Calumet Inc (CLMT) 2015 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Calumet Specialty Products Partners LP second quarter 2015 earnings conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time.

(Operator Instructions)

As a reminder, this call is being recorded. I would now like to introduce your host for today's conference, Vice President of Investor Relations, Noel Ryan. Please go ahead, sir.

Thank you, Mallory. Good afternoon, and welcome everyone to the Calumet Specialty Products Partners second quarter 2015 results conference call. We appreciate you joining us today. On today's call are Bill Hatch, our Interim CEO; Pat Murray, EVP and Chief Financial Officer; Bill Anderson, EVP of Sales; and Ed Juno, EVP of Operations. 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 and 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 Management can provide any assurances that the expectations will prove to be correct. Please refer to the Partnership's press release that was issued this morning, as well as our latest filings with the Securities and Exchange Commission, for a list of factors that may affect our actual results and could cause them to differ from our forward-looking statements made on this call.

As a reminder, you may download a PDF of the presentation slides that will accompany the remarks made on today's conference call, as indicated in the press release we issued earlier today. You may now access these slides in the Investor Relations section of our website at calumetspecialty.com. With that, I'd like to introduce Bill Hatch to the call.

Thank you, Noel, and good afternoon to each of you joining us today.

Please turn your attention to slide 3 of the slide deck for a high-level overview of our second quarter 2015 results. We are pleased to report that the Partnership had a very good quarter, as plant utilization, sales volumes and refined product margins increased significantly on a year-over-year basis. We generated adjusted EBITDA of $95 million in the second quarter of 2015, versus $39.3 million in the prior-year period, as gross profit within both specialty products and fuel product segments grew significantly when compared to the second quarter of 2014.

While our oilfield service business has seen its share of challenges along with the rest of the oilfield service sector, following a material decline in domestic land rig counts during the past nine months, our refining operations fired on all cylinders during the second quarter. This resulted in improved trailing-four-quarter distribution coverage of 1.3 times and a lower trailing-12-months leverage ratio of 4.3 times. Excluding the impact of a $13.9 million LCM inventory change in our oilfield services segment, and an $8.3 million loss from unconsolidated affiliates primarily from our Dakota Prairie joint venture, adjusted EBITDA would have been more than $22 million higher than what we're reporting today, illustrating the continued strength of our core businesses.

Specialty products segment adjusted EBITDA increased to $59.1 million in the second quarter of 2015, versus $34.3 million in the second quarter of 2014, a combination of solid operational reliability at our specialty products facilities, coupled with strong demand across most of our major specialty product categories, contributed to the improved year-over-year performance in this segment. Margins on our packaged and synthetic specialty products were particularly strong this quarter, as average prices have remained stable despite a more than 50% decline in feedstock costs during the past 12 months. In addition, demand for our branded products was strong in the period, resulting in record package and synthetic sales of $88.4 million in the second quarter. Margins within our wax business also remained elevated in the second quarter, as wax capacity in the US has grown tighter during the 2015 period, much to the benefit of Calumet, one of the top five wax producers in the United States.

Fuel product segment adjusted EBITDA increased to $50.1 million in the second quarter of 2015, versus a loss of $3.1 million in the second quarter of 2014. As a system, our four refineries have produced fuels products; Shreveport, Montana, Superior and San Antonio, operated well during the second quarter with the total production up nearly 20% when compared to the prior-year period. From a market perspective, fuels demand in the niche geographies in which we serve seasonally strong -- were seasonally strong during the second quarter, which allowed us to better capitalize on elevated fuel crack spreads in the period. Our asphalt business, which is included primarily in our fuels segment, did very well in the first half of 2015, with our average price per barrel well above the per-barrel price of WTI.

Please turn to slide 4. As illustrated in the top chart, production across our specialty and fuel product segments has become increasingly stable during the past four quarters, following the completion of planned maintenance in 2013 and early 2014 time frame. This increased operational reliability has positioned us better to capture demand as illustrated in the bottom chart, which shows a significant year-over-year increase in sales volumes across multiple product categories. Our ability to effectively maintain stable production levels has resulted in us averaging approximately $115 million in adjusted EBITDA per quarter during the most recent four quarters.

Please turn to slide 5. As you can see from the top chart of this slide, specialty products' gross profit per barrel increased more than 35% on a year-over-year basis to $44.22 per barrel, due primarily to the lower cost of materials and increased sales volumes. Our fuel products gross profit per barrel increased significantly to $10.40 per barrel in the second quarter of 2015, up from a loss of $0.45 per barrel in the prior period, giving increased fuels production coupled with a much improved gasoline crack spread. This increase in fuel products' gross profit per barrel was reflected in the year-over-year growth in fuels products' adjusted EBITDA, which increased more than $50 million on a year-over-year basis, even while accounting for the fact that crude oil differentials narrowed significantly in the second quarter of 2015 when compared to the second quarter of 2014. Our oilfield services segment struggled during the second quarter, given weaker demand for drilling muds and related services. However, we believe our ability to further reduce costs within this segment should help to remedy the market-related challenges evident in this segment.

Please turn to slide 6. From a refining perspective, Calumet is one of the chief beneficiaries of the recent pullback in crude oil prices. In the top chart you can see the positive correlation between a decline in crude oil prices and the corresponding lag in the decline in the average selling price per barrel of specialty products, resulting in a net margin expansion within the specialty products segment. With crude oil having declined another $10 a barrel in July, it is reasonable to assume that we should continue to enjoy healthy margins in this segment during the third quarter of 2015.

One specialty product category that has performed exceedingly well amidst the drop in crude oil prices has been our packaged and Synthetic products, which includes branded products such as TruFuel, Royal Purple and Bel-Ray. While these products only represent approximately 7% of total Company sales, they carry some of the highest profit margins in our entire portfolio. In the second quarter, we not only enjoyed increased demand for these products, we also enjoyed elevated margins on the products we sold.

Please turn to slide 7. Clearly, oilfield services is the sector that is out of favor with investors at the moment. Unfortunately, our timing around entering this business was poor. We acquired Anchor and SOS in the months leading up to a significant collapse in crude oil prices. At the time, these businesses were generating approximately adjusted EBITDA of $35 million to $45 million per year in the first half of 2015. In the first half of 2015, this business posted a negative $18.3 million in adjusted EBITDA, which includes a loss of $13.9 million in the LCM inventory charge. With the recent steep decline in the US land rig count, the oilfield services segment, which by far remains our smallest reporting segment, has sharply underperformed our specialty products and fuel products segments, which have put up impressive numbers this year.

In the near term, we have committed to address the market headwinds facing our oil services segment by sharply reducing costs within this business. We have reduced significant headcount within the oilfield services segment beginning in the beginning of 2015, which has served to reduce SG&A expenses. We remain highly focused on further rationalizing costs within the business, given the underperformance of this segment.

Please turn to slide 8. Our multiyear organic growth campaign remains on budget and on time with the forecast we provided in our first quarter of 2015 conference call held in May. The Partnership currently forecasts a total projected cost for the organic growth project's campaign to be approximately $665 million. As of June 30, 2015, we had invested more than $605 million in the organic growth project's campaign. During the next six months, we are slated to complete all three of our remaining organic growth projects. These projects have forecasted annualized rates of return in excess of 20% and stand to provide significant incremental EBITDA growth for the Partnership over time.

Our Great Falls, Montana, refinery expansion, which is the largest of the three remaining growth projects, remain on track. All major critical path items have arrived on site. We currently expect to ramp up production to 25,000 barrels a day beginning early in the first quarter of 2016. We have established multiple marketing relationships with local and regional customers who will buy the fuels and the asphalt being produced at this facility. The total estimated EBITDA contribution from this project is between $70 million and $90 million, subject to market conditions. Estimated annual EBITDA contributions -- contributed stemming from the Montana refinery expansion assumes that per-barrel discount of $10 on Bow River, sourced at the Montana refinery, when compared to WTI.

At our Missouri esters plant, we continue to make steady progress on a project designed to more than double the production capacity of this facility from 35 million pounds per year to an estimated 75 million pounds per year. During the second quarter of 2015, we sold out of esters produced at this plant, so the capacity addition is timely. We anticipate this project to be completed late in the third quarter of 2015. The total estimated annual EBITDA contribution from this project is estimated to be between $8 million and $12 million.

Finally, at our San Antonio refinery, our solvents projects continue to make good progress. In mid-September we will take the plant down for 10 days while we do the final tie-ins related to this project, which will take a portion of our ultra-low sulfur diesel and jet fuel production at San Antonio and convert it into at least 3,000 barrels a day of higher-margin solvents that will meet customer requirements for low aromatic content. This product will be shipped to our customers in the Mid-Continent, as well as some of our South American customers. This project is expected to be completed during the fourth quarter of 2015 with a total estimated annual EBITDA contribution of approximately $20 million.

Please turn to slide 9. Distributable cash flow for the second quarter of 2015 was $73.3 million, up from a loss of $15 million in the prior-year period. This significant year-over-year improvement was primarily driven by higher gross profit in both the specialty products and fuel products segment, and a significant decline in turnaround costs and other factors. As illustrated in the bottom of the chart, our distribution coverage ratio continues to reside within our long-term target range of 1.2 to 1.5 times. In the second quarter of 2015, coverage reached 1.3 times, while on a trailing-12-month basis, coverage is at 1.3 times.

Before I hand the call over to Pat for a few details of our second quarter financial results, allow me to share a few comments on how the third quarter is shaping up through July. In recent weeks, crude oil prices have once again moved lower, representing an opportunity for near-term margin expansion within our specialty fuels product segment which stands to benefit from the lower feedstock costs. Further, fuel refinery economics improved during July due to a further increase in gasoline crack spread, a general widening in crude oil price differentials and favorable economics on asphalt, as compared to the second quarter of 2015. Also as we look to the late third quarter and fourth quarter, we expect increased turnaround activity in some of our competitors within the PADD 2 and 3 markets, which should serve to benefit fuel crack spreads in those regions, even as the industry exits a period of the year historically characterized by seasonal strong demand for fuels.

With that, I'll hand the call over to Pat.

Thank you, Bill. Good afternoon everyone. Thank you for joining us today.

Let's all turn our attention to slide 11 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 was $95 million in the second quarter of 2015, versus $39.3 million in the prior-year period. As indicated ins this slide, a significant year-over-year increase in fuel product segment gross profit was the single most significant factor contributing to the year-over-year growth in adjusted EBITDA when compared to the prior-year period, while lower oilfield services segment contribution increased realized hedging losses serve to partially offset this growth during the 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 discussion and definitions of EBITDA, adjusted EBITDA and distributable cash flow financial measures and reconciliations of these non-GAAP measures to the comparable GAAP measures.

Please turn to slide 12. As indicated in the top portion of this slide, the fuels refining economics as expressed by the 2:1:1 Gulf Coast crack spread, improved both on a quarter-over-quarter and year-over-year basis in the second quarter 2015, driven mainly by strength in the gasoline crack spread, which benefited from strong seasonal demand from motorists during the period. However, as seen in the chart at the bottom of the slide, crude oil price differentials did contract meaningfully on a year-over-year basis as evidenced by more narrow discounts for WCS, Bow River and Bakken crude oils during the second quarter 2015 versus the prior-year period.

As we enter the third quarter, refining economics have exhibited signs of improvement versus the second quarter of 2015. To that end, the Gulf Coast 2:1:1 crack spread averaged $25 per barrel in July, better than the $22 per barrel averaged in the second quarter. Price-per-barrel discounts on WTI versus other crude oil grades processed at our facilities, including Bakken and WCS, both widened substantially in July versus the second quarter average, and, not insignificantly, D6 ethanol RINs prices have declined as compared to the second-quarter average.

Each year the EPA may adjust the volume of renewable fuels mandated to be blended by refiners, given certain circumstances. In May, 2015, the EPA proposed new rules to implement a revised renewable volume obligation, or RVO, for 2014, 2015, and 2016. By revising the RVO, the EPA has sought to balance infrastructure and market realities with Congressional intent to increase the volume of renewable fuels blended into the overall motor fuel pool used each year. Since the EPA's May 2015 announcement, RINs prices have declined resulting in a benefit to Calumet who is a net buyer of RIN credits each year.

For the full year 2015, excluding the potential benefit of small refinery exemptions at one or more of our refineries that might be granted to us by the EPA at a later time, we expect our gross estimated annual RINs 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 90 million to 100 million RINs. We record our outstanding RINs obligation as a balance sheet liability. This liability is marked to market on a quarterly basis to reflect the market price of RINs on the last day of each quarter.

Now turning to slides 13 and 14. In bridging cash during the second quarter, the combination of lower working capital, increased operating cash flow, and borrowings on our revolver was more than offset with the redemption of our 2020 senior notes, capital expenditures and cash distributions to our unit holders. As indicated on slide 14, our combined cash position and availability under our $1 billion revolver, which matures in July 2019, totaled $435 million as of June 30, 2015, up from $320 million on December 31, 2014.

From a total liquidity perspective, our revolving credit facility remains our primary vehicle that assists us in funding the ongoing growth of the Partnership. We believe we will continue to have adequate liquidity from cash from operations, borrowing capacity under our revolving credit facility, and adequate access to capital markets to meet our financial commitments, minimum quarterly distributions to unitholders, debt service obligations, contingencies and anticipated capital expenditures.

Turning to slide 15. At the end of the second quarter 2015, our total debt to LTM EBITDA ratio was 4.3 times, versus 7.4 times at the end of the second quarter of 2014. Looking ahead, we expect solid operational reliability at our key fuel refineries, seasonally robust fuel and specialty products refining margins and contributions from organic growth projects coming online during the next several quarters to support a further reduction in our leverage ratio to at or below our long-term target of 4.0 times.

Now turning to slide 16. We have in place a multiyear hedging program designed to mitigate commodity 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 in this segment. Earlier this year, in addition to the selective use of crack spread hedges, we added a percentage hedging strategy to our traditional fixed crack spread hedging strategy, which locks in a fixed percentage of gross profit on refined products in excess of the floating value of a barrel of WTI crude on a fixed volume of anticipated fuels production.

In the case of a percentage hedge, as the value of WTI increases, so too the absolute dollar value of the gross profit realized under these hedges. Using fixed crack spread hedges, we have locked in 1.4 million barrels of anticipated third quarter 2015 gasoline production at an average gasoline crack spread of $15.81 per barrel. We have also locked in 0.8 million barrels of anticipated fourth quarter 2015 gasoline production at an average gasoline crack spread of $8.05 per barrel.

Further, we have locked in 1.4 million barrels of anticipated diesel production in the second half of 2015 at an average diesel crack spread of $20.42 per barrel. We have also locked in 0.5 million barrels of anticipated diesel production in 2016 at an average diesel crack spread of $19.56 per barrel. Using a percentage hedge, we have locked in 0.1 million barrels of anticipated third and fourth quarter 2015 diesel production at 132.5% of WTI. We have also hedged 2.2 million barrels of anticipated 2016 diesel production at 131.8% of WTI. Looking ahead to the 2015, 2017 time frame, we will look to opportunistically add to our hedging positions much as we have in the past.

Now turning to slide 17. As indicated in the press release issued this morning, we currently forecast total capital expenditures of $320 million to $335 million in 2015, approximately $245 million of which is allocated towards organic growth projects. The 2015 capital spending plan also includes an estimated $60 million to $70 million in replacement and environmental capital expenditures and approximately $15 million to $20 million allocated to turnaround costs. During the six months ended June 30, 2015, consolidated capital expenditures totaled $228 million, including $158 million of which were related to capital improvement expenditures such as the organic growth projects, while capital contributions to joint ventures, including Dakota Prairie and our Juniper GTL investment, totaled $46 million.

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

Thank you.

(Operator Instructions)

Our first question comes from the line of Richard Roberts with Howard Weil. Your line is open. Please go ahead.

Hey, good afternoon, folks. Couple from me today. I guess to start with, so now you've had four quarters in a row here with distribution coverage at or above 1.3 times and pretty good line of sight here into the organic projects coming to completion. So I'm wondering what kind of goal posts you're looking for before you're going to feel comfortable with looking at a distribution increase?

I think that as we mentioned in the press release and as we've mentioned many times on these calls, we're looking for a combination of several factors to come together, at which time we'll feel comfortable recommending restarting the increase in the distribution. We're making great progress. As you note, we've made continued progress in leverage, in distribution coverage. We think those are very important factors to consider as we think about increasing the distribution again. And also, line of sight as to the completion of these very important organic growth projects, with each passing quarter we've gotten much closer to the end of that spending cycle.

So I think over the short term here, we are looking for the continuation of progress in those areas, as well as completion of the organic growth capital campaign. And at that time it will be time to start to think about increasing the distribution again and looking at where current market conditions are. But I think we are -- a lot of the factors that we think about every quarter in making that discrete decision and making that recommendation to our Board of Directors, we have been checking a lot of boxes along the way. So we're certainly making progress to that end. I wouldn't necessarily commit to a specific time line, although, as you note, we've been tracking very well in these important initiatives.

Thanks, Pat, for that. Maybe a strategic question, and maybe it's too soon to talk about 2016 CapEx, but at this point should we be thinking about spending levels next year pretty much in line with your turnaround and replacement environmental spending levels or are there some organic projects maybe you've identified but haven't necessarily announced yet?

This is Bill Hatch. I think what you're asking me is if we have any planned large capital expenditures similar to the organic growth projects that we just went through. And the answer to that is no. I'm sure we will have smaller opportunistic kind of capital projects next year, so we would implement those. But they would be smaller and they would have very quick payouts. That's kind of what our thinking is right now, besides the normal turnaround in environmental projects that we always have with refineries.

And for which we don't anticipate major shifts in those cost levels or projected levels as we look forward. But as we do each, at the beginning of each fiscal year, we'll provide guidance on those levels at that time.

Got it. Maybe just one more. In the press release you mentioned some challenged economics in the local market at Dakota Prairie. Wondered maybe if you could provide a little bit more color there on how the market was challenged in 2Q and how it's shaping up today and your outlook for the rest of the year? Thanks.

This is Bill Hatch. When we first brought the plant up, you could go back and look at the history and the pricing of diesel in that market, it was really tough, very little margin. It has expanded and gotten better over time. Today, diesel prices are $20 to $25 over WTI -- Gulf Coast prices for WTI. I can't really tell you if it's going to go up or any significantly more. We would hope that it would. History says that the diesel price will move higher. We're anticipating that. We're hoping for that.

The other thing that's helping Dakota Prairie out is when we first started the plant up, Bakken crude was almost flat with WTI in that locale and that since has moved down to about $3 to $3.50 under WTI at that locale. That's been a big help. The other thing is the plant is getting some of the startup kinks out of itself and with some of the one-time costs associated with starting up a brand-new plant like that, we're sort of putting in the rear view mirror and hopefully things are going to get better as we go forward.

Got it. Thank you.

Thank you. Our next question comes from the line of Roger Read with Wells Fargo. Your line is now open.

Thank you. And good afternoon. Congrats on the quarter.

Thanks, Roger.

I guess maybe let's -- since you covered so well the major projects coming to an end and maybe following up with the CapEx question on the last call, what looks like the most attractive future growth opportunities? Is it acquisitions within your kind of existing product suite? Something outside of that? Or is there potentially another wave of growth projects we should expect on the somewhat more organic front?

Well, the answer is yes. I mean, we always are looking for acquisitions that complement our business and when those opportunities avail themselves, then we'll certainly take a hard look at them. I can tell you right now, I don't have any specific ones in mind for that. Organic growth projects, there's opportunities there for investment and growth. But again, I don't have one specific project that are the size of the ones that we just finished. There are several that are on our plate that are smaller capital that could look or that do look, actually, very attractive. We've got a lot of engineering to do and a lot more buildout on their potential. But again, we're always looking for opportunities, both internally and externally, because the Board of Directors wants to continue to grow the Company, but we're going to do it in a very measured way.

Sure. Let me ask the question slightly differently. If we look at the large integrated oil companies, a group that has historically shed some of these specialty product lines, they're definitely under pressure, even if they aren't necessarily marketing something, I think they would be approachable at this point. Is that something you're proactively moving on? It's a little too early? Or anything else you can offer along those lines?

We'll let Bill Anderson answer that for you. He hasn't spoken yet.

Sure. This is Bill. We're watching our markets that we participate in. We don't really see a whole lot of opportunities currently. There are some closures of some group one base oil facilities happening later this year in Europe, but we still see some capacity getting placed from Chevron's addition to the market about a year ago. So we're watching these markets, and if we feel like we see somebody that might have some interest in talking to us, we're certainly keeping our eyes open.

Well, maybe they're listening to this call.

Fair enough.

The other question, Bill, you've been wearing the interim tag here. Unless I missed it, there was no particular comment about the CEO search. I was wondering if you could fill us in on the thoughts of where we are maybe with candidates, timing, et cetera.

I really can't. There's just no news that I have regarding that. I'm sure that, that process is still going on, but I don't think they've found just the right person yet. When it happens, then that's fine and good. I'll more than support that. The Board will make that decision. I'm sure I'll get to interview that individual when that person comes along.

But I'm committed to staying here for as long as the Board needs me and desires me to run the Company. So I enjoy it here. It's a great Company, got great people. I like our product. I like our business model. So I'm real enthusiastic about it. So when that day comes, I'll be very supportive of the Board. I'll make sure that there's a seamless transition on my job. But at this point in time, I just don't have any further information about it.

Okay. Great. Thank you.

Thanks, Roger.

The next question comes from the line of John Ragozzino from RBC Capital markets. Your line is now open. Please go ahead.

Good afternoon, gentlemen.

Good afternoon, John.

Bill, first appreciate the enthusiasm for the new role. We talked a little bit about this at the Analyst Day. Could you perhaps give us a little bit more color on some of the internal initiatives and maybe cost savings opportunities that you see when you just think about the near-term ability to streamline the operation?

Calumet, over the last several years, has gone through, as you all know that follow the Company, that many acquisitions. And so with acquisitions comes opportunities to integrate them into your business portfolio and they'll generate, to me, very obvious synergies. Some of them might be just in the area of purchasing where you can use some of your leverage, where you might buy a lot of pipe valves and fittings for your refineries and your plants. If you have 1 national contract versus having 14 different contracts for each individual plant, you can garner and affect some economies of scale for your size. That's the kind of things that we don't have in place now that we will. We're working on those things. Just the minor example.

Our crude acquisition group, we're kind of spread regionally around the country. I think bringing those into one area and one facility and working with the economics and planning kind of [LT] people, I think that's another area that's real obvious to me that I think we can do better on our crude selection, not only in price but in yields and more fitting our kind of facility that we have. That's just a couple examples. There's probably hundreds of them across the Company. That's the kind of things that I'm looking for and trying to implement here right now.

That's helpful. And then keeping in line with the train of thought on the acquisition and integration front, you kind of walked into poor timing when it comes to the oilfield service businesses. In the current market environment, do you think that there's sufficient demand or would you consider monetizing it when you consider what the expected possible monetization value might look like or is it something that you'd probably prefer to wait for a bit of an uptick in the US activity before you would consider divesting that?

Like I said in the call, we're very committed to the oilfield services group Anchor. Sure, we're disappointed with the results and our timing. As I went through in the call, our timing was bad. But, no, we haven't given up on it. I guess that's a roundabout way you're asking me. No, we have not given up on it and we want to see it improve. We're going to go through this difficult period. The people I've talked to in our Anchor business that have been through these kind of up-and-down periods before, they know how to weather the storm. They're good at it. And we have got the Company or at least the Anchor Company in a position to weather it.

And so I'm committed to the folks at Anchor and the team that we have running it and the business itself. So we're going to make it better. We're going to make through this and when it's all over, we'll be a survivor and we'll be glad we are one. So that's the best I can --

Just one last one for me. You guys have provided a clear line of sight towards the ramp at the Montana refinery to the 25,000-barrel-a-day utilization. As the other Bill in the room continues to get after it, so-to-speak, do you see any further upside if he finds a home for additional fuels in the local market to ramp that meaningfully higher? I think I've talked to Noel about the excess capacity at that facility that is underutilized at a 25,000-barrel-a-day level.

You're right, we anticipate that Montana is -- or at least we hope Montana is going to be able to operate at a higher level than we've advertised and we are planning for that in working our crude supply and our products. I don't think the incremental barrel, the incremental production would be in that market, though. I think we're going to have to move it out into other markets. And so that's a challenge that we have facing us right now.

So first thing is we've got to get the plant up -- finish the plant, get it up and running safely and line it all out and then hopefully ramp the production up on that plant to some capacity limit. We're impressed with the Montana facility. It's just got a lot of bells and whistles and the hydrocracker there is just -- for an old refiner like myself, it's like magnificent sight to see it. I'm very excited about it and I'm hopeful that we can squeeze a lot more production out of that plant. The local markets are pretty well full. And so to add incremental barrel beyond what I'm talking about here will end up going somewhere else and we're working on that. And you're right, Mr. Bill Anderson can -- if anybody can get it moved out, he can do that. So I have all the confidence in the world that we'll be able to do that and make some attractive returns on it.

That's all I've got. Congrats on the quarter, guys. Thanks a lot.

Okay.

Thanks.

Thank you. The next question comes from the line of Richard Verdi with Ladenburg. Your line is open. Please go ahead.

Good afternoon, guys. Great quarter and thanks for taking my call. Just a quick housekeeping question first. Pat, maybe you could help me with it. What was RINs expense for the quarter? Maybe I overlooked it. Can you just share it with me, please.

Yes. We actually wouldn't have had an expense for it. We would have had, had a benefit in the quarter. About a $13.9 million favorable adjustment for RINs for the mark-to-market liability in the quarter compared to the second quarter of 2014.

Okay. Great. And then with the first half of the year in the rear view mirror, as we move forward into the back half of the year and into the first half of 2016, where do we see the most potential for strength for Calumet from a product standpoint and also from a facility strength standpoint?

That's a really good question. We consider ourselves and our core business strength to be our specialty products. And I would surmise that the second half of the year, the specialty products will continue to carry the bulk of the load. And especially with the fall in crude prices. We're excited about the specialty products area in the second half. Bill, you want to comment on that?

Yes, additionally, we've got real good balance right now. We don't typically have such a nice balance between performance from our fuel side and our specialty side. So we're very optimistic going forward the rest of the year.

Okay. That's super. Thank you.

As far as your question about facilities, I would just -- I'm not stepping out here, but I would guess that Superior will be our most profitable facility. I'd like to see all the other ones get to that level too.

Just to add onto that, Rich. Basically you're looking at a widening in the WCS dif over the past several weeks relative to Q2 levels which should help Superior. You're also seeing a widening in the Bakken dif, which should help DPR. We're looking right now at a situation where there's about 1.3 million, 1.4 million barrels of pad 2, pad 3 fuels refining capacity coming offline between October and December, which should help to assist coming out of the seasonally strong period of the year -- assist fuels refining margins.

Looking to the remainder of the year, really the only maintenance that we have planned at our facilities in Q3 we've got basically a lubes unit that's going down at Shreveport and we've also got 10 days of maintenance at San Antonio. From an operational reliability perspective, after getting through 2013 and the first half of 2014, we've made the investments in the facilities and you've really seen it in strong operational reliability and strong production levels. So we're very optimistic going into next year.

That's excellent color. Thank you, guys. That's great. And just one last question. I know it's probably going to be somewhat difficult to answer. But I just figured I would try.

The first caller, his inquiry was into the distribution picture. We've spoken about the distribution picture a number of times. But when it is finally implemented, once you start you can't stop, so I'm trying to get a feel of what type of level of increases we might -- maybe we should expect. Could we see maybe half a penny or a penny? Just some sort of growth rate. Any sort of color would be really helpful.

Rich, I think that the question that you ask, I mean, it's a fair question. I think as we look at it going forward, I completely agree that once we start -- given we've held the distribution steady now for multiple quarters. It will be an important sort of line when we cross and we begin the increase again. I think what you could expect from us are measured increases over time that might be more consistent versus maybe a prior track record of having sort of variation in quarterly distributions. I think that, as we've discussed this, one area we'd like to be is just someone who's consistently growing the distribution at a sustained and sustainable level over time.

And I think that leads to something that would be a bit more measured and paced versus increasing it by $0.03 a quarter and then pulling it back to a $0.005 and then going up to $0.02, just as a frame of reference or an example. But we do see it as a very important step when we do begin to increase the distribution again that we're going to want to keep together a very consistent pattern, because ultimately I think that's what investors are looking for and we certainly are wanting to be able to provide that type of growth consistently over time.

That's great. Thank you, guys, and great quarter. I appreciate the time today.

Thanks, Rich.

Thanks.

The next question comes from the line of Sean Sneeden with Oppenheimer. Your line is now open.

Hi. Good afternoon, thank you for taking the questions. Pat, maybe for you. Obviously fuels margins were pretty solid during the quarter, but I was kind of curious if you could quantify or give us any directional guidance as to how much Dakota Prairie contributed to that, if at all?

Well, it didn't contribute to that at all in the quarter. We recorded an $8.3 million loss from unconsolidated affiliates on our income statement and that's primarily related to the impact of Dakota Prairie. So you can see that those results are going to be quantified in that line item going forward.

Just as a general comment, Sean, I want to highlight the fact that excluding the impact of about $14 million LCM inventory charge in the oilfield services segment and the $8.3 million loss that Pat just mentioned from unconsolidated affiliates, adjusted EBITDA would have been about $22 million higher. So we did $95 million in the quarter, add $22 million, that's $117 million of EBITDA. Basically DPR and oilfield services were the principal reasons we didn't have an even better quarter. That's just something to think about for your modeling purposes.

That's very helpful. The follow-up was going to be thinking about the impact going forward. But it sounds as though, from the third quarter going on, we should see a rebound, at least on the DPR side; is that right?

Well, it's going to rebound some. Starting out the third quarter is certainly better than it was the beginning of the second quarter. So unless things materially change between now and then, yes, I would say we're going to improve.

Okay. That's helpful. Maybe, Bill, for you. A couple folks have been pinging you about strategy going forward. Sounds like the plan is to kind of fully integrate a lot of the organic growth projects before expanding any further, at least from acquisitions. From your standpoint, how are you thinking about any kind of geographical expansion? Obviously you guys have a pretty big concentration in pad 2, pad 3. How would you view getting into some other part of the world?

I'd say from the specialty side of our business -- this is Bill Anderson -- we do have a conscious program going on where we are consciously growing some export business, but we're doing it in a way that we're promoting some of our more unique and higher value specialty products to some of these other markets. And we opened up a Mexican office this year and had a grand opening last week and we're moving up, channeling some business through that operation. So we're kind of getting our feet wet and getting in some markets and getting to know some people and getting some feet on the ground, which could lead to something down the road. But obviously, being an MLP, we have to be kind of measured when we look at things out of the US.

Okay. That's helpful. Thank you.

Thank you. And our next question comes from the line of Johan [van der Kooij] from Credit Suisse. Your line is now open.

Hi. Thank you for taking my call.

Sure.

I think a lot of the material that I was curious about has been covered, but I do have one follow-up on Dakota Prairie specifically. That's to the extent that the diesel prices that you had mentioned are weak, have been so, I'm kind of curious as to whether or not you think that's attendant to reduced drilling activity around the Bakken and as a consequence reduced diesel demand? And what impacts this sort of activity has had on demand in the region for you all?

Yes, I'm sure it has, yes. The decreased drilling activity certainly has affected the diesel consumption. At the same time, I feel like there's still a lot of supply that's coming into North Dakota from external sources and I think that rationalization of those supplies has not been fully completed. And when it does, it will certainly put a floor under and support higher diesel prices with -- it just hasn't happened yet. And I would expect there's probably a lot of reasons why it hasn't happened; contracts and commitments and other things like that.

But I really have to feel like it will. It's got to be expensive for people to bring -- or other companies to bring diesel into that area from an external source. So it will take the time. I was very hopeful that it would happen faster than it has, but it hasn't. And again, like I said, the drilling activity being down there has definitely hurt the price some.

As a follow-up question, then, on Dakota Prairie as well. My understanding is that the plan has been to take some of the other products thrown off by the refinery, like atmospheric bottoms, and move them over to Montana? Is that something that's actively able to be done or is that something that is going to have to be ramped up once the Montana expansion is finished and if so how quickly can it be done?

I'm going to let Ed -- Ed hasn't spoken yet, Ed Juno. So I'll let him answer that question.

This is Ed Juno, EVP of Operations. We anticipate, once we have the hydrocracker complete and up and running that the ATB will then be processed there in Montana. So at this time -- this was a hydrocracker still under construction, that's not an option for us at this point.

I guess my question is are the logistics assets in place to do that on kind of a rapid basis or is it something that's going to take a little bit of growing pains here and there?

No, the logistics are in place to take advantage of that opportunity.

Okay. Perfect. Thank you very much. That's it.

Thank you.

(Operator Instructions)

Our next question comes from the line of Gregg Brody with Bank of America. Your line is now open.

Hey, guys. Just on your hedging strategy, I know you did some hedges during the quarter, but the strength in cracks you saw in July, what's stopping you from adding more for this year and next year?

I don't think there's anything that's necessarily stopping us from hedging more into this year and next year. We never hedge everything. We've got a fair number of gasoline hedges on for Q3 and Q4, as we noted earlier in the call. I think the outright price of diesel, while fairly attractive, has not been overly attractive in our view. We still like to have lots of market exposure. But beyond 2017, it does become rather a liquidity issue in the ability to secure trades out that far. So I'd say nothing keeps us from hedging additionally.

This is part of our strategy and even though we had larger hedging losses in the second quarter compared to a year-ago period, the program is doing what we want it to do, which is to stabilize cash flows over time in the fuel products segment. So structurally, we'll never hedge all of it. We like to have some exposure to the market crack spreads. We're glad that we're achieving gasoline margins on a significant portion of the production at those elevated levels. But we do kind of look at where we are from a credit metric standpoint and where we are from a budget standpoint and we can remain committed to continuing to lock in trades that are supportive of our goals.

Got it. And then these -- on page 12 of your presentation you provide the change in the crude prices relative to WTI. Are those your numbers or is that some benchmark you're looking at that reflects what's in your refining system?

Those are benchmarks, but our refineries do run these types of crude. Like, for example, the Bow River is exclusively what's run in Montana. We run Bakken, WCS, at our Superior refinery.

So these are indicative of the types of spreads and the patterns that we would see in our crude oil procurement across our own system. We run Eagle Ford at our San Antonio refinery. So these are relevant to our operations.

Got it, and I understand it. I guess the question is on the Bakken when we look -- when I look, I know there's more than one price point out there and obviously I can't see it all if I'm looking on Bloomberg, which is the extent of the information I have. I'm just curious if there's any dynamics that are specific to your region that are just worth thinking about right now?

That's a Bakken Clearbrook quote, Gregg, so --

Yes.

So basically our realized price is going to be better. We're going to realize a higher discount than what you're seeing on the screen. The reason I put a Bakken Clearbrook in there is because you can look at it directionally and source that off of Bloomberg and it will help you directionally from a modeling perspective. Our laid-in cost there is lower because we are sourcing local crude in the Bakken in Dickinson and processing it at a refinery that is local and selling it to customers that are, for the most part, local. We try to keep everything sort of in the local area.

Can you estimate what the ballpark is for your local advantage you have, since you don't have to transport it?

You're asking what the transportation cost between Clearbrook and Dickinson would be from a barrel perspective?

Maybe more if I look at Clearbrook, what should I think about? [Irrealizing] a better price, how should I think about that for you? Is there an average I should think about or is it the transport?

It's probably a $2 to $3 benefit.

Great. Thank you, guys.

Thank you.

Thank you. I am showing no further questions at this time. I would now like to turn the call back to CEO Bill Hatch for any further remarks.

I'd just like to thank you all for listening in and your good questions that you asked today. And should you have any more questions, please contact our Vice President of Investor Relations, Noel Ryan. And thanks again for the participation today and we'll see you next quarter. Bye.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone have a great day.