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’ll 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 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 21E 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 early today. You may now access these slides in the Investor Relations section of our website at calumetspecialty.com. With that, I’d like to hand the call over to Jennifer.

Thank you, Noel. 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 a as reported basis results include six special items: first, a charge related to the lower of cost or 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 derivatives 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 exemptions from compliance with the U.S. Renewable Fuels Standard at our Shreveport, San Antonio refineries for 2013. Our fourth quarter results benefited from a combination of factors including excellent reliability of each of our major specialty clients and fuels refineries. And second elevated specialty product margins, which benefited from a sharp drop in crude oil prices during the fourth quarter. And thirdly, the fuel refining economics in several of our key niche refining markets during what was 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 plan maintenance expenditures were key drivers behind the improvement in DCF. Specialty products segment adjusted EBITDA…

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 of 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 both fuels and specialty product margins and hedging gains. We encourage investors to review the section of our earnings press release found on our website [indiscernible] non-GAAP financial measures and the attached tables for discussion and definitions of the 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. 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 of 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 plan maintenance at regional competitor refineries, as well as a reduction rates for certain competitors impacted by the United…

[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 the big picture win. I guess Jennifer, could you just give us an idea sort 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 are 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’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 is really only one or two other fuels refineries that I think Calumet would like to own in North America.

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

Sure. I think on 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 that being said if the market is 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 just one last one, can you just maybe give us an update on Shreveport, I mean, 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 has been running pretty well. Is that when you think you’ve sort of worked the kinks out of or is it one you're still sort of evaluating strategic opportunities around? Kind of what's the status there?

Shreveport performed very well for Calumet since the turn around in the second quarter of last year. We’ll always continue to evaluate strategic options there. And a lot of those would be upgraded in the product slate and changing out crude slate, we’ve got the pipe – we’ve got some different scenarios that we are 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 oilfield service business, it does look like you guys made some pretty nice market share gains here in the fourth quarter, against the backdrop of what is looking like it sort of 30%-plus decline in activity levels. Would you be able to sort of highlight some of the different areas where Anchor is maybe a little better positioned, whether it's more of your gassy exposure versus liquids and how we should really think about just conceptually the declines over the next call it six 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 the rig count in Bakken fall away, that hasn’t impacted us likely it would some other people in this 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, that makes sense. And I appreciate, sort of 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 I know you guys talked about in terms of bringing those [bottoms] [ph] from Dakota Prairie over to Montana or should we think of anything there as sort of incremental on top of this?

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

Okay, perfect, 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 guys just give us a little bit more color on liquidity, I know you kind of highlighted in your 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 kind of managing liquidity in light of somewhat higher CapEx?

Right, right. But I think it’s important to point out that our CapEx forecast includes fairly ratable capital expenditures over the course of year, we always have multiple options on liquidity, we’ve over time have found various ways to gain efficiency and liquidity whether it’s working capital initiatives. And 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 sort of 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 sort of to stay in business kind of 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 [poet] [ph] if necessary.

Right, that does make sense. I know it’s really, but could you kind of 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 can you kind of give us maybe an order of magnitude 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.

Great, 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 one times over the next three years. So I'm wondering how many quarters, you know, 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 in operational cash flow in 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 – a lot of them are DOT contracts that are let during the spring. So right now we are bidding on 2015 business, so they are really seasonal.

Okay. Sure, and one last question, a kind of 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 some chatter of increased global refining capacity. So given this dynamic market, you know, 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're not generally impacted by large increases in global refining capacity. We run cost advantage feed stocks in some local markets which give us a benefit over Gulf Cost refiners. And as we look at our Specialty Products majority of those spaces again are – we’re market leaders and we've got superior products to our composition, competition, so we're very confident.

Okay, great. That’s it for me, thank you.

Thanks Rich.

And our next question cones form the line of Jason Smith with Bank of America, please proceed.

Hey, good afternoon everyone and congrats on solid results. Jennifer, just wanted to dig into the Montana project a little more and you disclosed the new bow river assumption, where there any other assumptions that you guys changed there?

No, we’re 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. That's the only other change that was made.

So what bow river assumption were you using in the prior estimate?

Prior estimate it’s still the same estimate we're using now. What we've seen as we tracked bow river over the long-term is it trades at percentage WTI and we’ve been about of 76% WTI basis. And so that change that with crude for $105, which is 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 – it’s going to be 6% of that $10 differential. That's really what's driving the dramatic change.

That makes a lot of sense, thanks. And one follow-up, especially and I may have missed this in your prepared but have you seen any impact from new capacity in that market? I know you always see a big impact, positive impact on the margin side. Can you tell us what you're seeing on the actual supply and demand front?

Yes, Chevron's path Google plant came online midyear last year with between 20,000 and 25,000 barrels a day the incremental group the incremental group to paraffinic based oils. And I think also based are just one small part of specialty product segment. So that’s area we’ve seen, it’s been long, and we’re seeing 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 had a couple of questions for you please. With your oil fuel service right down the charter, what is your view? What do you want to do with that division over the next couple of years?

Well, 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 this space and that will be able to pickup 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 kind of through the curve into the refining market price of RINs kind of 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’re going to prepare for it?

And as you know the EPA will be coming out later this summer with guidance for the next several years, more optimistic that there will be rational and what their expectations are, and the – like every other refiner out there we will adapt to whatever is required of us.

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

We 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.

Just as a follow-up back I think it was two summers ago, what was the net exposure you had? The $10 million seems to stick in my mind, was that something that you all had. I mean, $10 million was I think, the shortfall that you had to makeup during that calendar year, does that sound right? A – Bill Anderson: Just on a kind of go-forward basis what we said publically well, 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 dispensations under the Shreveport and San Antonio refineries relative to RVS or RVO 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. This concludes our conference call.