investor Relations. Joining me for today's call are Dave Lamp, our President and CEO; Dave Bonczek, our CFO; and other members of our management team.

We will be referencing our earnings call slides throughout the call this morning. The slide presentation, as well as our earnings release, can be found in the Investors section of our website at ntenergy.com.

Before we proceed, I would like to make the following Safe Harbor statement. Today's call and presentation will contain forward-looking statements and I refer you to the forward-looking statements section of our earnings release and recent filings with the SEC. We assume no obligation to update or revise any forward-looking statements to reflect new or changed events or circumstances.

In addition to reporting financial results in accordance with Generally Accepted Accounting Principles, or GAAP, we report certain non-GAAP financial results. Investors are encouraged to review the reconciliation of these non-GAAP financial measures to the comparable GAAP results, which can be found in the press release, which is posted on the Investors section of our website.

As a reminder, this call is being recorded and will be available on the Investors section of our website in the Calendar of Events or Presentations subsections.

I will now turn the call over to Dave Lamp for opening remarks.

David L. Lamp

Thanks, Paul, and thank you for joining us today. I'd like to begin the call with our operating performance for the quarter. Dave Bonczek will further provide further details on our financial results for the quarter, as well as provide guidance for the third quarter, after which we will take questions.

This morning, we reported our second quarter '14 results and declared our quarterly distribution of $0.53 per unit. Dave will discuss our distribution later. Our operating performance for the second quarter was solid. The St. Paul refining -- St. Paul refinery ran safely and reliable at expected throughput levels.

Our second quarter '14 adjusted EBITDA was $82 million, compared to $91 million for the same period of 2013 and $103 million for the first quarter of 2014. This decrease in adjusted EBITDA from second quarter of '14 to second quarter of '13 was a result of lower refined product margins, partially offset by an increase in our throughput.

The benchmark crack we utilized is the 6:3:2:1 group spread to WTI. This benchmark crack was down some 40%, from $19.07 into $11.50 in the second quarter of '14, compared to second quarter '13.

Refining gross product margin per barrel of throughput averaged just over $15 for the quarter, compared to $25 for the same period in 2013, and $18 for the first quarter of '14. We recognized higher gross margin per barrel, when compared to the benchmark crack, primarily due to discounted crude we processed in our integrated retail market.

Spot crude differentials tightened towards the end of the first quarter. And given the transit lag in the crude rerun, we saw these tightened differentials impact our gross margin in Q2.

We ran 100% light slate for the month of May, as a result of maintenance activities, which occurred on the Minnesota Pipeline during that period. This reduced our quarterly average crude differential by approximately $1 per barrel. For July, the 6:3:2:1 benchmark is down from the second quarter. However, our crude differentials have widened versus second quarter.

Total throughput averaged approximately 93,000 barrels a day for the quarter, compared to approximately 55,000 days -- 55,000 barrels per day for the second quarter of '13. Second quarter of '13 was impacted by a major turnaround and expansion activities. These expansion activities resulted in higher throughput capacity during the second quarter of '14, and also increased our distillate yield by approximately 3 percentage points during this period.

Refinery operating expenses per barrel of throughput, excluding turnaround expenses, were $4.17 for the quarter, compared to $6.52 the second quarter of '13. These lower per barrel costs were primarily due to our higher throughput. Maintenance spending during the second quarter came in favorable to our estimates, and our variable cost, including electricity purchase, natural gas and other variable costs, were lower than expected.

Turning to our retail segment. Operating income was $5 million for the quarter, seasonally higher compared to the first quarter of $3 million. Fuel margins for the quarter were $0.19 per gallon. The number of company-owned stores increased from 163 to 164, Q2 '13 over Q2 '14. The number of franchise stores we supported grew by 8 over -- during the same period. We continued to work -- working on growing this, our retail footprint.

With that, I'll turn it over to David Bonczek for a further discussion of our quarterly financial results.

David Bonczek

Thanks, Dave. On a GAAP basis, we reported net income of $57.9 million for the quarter, compared to $63.9 million for Q2 '13. Excluding reorganization-related costs, adjusted net income, which is a non-GAAP measure, for Q2 '14 was $61.4 million, compared to $64.4 million for the same period last year.

Cash from operations totaled $154 million for the 6 months ended June 30, 2014, compared to $124 million for the comparable period of '13. We benefited from lower working capital requirements in the first half of '14, compared to the prior-year period, due in part to lower cash requirements for realized crack spread derivative losses in 2013. We currently have no crack spread derivatives in place.

As you can see on to Slide 2, we continue to maintain ample liquidity along with minimal leverage. We had approximately $107 million in cash on hand and total liquidity of $351 million as of June 30, 2014. Our leverage ratio, as measured by total debt to LTM-adjusted EBITDA, is 0.9x. Total debt has not changed, compared to December '13. Turning to Slide 4. Starting with adjusted EBITDA of $82 million, then deducting requirements for cash interest, maintenance CapEx and other items, cash available for distributed amounted to approximately $49 million for this quarter, which equates to a $0.53 distribution per common unit. Also, we set aside reserves for turnaround activities of $7.5 million. We expect quarterly turnaround reserves to approximate this amount in future quarters, based upon our forecasted costs for our 5- to 6-year turnaround cycle.

We also reserve $7.5 million related to discretionary capital projects this quarter. As we replenish the cash used for discretionary spending in 2013, we are also evaluating additional discretionary growth projects to undertake over the next few years, which Dave will discuss in his closing comments. To fund these growth projects, we currently expect to continue our quarterly discretionary capital cash reserve at approximately $5 million on a prospective basis.

As we've said in the past, we're a variable rate MLP and quarterly distributions will vary, as a direct result of variations in certain factors including, among others, changes in throughput, refined products, crude oil and other feedstock prices, capital expenditures and other cash reserves as deemed necessary and appropriate by our general partner's board. Unlike most publicly traded partnerships, we do not have a minimum quarterly distribution.

You can find our updated guidance for Q3 '14 on Slide 5. For the refining segment, we project a total throughput of between 90,000 and 95,000 barrels per day at St. Paul Park refinery. This throughput range reflects a switch to a light crude slate during late September, as we prepare for routine catalyst replacement and related turnaround maintenance activities on our gas oil hydrotreater in Q4.

I'll now turn it back to Dave Lamp for closing remarks.

David L. Lamp

Thanks, Dave. As I stated, our operations ran safely and reliably for the quarter at expected production levels. While our crude differentials narrowed in the first quarter, our location advantage still enabled favorable margin, when compared to our benchmark crack. Despite the weaker margin environment in July, we experienced some margin improvement month-to-date in August. In addition, we're currently realizing the benefits from our successful expansion projects in 2013.

We are also evaluating several organic projects. If completed, these products should help protect and grow favorable returns for our unit shareholders. These projects include: one, replacing certain components in our crude units and expanding our kerosene hydrotreater and distillate hydrotreater to further increase distillate yields; two, adding 2 new desalters to increase our crude optionality; three, relocating an existing solvent deasphalter to increase SEC utilization, while reducing our asphalt yield; and four, continuing to expand our retail footprint with the construction of new stores.

With that, I'll take -- we will take questions now.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Ed Westlake.

Edward Westlake - Crédit Suisse AG, Research Division

Just sort of a bigger picture question. Any progress on swapping your logistics assets and your potential retail assets with WNR, the parent, to NTE LP [ph]?

David L. Lamp

Ed, not -- no progress to really report on today. I think we like our integrated model at NTI, and we're evaluating the brand and the brand's strength and what we might be able to do with it. But nothing to report today.

Edward Westlake - Crédit Suisse AG, Research Division

Okay. And then, I mean, those -- all of those are organic projects, make a lot of sense to me at least. Any sort of idea of the type of EBITDA uplift, if you added them together, and the CapEx costs for the total program?

David L. Lamp

We are still developing the...

Edward Westlake - Crédit Suisse AG, Research Division

Including marketing, yes.

David L. Lamp

Yes, we're still evaluating some of these projects, but we expect the capital for all the above to be less than $100 million, and the return to be in the 30% range or better. On the retail, the retailer is, as you know, is probably, is really not capital-intensive as we leaseback most of the properties. And we expect that to grow at 5 to 6 stores a year. On our franchise size, we expect to grow that, probably, 10 to 15 a year.

Edward Westlake - Crédit Suisse AG, Research Division

And then on the -- I mean, with at least some of the prices that I look at, some of the -- I guess, the discounts for product pricing up in the North seem to be a bit wider this year than last year, I may be incorrect. So maybe just some color on how sort of gasoline, in particular, is trading relative to, say, some of the benchmarks further South?

David L. Lamp

We did see, in the second quarter, some bases that were extremely high. I'd say probably the record numbers that I've ever seen, $0.25, $0.22. They have since come in to more like $0.17, that's on gasoline. On diesel, typically, we do quite well there in that market, and that basis is much more towards the Gulf Coast type number.

Edward Westlake - Crédit Suisse AG, Research Division

And presumably, those -- that basis should stay pretty wide in fourth quarter, you think, as demand seasonally drops? I mean, is this the new normal or do you think this is -- the things that could change?

David L. Lamp

Well, there's some activity in the group that has changed a little bit of that. Some refiners have gone down, and I think that's largely the response you've seen to the basis. That won't last forever. So I would expect it to be wide as most of the barrel is trying to clear for exports.

Operator

Your next question comes from the line of Paul Cheng from Barclays.

Paul Y. Cheng - Barclays Capital, Research Division

Dave, I think that you guys have -- maybe had mentioned it, but I didn't catch it. Do you think that the crude differential is better in the third quarter, comparing to the second quarter?

David L. Lamp

Yes. The -- almost all crude differential Syn, as well as the Bakken, as well as WCS has widened in the third quarter.

Paul Y. Cheng - Barclays Capital, Research Division

Right. Is there any number that you can share? I mean, by now you're probably have locked in more than 2 months off in your crude purchase?

David L. Lamp

We don't really -- I mean, we're always in the rear, so it takes 2 months' lag, typically. So -- I mean, we'll expect it to improve over the -- third quarter over the second quarter. But I don't have numbers for you, Paul, on absolutes.

Paul Y. Cheng - Barclays Capital, Research Division

And you mentioned earlier that your third quarter crude slate is lighter than usual because in preparation of the hydrotreater fourth quarter turnaround. So should we assume that third and fourth quarter that crude slate will be similar to the current -- what you suggested in the third quarter, but then going forward, will be returning back to more normal, like 20% up WCF, 20% Syncrude, and 60% Bakken kind of rate?

David L. Lamp

Yes. The short answer is, yes. The unit we're having to turnaround on is the gas oil hydrotreater, which, as you know, makes sulfur on gasoline. So we will go to a light slate to minimize the effect of heavy crude or sour crude on that -- on the sulfur balance. But that's just -- most of that turnaround was in the fourth quarter, only starts in the third quarter, but the slate will tighten up during that. So I expect less than $1 impact on that.

David Bonczek

It's just the last 10 days that we're really lightning up, and we do give some specific guidance on the slate in the earnings slide.

Paul Y. Cheng - Barclays Capital, Research Division

So that means that fourth quarter, the slate will be even lighter than the third?

David L. Lamp

I would expect it to be, yes.

Paul Y. Cheng - Barclays Capital, Research Division

Okay. And I think that there's been discussion talking about you dropping down the -- or selling the logistic asset down to WNRL. And of course, before you can do that, you need to have their financial statements set up for those logistics asset. I think, previously, talking about it would you take maybe until the early of next year, say, in the first quarter. Is that still a reasonable timeline? Or do you think it will later than that?

David L. Lamp

Yes, I think it is, Paul. We're actively working on it now. And I think, we -- it's reasonable to believe by the end of year, we'll have that broken out. I do think on an -- on any kind of drop down, it's somewhat contingent on having -- us having a use for the proceeds from it and are actively working that. Of course, the project I outlined, we pretty much can finance out of what we're basically holding back from distributions just on the regular basis, just for organic growth. So a lot of -- any dropdown or any further dropdowns would depend on the use of the cash.

Paul Y. Cheng - Barclays Capital, Research Division

Okay. So that actually is my second part of the question. That in the event if you do decide to drop down, will the cash -- the cash flow usage there will you just distribute totally to the shareholder -- to the unit holder? And also, that whether it's going to trigger any cash tax payment to the government?

David Bonczek

Well, our covenants do require us to replace any assets that we divest. So we would need to utilize those proceeds, as Dave said, to replace those assets. Otherwise, pay down debt within 1 year's time. So...

Paul Y. Cheng - Barclays Capital, Research Division

I see. And then the final one, what is the market value of your inventory in excess of book at this point, or as of the end of the second quarter?

David Bonczek

From a current cost standpoint, our inventory -- our LIFO reserve is about $5 million, so that gets you to current cost. But you're saying true market value to liquidate that the inventory, it would be about $30 million.

Operator

Your next question comes from the line of Mohit Bhardwaj.

Mohit Bhardwaj - Citigroup Inc, Research Division

Dave, if you could just expand on what you just talked about. So as far as the covenant goes, if you drop down any assets, it just -- your total debt repayment gets triggered. It doesn't matter whether they're logistic assets or refining assets, it's just any asset that you get move away from NTI or a covenant triggered a debt paydown, is that how it works?

David Bonczek

Well, there is a requirement within 1 year to -- I think, within 1 year to replace those assets. Otherwise, it would trigger a debt paydown. Now, some of these projects that Dave was discussing, would likely qualify as assets that would provide incremental EBITDA. So therefore, could we suspend the discretionary cash reserve as necessary, or could there be other opportunities out there for us to add more assets.

Mohit Bhardwaj - Citigroup Inc, Research Division

Right. And Dave, just from a strategy point of view, what are you looking at in terms of where, outside organic growth projects that you have -- that you've highlighted here, are there any other options either on the logistic side or on the refining side that are available right now or you are looking at, which you could share with us right now?

David L. Lamp

Well, I think we've previously talked about the crude gathering side of the business and first purchase, we continue to grow on that piece. We believe we have a strong position in North Dakota, around the Bakken assets, and have a trucking operation there that we plan to continue to grow. We're purchasing roughly 60,000 barrels a day of that type of crude. We believe there's a probably crude -- quality arbitrage there that we can capture, if we can develop the assets to harvest that. So that's another big area we're looking at. I think, the other one strategically for us is that a single refinery asset gets penalized in the market. We're actively looking and will -- and think we have a pretty good offering to make to -- for an acquisition of some sort to solve that problem. Time will tell on that. But with the tax-advantaged structure we have, we believe that, that is something that we can make an offering to the market that will be attractive. But those are two -- other than the organic growth, those are the other two areas I'd mention.

Mohit Bhardwaj - Citigroup Inc, Research Division

And when you think about other defining assets under NTI, how do the conversations go with WNR in terms of what they could do with their own refining assets? Or your thought process was independent of making that call in terms of your NTI assets -- or sorry, WNR assets getting into NTI, versus you going out and acquiring other refining assets?

David L. Lamp

Well, I don't think anything is out of the question from WNR's standpoint or from an NTI standpoint. So we'll look at it from a holistic view of the market, and make the best position for our unitholders.

Mohit Bhardwaj - Citigroup Inc, Research Division

Right. And if I can just ask one final one. So if you look at the whole Group 3 product basis dynamics that you highlighted before. A lot of the refiners in the U.S., starting from Gulf Coast to the Mid-Continent, they have been running very hard. And the product basis has been negative. So if the Group 3 refiners down in Kansas, in that region have been able to diversify where they're placing their products, and sort of make sure that you're not really getting hit by the product basis. What are the opportunities for you guys? Just because you're right upon the north [ph], so if the basis goes negative, your margin capture really declines. Is there anything that you could do to just negate the fact of this whole basis going negative?

David L. Lamp

Well, I think our big strategy, and part of it is growing our retail footprint, is around that very issue. The integrated model we have negates that some degree, although not completely. But any barrel we have to move via wholesale is subject to that complete basis exposure. As far as other alternative for the barrel, it's kind of difficult because you're kind of at the end of the system. But I think Magellan continues to look for alternatives to clear barrels out of the group, and that doesn't do anything but benefit us.

Operator

[Operator Instructions] Your next question comes from the line of Jason Smith of Bank of America.

Jason Smith - BofA Merrill Lynch, Research Division

Dave, if I can maybe come back to the organic projects and specifically the crude optionality project. Could you maybe get a little more specific on that, in terms of what exactly you guys look to do? Would look to make the slate heavier or lighter? What exactly are you looking at there?

David L. Lamp

Well, the way I'd answer that, Jason, is that we'll chase the margin wherever it is. And that's what I mean by optionality. So today, we're kind of locked into running a certain volume of synthetic, which if you look at our kind of our pecking order of crudes, it's -- the most profitable is the heavy Canadian, the next is North Dakota Light, and the last is the Synthetics. So you can see our incentive is -- and that varies with season, all kinds of different dislocations that occur. But in general, that's kind of the pecking order. And so by replacing these desalters which are fairly -- we've fairly well outgrown over the years, we basically get that -- we get to the point where we can back out Syn when we want to and replace it with either light or, to some degree, some heavy. We'll still be constrained on heavy by total asphalt output. But other than that, we're just going to gain that flexibility to back out Syn. It also give us a little bit of -- by having -- getting rid of these constraints just gives us ability to not have to worry about salting in the crude towers, and that allows us to reduce the overhead temperatures in the crude units to allow us to make more diesel also. So it's kind of a mixed incentive here.

Jason Smith - BofA Merrill Lynch, Research Division

And I think you guys are capped around 30,000 a day on heavy Canadian today, so you should be able to take that higher if you go forward with this.

David L. Lamp

I'd say 30,000 is our weight out balance, just because of the asphalt outlook. But today, we typically run between 25,000 and 28,000. So your number is pretty close.

Jason Smith - BofA Merrill Lynch, Research Division

And then -- so on the product side, just the gasoline yield in the quarter looked pretty high, relative to what it's been historically, and I know you guys ran more light crude than normal. Was it just a function of that or was there anything else that was driving that? And how should we think about that playing out over the rest of the year, as your crude slate gets a little lighter as well?

David L. Lamp

There were 2 factors on that: one was the light crude slate; the other factor was we had the hydrogen plant down for about half the quarter. So that's back up and now we're aggressively doing it and filling up the kerosene hydrotreater and distillate hydrotreater to their max.

Operator

Your next question comes from the line of Jeff Dietert from Simmons.

Jeffrey A. Dietert - Simmons & Company International, Research Division

Jeff Dietert from Simmons. Dave, I think I'll be curious what your expectations are for Line 9 Reversal timing. You talked about Syncrude being one of your least crude -- profitable crudes, and Line 9 should increase demand for that crude. So what are your thoughts there, and does that timing matchup was shifting away from Syncrude towards North Dakota light?

David L. Lamp

Well, I think it's a factor that just make Syns more expensive. So it just tells me this is the right move to make, ultimately. Syn goes all over the place, as you well know. I mean, it can come in and out of the money. And just takes one upgrader going down, and the price -- or starting back up and flips completely. So I don't -- I think Line 9 takes some of that away, to some degree, but it's still going to be there.

Jeffrey A. Dietert - Simmons & Company International, Research Division

And Line 9 kind of end of the year timing?

David L. Lamp

Yes, we're looking at these desalters, we're probably -- it will be before the end of '16 -- or really end of '15, excuse me. We have them on order already. So it's a question of when we exactly tie them in, so I think the timing matches up pretty closely.

Operator

Ladies and gentlemen, that concludes question-and-answer session. I will now turn the conference back to Dave Lamp for closing remarks.

David L. Lamp

We'd like to close by thanking our NTI and SuperAmerica employees for all their hard work and continued commitment to safe, reliable operations. Thank you for participating in today's call, and we'll see you next quarter.

Operator

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect, and have a great day.

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