Calumet, Inc. (CLMT) Q4 2014 Earnings Report, Transcript and Summary

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 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 for crude oil declined from well over $100 to less than $50, between the end of July and year-end prices on select specialty products are slow to follow through, contributing to an expansion in gross profit margins, that were well above the historical norms. If there was ever any doubt that Calumet is key beneficiary of falling crude oil prices, excuse me, 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, white oils 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 products of [indiscernible] fuels products, Shreveport, Montana, Superior and 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 per 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 refiner in Wisconsin and access to cost advantaged feedstock. Down south San Antonio has really started to see improved economics on the fuels that sells locally, while also benefiting from lower crude oil transportation cost [following] [ph] a $0.03 connection to the TexStar System which feeds Eagle Ford crude oil direct to – 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 fourth quarter and 1.0 times on a trailing 12 month basis through December 31, 2014. Having [indiscernible] above one times coverage on the trailing 12 month basis, is great news for us, as it removes one of the principle criticisms of Calumet's detractors. Looking ahead, we continue to target coverage in that 1.2 times to 1.5 times range. On an as reported basis our leverage ratio improved significantly on a trailing 12 months basis. We continue to target a long-term debt to trailing 12 months adjusted EBITDA ratio below four times and continue to make solid progress towards that goal during the first quarter. As I mentioned earlier we are 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 at elevated rates during the second half of 2014, as the targeted investments and plant maintenance conducted in 2013 and early 2014 facilitated improved performance of 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 maintenances [on major] [ph] turnaround and growth spending to be well below historical levels. Turning now to Slide 5. The year-over-year variance in 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 were partially offset by higher cash interest expense. Our distribution coverage ratio will exceeded one 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 specially products gross profit per barrel was partially offset by lower fuel products margins, which were impacted by narrowing crude oil discounts and product crack spreads in the fourth quarter, when compared to the prior year period. During the first quarter, wax, white oils and petrolatums margins remained very strong. We’ve recently enjoyed increased market penetration in [southern] [ph] market with higher lighter fluid and aluminum rolling oil sales, while [indiscernible] margins remain 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 short 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 product 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 that oil field services, a new reporting segment for us beginning in the fourth quarter, generated nearly $10 million of adjusted EBITDA during what was 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 – 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, accommodation 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 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 costs 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 adjusted – annual adjusted EBITDA contribution to the joint venture from this project is estimated to be between $60 million to $70 million subject to market condition. Both the project cost and EBITDA contribution are to be split equally between the joint venture partners. For modeling purposes, we would expect to deliver cost of crude oil into Dakota Prairie several dollars 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’d do expect to do see several dollars per barrel better than this discount the WTI on a deliver 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 along side during the construction process. The project which is design to more than double production at our Louisiana, Missouri Esters plant will increase capacity from ₤35 million 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 cost through the plant expansion is approximately $40 million to $45 million. Well, the total estimated annual EBITDA contribution for this project is estimated between $8 million and $12 million subject to market condition. We estimate a rate of return on this project to nearly 25%. Our San Antonio refinery solvents project is making good progress. Recall that with this project, we are taking 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 schedule for completion in the second quarter of 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 cost. The total estimated annual EBITDA contribution from this project is estimated to be approximately $20 million or rate of return of approximately 30%, still at 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. On 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 towards replacing incremental asphalt and diesel for 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 spread. 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 emerging realization perspective. We continue to capture strong margins on many of our special products, given the drop in crude oil prices and an increased penetration of the wax and solvents markets of new customer additions recent month. Overall, the first quarter shaping up well with no plan 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 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 Steelworkers strike that 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 into a lesser degree turn around 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 with 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 to 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 2014. 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 have reduced our total inventory levels by approximately 970,000 barrels or approximately 16% as of December 31, 2014, as compared to 6months 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 the notional amount of $200 million. And the settlement of this swap we received approximately $10 million. Now turning to Slide 13, at the end of the fourth quarter 2014 our total debt to LTM EBITDA improved 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, 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 four 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 selected 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 refine product in excess of the floating value of a barrel WTI crude oil, on a fixed volume of anticipated fuels production. In the case of the percentage hedge as the value of WTI increases, so too the absolute dollar value of the gross profit realized under the hedge. Using fixed 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 a 133.5% of WTI. We’ve also hedged 2.7 million barrels of anticipated 2016 diesel production at a 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 turn around 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 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.