PBF Energy Inc (PBF) 2013 Q2 法說會逐字稿

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Q2 2013 PBF Energy Inc. earnings conference call with Tom O'Malley, Executive Chairman. My name is Marie and I will be your operator for today. At this time, all participants are in a listen-only mode and later we will conduct a question-and-answer session and instructions will follow at that time. As a reminder, this conference is being recorded.

And now I would like to hand the call over to Mr. Matt Lucey, CFO. Please proceed.

Thank you. Good morning and welcome to our earnings call today. With me as always are Tom O'Malley, our Executive Chairman, and Tom Nimbley, our CEO. If you have not received the earnings release and would like a copy, you can find one on our website at PBFenergy.com. Also attached to the earnings release are tables that provide additional financial and operating information on our business.

Before we get started, I would like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary it states that statements in the press release and on this conference call that express the Company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor Provisions under the federal securities law. There are many factors that could cause actual results to differ from our expectations, including those we described in our filings with the SEC.

As also noted in our press release, we will be using several non-GAAP measures while describing PBF's operating performance and financial results including adjusted pro forma net income, adjusted pro forma EPS, refining gross margin, EBITDA, and adjusted EBITDA. We believe these measures provide useful information about our operating performance and financial results but they are non-GAAP measures and should be taken as such.

It is important to note that we will emphasize adjusted pro forma net income and adjusted pro forma EPS in our earnings call rather than GAAP earnings. Our GAAP net income and GAAP EPS reflect only the interest in PBF Energy Company LLC owned by PBF, Inc. We think adjusted pro forma net income and adjusted pro forma EPS is more meaningful to you because it presents 100% of operations of PBF Energy Company LLC on an after-tax basis.

With that, I will move on to discussing PBF's second-quarter 2013 results.

Today we reported second-quarter operating income of $133 million. Adjusted pro forma net income for the second quarter was $71 million or $0.73 a share on a fully exchanged, fully diluted basis. This compares to operating income of $580 million, adjusted pro forma net income of $336 million or $3.45 per share for the second quarter of last year.

EBITDA for the quarter was $167 million. Included in our second-quarter EBITDA are $10 million in charges related to the now-terminated Morgan Stanley offtake agreements on the East Coast. In the absence of the Morgan Stanley agreement, these charges will not occur.

Needless to say, the financial results fell below our expectations as our realized margins for both the East Coast and Midcontinent reflected the challenging market conditions. Narrowing crude oil differentials and the high flat prices for feedstocks as well as the cost of RINs all negatively impacted our results. In particular, capture rates on the East Coast were negatively impacted by the narrow light/heavy spread as evidenced with the Brent/ASCI differential, which averaged $3.14 under Brent for the quarter, which is narrower than it has been for the last five quarters.

This differential is important to PBF because ASCI is an indicator for many of the medium sour barrels we bring into the East Coast including Arab light.

In the Midcontinent, the high cost of syncrude, which averaged $4.33 per barrel over TI, negatively impacted Toledo's capture rate as the refinery runs on average about 35% to 40% syncrude on a daily basis. It is important to note that the benchmark prices that I have referred to can differ from PBF's costs as the benchmark does not reflect transportation or other timing-related costs.

In regards to RINs, the first half of the year PBF RIN expense for the 2013 obligation for all types of RINs was approximately $69 million with the second quarter being $37 million. Given all the uncertainties, it is difficult to predict the second half expense associated with RINs but Tom will address the subject in more detail shortly.

In the second quarter, we had a LIFO benefit of about $25 million. As you may recall in the first quarter, there was a LIFO charge of $66 million. Therefore year to date, we have taken a LIFO charge of approximately $41 million.

For the second quarter of 2013, G&A expenses were $19 million compared to $25 million during last year's second quarter. The decrease in 2013 primarily -- relates primarily to lower employee-related costs in 2013. In the second quarter of 2013, G&A expense was $28 million, again compared to $22 million for the year-ago quarter. Second-quarter 2013 interest expense was $22 million versus $28 million for the year-ago quarter.

PBF Energy's effective tax rate for the second quarter was approximately 39.5%.

Capital spending was approximately $54 million for the quarter. On the Company's capital program, we now expect 2013 expenditures to be approximately $250 million to $275 million for the year, which includes both mandatory spending of approximately $145 million with the balance being strategic projects.

We have made some changes to the program regarding the timing of certain projects and the inclusions of new projects. The most significant changes are that we have added several initiatives on the East Coast focused on increasing our yield of ultralow sulfur distillate. We deferred crude unit and lube block turnaround at Paulsboro from Q4 2013 to the end of the first quarter of 2014, and we pushed out the schedule for the completion of the heavy crude unloading rack and now expect completion in the third quarter of 2014.

The delay in the heavy unloading rack project is driven by infrastructure delays in Canada and now aligns the construction of the rack and the ensuing additional capacity with the anticipated delivery schedule of our own rail fleet. It is important to note that our deliveries of Canadian heavy crude oil to our Delaware unloading facility are not expected to exceed 40,000 barrels per day, our current capacity, until the expansion is complete. Again, this change is entirely driven by delays on Canadian infrastructure.

At the end of June, cash was $69 million with $95 million outstanding on our revolving credit facility and our net debt to cap ratio was 30%.

During the quarter, PBF had significant uses of cash which breaks down as follows. We used approximately $160 million in normal corporate spending for CapEx, taxes, and dividends. We had $110 million in one-time nonrecurring uses related to the purchase of Paulsboro crude inventory from Statoil relating to the termination of that supply agreement and the final Toledo earnout payment. We spent about $32 million on RINs purchases for obligations that fell outside the second quarter and we had about $250 million in other working capital spending, which include swings in inventory.

As of the end of July, we have fully repaid all outstanding borrowings on our revolving credit line even as we increased our receivables by approximately $150 million to $200 million as a result of terminating the Morgan Stanley offtake agreement on the East Coast. Importantly through July, the working capital swing we experienced in the second quarter has substantially reversed itself and our cash balance has remained relatively flat even as we paid down all of the debt.

At the end of June, we had approximately $650 million of available liquidity. Our Board of Directors has approved a quarterly dividend of $0.30 a share on August 21 to shareholders of record as of August 12, 2013.

The dividend for the quarter is reflective of both the Board and management's confidence in the earnings power of PBF and our continuing commitment to returning cash to shareholders.

For modeling our third-quarter operations, we expect the refinery throughput volumes to fall within the following ranges. The Midcontinent should average 150,000 to 160,000 barrels a day and the East Coast should average between 290,000 and 300,000 barrels a day. On the East Coast, market conditions permitting, we expect to receive approximately 70,000 barrels per day of Bakken crude oil and 30,000 to 35,000 barrels a day of Canadian heavy crude oil during the third quarter.

Our run rate for the year will be impacted by the previously announced turnaround at Del City, expected to be 40 days. We expect our operating costs for the year to range between $4.60 and $4.70 per barrel, which includes the impact of the Toledo fire in the first quarter, increased natural gas usage at a higher natural gas price, and reflects lower than planned throughput through the first six months and the impact of the turnaround at Delaware in the fourth quarter.

Before turning the call over to Tom, I would like to highlight a couple of other items. First, in early June, PBF engaged in a successful secondary offering of approximately 16 million shares sold by Blackstone First Reserve. While the Company did not receive any proceeds from the offering, we are pleased to have the additional shares in the marketplace and increased liquidity of the stock. Following the offering, PBF Energy, Inc. holds approximately a 41% interest in the underlining business.

Secondly, at the beginning of the third quarter on the East Coast, we exited the Morgan Stanley offtake agreement and entered agreements with J. Aron, who will purchase and hold 100% of the in-tank product inventory on the East Coast. Under the newly executed J. Aron agreements, PBF is able to sell its products to the markets of its choice and achieve the highest available net back to the Company. We did not have that capability under the previous Morgan Stanley offtake agreement.

Lastly, I would like to highlight the completion of the next step in the creation of the previously mentioned logistics-focused MLP as announced in this morning's earnings release.

PBF Logistics LP submitted a confidential registration statement with the SEC for a possible initial public offering of its limited partnership units. We have identified a pool of potential assets that could ultimately become a part of the MLP but the initial mix of contributed assets is still being finalized. The timing of an offering of the MLP units is subject markets and other conditions.

I am now going to turn the call over to Tom Nimbley, who will go over the operational review of the Company.

Thank you, Matt. Good morning, everybody. Before continuing discussions on the second quarter, I wanted to comment on recent reports on Bloomberg regarding operational issues at Paulsboro.

On Sunday, last weekend, we did shut down the fluid cat cracking unit for unexpected maintenance due to a pump failure. The unit was safely shut down, repairs were made to the pumps and the unit returned to service on Tuesday.

As Matt mentioned, PBF had a challenging second quarter. Overall, our refineries ran as expected but were faced with adverse market conditions. Throughput for our overall system was about 465,000 barrels a day with the Midcontinent averaging 147,000 barrels a day and the East Coast system 317,000 barrels a day. Throughput was lower than planned as we adjusted our run rates due to poor margins associated with narrowing crude differentials which resulted in poorer coking economics and higher RIN costs. Operating costs on a systemwide basis averaged $4.79 a barrel.

As Matt mentioned a moment ago, per barrel operating expenses are higher due to higher natural gas costs and lower than planned throughput.

During the quarter, the Mid-continent 4-3-1 crack spread averaged $29.26 per barrel and our margin was $17.42 per barrel in Toledo for the second quarter. The Brent 211 East Coast crack averaged $14.67 a barrel and the gross margin for our East Coast system was $5.16 a barrel. Again, margins throughout our system were negatively impacted by narrow crude oil differentials as well as the seemingly ever-increasing cost of RINs.

Our cost of crude in the Mid-continent was approximately $6 a barrel over WTI, principally as a result of the high cost of syncrude, which comprises about 35% to 40% of our crude slate at the Toledo refinery.

On the East Coast, our cost of crude was about $1.50 a barrel over Brent as a result of narrow crude oil differentials which negatively impacted the economics for North American barrels, light and heavy, as well as narrow ASCI and waterborne heavy differentials. In the third quarter we expect our crude costs to come down and for the Mid-continent, we expect our landed costs excluding any LIFO or hedging events to be about $5 a barrel over WTI and for the East Coast, we expect our crude to be landing in at about a $3 a barrel discount to Dated Brent.

During the second quarter, we delivered approximately 17,000 barrels a day of Canadian heavy crude and 75,000 barrels a day of light sweet crude to Delaware City by rail. Our dual lube track has demonstrated capability to unload in excess of 100,000 barrels a day of light crude oil and depending upon the economics, we expect deliveries of Bakken crude to be approximately 70,000 barrels a day in the third quarter.

On the heavy side, again subject to the market, we expect our deliveries of Canadian heavy crude to be approximately 35,000 barrels a day in the third quarter. As Matt mentioned previously, due to delays in the buildout of logistics infrastructure in Canada, we do not expect deliveries of Canadian heavy crude to exceed 40,000 barrels a day until the second half of 2014 and consequently, we have deferred the expansion of our heavy crude unloading rack to match that timeline.

While our second-quarter results were below our own expectations, we continue to believe in our strategy of sourcing lower-cost feedstocks for our system by procuring additional volumes of North American crude, both light domestic and Canadian heavy.

Our view is that the high prices and the volatility in the North American crude oil environment in the second quarter was primarily event-driven. Light crude demand in the Mid-continent increased as a result of refinery startups, line fill for pipeline startups, and outages decreasing the availability of imported syncrude.

On the heavy side, differentials were negatively impacted by infrastructure constraints in Canada, floods and pipeline outages, and maintenance to production facilities. While we expect to continue to see near-term volatility in both the flat price of crudes and the differentials as the industry continues to adjust to growing North American production and infrastructure changes, we believe that over the long-term, discounted North America crudes versus waterborne alternatives will provide PBF with a cost advantage.

As always, the crude slate we select for our refineries will be determined based on economics. If economics justify the use of waterborne crudes versus North American crudes, then we will adjust our slate accordingly.

While we wait for the markets to settle down, we continue to focus internally on smaller self-help initiatives such as a project that we completed in Delaware in the second quarter, which has increased our output of NONI, a high-value chemical product and several smaller investments focused on increasing our production of ultra-low sulfur diesel.

One last item before I turn the call over to our Executive Chairman, Tom O'Malley. During the second quarter, in fact on May 31, we received a permit from the Delaware Environmental Agency allowing us to transport crude from Delaware to Paulsboro over the Delaware docks. Assuming acceptable economics, we expect to transship as much as 45,000 barrels a day of rail delivered crude from Delaware City to Paulsboro.

The Sierra Club and Delaware Audubon challenged the grant of this permit and appealed it to the Coastal Zone Industrial Control Board, which had a hearing on July 16, denied the Sierra Club and Delaware Audubon appeal. As a result, our operations were unaffected and we continue to execute our strategy for the East Coast.

I would like to now turn the call over to Tom O'Malley.

Thank you, Tom. Tom Nimbley mentioned the first half of the year and the second quarter as challenging. I would rather call it disappointing. I want to cover a couple of factors that I think will improve the second half results.

The first item is the renewable identification numbers better known as RINs and in our industry this has become the topic du jour, a very important item, with a lot of people in the industry appealing to the government to take a more reasoned position. We and most of the rest of our industry were surprised at the rapid escalation associated with the cost of RINs.

PBF, as Matt mentioned, spent about $70 million on this program in the first half of 2013. It all happened so fast that from my perspective, very little was passed on to the consumer. It was a cost that we and it seems many other independents absorbed. I want to state very clearly we can't afford to absorb this expense in the future.

Based on what we see in the marketplace, that is much stronger gasoline cracks, we believe the RINs costs on ethanol are now being passed on to the consumer.

RBOB on the East Coast averaged about $13.20 during the first half of the year. The July average was $19.44. The consumer is now paying this hidden tax or I guess ethanol subsidy once again without really understanding it.

Can we expect the government to correct a program that makes little sense and one that could easily raise gasoline prices by $0.25, $0.30, or even $0.40 a gallon? I believe we will see a regulatory fix coming out of the EPA or Congress in the next couple months. The blend wall of 10% is real and it is upon us.

PBF is today neither long nor short ethanol RINs. We're covered through the early days of August and plan to buy what we need on a more or less ratable basis. Now people are giving estimates as to what their RIN expense will be and indeed we have in the past.

But given the volatility associated with this program, I would hesitate to make any estimation at this point as to what the total of the second half of the year will be. You tell me what the price of an individual RIN is and then I will tell you what the associated costs are for our Company, but I can tell you today that these costs are so extreme that we can't and I believe probably no other independent can absorb them. The consumer will pay for this program.

In summary, RINs cost the Company a great deal in the first half and I believe will cost us less in the second half either through the cost pass-through, which I think is happening right now, regulatory action, and if we have any regulatory action, you will see the RINs price melt in a day. Last but not least, a greater percentage of the product we produce sold as blended material or exported and this plays due to our takeover of product sales from Morgan Stanley on July 1.

The second item I would like to talk about is the change in our crude oil buying programs and our product sales arrangements. Frankly, the programs that we had in place using Statoil and using Morgan Stanley were appropriate when the Company was privately held by Blackstone and First Reserve. We indicated when we did our IPO that we wanted to get out of these deals and we wanted to get out of them because they cost us a lot more than was on the cover of the deal. We took over 90% of the Statoil purchasing program at the very beginning of the second quarter of 2013 and given the way crudes have purchased, we are now only seeing the full effect of this change during the month of July.

I certainly expect our economics to improve by $2 million or $3 million per month because we now have our own crude volume organization and believe me, they canvas the market in a very thorough way and we don't have to rely on one quote from one organization.

Of greater importance to PBF as we see it today, was our takeover of the product sales from Morgan Stanley on July 1, 2013. It wasn't that Morgan Stanley did a bad job for Morgan Stanley. I suppose they did a very good job for them but certainly they didn't maximize the amount of revenue that we collected.

The arrangement with Morgan didn't obviously give them enough incentive to search for the best outlet for the products coming from our organization. I'm not sure that they always allocated on the fairest basis, but we can't cry over spilled milk.

We have seen in the month of July a dramatic improvement in product net backs. I think we will see product net backs improve versus the first half by a cumulative amount of more than $20 million. I am hopeful that the changes in RINs and crude oil purchasing and in product sales will make our East Coast system a strong contributor to PBF's second-half results and the first indications are that it certainly will.

At this point, we will be pleased to take your questions. Operator?

(Operator Instructions). Evan Calio, Morgan Stanley.

Good morning, guys. Busy morning. Tom, maybe you can continue on your favorite topic here of RINs and just clarify when you assess whether to run or not run an asset that RIN cost, if not transferred in the product price, factor into your equation? When you state that you expect a regulatory fix sooner than expected, and I agree, do you believe decision-makers understand the potential risk of run cuts to the Northeast system?

Tom, I'll take that one. The first thing we do is -- by the way, everybody else asking questions, either to specify O'Malley or Nimbley. We have the same name. Our families where we grew up only had about three names for boys.

The question do we include it in the cost, it is embedded now in the weekly report we send to our directors. As a cost item on our production, RINs costs are real. They are not going to disappear unless some action is taken and frankly, I don't think there's anybody in our industry that can absorb these numbers. This is just another subsidy or hidden tax or some goofy thing.

Right now it's costing the consumer a minimum of $0.10 a gallon. Certainly do we take that into consideration when making product? You bet we do and we adjust our product make. We adjust the markets that we want to sell into and again, I don't think that we are any different than anybody else. If we export gasoline, then we don't have a RIN expense, so it's very much there.

With regard to action on the part of the Congress or the regulatory agencies, I think the EPA must be embarrassed that the statistic that they were supposed to pass out in November of 2012 is still not out and that's what is the true ethanol required for this year on a percentage basis.

It's our understanding based on discussions with the Agency and rumors of course we hear in Washington that we will see this number coming out in the first half of the month of August. Of course, they could solve the RINs problem instantaneously if they came out with a number that said, gee whiz, there is a blend wall for the moment and give some hint as to what would happen in the year 2014.

This case has been made to the Agency by people in the industry, by myself, by various people in both the House and the Senate. It's been made in visits to the White House, which included myself, other industry executives. Do the legislators finally understand what the problem is? Yes, they do. And will they do something about it? I do hope so, otherwise the consumer is going to have an awful shock in store for them.

This is Tom Nimbley. Just to add a little bit to the first part of your question, Tom made it clear. But we view RINs as a cost just like gas or salary wages and benefits or anything else that goes into our operation. So we fully load whatever the cost is that we have into the linear program that effectively shows how we are going to run our refineries and I can tell you if the RINs, all other things equal, if the cost of RINs goes from $0.06 to $1 and you hold everything else equal, obviously that's not the case it's going to be there. But if you did, we would see a 20,000 barrel a day decrease in gasoline production at the Delaware City Refinery just alone based on that step change in RINs cost.

So everybody in the industry runs the business that way so that everybody is looking at the same increase in cost which means the production on the margin is not going to be profitable. We are taking steps and that's why -- one of the reasons our throughput is down in the first half is we had a higher operating cost effectively because of RINs. It wasn't in the operating cost of $4.79 a barrel, but it is in the production cost and we feathered that because we weren't making money on the margin.

Great, very clear. Let me shift gears to a second question, if I could. On the MLP, could you clarify why you filed confidentially versus outright and is the potential timing of any offering correlated with an improvement in oil differentials as many of the assets are likely rail-related?

Matt, why don't you take the first part of that. I'll take the second.

In regards to our filing this morning, we put a team together focused on MLP working very, very hard. We are very focused to get an offer -- a filing done in the third quarter. That being said, The Jobs Act, the recent passage of The Jobs Act provides a couple of benefits that we decided to take advantage of, namely The Jobs Act allows us to use two years of historical financials as opposed to three, and for a new Company such as ours, it's a very important fact as we have to compile carve out financials for this full suite of assets that potentially can drop into an MLP.

Then the second part is as we work those financials with the confidential side of The Jobs Act, we can continue to massage our final suite of assets as those financials get complete. So we have identified and I've talked about in the past a considerable amount of assets that can go into an MLP. And so this is our first step showing the market that we indeed intend to do it but we continue to work the process to get closer to eventual offering.

Evan, it's Tom O'Malley. I think it's fair to say that we need some good and sustained results from the US East Coast assets. I think we are going to get them and certainly they will be an important part of the MLP. We have outstanding rail assets that we can put into this program.

We are considering some rail assets out at the Toledo refinery. We do deliver by rail some crude to a third-party terminal at the present time and we think we will see rail movements into that area. We have authorized the construction of an additional tank out there and are considering some additional construction on the rail side for that market.

With regard to timing, I think one has to be realistic. We have seen over the past year or two quite a few companies file for an MLP with these transportation assets and we've seen that the SEC generally doesn't rush to a judgment on this. There are many questions -- I would not anticipate an offering during the year 2013. Certainly would like to see it come forward during the first quarter or first half of 2014.

Thanks, guys. I will leave it there.

Paul Sankey, Deutsche Bank.

I don't think you have Paul on the line.

Jeff Dietert, Simmons.

Jeff Dietert, Simmons. Good morning. On your guidance for rail deliveries in the third quarter, they look similar to the deliveries that you took in the first quarter. And yet the differential between Bakken and Brent has narrowed a bit. Could you talk about what kind of differential you need there in order to sustain those volumes?

I'll take that one. Look, first of all, we were in front of the [power] curve in terms of the months of July and August with regard to our purchasing of the Bakken and fixing the Brent differential. So in July, I believe we have taken in about 75,000 or maybe a touch more per day of Bakken crudes and so that meets the guidance. I think it will be reasonably close to that number in the month of August. But at the differentials which currently exist, we would rather substitute some imported crude for Bakken.

What do we need? Well, effectively we need to land Bakken at a discount to Brent. And what is that discount? Well, the discount should be order of magnitude $2 or $3 on the Brent.

When it goes even or over Brent and today it would be about $2 over Brent, then it's not a particularly attractive crude to us. We saw our differentials shrink enormously back about three weeks ago, where in fact Brent and Bakken were -- we couldn't move it.

On WCS, we also saw an enormous shrinkage and again, we were in a position where we were much better off substituting something like an M100 for WCS. M100 for us generally is about $0.75 better than the WCS grades delivered and we were successful in buying that, particularly now that we are buying pretty much for ourselves at a very good differential (technical difficulty)

So we need the Canadian heavy crudes to land in our refinery to have a reasonably good margin I suppose at about $12 under Brent. And that is of course going to depend on what we can buy other crudes at and I gave you the number on Bakken. How resilient will those numbers be? That's always the bet in the marketplace. Will Bakken be rail tied?

And as best I can tell for the next couple of years, anyhow, Bakken must move by rail. We have very favorable economics in the sense that we own our own facilities. We think we are better off than our competitors on the US East Coast by a couple dollars a barrel.

But exactly how will it work out? Hey, your guess is probably as good as mine. It will be the market. And on Canadian, I think it's the same situation. Do we have stranded crudes? And I believe yesterday we probably bought our first Canadian heavy at economics that suited us that we bought actually during the month of July. We didn't buy any crude or any new crude during the month July because the diffs didn't work. I hope that answers your question.

Yes, as a quick follow-up, how do you consider any kind of take-or-pay commitments on either rail loading or railcars or rail tariff within your calculation for whether or not it's coming in under Brent?

And secondly, do you expect if differentials are narrower for the rail tariffs to be more competitive and potentially see some relief on the rail tariff in order to make it work both for the railroad and for you?

We don't see any problem. First, I have got to be time-sensitive on that issue. I don't see any problem for this year on either of your questions, i.e. we will fulfill the requirements that we have to the railroads this year without difficulty. And in fact, we will be I believe pretty far ahead of what we promised to do.

Our railcar deliveries regretfully, I must say, stretch out over a period of time and we can absorb our railcar deliveries we believe and use those cars without any difficulty certainly through next year. I say that because we have a lot of railcars coming off lease. So we are not sitting there worried about the railcars sitting on sidings.

Could it happen if we had events like we had in Canada with the tremendous flooding and disruption of shipments across the board? Sure, that's going to always be a situation where everybody can suffer. We don't have any freight commitments locked in in Canada to move Canadian crude. It's premature at this point to have that. So I think it answers your question.

Thanks, Tom.

Roger Read, Wells Fargo.

Good morning. I guess a question I had, and number one, thanks for going through on the cash side. That helped certainly resolved that question.

But as you look at the second half of the year, and I recognize the challenges that are out there, but the gain that you should be able to achieve on the product sales, the number on the crude cost, which if you could repeat I would appreciate it because I didn't get that one down. Then the opportunity to push the RINs cost through on the product pricing side, are we looking at a significantly better second half even if we get no real recovery in the differential aspects of the market?

The quick answer is yes. Take numbers with some sense that they do tend to move around. I think we are better off on the crude side by somewhere between $12 million and $15 million. I think we are better off on the product side somewhere between $20 million and $30 million. And on the RINs, well, we spent $69 million on this stuff in the first half of the year.

Will we have to absorb some of it? You know, you never get 100% of anything, but I would be surprised if our net was more than $10 million or $12 million.

You have to recognize that this nutty program was on a path -- is on a path that we will wind up paying -- in fact, the entire industry will wind up paying more in RINs than it pays for all wages and salaries for the unionized employees throughout the industry. How can this damn thing make sense? It makes no sense.

So it is being passed on today. Witness the cracks. I think you see that.

Now with regard to recovery and the differential, let's just talk about that for a minute. I long considered the differentials $20 range Brent PI to be insane and they are a result of trapped crude oil, and it was trapped at Cushing. And a lot of people I suppose made a lot of money on it and that trap in Cushing somehow opened up. We have more pipeline capacity coming in.

But now we have a new trap and the trap is actually on the Gulf Coast. And I believe you will see prior to the end of the year that there will be no net imports of sweet crude to the US Gulf Coast.

What does that mean? Does it mean Brent PI opens up again? Yes, I think it will. I think Brent probably trades, you know, in a little bit of a strange way. I don't know what the number is going to be but I think what you have to look at is what is the overall crack? In other words, what is the sum and total of the 211 and that Brent differential? We have seen the 211 crack, particularly the crack for gasoline expand very significantly.

So that is what is going to determine our profitability, the two taken together. I do not personally see a $7 or $8 Brent WTI. I think you are going to settle in at $2 or $3, not too much more.

Okay, and just as a clarification, in terms of the RINs flowing through, that is all incorporated within the gross margin. None of that is in a cash operating cost or any other part of the results? Is that correct?

That's incorrect. It is a cash operating cost, so during the month of July, we had a RINs expense and that's a separate expense. If my memory serves me correctly, and occasionally it does, that was somewhat more than $20 million and the average RIN cost across our spectrum, that means we included biodiesel, etc., etc. in there. That is a real expense that we take and in our LP, we mark that down. So the LP that we are running for August will take the current market for RINs, try and experience it a bit in the sense of how does it normally work, and make our run plans based on that.

At these levels, we will make less gasoline in Delaware. How can this possibly be good for the consumer? And this wisdom I'm not asking you guys and ladies. I'm really trying to pose the question to governments in Washington. I believe we have three of them. One is the Senate, one is the House, and one is the Administration, and never shall they meet.

Okay, but I guess just to get right back at the question of kind of where we see it flow through from a results standpoint, the RINs cost is embedded from what I'm seeing, from what the Street is seeing in the actual gross margin, not in the cash operating costs, or is the reason we see cash operating (multiple speakers) --

We do not look at it that way now. We look at it -- and unfortunately, we I believe and a good part of the industry I believe -- we're looking at it as a gross margin situation. That is idiotic. It is an expense. We by law we have to buy these numbers. It is not an option and the fine for not doing it is pretty extreme. So you can be sure we will (multiple speakers) --

But to be clear, we do not have the cost of the RINs in the $4.79 a barrel cost. It is a separate cost that we factor into the LPs and it is correct that it is a cost. It is a -- it's just like a tax. But in terms of the cash cost when we present our numbers, that does not include the cost of the RIN. (multiple speakers)

Okay, that's good. Thank you.

Edward Westlake, Credit Suisse.

Thanks also for the color on changes in cash flows in 2Q, Matt. That was very helpful and also the new contracts, Tom. Obviously keeping the dividend sustained.

I guess a follow-up on rail, are you seeing any of the rail companies thinking about tariffs, given that they must see the spread environment and the economics change?

The rail companies I think are ignoring the situation for the moment. If it would continue, my guess is they would certainly have to adjust. This business has become very, very important to them. They see a good situation with the coal shipments and this is the biggest upside item that they have, so they certainly haven't come to us at the present time, nor frankly have we gone to them.

We view the situation in the Bakken as something that it is rail-defined. I think that's -- and we have a very competitive rail number, so we are always interested in all costs but at the present time I don't see that happening.

And then on the producer side, clearly the East Coast market is going to be important for light. Obviously you have cokers which make you relevant for the Canadian producers as well. Given production growth and uncertainty of the pipelines, etc., are you seeing any of the producers willing to give you long-term contracts maybe on a sort of a cost plus basis or are they still trying to just sort of maximize the options in terms of flexibility on pricing?

I would say the following. We have bought oil for the third quarter at a discount to Brent delivered into our refinery. And are the producers talking to us on a whole series of scenarios? Yes, they are. And we haven't gotten into the true cost plus discussion with anybody. Those remarks are valid for both the Bakken and Canadian producers. So we are seeing particularly on the heavy side as an important outlet for rail shipments and certainly from the Bakken, I believe probably on the East Coast, we have taken more than anybody else with Bakken and we are discharging on a daily basis an awful lot of crude.

Then a final smaller one. Just on the East Coast market and obviously buying sort of sours, what is the time lag into the East Coast versus the spot prices that we see on the screen for realizing the discounts? I appreciate obviously that the discounts were very narrow in Q2 and obviously are normalizing as we look at Q3.

I think you should look at a one-month timeline.

Okay, that's helpful. Thanks very much.

Paul Cheng, Barclays.

Good morning. Three quick questions, hopefully. First based on your contract with either the loading terminal operator or the well operator, when the market conditions change, how quickly that you can change in terms of whether you decide to continue to ship from Bakken or not? Is it one month?

Just to clarify things, we do not have a significant loading terminal obligation in the Bakken. Our total contract is 20,000 barrels a day. We are taking a lot of the crude on a delivered basis into our own facility, where the producers of the crude are loading it through terminal space that they control. So it's not a significant issue for us on the Bakken front and on the Canadian front, we have no fixed obligations on [loadings].

So you can change nearly that in theory momentary, although that would mean you'd still need to source alternative crude, so it's probably more like a month or so?

I would say that the timing you mentioned is reasonably on the mark but we are always more or less covered at least a month in advance. We don't -- we are not out there buying crude for delivery on August 15 at the present time. Our program for August is reasonably well set. We are buying crude at the present time for September and October loadings and we are taking our time with that. So we really don't have the kind of commitments that are putting us in a box.

Tom, you mentioned that you believe some of the RIN costs now is being passed through. What is your best estimate or guesstimate how much is the RIN costs that's now being passed through?

I would tell you that we think based on the gasoline cracks that we are seeing in the marketplace that the market has passed through RIN costs when you take RINs at $1 and you basically say, all right, that's $0.10 a gallon, just keep the thing simple although the calculation is a bit different, take a look at (technical difficulty)

Tom was dialed in from another location. We may have lost him.

We have lost him, sir. Hopefully he will dial back shortly.

Okay, maybe then let me ask a final question while we are waiting for Tom to come back. As you gentlemen have said that this is a train wreck and the whole industry will ultimately have to pay or consumers have to pay, is that really that much different between what the RIN in nature comparing to what we have seen in the ethanol back from say several years ago when the whole industry moving into E10?

I believe that after the initial confusion the industry have moved into a building system where that the invoice is specifically identified as a pass-through what is the ethanol causes in the refinery gasoline, for example, and it's just being passed through and (inaudible) would not include the ethanol price?

Doing it in this way, is there any limitation why you guys or the industry is not moving into that direction? Because by doing it in this way, you can identify exactly how much is the consumer getting. You may allow discussion or action from DC to accelerate.

Paul, this is Tom Nimbley. While we wait for Tom to come online, I will take a shot at this. I have participated in all the discussions, most of the discussions in Washington.

The industry's position by the way is yes, this is a major issue and it is going to be a major issue for the consumer the way the regulation is constructed. It is not an anti-ethanol position because I think factually what you said is correct. You can blend an E10. You can blend 10% of ethanol. The infrastructure is in place to do that. In fact, the economics are supportive of it because ethanol does have some favorable characteristics, octane, etc.

The problem comes when you go beyond 10% in an environment where the infrastructure isn't in place, where the automobile manufacturers say they won't continue to warrant the engines at least for a large percentage of the engines. So then you get into this artificial problem where you physically can't blend ethanol in above 10% without having these onerous problems. E15 right now is not a solution. It could be later. E85, the flex fuel vehicles is not working. You guys know all of this stuff.

So therefore, what happens is you get into what steps do you take to combat that. Well, okay, you can say I can't buy the RIN because in theory the cost of the RIN should be exponential or go to infinity because they are not there. So you can take reduction or production cuts as we said before. It's clear that as the cost of RINs goes from $0.06 to $1, I gave you an example of what would impact just one of our refineries and we are just like everybody else.

Tom, I understand all that. I guess my question is that in order for Washington DC to act, they typically END AUDIT * AUDIO AT 1 HOUR wait for a crisis and the crisis needs to be driven or that have been spoken by the consumer. The problem is that the way that how currently that the building invoices that no one really know how much exactly is the (inaudible) increases relate to the RIN. So by in your invoice to separate out into two separate items how much you are charging as a pass-through on RIN and how much you are charging for the RBOB that by doing it this way perhaps we can help to accelerate the transformation or that to force Washington DC to take action because the consumer will actually be able to tell exactly how much they get hit at the pump.

I understand your question. I didn't quite get that the first time. But the industry probably can certainly do a better job. Let me say this. I wouldn't say whether or not we put it on the invoice, how that matters. I think the industry has to do a better job of getting the message across to the general population that this is a cost to them. And, candidly, I don't think it was a cost to them through most of the first half. I think it was a cost to the refiners and that is a different message than to the general populations, to the cost is actually being passed through. We can do better in doing -- in getting that message across.

I would also add, and I know it's not specific to your question or where should we put it on an invoice or have a separate line. But the thing that we are seeing in Washington DC that we didn't see before is that this is not the refining industry going in and saying this is a terrible thing for our industry. We need relief. The consortium has grown dramatically. Last week when I was in Washington discussing this with other people from the industry, with the OMB, we had the unions represented, the Steelworkers at several refineries with us, and they were saying this is a labor issue.

And as well as there's issues on -- not issues, but there's support from a wide range of groups, poultry farmers, chicken farmers, cattle raisers, the price of corn going up is impacting a lot of other businesses. So it's a wide range. I understand that Tom is back on the line. Is that correct?

Yes, I'm back on. It's Tom O'Malley. I'm back on the phone. I apologize for being out, but it sounds like you answered the question better than I can anyhow. So operator, keep going with questions.

Clay, Tudor Pickering Holt.

Good morning, guys. Just to stay on the RINs issue a little bit, you guys had mentioned that you are going to try to sell more blended product in the second half. Is that simply a function of kind of getting out of those supply agreements or did you invest -- have to invest some infrastructure to do some more blending? Just kind of talk around that and if you can continue to increase or what the dynamics are there?

We didn't invest in the classic sense of the word going out, buying terminals. We have taken space in a number of terminals running out Laurel and our selling product further a field in Pennsylvania. We are in the Central part and Western part of New York State also. So we have put a lot of effort into putting together a marketing group.

We have invested in people, built a staff up and I would expect in the ordinary cost of business, it's something we would do regardless of the RINs. It's the right way to run the business. We want to be a supplier through a broad system of terminals. We already had that situation in Toledo, where we handled the marketing of products and it has now spread to the East Coast. It's a business we know.

Tom Nimbley and I worked together on it for a long time at Tosco Corporation and Premcor, so it's not anything that is requiring rocket science on our part. It is in essence taking the correct structural position and I would expect over time significant growth in that sector.

Just to follow-up on that, do you think you will be able to continue to increase the amount of blended gasoline you sell rather than unblended? Is that going to --? Are you constrained in that front?

Sure, we are constrained in the sense that some people want to do the blending themselves but our preference is to supply blended gasoline and/or export gasoline, which in a gasoline to gasoline component, which we are doing.

Okay, thanks.

Thank you. Now, ladies and gentlemen, I would like to turn the call over back to Thomas O'Malley for closing remarks.

Thank you very much for attending today's conference call. We hope we do a great job for our shareholders during the second half of the year. Goodbye.

Thank you, ladies and gentlemen. That concludes our conference call for today. Thank you for joining us and you may now all disconnect.