菲利普斯66 (PSX) 2013 Q2 法說會逐字稿

Welcome to the second quarter 2013 Phillips 66 earnings conference call.

My name is Kristine, and I will be the operator for today's call.

At this time, all participants are in a listen-only mode.

Later, we will conduct a question-and-answer session.

Please note that this conference is being recorded.

I would now like to turn the call over to Mr. Clayton Reasor, SVP of Investor Relations, Strategy and Corporate Affairs.

You may begin.

Thank you.

Good morning, and welcome to the Phillips 66 second quarter earnings conference call.

With me this morning are Chairman and CEO Greg Garland, CFO Greg Maxwell, and EVP Tim Taylor.

The presentation material we'll be using this morning can be found on our Investor Relations section of the Phillips 66 website, along with supplemental financial and operating information.

Slide 2 contains our Safe Harbor Statement.

It's a reminder that we'll be making forward-looking statements during the presentation and our question-and-answer session.

Actual results may differ materially from today's comments.

Factors that could cause actual results to differ are included here on Slide 2, and on our filings with the SEC.

Also, the registration statement relating to the securities of Phillips 66 Partners LP was recently declared effective by the SEC.

Because we remain in a sensitive period regarding the disclosures around this offering, our remarks about the MLP will be limited, and we will not take questions on the offering during today's call.

That said, I'll turn the call over to Greg Garland for some opening remarks.

Thanks, Clayton.

Good morning, everyone.

Thanks for joining us today.

We faced some challenges in the second quarter, both operationally and with overall market conditions.

Crude differentials narrowed, and although overall crack spreads improved second quarter versus the first quarter, our realized margins were significantly lower.

We had unplanned downtime at some of our chemicals and refining facilities, which reduced utilization rates, and because of the extended downtime in chemicals, we really missed an opportunity to demonstrate the earnings resilience of our portfolio.

We should have run better, and our earnings results reflect this.

In spite of these challenges, we continue to generate strong cash flows.

Cash from operations was $1 billion dollars for the quarter, just over $3 billion year-to-date.

During the quarter, we returned more than $700 million of capital to our shareholders, and continued on our stated plan to strengthen our balance sheet, paying down $500 million of debt.

In addition, we plan to complete the current $2 billion share repurchase program this year, and our Board has authorized an additional $1 billion share repurchase program that we plan to initiate before the end of 2013.

Our strategy to enhance refinery returns through increasing use of advantaged crudes while growing our higher value businesses, remains unchanged.

On July 15, we launched our master limited partnership, Phillips 66 Partners.

This MLP will own, operate, develop, and acquire primarily fee-based transportation and midstream assets.

The MLP will be a tool to grow the midstream business of Phillips 66, and weave a web of infrastructure between our operating businesses.

We continue to deliver on our plans.

By the end of the second quarter, we have taken delivery of 650 railcars of the 2000 that we've ordered.

These cars will be used to transport advantaged crude to Phillips 66 refineries on the East and West Coast.

Our chemicals joint venture CPChem completed the NGL fractionator expansion project during the second quarter at the Sweeny facility.

The project increased capacity by nearly 20%.

Also during the quarter, we commission a high capacity truck facility at a Ponca City refinery, which gives us additional access to Mississippian Line crude.

We continued to increase our refined product exports.

In the second quarter, we set a new quarterly record of 181,000 barrels a day.

Finally, as part of our ongoing portfolio optimization efforts, Phillips 66 sold its proprietary E-gas technology.

And earlier this month, we also closed on the sale of the Immingham Combined Heat and Power plant in United Kingdom.

So with that, I'll turn it over to Greg Maxwell to take you through the quarterly numbers.

Thanks, Greg.

Good morning, everyone.

For the second quarter, reported earnings were $958 million, or $1.53 per share.

If we look at it on an adjusted basis, earnings were $935 million, or $1.50 per share.

Excluding changes in working capital, cash from operations for the quarter was $1.2 billion.

Our cash flow generation enabled us to fund our capital expenditures, pay over $190 million in dividends, and repurchase nearly $550 million, or 8.6 million shares of our common stock during the quarter.

From the inception of the share repurchase program in 2012 through the end of the second quarter, we've repurchased 22.6 million shares.

On an adjusted basis, our annualized year-to-date return on capital employed was 17%.

Slide 5 provides a comparison of our second quarter adjusted earnings with that of the second quarter a year ago on a segment basis.

As you can see, adjusted earnings decreased by $482 million to $935 million, with lower realized refining margins accounting for the bulk of this variance.

I'll cover each of these segments in more detail later in the webcast.

Moving next to our second quarter cash flow, during the quarter we generated $1.2 billion in cash from operations, excluding the impacts of working capital changes, and as you can see on the slide changes in working capital were a negative impact of $206 million.

We returned $738 million to our shareholders in the form of dividends and share repurchases, and this represented 76% of our cash from operations.

And during the quarter, we repaid an additional $500 million of our three-year term loan.

And finally, we funded about $370 million of our capital expenditures and investments, and this was primarily in the refining and midstream segments, and we ended the quarter with cash and cash equivalents of $4.2 billion.

As for our capital structure on Slide 7, at quarter end we had equity of $21.7 billion and debt of $6.5 billion.

This resulted in a debt-to-capital ratio of 23%, which as shown in the shaded area is at the lower end of our targeted range of 20% to 30%.

Taken into account our $4.2 billion ending cash balance, our net-debt-to-capital ratio was 9%.

As a reminder, we plan on further reducing our debt balance to $6 billion by the end of the year.

Next we'll cover each of our segments in more detail, starting with midstream on Slide 8. The midstream segment includes three business lines.

It includes transportation, it includes our equity investment in DCP Midstream, and it also includes NGL Operations and other.

Overall, the midstream segment was down this quarter versus last year, with benefits from transportation more than offset by declines from DCP Midstream and our NGL Operations.

The annualized year-to-date adjusted ROCE for midstream was 11%, and this is based on an average capital employed of $3.1 billion.

Slide 9 shows midstream's adjusted earnings of $90 million, which is a decrease of $5 million from the prior year.

Transportation was up $26 million, and this is mainly due to improved throughput fees driven by implementation of new market-based rates across many of our logistics assets, as well as higher volumes, which include increases from refinery utilization.

Adjusted earnings from DCP Midstream decreased by $12 million this quarter.

This is primarily due to impacts of asset drop-downs to DCP Midstream Partners, offset somewhat by improved natural gas prices, as well as lower operating costs compared to last year.

Earnings for NGL Operations and other were down $19 million, and this is related mostly to gains associated with inventory draws during the second quarter of 2012.

On the next slide, we'll move on to a discussion of our chemicals segment.

Our chemicals segment results were largely impacted by planned and unplanned downtime, primarily at the Sweeny and Port Arthur facilities, resulting in a global olefins and polyolefins capacity utilization of 78%.

While earnings for the specialties, aromatics, and styrenics segment were flat for the for the quarter, we did see an increase in earnings from CPChem's joint ventures in this segment.

The annualized year-to-date return on capital employed from our chemicals segment was 25%, and this is based on an average capital employed of $3.6 billion.

As shown on Slide 11, second quarter earnings decreased by $61 million compared to the same period last year.

The decrease in earnings was primarily in olefins and polyolefins, driven by unplanned power outages at CPChem Sweeny Complex, as well as an extended 91-day turnaround at its Port Arthur facility.

In May of this year, CPChem was required to declare a force majeure on ethylene and certain derivatives following these outages.

The outages at the Sweeny facility during both the first quarter and the second quarter of 2013 resulted in loss production of approximately 540 million pounds.

These outages, as well as the downtime at Port Arthur, resulted in higher manufacturing costs and decreased production and sales volumes for ethylene, polyethylene, and normal ethel olefins in the second quarter of 2013.

While industry ethylene margins remain strong, CPChem realized lower margins because of these unplanned events.

Specialties, aromatics, and styrenics earnings were flat compared with last year, as higher equity affiliate earnings were offset by lower volumes and higher costs.

The improvement of $27 million shown in corporate and other is primarily due to a lower effective tax rate in the current quarter, largely as a result of the mix in foreign and domestic taxable income.

As we move next to refining, our realized margin was $9.88 per barrel, with a global crude utilization rate of 94% and a clean product yield of 85%.

Our utilization rate this quarter was reduced 5 percentage points, as a result of unplanned downtime at several refineries, including the Sweeny and Wood River refineries.

This unplanned downtime equates to the absence of 116,000 barrels per day of crude throughput, in a quarter where our weighted average realized refining margin was almost $10 per barrel.

In addition, downtime in our chemicals segment yielded a similar negative economic impact.

We increased our advantaged crude slate in the US from 58% in the second quarter of last year to 68% in 2013, and this is mainly due to processing more shale, more WTI, and more heavy Canadian crudes.

The annualized year-to-date adjusted return on capital employed in the refining segment was 19%, with an average capital employed for the segment of $14.3 billion.

Slide 13 provides more detail on earnings in our refining segment.

Adjusted earnings for refining were $481 million this quarter.

This is down $404 million from a year ago, primarily due to lower margins, particularly in the Central Corridor and the Gulf Coast regions.

Starting on the left, the decrease is $77 million in the Atlantic Basin Europe region, primarily reflects decreased margins, as well as the negative impact from the scheduled turnaround at our Humber refinery in the second quarter of 2013.

Results from our Gulf Coast operations decreased nearly $250 million compared to last year's second quarter.

And this was mainly due to lower gasoline and distillate differentials, as the second quarter 2013 had larger discounts on distillate products, as well as lower premiums for gasoline.

Market capture in the Gulf Coast was 39% this quarter, compared to 74% for the second quarter of 2012.

The Central Corridor results largely reflect weakening Canadian crude differentials, as well as lower market cracks.

The WTI/WCS differential was $16.71 during the second quarter of 2013, compared with $19.80 in 2012.

This contributed to a market capture of 71% in the second quarter of 2013, compared with 94% last year.

Western Pacific's improvement of $67 million over last year is largely due to fewer turnarounds and less downtime in the second quarter of 2013.

And then finally, other refining was up this quarter compared to last year, primarily as a result of favorable foreign exchange impacts.

Now, our refining segment continued to incur increased costs for RINs in the second quarter.

To the extent that these costs are not included in the cracks and the selling price of motor fuels, then such costs negatively impact our realized refining margins.

Let's now take a look at our market capture, as shown on Slide 14.

When we compare the weighted average market 3-2-1 margin against the actual margin that we captured, you can see that we were negatively impacted by the value of secondary products and our overall configuration.

Market capture for the quarter was 56%.

This is down from 72% in the second quarter of 2012.

Our realized margin for the second quarter of 2013 was $9.88 per barrel, and this compares with $12.85 per barrel last year.

This $2.69 per barrel configuration adjustment reflects the fact that our clean product yield of 85% is less than the 100% assumed in the market crack.

And the $5.41 per barrel reduction related to secondary products is primarily driven by coke and NGLs, and reflects the fact that these products attracted a sales price that, on average, was lower than the cost of our benchmark crudes.

The positive $2 per barrel adjustment for feed stock stems from running certain crudes and other feed stocks that are priced lower than our benchmark crudes.

For example, our feed stock advantage this quarter was primarily related to running Canadian heavy crude.

And finally, the other category reflects the impacts of various product differentials and higher RIN costs.

Slide 15 shows the comparison of advantaged crude runs at our refineries, as well as clean product yields for 2011, 2012, and year-to-date 2013.

In the US, advantaged crudes increased from 62% in 2012 to 68% in 2013.

The decrease in other heavy crude from 27% last year to 23% year-to-date this year was largely due to turnaround activity and power outages at our Sweeny refinery this year.

As shown on the graph on the right, we continue to focus on improving our clean product yields, achieving an overall 84% yield across our refining system this year.

This next slide covers our marketing and specialty segment, or our M&S.

Worldwide marketing margins were $0.052 per gallon in the second quarter, and while our refining segment experienced higher RIN costs in the second quarter, M&S benefited from higher RIN values created by its renewable fuel-blending activities.

In specialties, compared to last year our flow improver sales volumes increased by 17%, and our lubricant volumes were up by 7%.

And the annualized year-to-date adjusted return for the M&S segment was 29% on average capital employed of $3.6 billion.

Slide 17 provides some additional detail about the marketing and specialty segment.

Actual reported earnings for M&S in the second quarter of 2013 were $332 million.

If we exclude the gain from the sale of the E-gas technology and related licenses, adjusted earnings were $309 million, and this is a $25 million increase from the same quarter last year.

Marketing and others adjusted earnings increased $22 million, largely driven by higher volumes on renewable fuel blending and decreased costs, partially offset by lower inventory impacts.

Specialties adjusted earnings improved slightly over last year's second quarter, as improved volumes more than offset lower margins.

Moving next to corporate and other, this segment includes net interest expense, corporate overhead costs, technology, and other costs that are not directly associated with our operating segments.

Corporate and other adjusted costs for the second quarter of 2013 were $126 million after-tax, compared with $95 million for the first quarter of this year.

This increase of $31 million was largely due to taxes and higher environmental expenses, both of which are included in the other category.

This concludes my discussion of the financial and operational results for the quarter.

I'll next cover a few outlook items.

In chemicals.

For the third quarter, we expect the global O&P utilization rate to return to the low 90%s.

For refining for the third quarter, we expect our global utilization rate to be in the mid-90% range.

With regard to turnarounds, our pretax turnaround expense is expected to be approximately $60 million to $70 million in the third quarter.

And in corporate and other, we continue to expect our after-tax costs to be in the $105 million to $110 million range.

And the total effective tax rate for the Company is expected to be in the low 30%s.

And then finally, regarding capital expenditures for the year, we are on track to be in the $1.9 billion range, as we previously have guided.

With that, now we'll open the line for questions.

Thank you.

We will now begin the question-and-answer session.

(Operator Instructions)

Our first question comes from Doug Leggate from Bank of America.

Please go ahead.

(Inaudible) if I may.

Greg, can I ask you about RINs?

It seems that you had a fairly big impact, both on refining and in the marketing segment this quarter.

What I'm trying to understand is the RINs have obviously spiked higher.

I guess they've pulled back a little bit here.

In terms of the moving parts as when you acquired your RENs for refining, perhaps at lower prices versus selling RINs in retail at higher prices, how should we think about the net impact difference there at this kind of level as we move into, let's say, 2014?

because obviously it's a big deal for Valero.

Trying to understand what the scale could be for you guys.

Then I've got a follow-up, please.

I'll take a stab, and then Tim can kind of fill in.

You've got to let me get on the soapbox for a minute, and with the standard that this is an unworkable program in our view in terms of RINs and where RINs is going, but with some hope that ultimately this is going to get fixed on a political level in Washington.

I would say there is a broader understanding about the potential impact what RINs causes for American consumers and for refiners.

We look at RINs, we do trade RINs.

And we have a very sophisticated commercial organization that does that to optimize the value for P66.

So we don't necessarily want to go into what our positions are on RINs, because we really think it disadvantages our commercial people in terms of that.

We continue to believe we have a very sophisticated system, a complex system.

We have multiple levers that we use, whether it's export, producing non--RINs bearing product, blending more, as we look to manage that overall value increment for PSX.

So sophisticated commercial capabilities, a large system, and this is just one of the costs that we manage every day.

Just to reiterate that, I think it is something that we look at in terms of the optimization of our systems.

We have to certainly factor that in.

And I think that you have to wait and see what the future holds in terms of those values, but there's a lot of moving parts to address RFS at the larger level, and I think that just will continue until the resolution reaches.

But to reiterate what Greg said, we look at this, and just say it doesn't work post-2014.

And that needs to be addressed.

Tim, are you prepared to say whether you're net long, or not, across your organization?

No, we haven't.

And again, it reflects the commercial activities.

They have managed the RINs, program and do a great job at that.

We don't view that as a large determinant of our results.

Great.

My follow-up is really more of a logistics question, I guess, in terms of moving crude around.

Obviously, we've seen a lot of changes since the last call on the differentials.

I'm just curious, as you step up your shale share of your feed stock, how important is yield improvement relative to the differential in terms of how sticky your commitment would be to maintaining that very high level of share production?

And maybe any color around how it's changing your transportation thoughts and moving advantage crude to the different plants.

And I'll leave it at that.

Thanks.

Yes, I think clearly the second quarter saw substantial narrowing on the light crude, and several factors drove that.

So my comment is, we have a very large multipoint logistics system, refining system, and we take into account those current market signals, and we're adjusting our crude slates.

So the value of the shale crude in terms of its yield, its absolute price relative to other alternatives is what we think about.

So going forward, we still believe that those fundamentals are there on the supply piece as they continue to increase.

So we like what we've done on the logistics piece for our system.

We're going to continue to increase our options on that.

However, we are mindful of the current market, and we adjust our crude slates accordingly.

And we're making some of those adjustments now to really maximize the value of our system, and taking into account all the factors, yield, price, et cetera.

But fundamentally, we still see that inland crudes from Canada and North America will be advantaged, and we're going to continue to find ways to increase our ability to run those.

I'll leave it there.

Thanks.

Thanks, Doug.

Thank you.

Our next question comes from Evan Calio from Morgan Stanley.

Please go ahead.

Hi.

This is Manav Gupta for Evan today.

Given your unique and leading position as a North American engineering gatherer, a global chemical operator, and now the new MLP, do you see additional growth projects for NGL exports out of the Gulf Coast, and in propane and in butane and the heavier NGL battles that has occurred all the way across the global prices are much higher?

So exporting NGLs will ultimately support your [fuel] prices, and the infrastructure might even be MLP-able.

So anything along those lines?

Well, I think we have a stated position we want to grow our midstream business.

I think when you look at the breadth of our portfolio spanning refining, petro chemicals, NGLs, et cetera, we sit in a unique position, and I talk about weaving this web of infrastructure.

So we see both sides of this, and I think we said, in a unique spot to make these investments.

So we've talked about a new 100,000-barrel a day frack at our Sweeny facility, all the associated infrastructure whether it's pipelines, storage, and an export facility at Freeport.

So it's a multibillion dollar investment, as we think about this.

We're advancing the engineering on this project, but we see a clear opportunity, and one that we think that Phillips 66 can execute on.

And just follow-up on the crude by rail, you took delivery of 650 cars in this quarter and stuff.

So the [odds] between the Bakken and what's coming on the East Coast through the African crudes has closed a little.

So is your system flexible so you can move crude not only to the East Coast, but divert those cars to the West Coast, and now any other place you want, or it's more rigid when you have long-term contracts?

Specifically on the flexibility of the rail, that's why we like rail.

It's a flexible system.

So we have a lot of optionality, in that, and we have reduced our take on the Bakken to the East Coast as we've adjusted our crude slates, and replacing that with more competitive barrels from imports.

Thank you so much, guys.

Thanks again.

Appreciate it.

Thank you.

Our next question comes from Ed Westlake from Credit Suisse.

Please go ahead.

Yes, congratulations on PSXP.

Just wanted to just follow up on the prior question.

When do you think you would actually sanction this multibillion project, and what sort of, I guess, returns or EBITDA-type multiples do you think such a project would -- is the correct way for us to think about it?

So I think in terms of timing, Ed, that I think the fractionator is advancing, and we think about that as start-up in 2015.

So we're trying to bring that into a decision point from an FID in the early part of next year.

It takes a little longer on the export terminal, and so we're working that piece.

And I would look at the returns on these projects as what I would call typical midstream returns to be competitive in the MLP space.

So to be accretive to MLPs, and you look at transactions in the marketplace, 10 to 12 multiples in EBITDA are kind of the kinds of things that kind of have to be met from a cost of capital standpoint.

So clearly large investment opportunity, but we think these are very competitive from the midstream standpoint.

Ed, I'll let Tim answer that question, because whatever date he gave you wasn't going to be soon enough.

Right.

So you said a little longer on the export facility at Freeport, in terms of start-up beyond 2015?

Yes, beyond start-up.

I think that takes longer with permitting and additional work that has to be done down there.

Right, okay.

And then just you mentioned in the sort of opening remarks that product premiums were below and above benchmarks over time, and obviously that affects capture rates.

Is there any sort of dollar million number you could put around that in refining as we think about that, just to help on the modeling side?

Maybe versus Q1 or year-over-year?

I'm not sure we -- I can come back to you on that one, Ed.

I think you're talking about tens of millions of dollars sequentially between -- on the Gulf Coast, between the first and the second quarter.

But we can circle back around.

Okay, and then final question on your Louisiana refineries.

Obviously you've seen competitive results, which also suffer from RINs, but the refineries are EBIT positive, because probably they're situated over in Texas, and obviously you had you some downtime as well.

But maybe talk a little bit about how you can improve the profitability of the sort of Louisiana refineries, say, as more crude production comes out of Texas?

Ed, it really is around getting the crude slate more competitive.

And so we have in Louisiana quite a bit of light exposure, ALLS-based crudes.

And so the Eagle Ford connection that we've started moving more barrels there, and the charters that we took on the marine vessels are a key piece of that.

So we're increasing our utilization of really, you might say Texas-based crudes into that system, and I think that's really the shorter term opportunity.

Our view would be Ho-Ho will help alleviate the situation in Louisiana as well, when it comes on at the end of the year, but despite that, I think there's additional logistics capacity in it to really bring additional pressure on the LLS.

But our view continues to be that as these light oils make it to the Gulf Coast and they come into Texas, that that's going to continue to pressure.

So we're spending a lot of time thinking about how do we get additional amounts of those crudes into the Louisiana system.

So that really is the focal point for Louisiana.

Yes.

Thanks very much.

Thanks, Ed.

Thank you.

Our next question comes from Bradley Olsen from Tudor, Pickering.

Please go ahead.

Good morning, everyone.

Good morning.

I wanted to follow up on Ed's question about Louisiana refining operations.

Given the kind of persistent, stubborn strength we've seen in LLS over the last several months, are you finding that you're still processing, I guess, more than you would like of LLS crude?

And I guess put another way, between your tanking operations, as well as the opportunity to potentially take crude by rail down there in St.

James, do you have the opportunity to potentially displace all of the LLS imports which, at least according to EIA data, are now at a relatively low level?

You meant light oil imports essentially in our system.

We've essentially pushed that out.

Frankly, I think that my comment would be is, as we'll make the economic optimum decision, and if we need to bring in water-borne cargoes to optimize that, then we will.

But, yes.

I look at this, and there's no reason, as you look at the balances, to believe that the next 6 to 12 months that you shouldn't be able to really push on the Gulf Coast in general those light imports out of the system.

And we think ultimately that's what brings the pressure on the local production of the LLS-type of crudes.

And I guess in another way of asking that, the LLS benchmark, you don't believe, is going to see significant pressure from just rail volumes and the barge and tanker volumes alone?

You think that over the next kind of 12 months, we're going to need to actually see that Ho-Ho pipeline come online from Texas to Louisiana to really bring an end to the LLS premium that we've seen recently?

That's the short-term, largest volume impact that we see on the supply side of that.

And clearly, there's a lot of incentive for Bakken, for instance, to go to the Gulf Coast today.

So that has an impact as well.

I will say that I think the general shortage of light oil in the second quarter probably propped up that, the LLS because there was actually pull on that to the midwest as well.

Right.

Okay, great.

And you mentioned in your press release that RIN, or rather that product sales differentials reduced sequential quarter-over-quarter results in refining by about $200 million.

I realize that you don't want to give specifics around RIN exposure, but is it fair to say that those product sales differentials are largely composed of RIN-related costs?

No, I don't think so.

Greg, I don't know if you know what the specific numbers are, but what we were talking about there is the premium that we had been receiving for gasoline on the Gulf Coast shrunk in the second quarter versus the first, and the discount that we were receiving for our distillate sales on the Gulf Coast actually widened.

And I don't think that that was related or tied to RIN values increasing.

I think that just was market forces on the Gulf Coast and the value of, I guess the value of the products that we're selling declining relative to the US Gulf coast markers.

I think that's right.

Okay, great.

So I really wouldn't tie it to RIN values.

Right.

And generally speaking, when talking about RINs, they flow through refining reporting through the other line alongside the differentials?

Is that the right way to think about it?

Yes.

Okay, great.

And just, I don't want to belabor this point, but on the Gulf Coast segment, you did mention LLS specifically, but didn't mention Maya or heavier grade crudes as much.

Was the miss in the Gulf Coast really just an LLS-driven phenomenon, or did you feel some of the impact of tight heavy/light spreads in the second quarter?

And going forward into the latter half of this year, do you feel as though maybe some of the pressure that you felt in the Gulf Coast around LLS will ease as we've seen heavy spreads widen out in the last month or two?

So I would say the answer to that is yes.

I mean, clearly the pulldown in the light/heavy differential.

We run about 40% heavy on the Gulf Coast.

So that's a piece of it, and Maya was a large part of that.

I think the other thing, too, is around, we make about 40% distillate.

And so we saw distillate crack go down, and while the gasoline crack went up.

So I think there is a component of that in the miss also.

But clearly, we underperformed in the Gulf Coast.

Great.

That's, that's all for me.

Thanks a lot, guys.

Thanks.

Thank you.

Our next question comes from Jeff Dietert from Simmons.

Please go ahead.

Good morning.

Good morning, Jeff.

I was curious.

On the RINs activity, just for clarification, is 100% of the RINs requirement for purchases going on in the refining segment, and 100% of the blending in RINs generating activity going on in the marketing and specialty segment?

Or is it a little bit more of a mix?

Well, Jeff, this is Greg Maxwell.

I think you have it right.

Basically, all of the RINs that are generated through our blending activities show up as a benefit in marketing and specialties.

And then the cost of those RINs, or the value, if you will, are transferred over to refining.

So the refining segment reflects the full impact of the RIN costs during the quarter.

Good.

And have you seen the high price of RINs impact the supply of gasoline more broadly in the US?

Have you seen evidence of RINs discouraging fuel imports or encouraging fuel exports?

Have RIN prices gotten high enough to discourage gasoline production?

Are you seeing that evidenced in your portfolio, or in the industry more broadly?

Yes, I think on the industry perspective, I think utilization is still pushed to run, given the spreads that we've seen.

So I don't think that that's really affected the industry, the run.

So still a lot of incentive.

It has affected the mix.

Imports clearly have become more dear, as you've got to put a RIN value on that.

So you're kind of seeing some shifting around a little bit in terms of, say, where European producers would sell, where they maybe have gone to the northeast in the past, they may go to West Africa or some other markets.

And then you're seeing some of the production filling in that gap on the import side.

But it also still creates an opportunity on the export side of the Gulf Coast as well.

So the value of a RIN does impact the optimization about which markets and where you choose to sell, and I think you're seeing that across the system.

But with the market cracks where they are, it's still encouraging high run rates.

Good.

Finally for me, I was wondering if you could provide the opportunity loss and EBITDA for the Sweeny and Port Arthur outages for refining and for chemicals.

We can do that.

Yes, we've got that here.

Hold on a second.

You're looking for the lost opportunity, or what the cost is?

Correct.

For those being down.

We've got that, don't we, Greg?

Yes.

I'll get that you for you.

Maybe I'll address the chemicals piece.

Most of the change in the operating income for the quarter-on-quarter was, the majority of that change was due to the lost opportunity that we had in the power outages at Sweeny.

Secondarily, the impact of the Port Arthur extended turnaround was the other piece of that.

So that was -- the margin environment was still quite strong, so it really was about the volume impact.

Yes.

Jeff, if you look at loss/profit opportunities as we calculated it in the second quarter, it was about $175 million.

That $175 million is total for both Sweeny and Port Arthur, including chemicals and refining, all aggregated?

That is correct.

And it's our, obviously our equity impact from CPChem, and it also includes a small portion of midstream, but it wasn't really material.

Thanks for your comments.

You bet.

Thank you.

Our next question comes from Paul Sankey from Deutsche Bank.

Please go ahead.

Good morning, everyone.

Good morning, Paul.

I've got a couple kind of kind of deep-in-the-weeds question about sensitivities to changes that you've put on, I can't read it now, Slide 22.

But rather than go straight into the weeds, Greg, a high level question for you as CEO.

Was there a pattern of issues with the underperformance that you identified in the quarter?

Is there a concern here regarding your relatively low CapEx levels, and what you said was a tough quarter for you guys?

No.

I mean, we just look at the fundamentals, Paul, and we think that the advantaged crude thesis remains intact.

We do expect spreads to open back up later this year.

It doesn't change our investment profile in terms of putting advantage crude to the front of the refineries, through infrastructure, or increasing our ability to export, because long-term we think that's value creative.

Doesn't change our view on our midstream investments or our chemicals investments, and shifting more investment into these higher valued businesses.

So I would say that our views, the strategy remains intact from that standpoint.

The other thing I would say is there -- that the themes to the underperformance, the power outages, so we had an extended turnaround, major turnaround at Sweeny in the first quarter, which was followed by a power outage.

We had a second power outage in the second quarter.

And in my view, that's unacceptable.

And so we're working with the third-party power supplier to upgrade their systems, their networks.

We're looking at what we can do within refinery to recover from one of these incidents quicker around our own steam systems and balances.

There is a co-gen unit at Sweeny, it's running circa 350,000 megawatts, and we've used about 125 at the complex.

So we're looking to say, what can we do to island that facility?

Technically it's possible, practically difficult, but it can be done.

We're working, and finally, we're working to get a second supplier of power into that complex.

So that should be an event that is not repeated in the future.

And so I think, if you think, for me personally, and the biggest disappointment in the quarter was having a second power outage at Sweeny, which by the way, impacts all the way across our businesses.

So we have the refinery down, all the ethylene units were down, the frack was down.

So it impacted all three business platforms that we had.

We'll absolutely get that one fixed.

Yes.

Thank you.

I know how important safety is to you personally.

If I could go to this weedy question on sensitivities/ And apologies, it's kind of -- to do with the comparison between this year and last year.

One thing that stands out is that you seem to have flipped your sensitivity to the LLS/Brent differential from a positive last year to a negative.

But that would imply, obviously, that a widening discount of LLS to Brent last year would have been a negative, but this year is now a positive.

No, that's not right.

I don't know if -- that's not true.

I mean, LLS prices weakening benefit us.

Yes.

It just seems to have been the case last year that it was a $30 million positive if LLS went up.

Now it's a $20 million negative.

So I can -- let us work on that.

I mean, we benefit on the Gulf Coast when LLS prices weaken relative to Brent.

That was true last year, and that's true currently.

Okay.

I think we have to take a look at the slides to, Clayton that piece that you probably don't have the 2012 slide in front of you.

I don't.

The other thing you've done is you've dropped the sensitivity to a WTI/Brent differential.

Is there any particular reason for that?

I understand you've given plenty of detail here, but it's just one differential that's no longer on that sensitivity.

Well, we really broke that up between -- we really think about it on inland crudes to Gulf Coast crudes.

We have a WTI/LLS sensitivity, and then we have an LLS to Brent sensitivity.

We think about it that way, rather than going all the way from inland to international.

But let us do some work.

We understand that this quarter our number was quite a bit different from where a lot of analyst numbers were, and we take some responsibility in that, too, to make sure that we're giving you the sensitivities you need to be better predictors of what our earnings are going to be.

What also is not on these sensitivities are -- or the thing that there was no way of you knowing was the relationship between the product prices that we realized and what's implied by either LLS 3:2:1 or a midcon 3:2:1, where we're using Chicago-based products there.

So we're thinking about ways of providing additional sensitivities so that you guys are better equipped to predict what we're going to do on a quarterly basis, knowing that this business is complex and difficult to predict.

Yes.

I mean, I guess you saw preannouncements as well.

Was there any particular reason you didn't just preannounce?

I don't think we really believe in preannouncements.

I don't think you really should expect to us do preannouncements.

We think sensitivities and the relationships we have with you guys was good enough to help you get to right number.

Okay.

That's interesting.

Just, again, just hammering on this point a little bit, the gas sensitivity has changed.

Is there anything -- nat gas sensitivities.

Is there anything particularly operationally going on with that, or is it just a function of the basis between '13 and '12?

I don't know if it would be that we have a (multiple speakers)

Well, we've done a lot of energy projects, too.

That's true.

That we're trying to capture additionally.

It's a lower number now, isn't it?

Yes.

It's quite a bit lower, yes.

But let us take -- let's take this whole sensitivity issue up with you offline, and we'll see --

Yes, sure.

I appreciate.

It's kind of seriously in the weeds.

If we could look at the very big picture, this is the last thing for me.

3Q to date, you've got the wider heavies, you've got the wider Canadians, you've probably got less product prices.

On balance, 3Q to date is worse than Q2, or better?

You know we don't give (multiple speakers) I mean you know that.

You know better than the fact that we don't give quarterly guidance.

And so let's let the quarter unwind a little bit and see, before we have an opinion.

Yes, but what I was saying is not quarterly guidance, it's month-to-date, or quarter-to-date.

(Laughter) Yes.

I don't think we want --

Okay.

I'll drop it.

I don't think we want to give that.

Fair enough.

Thank you very much.

Thank you.

Our next question comes from Paul Cheng from Barclays.

Please go ahead.

Hey, guys.

Good morning.

Good morning.

Greg, just want to maybe confirm (inaudible) you're saying that 100% of your REN requirement is now currently showing up in your, the costs, or whatever, the implied costs, is showing up in your refining business, and that the 100% of whatever your brand is showing up in your wholesale marketing result?

That is correct, Paul.

The reason why I ask that, it seems that you're marketing, if that's the case, the results should be much better and refining should be far worse.

Based on your throughput level on gasoline and estimate on [world] diesel, you probably do about 1.2, million, 1.3 million barrel per day and you export about 181, accounting for 8.03% was the requirement.

That would suggest that for the quarter, your RIN obligation is about 315 million gallon, and that with the RIN cost in the second quarter of about $0.80, $0.85.

It seems like it should be a much bigger impact, than for both your marketing business in terms of the earning impact of the benefit, as well as the negative impact on refining.

I must be missing something.

I'll take a stab at it and then turn it over to Tim.

But as we've said earlier, with our commercial operations we're not going to signal to you whether we're balanced long or short, Paul.

But as far as the pure accounting perspective, that is exactly right.

As I said earlier, to the extent that we blend, we capture that positive value in marketing and specialties, and subsequently transfer that cost at market value to our refining organizations.

So the full cost impact for the RINs obligation ends up in our refining segment.

Tim, earlier, then, you were talking about how you have the flexibility on the rail system.

So with the volatility in the marketplace, how quickly that can you turn around and decide, I'm not going to ship you into this location, I decide to ship into another location, given your contractual obligation with the railroad operator and other peoples?

Is it 30 days that you can make the switch?

Is it three months?

Is it six months?

Any kind of rough number you can provide?

Generally, Paul, I would just say that you kind of fix your crude slate and you've got a period of time it takes for the options to develop in terms of the alternate supplies.

So this is shorter term versus longer term.

And then with our system, we have the flexibility to alter that, probably as fast as we can move the crude slate.

And I think that's the way we tend to look at that, realizing that in -- that the industry on pipeline commitments, et cetera, that you've got to schedule those out.

So that really is something that you've got, even the rail system, quite a bit of flexibility with.

So you, to reiterate, if I interpret your statement correctly, you would be somewhere between one to three months, because I mean to get the alternative, or is that -- probably would take that much--

It depends.

Yes, it depends.

It's probably on the shorter side of that.

Okay.

Greg, just curious.

One of your competitor was studying to build condensate splitter, and use the natural gas method, and then branded within their own system.

You sense that sort of a replacement of the light oil run in their refinery.

Is there any opportunity for you guys along that line?

Yes, so we've -- look.

I think we've said publicly we're not going to build a standalone condensate splitter, but we do have opportunities at our Sweeny facility, at our Alliance, Lake Charles assets where we think we can make some modifications and actually process more light oil through these facilities, and with minimal capital investment,.

But still, I mean, we think about where we want to spend our money, we're looking for 40% return type projects on the refining side.

And so we're looking for quick hit, fast payout projects.

And we have some underutilized equipment that we can kind of tie together and use that, Paul.

So we've got some projects around that that we're executing.

And when do you think you may be able to sanction one more [better] on those projects?

You mean in terms of the increased throughputs that we're looking at?

No, whether that you actually definitely go ahead with those project, and what type of CapEx and what type of throughput and what is the kind of benefit that you're looking at?

$30 million, $50 million type projects.

And they are underway.

They are already underway?

Yes, we actually do things like tie-ins at turnarounds and some other things.

So it kind of depends on the schedule, when things are available.

But those are plans that we have in place to make those mods in some of our refining system already.

What is the total capacity on the condensate splitter in those facility that we are talking about?

This is really -- I wouldn't call it condensate splitter per se.

Can just be idle cost, could be flash systems.

There's just a variety of ways to approach, primarily trying to drive lights out ahead of the crude column.

So it's not what I would -- it's not a new column per se.

It's really trying to see what's in the refinery to accomplish what you need to increase the ability to take out those lights, and then also looking at things to increase the, say the gas plant capabilities, to make sure that you can process that.

I see.

Okay.

Thanks.

If I can just make a proposal.

I am trying to understand the Tim, or Greg, what is the major difference in the RIN user compared to, say, the ethanol user back several years ago.

The industry has moved so that when you bill your customer, you will have in your invoice specifically identify how much he is charged on the output, and then what is the pass-through of the ethanol price, and given that everyone essentially has to pay for the RIN, why the industry is not moving into that direction so that from the consumer standpoint and the investment community standpoint, we know that this is 100% pass-through, and we won't get confused by the margin capture rate?

Because now that artificially the margin capture rate is lower, since that part of the RIN cost is perhaps in, at the outboard price already, and also that, I mean, you really want Washington, DC to act on it and change it.

You need to have a crisis and need to make sure that the consumer speak up and provide a transparent way, that seems is a more effective way to ensure something will get done in DC, because the consumer then realize how much they been getting hit.

Yes.

I mean, it is one approach, and to be explicit on the pump would be a great way for the consumer to realize what that means.

It's a competitive pricing business, and you're right, it has to be an industry kind of thing.

But it would be an interesting approach to highlight that.

And I think --

Because that would be one -- every single refiner, regardless, whether you are today balanced or not.

Next year you probably would be short.

Hey, Paul, I don't think we disagree.

We probably have to go onto the next question, if that's all right.

Okay, Thank you.

Thanks a lot.

Thank you.

Our next question comes from Arjun Murti from Goldman Sachs.

Please go ahead.

Thank you.

Just a question, as the Gulf Coast gets awash with light crude oil.

Can you talk about your ability or capacity to reship that stuff to the East Coast, especially if the differentials warrant it?

Yes, Arjun.

We have taken the charters on two marine tankers that allow us to move that product today from the southern Texas coast to Corpus into our system.

Clearly, as you go long haul to East Coast, the capacity drops because you've got longer haul times.

But I think it's all about the value, and where do we drive the greatest value?

So that's the optionality we do.

We do move from time to time cargoes from Texas up to Bayway, and so that's something that we've done and will keep open, but it really is part of our optimization.

And I think whether you use barge or other part marine will have to be a piece of the solution longer term on this.

Is there a, kind of a volume capacity you can do and order of magnitude kind of cost or tariff to do that?

That you can provide?

So yes.

I think we've said in the past $4 to $5 a barrel movement on Jones Act vessel.

We've said these vessels are -- each vessel's about 300,000.

Yes, and so depending on the length of haul, you're probably East Coast, we've not given that, but probably more on the order of $20,000 a day, and you can get a much better utilization on the Gulf Coast.

Clearly, if you're not using Jones Act vessels going to Canada, the cost drops to about half of that.

Right, and--

Arjun, I think our view is that because of the limitations on Jones Act vessels, that's going to push you to more barge and more rail, just to evacuate the Gulf Coast.

And I assume that it's Ho-Ho, or when Ho-Ho reverses that will free up barge capacity to increase volumes to the East Coast, again, if the differential warrants it?

Right.

That's part of what happens.

And as the supply increase in the Gulf Coast, clearly the Bakken's going to continue to clear the East and West Coast by rail.

Yes, great.

And then just a quick final one on stock buyback.

A nice bump in Q2 versus Q1.

Looking forward, do we think about this as sort of, if you have free cash flow, that's the quantity?

Are you kind of targeting a set amount, or a debt to cap ratio?

How do we think about the stock buyback go forward?

Well, I think one of the things we said on the call today, that we're going to finish the first $2 billion repurchase plan this year.

Okay.

And that we'll get started on the reload this year also.

So we're in the market every day, and you'll see us there.

Some days we'll buy more than others obviously, but we really don't want to put out a set amount of what we're going to buy every day, Arjun.

And going forward, in the out years, again, a free cash flow type metric is how we should think about it, or debt to cap, or both?

I think we think about the intrinsic value of the Company, and we see where we're trading now, and as long as we're trading at the discount that we currently see to what we think we're worth, you should expect us to be buying back shares.

Yes.

We're going to pay the dividend.

You should expect that we're going to increase the dividend every year, and then to the extent that we have free cash and it looks value accretive to us, we'll take shares in.

That's great.

Thank you.

Arjun, you saw that we did pay down the $500 million of the term loan.

We'll finish out prepaying that term loan, as I mentioned, this year.

So that will take our debt balance to roughly $6 billion, and put us at the low end of our debt capital target.

Got it.

Thank you.

Thanks, Arjun.

Thank you.

We have run out of time.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.