Calumet Inc (CLMT) 2014 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Calumet Specialty Products Partners LP fourth-quarter and full-year 2014 results conference call. My name is Jasmine, and I will be your operator for today. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes. And I would now like to turn the conference over to your host for today, Mr. Noel Ryan, VP of Investor Relations at Calumet. Please proceed.

Thank you, Jasmine. Good afternoon, and welcome to the Calumet Specialty Products Partners fourth-quarter and full-year 2014 results conference call. We appreciate you all joining us today. Joining our call are Jennifer Straumins, our EVP of Strategy and Development; Pat Murray, our EVP and Chief Financial Officer; and Bill Anderson, our EVP of Sales. At the conclusion of our prepared remarks, we will open the call for questions.

Before we proceed, allow me to remind everyone that during the course of this call, we may provide various forward-looking statements within the meaning of section 21-E of the Securities Exchange Act of 1934. Such statements are based on the beliefs of our Management, as well as assumptions made by them, and in each case, based on the information currently available to them. Although our Management believes that the expectations reflected in such forward-looking statements are reasonable, neither the Partnership, its general partner, nor our Management can provide any assurances that the expectations will prove to be correct.

Please refer to the Partnership's press release that was issued this morning, as well as our latest filings with the Securities and Exchange Commission, for a list of factors that may affect our actual results, and could cause them to differ from our forward-looking statements made on this call. As a reminder, you may download a PDF of the presentation slides that will accompany the remarks made on today's conference call, as indicated in the press release we issued earlier today. You may now access these slides in the Investor Relations section of our website at Calumetspecialty.com. With that, I would like to hand the call over to Jennifer.

Thank you, Noel, and good afternoon to all of you joining us on today's call. Please turn your attention to slide 3 of the slide deck for a high-level overview of our fourth-quarter results. Let me begin by congratulating our employees on an outstanding fourth-quarter performance. Excluding special items, we generated record single-quarter adjusted EBITDA of $136.1 million, versus $51.4 million in the prior-year period. Excluding special items, Calumet reported adjusted net income of $65.5 million, or $0.86 per diluted unit, for the fourth-quarter 2014. On an as-reported basis, results include six special items.

First, a charge related to the lower of cost of market inventory adjustment of $72.8 million. Second, a $31.8 million loss related to the liquidation of last-in/first-out inventory layers. Third, a $16.6 million gain on the early settlement of select 2015 and 2016 crack-spread, derivative contracts. Fourth, a $23.2 million of unrealized derivative losses. Fifth, an $18.2 million gain on sales of RINs related to the Partnership's retroactive exemption from compliance with the US renewable fuels standards at our Shreveport, San Antonio refineries for 2013.

Our fourth-quarter results benefited from a combination of factors, including excellent reliability at each of our major specialty plants and fuels refineries. And second, elevated specialty product margins, which benefited from a sharp drop in crude oil prices during the fourth quarter. And third, decent fuel refining economics in several of our key niche refining markets, during what is generally a seasonally slower period of the year. Excluding special items, distributable cash flow was $97.9 million for the fourth-quarter 2014, versus $8.8 million in the prior-year period. Year-over-year growth in gross profit, and lower planned maintenance expenditures, were key drivers behind the improvement in DCF.

Specialty products, segment-adjusted EBITDA, excluding special items, increased 75% in the fourth quarter, versus the prior-year period of $73.8 million, representing a 54% of total adjusted EBITDA in the period. As the per barrel price of crude oil declined from well over $100 to less than $50, between the end of July and year end, prices on select specialty products were slow to follow suit, contributing to an expansion in gross-profit margins that were well above historical norms. It was -- if there was ever any doubt that Calumet is a key beneficiary of falling crude oil prices, let this quarter be a testament to the fact that we are likely one of the most well-positioned companies in the market to benefit from current commodity price environment.

During the first quarter, we continued to enjoy elevated margins on select specialty products, particularly within the wax, [vitals] and petrolatum markets. Fuel products, segment-adjusted EBITDA, excluding special items, increased from $9.3 million in the fourth-quarter 2013, to $52.6 million in the fourth-quarter 2014, representing a 39% of total adjusted EBITDA in the period. As a system, our four refineries that produce fuel products, Shreveport in Montana, and Superior in San Antonio, operated well during the fourth quarter. Shreveport had a second consecutive quarter of solid reliability, after completing a plant-wide turnaround back in May 2014. Shreveport operated at 38,947 barrels per day in the fourth quarter, versus 30,088 barrels per day in the prior-year period.

Montana continued to operate at peak capacity of 10,000 barrels a day during the fourth quarter, which is typical for this facility. Superior continues to enjoy some of the best fuels refining economics in the entire system, given its niche as the sole refinery in Wisconsin, and access to cost advantage feed-stock. Down south, San Antonio has really started to see improved economics on the fuels it sells locally, while also benefiting from lower crude oil transportation costs, following its recent connection to the TexStar system, which feeds Eagle Ford crude oil direct by pipeline to the refinery.

Turning now to slide 4 in the slide deck, our distribution coverage ratio, excluding special items, was 1.9 times in the fourth quarter, and 1 times on a trailing 12-month basis, through December 31, 2014. Having moved back above 1 times coverage on the trailing 12-month basis is great news for us, as it removes one of the principal criticisms of Calumet's detractors. Looking ahead, we continue to target coverage in that 1.2 to 1.5 times range. On an as-reported basis, our leverage ratio improved significantly, on a trailing 12-month basis. We continue to target on long-term debt to trailing 12-month adjusted EBITDA ratio below 4 times, and continue to make solid progress toward that goal during the first quarter.

As I mentioned earlier, we're very pleased with the much-improved reliability of our fuels refineries. In 2014, production of fuel products increased by more than 10%, when compared to 2013. Our Superior, Montana and San Antonio refineries each ran elevated rates during the second half of 2014, as the targeted investments in plant maintenance conducted in 2013 and early 2014 facilitated improved performances at these facilities. Looking ahead, we anticipate maintenance and turnaround spending at these four fuels refineries will decline significantly until the next turnaround cycle, which begins in 2018. During the 2016 and 2017 timeframe, we currently expect total capital spending, including maintenance and environmental turnaround and gross spending, to be well below historical levels.

Turning now to slide 5, the year-over-year variance and distributable cash flow, excluding special items, was $89 million in the fourth quarter, a year-over-year improvement in gross profit, and a reduction in replacement and environmental capital expenditures and turnaround costs was partially offset by higher cash interest expense. Our distribution coverage ratio well exceeded 1 times in both the third and fourth quarters of 2014, as reflected in the bottom portion of the slide. Importantly, with no major turnarounds at our fuel refineries scheduled in 2015, 2016, or 2017, we would expect distribution coverage to reside closer to our targeted range of 1.2 to 1.5 times during the next three years.

Turning now to slide 6. As you can see from the top chart in the slide, specialty products gross profit per barrel, excluding special items, increased by more than 40% during the fourth-quarter 2014, given a backdrop of rapidly falling crude oil prices. This increase in specialty products, gross profit per barrel was partially offset by lower fuel products margins, which were impacted by narrowing crude oil discounts and product rack spreads in the fourth quarter, when compared to the prior-year period.

During the first quarter, wax, vitals and petrolatums margins remained very strong. We've recently enjoyed increased market penetration in the solvents market, with higher lighter fluid and aluminum rolling oil sales, while ester margins remained very stable, as we come out of a record year in this business. From a base oil perspective, pricing for naphthenics remains considerably stronger than in paraffinics, given capacity in the market. Further, with the sharp drop in crude oil, we have become increasingly bullish on the potential for strong asphalt margins heading into the start of the summer driving season and paving season.

Looking at the bottom chart on slide 6, we see the specialty products, segment-adjusted EBITDA, excluding special items, increased by more than 70% from the prior year, the primary driver for our strong financial performance in the period. We also want to highlight the oil field services, a new reporting segment for us, beginning in the fourth quarter, generating nearly $10 million of adjusted EBITDA during what is a seasonally slower period of the year for this business.

With an expected decline in domestic land, rig activity on the horizon, particularly in the second half of 2015, we expect this business may come under some pressure during the next 12 months. However, recent market-share gains in key shale basins should help offset some of this pressure. Importantly, oil field services is roughly 7% of our overall adjusted EBITDA, excluding special items. So our exposure to this is somewhat -- and to the somewhat volatile market is very limited.

Turning to slide 7. During the next 12 months, Calumet is scheduled to complete all four of its previously announced organic growth projects, a combination of which are expected to provide significant incremental EBITDA upon which to further grow our partnership. With forecasted annualized rates of return of 20% to 30%, expected contributions from these projects represent a significant base of incremental EBITDA upon which to grow our partnership, and our quarterly cash distribution, in the years to come.

Our Dakota Prairie refinery, a 50/50 joint venture with MDU Resources, is in the process of being commissioned. We expect to turn the refinery over to operations during the month of April, and expect to begin selling product during the second quarter of 2015. The estimated total construction cost for the expansion project to the joint venture is expected to be approximately $425 million to $435 million, versus the prior estimate of approximately $400 million.

While the total, annual-adjusted EBITDA contribution to the joint venture from this project is estimated to be between $60 million to $70 million, subject to market conditions. Both the project costs and EBITDA contribution are to be split equally between the joint venture partners. For modeling purposes, we would expect the delivered cost of crude oil into Dakota Prairie is several dollars per barrel below the per-barrel discount to Bakken to WTI, as priced at Clearbrook, given the refinery's proximity to local production centers. On a trailing 12-month basis, the Bakken Clearbrook discount to WTI has been about $6 a barrel, so we would expect to see several dollars per barrel better than this discount to WTI, on a delivered basis.

Our Missouri esters plant expansion is shaping up to be a great success. Our lead contractor, Westcon, has been a great partner to work alongside during the construction process. The project, which is designed to more than double production at our Louisiana, Missouri esters plant, will increase capacity from 35 million pounds per year to an estimated 75 million pounds per year. It's expected to reach completion during the second quarter of 2015. Our R&D and sales team already have customers lined up for portions of our incremental esters production. The current estimated construction costs for the planned expansion is approximately $40 million to $45 million, while the total, estimated annual EBITDA contribution for this project is estimated between $8 million and $12 million, subject to market conditions. And we estimate a rate of return on this project of nearly 25%

Our San Antonio refinery solvents project is making good progress. Recall that with this project, we are taking a portion of the refinery's ultra-low sulphur diesel and jet fuel production, and converting it into up to 3,000 barrels per day of higher margin solvents.

It will meet customers' requirements for low aromatic content. This project, which was initially scheduled for completion in the second-quarter 2015, has been pushed to the fourth quarter of 2015. The estimated total construction cost of the solvents project is approximately $65 million to $75 million, up from prior estimates of approximately $40 million, due primarily to higher labor and material costs. The total, estimated annual EBITDA contribution from this project is estimated to be approximately $20 million, or a rate of return of approximately 30%. Still a very attractive return, even in spite of the higher cost estimate.

And finally, with regard to the Montana expansion, the largest of the four projects, we remain very pleased with the progress we've made in recent months. Weather in the Great Falls area has been great, which has helped us to stay on budget and on schedule. Upon completion, we estimate this project will increase throughput capacity at the refinery from 10,000 barrels a day to approximately 25,000 barrels a day. Our sales teams continue to work toward replacing incremental asphalt and diesel fuel production in regional markets. The total estimated cost of the expansion project remains approximately $400 million, while the total, estimated annual EBITDA contribution for this project is revised to a range between $70 million and $90 million.

For modeling purposes, note that our revised annualized EBITDA estimate assumes a very conservative Bow River crude oil discount to WTI of $10 per barrel, which essentially means the return on the project could improve, if we see differentials expand in any meaningful way. During the trailing 12 months, the Bow River discount to WTI has averaged $17 per barrel, so our assumptions are intentionally conservative, with regard to crude oil spreads. During January and February, fuels refining economics were very strong, supported by a strong distillate crack and a much improved gasoline crack, when compared to fourth-quarter levels.

Further, WTI has moved from backwardation and into contango, which would benefit us from a margin realization perspective. We continue to capture strong margins on many of our specialty products, given the drop in crude oil prices, and an increased penetration of the wax and solvents markets with new customer additions in recent months. Overall, the first quarter is shaping up well, with no planned maintenance at any of the refineries during the period. With that, I'll turn the call over to Pat.

Thank you, Jennifer. Let's all turn our attention to slide 9 for a discussion of adjusted EBITDA. We believe the non-GAAP measure of adjusted EBITDA is an important financial performance measure for the Partnership. Adjusted EBITDA, excluding special items, was $136.1 million for the fourth-quarter 2014, versus $51.4 million in the prior-year period. As indicated in the slide, the primary drivers of the year-over-year increase include an increase in both fuels and specialty products margins and hedging gains.

We encourage investors to review the section of our earnings press release found on our website (technical difficulty) non-GAAP financial measures, and the attached tables for discussion and definitions of EBITDA, adjusted EBITDA, special items, and distributable cash flow financial measures, and reconciliations of these non-GAAP measures to the comparable GAAP measures.

Now turning to slide 10, fuels refining economics experienced some seasonal weakness during the fourth quarter. The benchmark, Gulf Coast 2/1/1 crack spread, averaged $12 per barrel during the fourth-quarter 2014, compared to $16 per barrel in the same period of 2013. The year-over-year decline in the 2/1/1 crack spread was driven by a combination of weakness in both the gasoline and diesel crack during what is generally one of the seasonally slowest periods of the year for this portion of our business.

Crude oil differentials also contracted on a year-over-year basis, as evidenced by more narrow discounts for WCS, Bow River and Bakken during the fourth-quarter 2014, versus the prior-year period. Fortunately, during the first-quarter 2015, refining economics have exhibited signs of marked improvement. With the Gulf Coast 2/1/1 crack spread up above $20 per barrel this week alone, as a combination of increased planned maintenance at regional competitor refineries, as well as a reduction in rates for certain competitors impacted by the United Steel Workers strike, have helped to bolster crack spreads.

Turning to slide 11, as we look to sources and uses of cash between the third and fourth quarters of 2014, the $137 million reduction in working capital was primarily the result of an inventory reduction initiative and lower accounts receivable. This source of funds, coupled with operating cash flow and revolver borrowings, was more than offset by significant investments in the organic growth projects, acquisition costs, distributions, and to a lesser degree, turnaround costs.

Now turning to slide 12. From a total liquidity perspective, our $1 billion ABL revolving credit facility remains our primary vehicle that assists us in funding the ongoing growth of the Partnership. Between cash on the balance sheet and revolver availability, we have approximately $314 million in available liquidity. During the fourth quarter, we sold no units under our $300 million At the Market equity program.

We believe we will continue to have ample liquidity from cash flow from operations, borrowing capacity under our revolving credit facility, and adequate access to capital markets to meet our financial commitments, minimum quarterly distributions to our unit holders, debt service obligations, contingencies and anticipated capital expenditures. As a result of the extreme fluctuations in crude oil prices during the fourth quarter of 2014, and the corresponding impacts on liquidity, as evidenced by a decrease in the revolving-credit, facility borrowing base, from $831.5 million at September 30, 2014, to $579.2 million at December 31, 2014, we've taken a number of steps to help bolster liquidity during the fourth-quarter 2014, and continuing on into the first quarter of 2015.

First, with several of our derivatives positions deeply in the money, our risk management committee approved the settlement of select second-quarter 2015 through calendar year 2016 fixed-priced, crack spread derivative instruments. As a result of the settlement of these derivative assets, we received approximately $45 million during the fourth quarter of 2014, and have received nearly $10 million in the first quarter of 2015.

Second, we have implemented strategies to minimize inventory levels across all of our operations, and we expect to maintain prudent levels of working capital to enhance our liquidity. For example, excluding inventory related to the Anchor and SOS acquisitions, we've reduced our total inventory levels by approximately 970,000 barrels, or approximately 16%, as of December 31, 2014, as compared to six months earlier, June 30, 2014.

Finally, during the first quarter of 2015, we terminated an interest-rate swap, which was designated as a fair value hedge related to our 2022 senior notes, with a notional amount of $200 million. In the settlement of this swap, we've received approximately $10 million.

Now turning to slide 13. At the end of the fourth-quarter 2014, our total debt-to-LTM EBITDA improved to 5.6 times, versus 7.4 times at the end of the second quarter of 2014. Looking ahead, we expect improved operational performance out of our key fuel refineries, as new contributions from the Dakota Prairie refinery, the Missouri esters plant expansion, the San Antonio solvents plant expansion, and recently completed acquisitions, should assist us in making progress in reducing our leverage ratio closer to what our long-term target of 4 times.

Now turning to slide 14. As of February 2015, we have entered into several new derivatives contracts designed to mitigate commodity price risk within our fuel products segment. Historically, our hedging strategy has rested principally on the use of crack spread hedges, which lock in a fixed, gross profit per barrel on a fixed volume of anticipated fuels production. Recently, in addition to the selective use of crack spread hedges, we added a percentage hedging strategy to our traditional fixed, crack spread hedging strategy, which locks in a fixed percentage of gross profit on refined product in excess of the floating value of a barrel of WTI crude oil, on a fixed volume of anticipated fuels production. In the case of a percentage hedge, as the value of WTI increases, so, too, the absolute dollar value of the gross profit realized under the hedge.

Using fixed-price, crack spread hedges, we have locked in 1.6 million barrels of anticipated 2015 gasoline production, at an average gasoline crack of $14.62 per barrel. Using a percentage hedge, we've locked in 1.5 million barrels of anticipated 2015 diesel production, at 133.5% of WTI. We've also hedged 2.7 million barrels of anticipated 2016 diesel production, at 131.7% of WTI. Looking ahead to the 2015 through 2017 timeframe, we look to opportunistically add to our hedging book, much as we have in the past.

And finally, turning to slide 15. As indicated in the press release issued this morning, we are introducing our 2015 capital spending forecast. We currently are forecasting total capital expenditures this year of $285 million to $335 million, approximately $210 million to $245 million of which is allocated towards organic growth projects. The 2015 capital spending plan also includes an estimated $60 million to $70 million in replacement and environmental capital expenditures, and approximately $15 million to $20 million allocated to turnaround costs. Importantly, as the organic growth project campaign winds down during the next 12 months, we anticipate significantly lower capital expenditures, as we transition into the 2016 and 2017 timeframe.

And with that, I'll turn the call over to the operator so that we can begin the Q&A session. Operator?

(Operator Instructions)

And our first question comes from the line of Richard Roberts with Howard Weil. Please proceed.

Good afternoon, folks. Couple for you today. Maybe we can start with a big picture one. I guess, Jennifer, could you give us an idea of how you think about growth heading into 2016, 2017, with the major capital projects being completed? I guess, are there other attractive projects in the portfolio that you're looking at that are of real size? Or is it going to be more acquisition-driven over the next couple of years?

We don't have any other major planned expansion projects at any of our facilities at this point in time. We continue to have those $3 million to $10 million projects that are 50% return type of projects. So we'll -- and we're doing those in the background all the time. We'll continue with that, and we'll return to the M&A space.

And I assume M&A will be more focused on specialties?

Right now, yes. There's really only one or two other fuels refineries that I think Calumet would like to own in North America.

Okay, great. Maybe one on the margins. If you could just give us a sense -- I know there's quite the lag in the specialties pricing versus crude. Just how those prices have caught up here through the first quarter? If there is still, I guess, a bit of catch-up between the two? And then if we think about the potential for crude to start heading up in the back half of the year, is it a better scenario for you, from a pricing standpoint, if crude steadily edges higher, or a big jump? How should we think about that?

Sure. I think our -- and a lot of our specialty products is based not only on crude pricing, but supply and demand. We expect to see pressure on our paraffinics, as we go into -- as we continue into 2015, with increased capacity in the market. Traditionally, rapid increases in crude prices have allowed us to raise prices faster to customers, so that is always what I prefer to see. But we -- that being said, if there -- if the market's long, we won't be able to get those price increases through. Stability is what we value more than anything.

Okay, great. Thanks. And then one last one. Can you maybe give us an update on Shreveport? I know it's an asset that's had some issues in the past, it sounds like, for the past couple of quarters since the turnaround, it's been running pretty well. Is that one you think you've worked the kinks out of? Or is it one you're still evaluating strategic opportunities around? What's the status there?

Shreveport's performed very well for Calumet, since the turnaround in the second quarter of last year. We'll always continue to evaluate strategic options there. And a lot of those would be upgrading the product slate and changing out crude slate. We've got the pipe -- we've got some different scenarios that we're looking at from a crude standpoint there. So we continue to always evaluate options.

Got it. Thanks very much.

Thanks.

And our next question comes from the line of Cory Garcia with Raymond James. Please proceed.

Thanks, and good afternoon, guys. I guess two quick ones out of me. Looking at your oil field service business, it does look like you guys made some pretty nice market share gains here in the fourth quarter, against a backdrop of what is looking like 30%-plus decline in activity levels. Would you be able to highlight some of the different areas where Anchor is maybe a little better positioned? Whether it's more of your gas exposure versus liquids? And how we should really think about, conceptually, the declines over the next, call it, 6 to 12 months?

Yes, Anchor is very strong in the Eagle Ford and in Oklahoma. We don't have a huge presence in Bakken. So as you've seen a lot of rig count in Bakken fall away, that hasn't impacted us like it would some other people in the space. And really, though, we would anticipate to see our rig count continue to trend with the market. We are obviously out there, always doing things to try and gain market share, considering we are one of the smaller players in the space.

Sure, sure. That makes sense. And appreciate -- switching focus -- the updated look on some of the project margin contribution. Curious if the economics you guys are baking into either Montana or your Dakota Prairie projects actually include some of the uplift that I know you guys talked about? In terms of bringing those bottoms from Dakota Prairie over to Montana? Or should we think of anything there as incremental on top of this?

We do have -- in our model, we've got 5,000 barrels a day of ATB out of North Dakota going into Montana.

Okay, perfect. (multiple speakers) No, that's clear. Thank you.

And our next question comes from the line of Sean Sneeden with Oppenheimer. Please proceed.

Hi, thanks for taking the questions. Pat, maybe for you, could you give us a little bit more color on liquidity? I know you highlighted, in the prepared remarks there, on the lower borrowing base, due to the lower value of inventory. But how should we think about that, going forward this year? And managing liquidity, in light of the somewhat higher CapEx?

Right, right. I think it's important to point out that our CapEx forecast includes fairly rateable capital expenditures over the course of the year. We always have multiple options on liquidity. We, over time, have found various ways to gain efficiency and liquidity, whether it's working capital initiatives, other options all around the business. So we do feel like we have multiple options, and multiple levers, we can continue to pull, to make sure that we have ample liquidity to not only service the business, but also complete the capital growth projects campaign, and cover our stay-in-business CapEx that we have each period. So we feel like we're in a decent position.

Obviously, the impacts on the borrowing base, due to lower crude oil prices, are fairly significant. But it's also important to remember that, at lower absolute crude oil prices, really, a lower level of liquidity, frankly, is needed to keep the business, and the stay-in-business stable. So multiple options. We're always investigating them. We laid out a few of them today on the call. We have several others that we can pull, if necessary.

Right. No, that makes sense. I know it's early, but could you give us a general sense of how we should be thinking about 2016 CapEx? Directionally, it sounds like it's going to be down. But could you give us maybe an order of magnitude of how we should think about that, in terms of -- especially in terms of free cash flow generation?

Really, CapEx for 2016 will be primarily maintenance and environmental and turnaround spending, and should look a lot like 2014 did. Our growth CapEx right now is going to be very minimal in 2016.

Right. That's helpful. Thank you very much.

And our next question comes from the line of Richard Verdi with Ladenburg. Please proceed.

Thank you for taking my call. Jennifer, quick question. You had mentioned the expectation for Calumet to see a target coverage ratio of greater than 1 times for the next three years. So I'm wondering, how many quarters would have to pass until the distribution could be lifted?

Our Board meets every quarter to decide what the distribution is going to be for that quarter. Management has been recommending to the Board that we get the majority of those growth projects online and operational, and cash flowing, before we would raise distributions. So that's looking like a late 2015. As with any capital project, the surprises always seem to pop up at the very end. So we want to make sure that we have a really solid feel for what our capital spending is going to be, before we start raising distributions.

Okay. That's helpful. Thank you. And the asphalt business, clearly, it will benefit from lower oil prices. But let's say oil climbs, and just not to a level where it was last summer. I'm assuming contracts eventually are going to be renegotiated. How long do you feel it would take until customers come to Calumet to pressure the Company to deliver, let's call it, more favorable prices on asphalt to them?

Our asphalt business is basically paving grade asphalt. Most contracts are -- lot of them are DOT contracts that are let during the spring. So right now, we are bidding on 2015 business. So those -- they are really seasonal.

Okay, okay. That's fair. And one last question, and a follow-up to the first caller's first inquiry. What's your general outlook for the market, longer term? As we exit 2016, it's starting to look like crude oil production growth could actually be down year-over-year. And there's some chatter of increased global refining capacity. So given this dynamic market, I would just love to hear your general big picture views, and how you're thinking about planning for that type of environment?

Sure. That's one of the nice things about Calumet is, our assets are very well sized and well positioned in the local markets where they do a lot of business. So we don't -- we're not generally impacted by large increases in global refining capacity. We run cost advantage feed stocks, and sell in local markets, which give us a benefit over Gulf Coast refiners. And as we look at our specialty products, the majority of those spaces, again, are -- we're market leaders, and we've got superior products to our competition. So we're very confident.

Okay, great. That's it for me. Thank you.

Thanks, Rich.

And our next question comes from the line of Jason Smith with Bank of America. Please proceed.

Good afternoon, everyone, and congratulations on a solid results. Jennifer, I just wanted to dig into the Montana project a little more. I know you disclosed you new Bow River assumption. But were there any other assumptions that you guys changed there?

There were not. We updated the crack spreads for the gasoline, diesel fuel and asphalt to be what we saw over the last 24-month average, since we've owned the asset. But that was -- that's the only other change that was made.

So what Bow River assumption were you using in the prior estimate?

Prior estimate, we were -- and it's still the same estimate we're using now. What we've seen, as we track Bow River over the long-term is, it trades at a percentage to WTI. And we've been using about a 76% WTI basis. And so that change -- that differ -- and crude is at $105, which was where it was at when we first put the estimate together. That gives you about an $18 differential to WTI for Bow River. And given $50 WTI, that -- 76% of that's a $10 differential. So it's -- that's really what's driving the dramatic change.

That makes a lot of sense. Thanks. And one follow-up. In the specialties business -- and I may have missed this in your prepared remarks -- but have you seen any impact from new capacity in that market? Because I know you -- you've obviously seen a big impact -- positive impact on the margin side. Butt can you maybe tell us what you're seeing on the actual supply and demand front?

Yes, Chevron's Pascagoula plant came online mid last year, with between 20,000 and 25,000 barrels a day of incremental Group II paraffinic base oils. And again, paraffinic base oils are just one small part of our specialty product segment. So -- but that area, we have seen -- it's been long, and we've seen some price reductions.

Okay. Thank you very much.

And our next question comes from the line of Will Hardee with RBC. Please proceed.

Jennifer, I've got a couple of questions for you, please. With the oil field service write-down that you all took, what is your view of what you want to do with that division over the next couple of years?

We're hoping to see, over the next several years, that industry is very fragmented, with a lot of small players. And we're hoping that, with the downturn in crude prices, it's going to rationalize some of the players in the space, and that we'll be able to pick up some good employees, and put some capital in the business, and continue to grow our market share.

Okay, and then my second question is probably more broader based. But a couple of years ago, the EPA, with their ethanol mandates, threw the curve into the refining market, and price of RINs went out of control. I believe that was two summers ago. What is your view, or Management's view, of what the EPA is going to do this year, concerning ethanol? And how you all are going to prepare for it?

As you know, the EPA will be coming out, later this summer, with guidance for the next several years. We're optimistic that they will be rational in what their expectations are. But like every other refiner out there, we'll adapt to whatever is required of us.

Have you pre-funded any of your potential obligations you might have, by purchasing RINs, or anything of that nature?

We've satisfied our 2014 -- what we think 2014 would be. But looking into 2015 and 2016, we've not done anything, as far as that goes.

And then just as a follow-up, back, I think it was two summers ago, what was the net exposure you all had? 10 million seems to stick in my mind. Was that something that you all had -- 10 million was, I think, the shortfall that you had to make up during that calendar year. Does that sound right?

Just on a go-forward basis, what we've said publicly, Will, is that we believe we have the obligation to blend or buy 90 million to 100 million RINs each year. When we got the special dispensation, under the Shreveport and San Antonio refineries, relative to the [RAVS RBO], that took off the table about 38 million RINs. So we haven't given any guidance as to what we would think potential special dispensations might be for 2014 and 2015. However, our guidance, as it stands, is 90 million to 100 million RINs each year.

All right. Thank you.

And there are no further questions at this time.

Thank you all for joining us on today's conference call. Should you have additional questions, please contact Noel Ryan, our VP of Investor Relations, at 317-328-5660. And this concludes our conference call.

Ladies and gentlemen, thank you for your participation. This conference is now over. Thank you, once again, and have a great day.