PBF Energy (NYSE:PBF)
Q2 2013 Earnings Call
August 1, 2013, 8:30 AM ET
Thomas O'Malley - Executive Chairman
Matthew Lucey - Senior Vice President and Chief Financial Officer
Thomas Nimbley - Chief Executive Officer
Evan Calio - Morgan Stanley
Jeff Dietert - Simmons
Roger Read - Wells Fargo
Edward Westlake - Credit Suisse
Paul Cheng - Barclays
Clay Rynd - Tudor, Pickering, Holt
Welcome to the Q2 2013 PBF Energy Inc. earnings conference call, with Tom O'Malley, Executive Chairman. (Operator Instructions, And now, I'd like to hand the call over to Mr. Matt Lucey, CFO. Please proceed.
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'd 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 federal securities laws. 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 a 100% of operations of PBF Energy Company LLC on an after-tax basis.
With that I'll 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 Mid-continent 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 from 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 narrow than its 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 in to the East Coast, including (inaudible).
In the Mid-continent, the high cost of Syncrude, which averaged $4.33 per barrel over TI, negatively impacted Toledo's capture rate, as the refinery run on average about 35% to 40% Syncrude on a daily basis. It's important to note that the benchmark prices differ from PBF's cost, as the benchmark does not reflect transportation or other timing related cost.
In regards to RIN, 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's difficult to predict that second half expense associate with RIN, and Tom will address this 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 the last year's second quarter. The decrease in '13 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 that we have added several initiatives on the East Coast focused on increasing our yield of ultra-low 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 then ensuing additional capacity with the anticipated delivery schedule of our own rail fleet.
It's important to note that deliveries of Canadian heavy crude oil to our Delaware unloading facility are not expected to achieve 40,000 barrels per day, our current capacity and total 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 is 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 a $110 million in one-time non-recurring 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 spend about $32 million on RINs purchases for obligations that fell outside of the second quarter and we had about $250 million in other working capital spending, which includes swings in inventory.
As of the end of July we have fully repaid all outstanding borrowings on our revolving credit line even as we increase 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 pay down all of the debt. At the end of June, we had approximately $615 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 dividends for the quarter is reflective of both the board and management's confidence and the earnings power of PBF, our continuing commitment to returning cash to shareholders.
From modeling our third quarter operations we expect the refinery throughput volumes to fall within the following ranges: The Mid-continent 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 turnarounds at Del City expected to be 40 days. We expect our operating cost 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'd 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 and 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 beginning of third quarter, on the East Coast we exited the Morgan Stanley Offtake Agreement and entered agreements with J. Aron, who will purchase and hold a 100% of the in-tank product inventory on the East Coast.
Under the newly executed, J. Aron agreements PBF is able to sell it's product through the market 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'd like to highlight the completion of the next step and the creation of the previously mentioned logistics focus 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 MLP units is subject to market and other conditions.
I'm now going to turn the call over to Tom Nimbley, who will go over the operational overview of the company.
Thank you, Matt, and 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 shutdown the fluid cat-cracking unit for unexpected maintenance due to a pump failure. The unit was safely shutdown, repairs were made to the pumps, and the unit returned to service on Tuesday.
As Matt mentioned, PBF has had a challenging second quarter. Overall, all 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 Mid-continent averaging 147,000 barrels a day and the East Coast system 317,000 barrels day. Throughput was lower than planned, as we adjusted our run rates due to poor margins associated with narrowing crude differentials, which resulted in poor coking economics and higher RIN cost.
Operating cost on a system-wide basis averaged $4.79 a barrel. As Matt mentioned, a moment ago, per barrel operating expenses are higher due to a higher natural gas cost 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 2-1-1 East Coast crack averaged $14.67 a barrel and the gross margin for 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 6,000 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 cost to come down. And for the Mid-continent we expect our landed cost excluding any LIFO or hedging effects to be about $5 a barrel over WTI. And for the East Coast we expect our crude to be landing in at about $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-loop track has demonstrated capability to unload in excess of 100,000 barrels a day of light crude oil.
And depending up on 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 build-out 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 the 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 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. Light fuel for pipeline startups and outages decreased in the availability of imported Syncrude. On the heavy side, differentials were negatively impacted by infrastructure constraints in Canada, floods in pipelines outages and maintenance to production facilities.
While we expect to continue to see near-term volatility in both the flat price of crude and the differentials, as the industry continues to adjust to grow in North American production and infrastructure changes. We believe that over the long-term, discounted North American crudes versus waterborne alternatives will provide PBF with a cost advantage.
As always, the crude spread 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 Nonene 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've 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 trend ship as much as 45,000 barrels a day of well 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. And as a result, our operations were unaffected and we continued to execute our strategy for the East Coast.
And I'd 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 is challenging. I'd 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 know as RINs, and in our industry this has become the topic to show a very important item, with a lot of people in the industry appealing to the government, to take a more recent position. We and rest of our industry were surprised that 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 spent expense in the future.
Based on what we see in the marketplace that is much stronger gasoline cracks, we believe the RINs cost on ethanol are now being passed on to the consumer. Our (inaudible) 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. And can we expect the government to correct the 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. A blend wall of 10% is real and it's upon us. PBF is today in a long or short ethanol rent, recovering 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'll 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, cannot draw 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, unless 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'd 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 the these fields 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 crude's approach is, 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 buying organization. And believe me they can invest in 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 their 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 outlook 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 spilt milk.
We have seen in the month of July a dramatic improvement in product net tax. I think we will see product net tax 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 second half results, and the first indications are that it certainly will.
At this point, we'll be pleased to take your questions, operator.
(Operator Instructions) And our first question comes from the line of Evan Calio from Morgan Stanley.
Evan Calio - Morgan Stanley
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, the RIN cost, if not transferred to the product price factor into your equation. And 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.
The question, do we include it in the cost? It is embedded now in the weekly report we sent 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 it 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 per gallon.
Certainly, do we take that into consideration when making product, you bet we do. And we adjust our product mix, we adjust the markets that we want to sell into. And again, I don't think that we're any different than anybody else. If we export gasoline then we don't have a RIN expense, so it's very much of that.
With regard to action on the part of the congress or the regulatory agencies, I think that 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. And of course, they could solve the RINs problem instantaneously, if they came out with the number that said, there is a blend wall for the moment and give some hint as to what would happen in the year 2014. this case made to the agency by people in the industry, by myself, by various people in both the House and the Senate. It's been in visits to the White House, which included myself, other industry executives. Due to the legislators finally understand what the problem is, yes they do and will they do something about it, well, I do hope so, otherwise the consumers can have an awful shock in store for them.
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 that the RINs, all other things equal, if the course of RINs goes from $0.06 to $1 and you hold everything else equal, obviously that's not the case that's going to be there. But if you did, we would see a $20,000 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 everybody is looking at the same increase in course, which means the production on the margin is not going to be profitable. And 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 its in the production cost and we felt that, because we weren't making money on the market.
Evan Calio - Morgan Stanley
Let me shift gears to second question if I could. On the MLP, could you clarify why you filed confidentially versus outright and is the potential timing with any offering correlated with the improvement in oil differentials as many of the assets are likely rail related?
Matt, why don't you take the first of that, and I'll take the second.
In regards to our filing this morning, we put our team together focused on MLP working very, very hard. We're very focused to get a filing done in the third quarter. That being said, the Jobs Act, the passage of Jobs Act, provides a couple of benefits that we decide 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 carved out financial for the full suite of assets that potentially can drop into an MLP.
And 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've identified and 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 to process to get closer to the better offering.
I think it's fair to say that we needed some good and sustained results from the U.S. 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 of the Toledo refinery. We do deliver by rail some crude to third-party terminal at the present time and we think we will see rail movements into that area. We've 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've seen over the past a 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 were 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 '14.
Our next question comes from the line of Jeff Dietert from Simmons.
Jeff Dietert - Simmons
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 the Bakken and Brent has narrowed a bit. Could you talk about what kind of differential you need there in order to sustain those volumes?
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 Bakken and fixing the Brent differentials. So in July, I believe we've taken in about 75,000 maybe a touch more per day 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 exists, we'd 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 particularly attractive crude to us. We saw our differentials shrink enormously back about three weeks ago, where in fact, Brent and Bakken, 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're buying pretty much for ourselves at very good differential.
So we need the Canadian heavy crudes to land in our refinery to have a reasonably good margin, I suppose, at about $12 on the Brent. And that's, of course, going to depend on what we can buy other crudes at. And I gave you the number on Bakken. And how resilient will those numbers be? Well, that's always the bet in the marketplace.
Will Bakken be real tight, and as best I can tell for the next couple of years any how, Bakken must move by rail. We have very favorable economics in the sense that we own our own facilities. We think we're better rough than our competitors on the U.S. East Coast by a $2 a barrel. But exactly how will it work out? Hey, your guess is probably as good as mine. It will beat the market.
And on Canadian, I think it's a same situation. Do we have stranded crudes, and I'd believe yesterday, we probably brought our first Canadian heavy at economics that suited us, that we brought actually during the month of July. We didn't buy any crude or any new crude during the month of July, because the diffs didn't work. Hope that answers your question.
Jeff Dietert - Simmons
Quick follow-up, how do you consider your any kind of take-or-pay commitments on either rail loading or railcars or rail tariffs 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've got to be more insensitive on that issue. I don't see any problem for this year on either of your questions, i.e. we will also feel the requirements that we have to the railroads this year without difficulty. And in fact 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. And I say that because we have a lot of railcars coming off-lease. So we are not sitting there worried about the railcar 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 fleet 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.
And our next question comes from the line of Roger Read from Wells Fargo.
Roger Read - Wells Fargo
Number one, thanks for going through on the cash side. That helped certainly resolve that question. But as you look at the second half of the year, and I recognized 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, I'd appreciate it, because I didn't get that one down. And then the opportunity to push the RINs cost through on the product pricing side? I mean are we looking at a significantly better second half, even if we get no real recovery in the differentials aspects of the market?
Quick answer is yes. Take numbers with some sense that they do tend to move around, I think we're a better off on the crude side by, somewhere between $12 million and $15 million. I think we're better off on the product side somewhere between $20 million and $30 million. And on RINs, well, we've done $69 million on this stuff, in the first half of the year where we have to absorb some of it.
You know, you never get a 100% of anything, but I'd be surprised if our net was more than $10 million or $12 million. You have to recognize that this nutty program is on the path, that we will wind up paying, in fact, the entire industry, will wind up paying more in RINs than it pays for all the wages and salaries for the unionized employees throughout the industry. How can, this goddamn thing makes sense, it makes no sense.
So it is being passed on, today witness the cracks, I think you'll see that. Now with regards to recovery in the differential, let's just talk about that for a minute. I won't consider the differentials, $20 range. Brent TI have been saying, they result a trapped crude oil and it was trapped to 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 the new trap and the trap is actually on the Gulf Coast. And I believe you'll see prior to the end of the year, that there will be no add imports as we go to the U.S. Gulf Coast. And what does that mean, does it mean Brent TI opens up again? Yes. I think it will. I think Brent, probably trades 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's the overall crack. In other words what's the sum total of the 2-1-1 and that's Brent differential. And we've seen the 2-1-1 crack, particularly, the crack for gasoline expand very significantly. So that's what's going to determine our profitability, the two taken together. I do not personally see a $7 or $8 Brent-WTI and I think you're going to settle in it, $2, $3, not too much more.
Roger Read - Wells Fargo
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 that cash operating cost or any other part of the results?
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. And if my memory serves me correctly, occasionally it does, that was somewhat more than $20 million and the average RIN cost across our spectrum that that means we included biodiesel, et cetera, in there. That's a real expense that we take.. And in our LP, we mark that down.
And so the LP that we're running for August will take the current market for RINs, you know, try and experience it a bit, in the sense of, how does it normally work and make our run plans based on that. And at these levels, we will make less gasoline in Delaware. How come this possibly be good for the consumer. And I'm not asking you guys, and ladies, I'm really tying 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, that never shall they meet.
Roger Read - Wells Fargo
But I guess just to get right back at the question of kind of where we see it flow through from a result standpoint, the RINs cost is embedded from what I am seeing? From what the street is seeing in the actual gross margin, not in the cash operating cost or is the reason we see cash operating cost?
We do not look at it right now. And unfortunately we believe, and the good part of the industry, I believe were looking at it as a gross margin situation. And that's idiotic. It is an expense. We buy more. We have to buy these numbers. It's not an option. And the fine for not doing it is pretty extreme. So you can be sure that we will.
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 of course 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.
Our next question comes from the line of Edward Westlake from Credit Suisse.
Edward Westlake - Credit Suisse
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, they would certainly have to adjust. This business has become very, very important to them. They see a different 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 this situation in the Bakken as something that it is rail defined. And we have a very competitive rail numbers. So we're always interested in lower cost, but at the present time I don't see that happen.
Edward Westlake - Credit Suisse
And then on the producer side, I mean clearly the East Coast market, it's going to be important for light, obviously, you have cokers which make you relevant for the Canadian producers as well. Given the production growth and uncertainty of pipelines, et cetera, are you seeing any of the producers willing to give you long-term contracts, maybe on, 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 all the producers talking to us, on the whole series of scenarios, yes, they are. And we haven't gotten into the true cost plus discussions with anybody. And 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'd believe probably on the East Coast, we have taken more than anybody else with Bakken. And we are discharging on the daily basis an off a lot of crude
Edward Westlake - Credit Suisse
Then a final, smaller one, just on the East Coast markets and obviously buying sort of Marcellus, what's the time lag into the East Coast versus the spot prices that we see on the screen for realizing the discounts depreciate. Obviously, the discounts were very narrow in Q2 and obviously normalizing as we look at Q3?
I think you should look at a one month time length.
And our next question comes from the line of Paul Cheng from Barclays.
Paul Cheng - Barclays
Three quick questions. First, based on your contract with either the loading terminal operator or that the well operator, when the market conditions change, how quickly that you can change in terms of whether you decide to continue to ship on 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 deal front. We have no fixed obligations on the line.
Paul Cheng - Barclays
So you can change mainly that in theory, momentarily, although that mean, you still need to source our alternative crude, so it's probably more like a month or so?
I would say that the timing that you mentioned is reasonably on the mark. We're always more or less covered at least a month in advance. We are not out there buying crude for delivery. And 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're taking our time with that. We really have don't have the time for commitments that are putting us in a box.
Paul Cheng - Barclays
And Tom, you mentioned that you believed some of the RIN cost now is being pass-through. What is your best estimate or guesstimate, how much of the RIN cost is now being pass-through?
I would tell you that think it's based on the gasoline cracks that we're seeing in the marketplace. The market has pass-through RIN costs, when you take RINs at $1. And you basically say, all right, that's $0.10 a gallon, just to keep the things simple, although the calculations are a bit different.
Paul Cheng - Barclays
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 trend rack, and whole industry will, ultimately they have to pay or consumer have to pay. Is that really that much different between what the RIN in nature comparing to what we've seen and happened though back from, say, several years ago, when the whole industry moving into ethane.
I believe that after the initial confusion, the industry had moved into a building system, where that and the invoice is specifically identified as a pass-through, what is the ethanol cost is in the refinery gasoline, for example. And it's just being a pass-through and I thought it will not include the ethanol price. By doing in this way, is there any limitation, why you guys or that the industry is not moving into that direction, because by doing in this way, it can identify exactly how much does the consumer may get. They may allow the discussion or action from DC to accelerate.
This is Tom Nimbley, while we wait for Tom to come online. I'll take a shot at this. I had participated in all of the discussion, most of the discussions in Washington. I mean the industry is positioned by the way is, yes, this is a major issue and 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 on 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, et cetera.
The problem becomes 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 owner-ish 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 ex-financial or go to infinity, because you've been out there, so you can take a production cuts as we said before. It's clear, that as the cost of RINs goes from $0.06 to $1, and I gave you an example of what would impact be just one of our refineries and we are just like everybody else.
Paul Cheng - Barclays
I understand all that. I guess my question is that in order for Washington DC to act, they typically wait for a crisis and the crisis need to be driven or that have been spoken by the consumer. And the problem is that the way that how currently that the building invoice is that, no one really know, how much exactly is the pump price increase is related to the RIN.
So in your invoice to separate out into two separate item, how much you are charging as a pass-through on RIN and how much you are charging for the output. And by doing in this way perhaps that we can help to accelerate the transformation or that to force the Washington DC to take action because the consumer will actually be able to tell exactly how much they can get to see the pump?
I understand your question, I didn't quite get that the first time. But the industry can probably, can certainly do a better job. I wouldn't say whether or not where you 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 through them, and candidly I don't think it wasn't cost to them through the most of the first half.
I think it was a cost to the refiners and that is a different message than to that general population that their cost is actually being pass-through. We can do better and doing in getting that message across. I will also add, and I know it's not specific to your question, where should we put it on an invoice or have a separate line, but the thing that we're 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 steel workers at several refineries with us. And they were saying this is a labor issue. And as well as there is issues, not issues, but there is support from a wide range of groups, poultry farmers, chicken farmers, cattle raisers, the price of corn going up is impacting of other businesses, so it's a wide range. I understand that Tom is back on the line is that correct.
And then we have our last question and it comes from the line of Clay from Tudor, Pickering, Holt.
Clay Rynd - Tudor, Pickering, Holt
Just a say on the RINs issue a little bit, you guys had mentioned that you're going to try and sell more blended product in the second half. Is that simply a function of getting out of those supply agreements or did you have to invest some infrastructure to do some 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 as a word, going out buying terminals. We have taken space in a number of terminals running out in the world. And are selling product in further of field in Pennsylvania. We are in the central part and western part of New York State also. So we've put a lot of effort into putting together a marketing group. We've invested in people, built the 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 have that situation in Toledo, where we handled the marketing of products.
And it's now have spread to the East Coast. It's a business we know. Tom Nimbley and I work together on it for a long-time at Tosco Corporation and Premcor Associates, not anything that's requiring market science on our parts. It's in essence taking the correct structural position and I would expect that overtime significant growth in that sector.
Clay Rynd - Tudor, Pickering, Holt
And so just to follow-up on that, do you think you will be able to continue to increase the amount of blended gasoline or so rather than unblended or is that kind of how you constrain in that front?
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 the gasoline component, which we are doing.
And now ladies and gentlemen, I'd like to turn the call over back to Thomas O'Malley for closing remarks.
Thank you very much for attending today's conference call. Hope we do a great job for our shareholders during the second half of the year. Good Bye.
Thank you, ladies and gentlemen. That concludes our conference call for today. Thank you for joining us. And you may now all disconnect.
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