Calumet Specialty Products Partners Management Discusses Q3 2013 Results - Earnings Call Transcript

Nov. 6.13 | About: Calumet Specialty (CLMT)

Calumet Specialty Products Partners, L.P. (NASDAQ:CLMT)

Q3 2013 Earnings Conference Call

November 6, 2013; 01:00 p.m. ET


Jennifer Straumins - President & Chief Operating Officer

Pat Murray - Chief Financial Officer

Noel Ryan - Director of Investor Relations


TJ Schultz - RBC Capital Markets

Anna Kohler - Imperial Capital

Cory Garcia - Raymond James

Theresa Chen - Barclays Capital


Good day ladies and gentlemen and welcome to the third quarter 2013 Calumet Specialty Products Partners L.P earnings conference call. My name is Lisa and I will be your coordinator today.

At this time all participants are in listen-only mode. (Operator Instructions). As a reminder this conference is being recorded for replay purposes.

I would now like to turn the presentation over to your host for today, Mr. Noel Ryan, Director of Investor Relations.

Noel Ryan

Thank you Lisa. Good afternoon and welcome to the Calumet Specialty Products Partners, third quarter 2013 results conference call. Thank you for joining us today.

Leading today’s call is Jennifer Straumins, our President and COO who will provide an update on our business and the opportunities for growth as we look ahead to the remainder of the year and beyond. Next Pat Murray, our Chief Financial Officer will provide detail on our financial performance during the third quarter. 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 in the partnership, its general partner nor our management team 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.

Just 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

And with that, I’d like to hand the call over to Jennifer.

Jennifer Straumins

Thank you Noel and good afternoon to all of you joining us on today’s call. Lets begin by turning our attention to page four of the slide deck for a high level overview of our third quarter results.

We reported a net loss for the third quarter 2013 of $34.8 million versus net income of $42.4 million in the prior year period. Adjusted EBITDA defined under our financing instruments declined to $38.3 million in the third quarter down from a $121.3 in the same quarter of 2012.

Although this was a disappointing quarter from a profitability perspective, many of the headwinds that impacted the third quarter have abated early into the fourth quarter. We remain confident in the long-term potential of our business, as well as our ability to remain a source of consistent distributions for all our Limited Partners.

As we indicated in the press release issued this morning, our third quarter results were adversely impacted by several factors, including a significant year-over-year decline in refined product margins within our fuel and specialties product segment, lower selling prices on lubricating oils and asphalt, which fail to keep pace with a rapid escalation in crude oil prices during the period and a 30-day planned wide turnaround at our 10,000 bpd Great Falls, Montana refinery, during which the refinery did not produce finished products.

Fuel product margins declined significantly during the third quarter of 2013 as reflected in the marked year-over-year decline it the Gulf Cost 211 crack spread. The U.S. refining complex operated at elevated levels during the third quarter, which in turn put downward pressure on gasoline in difficult margins as product inventory levels increased in regional markets.

The 2/1/1 crack spread declined by more than 50% to an average of $16.81 per barrel during the third quarter of 2013, when compared to the same period in 2012. Refining economics on gasoline were particularly impacted as reflected in a 50% year-over-year decline in Gulf Cost gasoline crack during the third quarter.

Fuel prices increased significantly during the third quarter 2013 when compared to the prior year period. NYMEX West Texas Intermediate crude oil per barrel increased on average by nearly 15% to more than $105 per barrel between the third period of 2012 and the same period in 2013. WTI increased nearly $12 a barrel between the beginning of June and the end of July and proceeded to remain elevated for the duration of the third quarter.

The average per barrel price difference between WTI and LLS crude oil narrowed to $4 per barrel during the third quarter versus more than $17 per barrel in the same period of 2012. This escalation in crude prices, coupled with a narrowing in crude oil differentials had a negative impact on our fuel products margins during the period.

In our Specialty Products segment asphalt prices failed to keep phase with the escalation of crude oil prices during the third quarter, resulting in less favorable economics on asphalt, which comprised 13% of our total production in the period. In addition, we saw some pressure on lubricating oil prices that contributed to lower segment gross profit during the quarter versus the same period in 2012.

Although we did raise prices on both Naphthenic and Paraffinic base oils half way through the third quarter, these price increases were not enough to full offset a tougher margin environment for asphalt and lube.

During September we successfully completed a plant wide turnaround at our Great Falls, Montana refinery where we conducted maintenance on the crude units, the FCC and the alkylation units. The turnaround was completed on schedule for a total cost of (inaudible).

During the turnaround Montana did not produce finished products, which further impacted our third quarter gross profit. We have since resumed operations at Montana during early October and are currently enjoying favorable economics at the refinery, given our local access to Bow River, the crude oil that currently sells for $23 a barrel below WTI.

Turning to slide five, despite a challenging quarter we remain confident in the underlying strength of our business, as well as the long-term opportunities ahead of us. We also continue to maintain ample liquidity on our balance sheet, which has allowed us to pay steady cash distribution to our unit holders.

On October 22, 2013 the partnership declared a cash distribution of $0.685 per unit or $2.74 per unit on an annualized basis for the quarter ended September 30, 2013 on all of its outstanding limited partner units. The distribution will be paid on November 14 to unit-holders of record as of the close of business on November 4, 2013. The quarterly distribution represents an increase of 10.5% when compared to the third quarter 2012.

Moving now to slide six. As you can see on this slide, a year-over-year decline in adjusted EBITDA, coupled with higher turnaround costs, replacement CapEx and cash interest expense resulted in lower distributor cash flow during the first nine months of the year when compared to the same period in 2012.

While much of the decline in DCF was related to year-over-year decline in adjusted EBITDA, its important to point out significant replacement CapEx and turnaround costs, but collectively increase more than $80 million during the nine months ended September 30 versus the same period in 2012.

Much of this spending centered on the heavy turnaround schedule we had this year, which included turnarounds in Shreveport, Superior and Montana. Importantly, our unit holders should recognize that this level of spending on turnaround projects is atypically and is expected to be significantly lower in 2014. In fact we do not anticipate a similar level of turnaround spending until 2018.

I summary, while near term distribution coverage has been impacted by the recent volatility in refined product margins and the heavy calendar year maintenance schedule, we will continue to manage the business towards a targeted distribution coverage ratio in the range of 1.2 and 2.5 times on an LTM basis.

Turning now to slide seven. We’ve made some significant progress in several areas of the business since our last conference call. Today we announced a 15-year throughput agreement with TexStar, a privately held company that we will build and operate a crude oil pipeline capable of delivering significant volumes of cost advantage Eagle Ford crude to our San Antonio refinery by year-end 2014.

In October we competed Phase 1 of our blending project at San Antonio refinery, which has allowed us to blend up to 3,000 barrels per day of finished gasoline. Phase 2 will allow us to blend up to 5,000 barrels per day of finished gasoline and will be complete during the first quarter of 2014.

We successfully completed the major turnaround at our Montana refinery and finally we continue to participate in the evaluation of several acquisition opportunities in the fuel specialty products and midstream markets.

Slide eight, vertical integration is a key facet of the Calumet growth story. From a strategic perspective we seek to own and operate refining assets that was in close proximity to local cost advantage for crude oil, as well as to customers to whom we will eventually sell our finished product.

Last quarter we announced the transaction in which we purchased seven crude loading facilities for Murphy Oil in and around markets where we own several refineries. While small in size there was strategic significance to this transaction as it signaled our growing interest in owning and/or leasing crude logistics assets that stand to provide us with a reliable supply of cost advantage feedstock, whether for processing at our centrally located refinery or resell to third parties.

Today we announced a second, more significant, crude logistics transaction that will provide our San Antonio refinery, with a steady supply of Eagle Ford crude oil at greatly reduced transportation economics by year-end 2014.

As indicated in the press release that we issued earlier this morning, Calumet has entered into a 15 year definitive agreement with TexStar Midstream Logistics, under which TexStar will construct, own and operate a 30,000 per day crude oil pipeline system that will supply significant volumes of local crude oil to our San Antonio refinery. At the conclusion of the 15-year term we have the right of first refusal to purchase the line.

Under the agreement TexStar will construct and operate the Karnes North Pipeline System. An 8-inch, 50-mile pipeline that will transport crude oil from Karnes City, Texas, a major center of oil production in the Eagle Ford shale formation to our Calumet's Elmendorf, Texas terminal, a key supply hub for Calumet's San Antonio refinery.

We anticipate that the refinery will receive delivers, at least 10,000 per day crude oil to the Calumet's Elmendorf terminal supply rout once the line comes into service during the fourth quarter of 2014.

Historically we have used truck shipments to feed crude oil into the refinery and once this pipeline comes into service our crude transport costs should be greatly reduced at the San Antonio refinery given the lower cost to transport crude oil via pipe versus by truck.

As we discussed last quarter, we are currently in the process of expanding the capacity of the crude unit at our San Antonio refinery from 14,500 barrels per day to 17,500 barrels per day. We expect this project will reach completion during the first quarter of 2014. While we intent to begin with shipments of 10,000 barrels a day on the TexStar line in late 2014, keep in mind San Antonio will likely pull increased volumes off this line once it comes into service, particularly given the ongoing crude unit expansion.

Although we have chosen not to provide estimated transportation cost savings resulting from the agreement at this early juncture, given the current economics, the savings would result in a significant benefit to San Antonio refinery’s gross profit beginning in 2015. We intent to provide additional updates on this products as we get closer to the expected startup in fourth quarter ’14.

Now lets turn to slides nine and 10. During the third quarter we finalized a series of engineering and feasibility study on several of the organic growth projects we first introduced during our Analyst Day in June.

Based on these studies we anticipate the total cost to compete the Montana refinery expansion, our portion of the North Dakota refinery joint venture, the esters plant expansion, as well as the aforementioned upgrade of the San Antonia refinery to be in the range of $500 million to $550 million.

As indicated on slide nine, we anticipate 20% of the total spend as expected to reside in the 2013 budget; 15% will be applied to the 2014 budget and 30% will be applied to 2015 budget. The Montana crude unit expansion project is currently anticipated to cost approximately $400 million and is scheduled to be completed in the first quarter 2016.

From an adjusted EBITDA contribution perspective, the Montana expansion project is the most significant opportunity for us among the portfolio of projects we have on deck. We are making good progress on the expansion project.

Our North Dakota refinery is currently on schedule and on budget. We continue to expect the new refinery to be complete during the fourth quarter of 2014. Our esters plant expansion project, which previously was expected to be competed by mid-year is now expected to be completed by year-end 2014. As I indicated earlier, our blending project and crude unit expansion product at San Antonio remains largely on schedule with both of these products coming to full completion early in the first quarter of 2014.

Although several of these projects require significant investments from our partnership during the next 24 months, the estimated average payback period on the basket of organic. The project was approximately 2.5 years. In total, we anticipate these projects will generate approximately $200 million of adjusted EBITDA upon completion. So we are talking about more than a 70% potential increase in adjusted EBITDA from our current trailing 12-month levels of 9.30, 2013.

Now I’d like to turn to slide 11. As part of our stated risk mitigation strategy we use derivative instruments to reduce our exposure to price fluctuations in the price of crude oil, refined field products and natural gas.

During the third quarter of 2013 we had a $13.7 million total cash gain on derivative settlements versus the $50.4 million cash loss in the prior year period.

At any given time we may seek to hedger up to 75% of our overall fuel production and of September 30, 2013 we have headed approximately 50 million barrels of production through year end 2016 at an average implied crack spread of approximately $27 per barrel.

And before I turn the call over Pat, I want to make a few comments regarding our general market outlook as we conclude the year look forward into 2014.

Please turn to slide 12. First with regard to crack spreads. During October we seen the Gulf Cost 211 improve versus September levels. Although the gasoline crack has improved marginally it remains well in the low single digits per barrel, hopping to more than offset the weakness in the gas margins, and the strong diesel crack, which averaged more than $22 per barrel in October.

We continue to anticipate some seasonal weakness in product cracks, however with the 211 over $13 per barrel in October, we are certainly in better shape than we were exiting third quarter.

Second with regard to crude oil prices and differentials. WTI is currently priced in the mid-90’s per barrel, nearly 15 below third quarter highs. With regard to crude oil differentials we’ve seen a widening in the price per barely of WCS, Bakken, and Bow River versus WTI during October. WCS traded at a $32 per barley discount to WTI in October versus a $24 per barrel discount in the third quarter.

Bakken Clearbrook traded at a $12 discount to WTI in October versus a $6 barrel discount in the third quarter. As both of these create a key feedstock for the Superior refinery, we hope to see better margins at Superior in the fourth.

At Montana the refinery where we currently run entirely Bow River crude oil, Bow River is trading at a $25 discount to WTI versus the $16 per barrel discount in the third quarter. With this refinery just having completed a major turnaround, this widening in crude differentials to help support a solid performance in Montana during the fourth quarter.

And third with regard to pricing and demand on specialty products, we implemented price increases on both naphthenic and paraffinic base during July and August in response to rapid escalation crude prices. As crude prices have started to decline, our static pricing should help support us in increasing our margins during the fourth quarter. Moreover we expect the lower crude oil should benefit residual product margins, particularly as it relates to asphalt. Overall we’re seeing average demand heading into what is typically a seasonally slower period of the year.

And fourth, with regard to pricing and demand for fuel products. Entering the fourth quarter, demand for gasoline is seasonally soft, while distillate demand is faring better. As an industry U.S. refineries have significantly reduced utilization rates relative to third quarter levels, particularly in PADD II, III and IV. We suspect the slow back to more disciplined run rates, coupled with a fairly active maintenance season, particularly in PADD III should provide near term support to product margins.

And finally with regard to the renewal fuel standards and the impact of RINs on our business. The company’s RIN obligation represents a liability for the purchase of blending credits to satisfy the EPA’s requirement to blend biofuels into the fuel products we produce. In accordance with the EPA’s renewable fuel standard, RINs are assigned to biofuels produced in the U.S. as required by the EPA.

The EPA sets annual quotas for the percentage of biofuels, unless we bough it in the transportation fuels consumed in the United States, and as a producer of motor fuels, we are required to blend biofuels into fuel products we produced at a rate they will meet EPAs annual quota. To the extent we are unable to blend biofuels at that rate, we must purchase RINs in the open market to satisfy the annual requirement.

During the second quarter conference call we provided guidance that compliance with RFS could cause Calumet as much as $20 million to $25 million per quarter during the third and fourth quarters of 2013. This forecast assumed RIN market prices as of June 30 2013. However between the second and third quarters, RIN prices declined dramatically resulting in a significant reduction in the cost of our RIN obligations. Pat will provide more detail on our go-forward events guidance shortly.

Looking ahead, the recent decline in crude oil prices and widening in crude oil differentials and improved refined product margins, all contributed to a solid start to the fourth quarter. Entering 2014 our focus remains on the execution of our multiyear organic growth plan, which has the potential to help drive incremental distribution growth over the long term.

Our balance sheet remains in good share supported by ample liquidity under our revolving credit facility and a sizable cash position. After a challenging third quarter, we are optimistic that we are poised to finish the year on a stronger note and with that I’ll hand the call over to Pat Murray, our CFO.

Pat Murray

Thanks Jennifer. Now lets all turn our attention to slide 14 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 defined under debt instruments declined at $38.3 million in the third quarter 2013 down from $121.3 million in the same quarter of 2012.

As illustrated in the chart on slide 14, the bulk of the year-over-year decline in adjusted EBITDA was due to a decline in gross profit margin, our fuel segment and to a far lesser degree in our specially products segment, although we benefited from a $48 million improvement in hedging activities during the third quarter of 2013 compared to the prior year period.

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

Now turning to slide 15, fuels refining economics are very challenging during the third quarter as Jennifer described. The benchmark Gulf Coast 211 crack spreads averaged $17 per barrel during the three months ended September 30, 2013 compared to $34 per barrel in the same period of last year. The sharp year-over-year decline in the 211-crack spread was driven primarily by a sharp drop in the gasoline crack and to a lesser degree at the diesel crack.

Crude oil price differentials remain volatile throughout the quarter, a factor, which further impacted gross profit in the fuel segment. However as you can see from the bottom diagram, we still enjoyed significant discounts on many of the crude oils and our feedstocks play.

Turning to slide 16, one of the more significant story lines during the third quarter involved the sharp compression in Asphalt margins. To help fully illustrate this point we indexed the average national posted price per barrel of asphalt as provided by Poten & Partners against the average indexed price of per barrel of NYMEX WTI. As crude oil prices increase during the third quarter, asphalt prices remain relatively range bound resulting in compression at the margin.

We currently produce most of our asphalt at our Superior, Shreveport and Montana refineries. With the recent decline in crude oil prices, we expect to see asphalt margins to have less of an impact on our fourth quarter results.

Now turning to slide 17 in comments on RINs. During the second quarter RINs were a major cost to our business, on our last conference call using market prices as of June 30, 2013. We calculated our quarterly RINs liability to be as much as $20 million to $25 million per quarter during the third and fourth quarters of 2013. Fortunately this guidance has proved to be conservative as RIN prices decline significantly from a high of $1.44 per RIN for D6 corn ethanol RIN in July 2013 to nearly $0.28 per gallon in late October.

While this decline in RIN prices has been largely driven by market speculation surrounding the EPA’s pending 2014 blending guidance, the net impact of lower RIN’s prices has been positive for fuel suppliers like Calumet, who traditionally purchased RIN’s in the open market to help comply with their blending obligation as mandated under RFS.

As a result of the recent decline in RIN’s prices, we are discontinuing our prior guidance of $20 million to $25 million of RIN’s expense for the fourth quarter of 2013. Instead we will begin providing investors with our annual projected RINs obligation based upon our anticipated annual fuels production. We believe this approach will better equip investors to measure the financial impact of our outstanding RIN viability given day-to-day fluctuations in RIN prices.

The partnership currently expects its gross estimated RIN obligation, which includes RINs that are required to be secured through either blending or through the purchase of RINs in the open market, to be in the range of $20 million to $25 million RINs for the fourth quarter of 2013. For the full year 2013 the partnership anticipates its estimated RIN obligation to be in the range of 85 million to 95 million RINs.

Now turning to slide 18, distributable cash flow for the third quarter 2013 was negative $16 million compared to $92.6 million in the same period of 2012. We calculate distributable cash flows, adjusted EBITDA, less replacement CapEx, turnaround costs, cash interest expense defined as consolidated interest and expense less non-cash interest expense and income tax expense.

Our third quarter DCF was negatively impacted year-over-year by a decline in gross profit of $96.3 million, an increase of $15.9 million in turnaround costs, primarily related to our planned turnaround at the Montana refinery and higher replacement capital expenditures across this, the refining complex of $9.8 million.

Now turning to slides 19 and 20, exiting the third quarter we remain very well capitalized, while leverage ratios remain at manageable levels. Including both cash and availability under the revolver as of September 30 we had $611 million in available liquidity, up from $387 million at the beginning of the year. We are pleased with the liquidity cushion available to us to help support organic growth, as well as opportunistic acquisitions as they may arise.

And finally turning to slide 21, we project that turnaround, replacement and environmental capital spending will be $124 million in 2013. During the nine months ended September 30, 2013 we had spent approximately $62.9 million, primarily related to scheduled turnaround at three refineries.

We do not expect a similar level of turnaround spending until the next major maintenance cycle in 2018. We intend to provide our full year 2014 capital spending forecasts on our fourth quarter conference call early next year.

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

Question-and-Answer Session


(Operator Instructions). Your first question comes from the line of TJ Schultz with RBC Capital Markets.

TJ Schultz - RBC Capital Markets

Good afternoon. Pat, maybe if we can stay on that last point on liquidity, you will have obviously built quite a bit of liquidity. Is there a level there you want to maintain as you kind of balance funding some of these organic projects and keeping some cushion for acquisitions and at the same time dealing with lower fuel margins this year.

You gave comfort on the distribution given the liquidity picture now, but just trying to understand if there is some level of liquidity that you want to keep to remain comfortable with the distribution.

Pat Murray

Sure. I mean and as we look ahead and certainly as we’re experiencing in the fourth quarter, I think Jennifer outlined the outlook and what we see is a lot of favorable momentum in the fourth quarter.

We’ve announced a lot of capital growth over the next couple of years and we’re relying on this significant liquidity position we have for that, but we also see capital markets being available to us as we need to access them over time, but as we look ahead and look to ’14, we do see ’14 as a source of operating cash flows to help fund not only stability of distributions, but also the growth CapEx that we anticipate and there’s a fair amount of spending that’s coming at us in 2014. But that’s the reason the liquidity is important for all of these items that we’ve identified.

We obviously need to maintain a certain level of liquidity just to continue to fund the working capital needs of the business, but we’re very optimistic about where we sit today, what we think the prospects are for additional sources from operating cash flows in 2014 and then as I said, we do believe that capital markets remain open. That we have a great story to tell and so we see all those as tools that are available to us as we push through in this period of we think exciting organic growth, as well as more favorable overall conditions in the sector.

TJ Schultz - RBC Capital Markets

Okay, fair enough. And then just staying on the specialty product segment, if you could just provide a little bit more granularity on the kind of sequential or year-over-year decline. Kind of what part of that is specific to asphalt and lube oil pricing. I know you had a page in the presentation on asphalt, but just kind of how you see that trending into the fourth quarter and into 2014?

Jennifer Straumins

The majority of the impact of the specialty products segment was driven by the asphalt margins with the BP coker project that they are whiting the Indiana refinery. We believe that they’ve been running a lot of incremental bakken crude, which has created a lot of additional Asphalt in that markets that our Superior refinery Asphalt competes in and we’ve seen our compressed margins. We would like to think that once that coker does come online, that we would see a reduction in Asphalt production in that particular geographic region.

TJ Schultz - RBC Capital Markets

Okay, thanks. Just lastly, the costs on the Montana expansion, correct me if I’m wrong, but I think it’s increased a little bit since the last update. Just any color on kind of what’s driving that and updated timing on that project?

Jennifer Straumins

Sure. When we last gave an update back in June, we were in earlier engineering stages than what we’re in now. Our cost estimates now are about plus or minus 15% versus a plus or minus 30% plus back in June.

TJ Schultz - RBC Capital Markets



Your next question comes from the line of Anna Kohler with Imperial Capital. Please proceed.

Anna Kohler - Imperial Capital

Great. Good afternoon. Just a follow up on that question in regards to the timing. The project is basically being diluted. The start up is being delayed from the third quarter of ’15 into the first quarter. What is that attributable to?

Jennifer Straumins

Just more detailed planning. We were giving estimates before and our team in Montana has done a substantial amount of work over the last four or five months putting together a concrete plan and we hope to beat that timeline, but we want to put out a timeline to the public that we feel like we can certainly hit.

Anna Kohler - Imperial Capital

Great. And then my follow up question is, in regards to the turnaround schedule, as you indicated earlier that the bulk of that now is going to – the next cycle is in 2018. Given the timing of the acquisition you had a very heavy maintenance or heavy turnaround this year. Is there any way that you could time those out better, so that they don’t all hit within the same year?

Jennifer Straumins

We will certainly try and do that. Our Montana and our Superior plants are our two plants that we do the whole refinery turnaround once every five years and just unfortunately they both happen to be on the same five-year cycle. Our specialty plants we bring down once and twice a year to do turnaround activity on different parts of the refinery.

Anna Kohler - Imperial Capital

Great, thank you so much.

Pat Murray

Thank you ma’am.


Your next question comes from the line of Cory Garcia with Raymond James; please proceed.

Cory Garcia - Raymond James

All right, I appreciate the line guys. It definitely seems like you are making some impressive strides at San Antonio and given a bit of a facelift and recognizing that we are still probably a year or so off from the startup of this new project. Any color on the degree of cost-benefit from moving these barrels off of truck onto the TexStar pipe? I mean it’s a serious, meaningful cost benefit? I was hoping you guys can quantify that a little bit better for us.

Jennifer Straumins

We’ll quantify it more in the future. I’m not prepared to quantify it right now.

Cory Garcia - Raymond James

Okay, and shifting focus to sort of the crude by rail initiative down to Shreveport, will you guys provide any color on how many barrels you actually moved down to Shreveport this past quarter, recognizing that the margins were pretty volatile up in the Bakken and then any updated timing on the Superior dock would be appreciated.

Jennifer Straumins

Sure. We don’t disclose how many barrels we’re moving out of Superior. We’re moving barrels out of Superior to both our own internal facility as well as third party and especially the barrels going to the third party, we’re committed to the business strategy and so even though the barrels were not highly profitable during the third quarter we did continue shipping where it made sense, just to maintain the relationship with our customers.

And as far as the dock project goes, we’re continuing to move forward for the permitting process. This is a lengthy permitting process and we are still looking for viable partners in this project.

Cory Garcia - Raymond James

Okay, that’s helpful. I appreciate it.

Jennifer Straumins

Thank you.


(Operator Instructions). Your next question comes from the line of Theresa Chen with Barclays Capital. Please proceed.

Theresa Chen - Barclays Capital

Hi. Would you mind giving some color on the year-on-year volume declines for lubricating oils and solvents, and what do you think needs to happen for these volumes to recover?

Jennifer Straumins

Part of the issue with the volume decline in the lubricating oils and solvents were our crude mix changed out of our Shreveport refinery somewhat and that impacted it. We have changed up our crude fleet there again. What we’re seeing is a lot of the lighted barrels that we’re running have less lube percentage in them and a higher gasoline percentage, so we continue to evaluate crude change based on profitability to the overall company.

The other thing that has impacted our lubricating oil mix is the production quality coming out of our lines, our relationship. They experience similar issues with crude quality that we have in our own refineries and we continue to work together with them to try and find profitable barrels to process.

Theresa Chen - Barclays Capital

Okay. And then on turnarounds, are you still expecting to have a turnaround at the San Antonio refinery this year, and I guess given the $67 million guidance, is that expected to be lower than the previous $10 million guidance?

Jennifer Straumins

We will be doing a crude unit turnaround out of San Antonio refinery at the end of this year.

Theresa Chen - Barclays Capital

Okay. And then finally on RINs, the previous guidance of $65 million to $75 million versus the updated guidance of $85 million to $95 million, is that just a matter of net versus gross?

Noel Ryan

Theresa, this is Noel Ryan. That’s incorrect. We has said $20 million to $25 million a quarter in RIN, potential RIN obligation expense and we discontinued that guidance of $20 million to $25 million a quarter. So what we’re doing now is we’re giving you the annualized RIN obligation in terms of the RINs that have to be purchased or blended and essentially we’re talking about $85 million to $95 million RINs for the full year ’13. So effectively take that number and multiply it by whatever the floating RIN number is on a daily or quarterly basis, depending on how you want to model it out.

Theresa Chen - Barclays Capital

Okay. But previously that number, the annual number was $65 million to $75 million, no?

Jennifer Straumins

No, that’s not correct.

Theresa Chen - Barclays Capital

Okay, thank you.


I would now like to turn the presentation back over to Ms. Jennifer Straumins for closing remarks.

Jennifer Straumins

I’d like to thank everyone for joining us on today’s call. Should you have any questions please contact our Director of Investor Relations, Noel Ryan at 317-328-5660. Thank you.


Ladies and gentlemen, this concludes today’s presentation. You may now disconnect. Have a great day.

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