Calumet Inc (CLMT) 2013 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the third-quarter 2013 Calumet Specialty Products Partners LP earnings conference call. My name is Lisa and I will be your coordinator for today. At this time, all participants are in listen-only mode. We will facilitate a question-and-answer session toward the end of this conference. (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.

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 20E 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 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 earlier today. You may now access these slides in the Investor Relations section of our website at CalumetSpecialty.com.

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

Thank you, Noel, and good afternoon to all of you joining us on today's call. Let's begin by turning our attention to page 4 of the slide deck for a high-level overview of our third-quarter results.

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

While 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 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 fuels and specialty products segment, lower selling prices on lubricating oils and asphalts, which failed to keep pace with a rapid escalation in crude oil prices during the period, and a planned 30-day plantwide turnaround at our 10,000 barrel a day 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 a marked year-over-year decline in the Gulf Coast 2/1/1 crack spread. The US refining complex operated at elevated levels during the third quarter, which in turn put downward pressure on gasoline and distillate 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 60% year-over-year decline in Gulf Coast gasoline cracks during the third quarter.

Crude oil prices increased significantly during the third quarter of 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 differentials 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 the 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 pace with the escalation in 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 halfway through the third quarter, these price increases were not enough to fully offset a tougher margin environment for asphalt and lube.

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

During the turnaround, Montana did not produce finished product, 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 it currently sells for $23 a barrel below WTI.

Turning to slide 5, 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 unitholders. 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 unitholders 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 of 2012.

Turning now to slide 6, 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 distributable cash flow during the first 9 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, it is important to point out significant replacement CapEx and turnaround costs that collectively increased more than $80 million during the 9 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 unitholders should recognize that this level of spending on turnaround projects is atypical and is expected to be significantly lower in 2014. In fact, we do not anticipate a similar level of turnaround spending until 2018.

In 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 toward a targeted distribution coverage ratio in the range of 1.2 to 1.5 times on an LTM basis.

Turning now to slide 7, we have 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 will build and operate a crude oil pipeline capable of delivering significant volumes of cost-advantaged Eagle Ford crude to our San Antonio refinery by year-end 2014.

In October, we completed phase 1 of our blending project at San Antonio refinery, which has allowed us to blend up to 3000 barrels per day of finished gasoline. Phase 2 will allow us to blend up to 5000 barrels per day of finished gasoline, and will be complete during the first quarter of 2014.

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

Slide 8. Vertical integration is a key facet of the Calumet growth story. From a strategic perspective, we seek to own and operate refining assets that are within close proximity to local cost-advantaged sources of crude oil, as well as to customers to whom we will eventually sell our finished product.

Last quarter, we announced a transaction in which we purchased seven crude loading facilities from Murphy Oil in and around markets where we own several refineries. While small in size, there was strategic significance to this transaction as it signals our growing interest in owning and/or leasing crude logistics assets that stand to provide us with a reliable supply of cost-advantaged feedstocks, whether for processing at our centrally-located refineries or resale 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 barrel 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 Elmendorf, Texas terminal, a key supply hub that feeds into our San Antonio refinery.

We anticipate that the refinery will receive deliveries of at least 10,000 barrels per day of crude oil through the Karnes-Elmendorf terminal supply route 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 transfer costs should be greatly reduced at the San Antonio refinery, given the lower cost to transfer 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 a day to 17,500 barrels per day. We expect this project will reach completion during the first quarter of 2014. While we intend 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 current economics, the savings would result in a significant benefit to San Antonio refinery's gross profit beginning in 2015. We intend to provide additional updates on this project as we get closer to the expected startup in fourth quarter 2014.

Now let's turn to slides 9 and 10. During the third quarter, we finalized a series of engineering and feasibility studies 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 complete the Montana refinery expansion, our portion of the North Dakota refinery joint venture, the esters plant expansion, as well as the aforementioned upgrades at the San Antonio refinery to be in the range of $500 million to $550 million.

As indicated on slide 9, we anticipate 20% of this total spend is expected to reside in the 2013 budget, 50% will be applied to the 2014 budget, and 30% will be applied to the 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 of 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 construction of the refinery to be completed during the fourth quarter of 2014.

Our esters plant expansion project, which previously was expected to be completed by midyear, is now expected to be completed by year-end 2014. As I indicated earlier, our blending project and crude unit expansion project at San Antonio remains largely on schedule, with both of these projects coming to full completion early in the first quarter of 2014.

Although several of these projects require significant investment from our Partnership during the next 24 months, the estimated average payback period on the basket of organic projects is 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 as of 9/30/2013.

Now I would 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 and the price of crude oil, refined fuel products and natural gas. During the third quarter of 2013, we had a $13.7 million total cash gain on derivative settlement versus a $50.4 million cash loss in the prior-year period.

At any given time, we may seek to hedge up to 75% of our overall fuels production, and as of September 30, 2013, we had hedged approximately 15 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 to Pat, I want to make a few comments regarding our general market outlook as we conclude the year and look forward into 2014. Please turn to slide 12.

First, with regard to crack spreads. During October, we have seen the Gulf Coast 2/1/1 improve versus September levels. Although the gasoline crack has improved marginally, it remains well in the low single digits per barrel. Helping to more than offset the weakness in gas margins is a 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 2/1/1 over $13 per barrel in October, we are certainly in better shape than we were exiting the third quarter.

Second, with regard to crude oil prices and differentials. WTI is currently priced in the mid-$90s per barrel, nearly 15% below third quarter highs. With regard to crude oil differentials, we have seen a widening in the price per barrel of WCS, Bakken, and Bow River versus WTI during October. WCS traded at a $32 per barrel 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 a barrel discount in the third quarter. As both of these crudes are key feedstocks at our Superior refinery, we hope to see better margins at Superior in the fourth quarter.

At Montana, a 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 could 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 oils during July and August in response to rapid escalation in 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 prices should benefit residual product margins, particularly as it relates to asphalt.

Overall, we are 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, US refiners have significantly reduced utilization rates relative to third-quarter levers, particularly in PADD II, III and IV. We suspect this pullback to more disciplined run rates coupled with a fairly active maintenance season, particularly in PADD III, should provide near-term support to product margins.

Then finally, with regard to the renewable fuel standard 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 US, as required by the EPA.

The EPA sets annual quotas for the percentage of biofuels that must be blended into transportation fuels consumed in the United States, and as a producer of motor fuels, we are required to blend biofuels into fuel products we produce at a rate that will meet the EPA's annual quota.

To the extent we are unable to blend biofuels at that rate, we must purchase RINs on the open market to satisfy the annual requirement.

During the second quarter conference call, we provided guidance that compliance with RFS could cost 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 RINs guidance shortly.

Looking ahead, the recent decline in crude oil prices, a widening in crude oil differentials and improved refined product margins have 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 shape, 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 will hand the call over to Pat Murray, our CFO.

Thanks, Jennifer. Now let's 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 as defined under our 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 in our Fuel segment and to a far lesser degree in our Specialty 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 website entitled Non-GAAP Financial Measures and the 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 were very challenging during the third quarter, as Jennifer described. The benchmark Gulf Coast 2/1/1 crack spread averaged $17 per barrel during the three months ended September 30, 2013, compared to $34 per barrel in the same period last year. The sharp year-over-year decline in the 2/1/1 crack spread was driven primarily by a sharp drop in the gasoline crack and to a lesser degree the diesel crack.

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

Turning to slide 16, one of the more significant storylines 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 per barrel of NYMEX WTI.

As crude oil prices increased during the third quarter, asphalt prices remained 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, and 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 declined significantly from a high of $1.44 per RIN for D6 corn ethanol RIN in July 2013 to nearly $0.20 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 RINs prices has been positive for fuels refiners like Calumet, who have traditionally purchased RINs in the open market to help comply with their blending obligation, as mandated under RFS.

As a result of the recent decline in RINs prices, we are discontinuing our prior guidance of $20 million to $25 million of RINs expense for the fourth quarter of 2013, and 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 RINs liability, 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 flow as adjusted EBITDA less replacement CapEx, turnaround costs, cash interest expense -- defined as consolidated interest 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 the refining complex of $9.8 million.

Now turning to slides 19 and 20. Exiting the third quarter, we remained very well capitalized, while leverage ratios remained 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 9 months ended September 30, 2013, we have spent approximately $62.9 million, primarily related to scheduled turnarounds 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 forecast on our fourth-quarter conference call early next year.

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

(Operator Instructions). T.J. Schultz, RBC Capital Markets.

Good afternoon. Pat, maybe if we can stay on that last point on liquidity. You all 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 fuels margins this year? You give 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.

Sure. I mean -- and looking -- as we look ahead and certainly as we are experiencing in the fourth quarter, I think Jennifer outlined for the outlook, and what we see is a lot of favorable momentum in the fourth quarter. We have announced a lot of capital growth over the next couple of years, and we are 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 2014, we do see 2014 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 is a fair amount of spending that is coming at us in 2014.

But that is the reason that liquidity is important, for all of these items that we have 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 are 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 the 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.

Okay, fair enough. And then just staying on the Specialty Products 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.

The majority of the impact to the Specialty Products segment was driven by the asphalt margin. With the BP Coker project at their Whiting, Indiana refinery, we believe that they have been running a lot of incremental Bakken crude, which has created a lot of additional asphalt in that market that our Superior refinery asphalt competes in, and we have seen compressed margins.

We would like to think the once that coker does come online that we would see a reduction in asphalt production in that particular geographic region.

Okay, thanks. Just lastly, the cost on the Montana expansion -- correct me if I am wrong -- but I think it has increased a little bit since the last update. Just any color on kind of what is driving that and updated timing on that project.

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

Thanks.

Ann Kohler, Imperial Capital.

Great, good afternoon. Just a follow-up on that question in regards to the timing. The project is basically being -- the startup is being delayed from the third quarter of 2015 into the first quarter -- what is that attributable to?

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 don't want to -- we want to put out a timeline to the public that we feel like we can certainly hit.

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

We will certainly try and do that. Our Montana and our Superior plants are two plants that we do whole refinery turnarounds once every five years on. And just unfortunately, the 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.

Great. Thank you so much.

Cory Garcia, Raymond James.

All right. I appreciate the line, guys. It definitely seems like you are making some impressive strides at San Antonio, 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? Is it a serious, meaningful cost benefit? I was hoping you guys could quantify that a little bit better for us.

We will quantify it more in the future. I am not prepared to quantify it right now.

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.

Sure. We don't disclose how many barrels we are moving out of Superior. We are moving barrels out of Superior to build our own internal facilities as well as third parties. And especially the barrels going to the third parties, we are committed to the business strategy. And so even though those 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 are continuing to move forward through the permitting process. This is a lengthy permitting process and we are still looking for viable partners in this project.

Okay, that's helpful. I appreciate it.

Thank you.

(Operator Instructions). 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?

Part of the issue is the volume decline in the lubricating oils and solvents. Our crude mix changed out of our Shreveport refinery somewhat and that impacted it. We have changed up our crude slate there again.

What we have seen is a lot of the lighter barrels that were running have less lube percentage in them and a higher gasoline percentage. So we continue to evaluate crude streams 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 Lyondell relationship. They've experienced 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.

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?

We are doing it -- we will be doing a crude unit turnaround at our San Antonio refinery at the end of this year.

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

Theresa, this is Noel Ryan. That is incorrect. We had said $20 million to $25 million a quarter in potential RIN obligation expense. And we discontinued that guidance of $20 million to $25 million a quarter.

So what we are doing now is we are giving you the annualized RIN obligation in terms of the RINs that have to be purchased or blended. And essentially we are talking about $85 million to $95 million RINs for the full year 2013. 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.

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

No, that is not correct.

Okay. Thank you.

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

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.