菲利普斯66 (PSX) 2014 Q1 法說會逐字稿

Welcome to the first-quarter 2014 Phillips 66 earnings conference call.

My name is Christine and I will be your 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 will now turn the call over to Clayton Reasor.

You may begin.

Good morning.

Welcome to Phillip 66 first-quarter earnings conference call.

With me this morning are Greg Garland, our Chairman and CEO, Greg Maxwell, our Chief Financial Officer and EVP Tim Taylor.

The presentation material we'll be using this morning can be found on our website in the Investor Relations section along with supplemental financial and operating information we think you'll find helpful.

Slide 2 contains our Safe Harbor statement.

It's a reminder we'll be making forward-looking comments during our prepared remarks and the question-and-answer session.

Actual results may differ materially from what we say today and factors that could cause these results to differ are included on the second page of the presentation as well as in our filings with the SEC.

My pleasure now to turn the call over to Greg Garland for some opening remarks.

Greg?

Thanks, Clayton.

Good morning everyone, thanks for joining us.

We're glad you're with us today.

We had another solid quarter.

Our Midstream and Chemicals businesses have demonstrated their earnings durability during the quarter.

We operated well across our businesses in Midstream, Chemicals and in Refining.

Also in Refining we completed our first-quarter major turnaround program this month.

We strive for operating excellence in everything we do.

We think that we protect and enhance shareholder value by getting this part of our jobs right, so we continue to drive improvements in personal safety, process safety, environmental metrics and reliability.

Adjusted earnings for the quarter were $866 million and we returned $2.2 billion of capital to shareholders.

We're making progress in building our higher value businesses.

In February we reached the final investment decision on the Sweeny Fractionator One and the Freeport LPG Export Terminal.

And in March we signed a significant LPG sales contract for this terminal.

We expect that the capital spend for these two projects to be just over $3 billion.

These investments are examples of how we plan to grow the Midstream business by leveraging on the capability and the infrastructure of our core assets.

We have the ability to expand the LPG export facility and we're already looking into other fractionator and condensate splitter options.

Also in March PSXP made its first post-IPO acquisition.

It purchased the Gold Line product systems and two refinery-grade propylene storage spheres which are located in Medford, Oklahoma.

These were acquired from PSX for $700 million.

This acquisition is expected to almost double the partnership's annual EBITDA.

The assets currently in Phillips' partners are key connectors to five of Phillips 66's core operating refineries.

Our intent is to get PSXP to scale so it'll have the balance sheet and the capability to be able to co-invest and ultimately invest in its own Midstream opportunities.

In Chemicals CPChem broke ground on its US Gulf Coast petrochemicals project which consists of a 3.3 billion-pound-per-year ethane cracker and two polyethylene facilities, each with an annual capacity of 1.1 billion pounds.

CPChem is the first to start construction on a new major US Gulf Coast pet-chem project and expect the start up to be in 2017.

In addition CPChem's 1-hexene project and a small specialty chemicals expansion in Belgium are expected to start up during the second quarter this year.

Regarding Refining, we continue to find ways to provide crude supply optionality to our refineries.

At the Bayway refinery we have a 70,000-barrel per day rail rack which is expected to come online in the second quarter.

In our Ferndale refinery a 30,000-barrel a day rail rack will start up later this year.

We've ordered another 1,200 railcars that will be dedicated to crude in addition to the 2,000 we already have in service.

We expect to start receiving additional cars this summer and by early next year we'll increase our crude by rail capacity to about 160,000 barrels per day.

We've also reached agreements with several third-party logistics companies to deliver more advantaged crude to our refineries.

We've secured 20,000 barrels a day of rail loading capacity in Hardisty, Alberta and 10,000 barrels a day in Casper, Wyoming all focused on Canadian crude.

Both of these facilities will be operational later this year.

In addition, we have a 20,000-barrel a day agreement with Plains in Bakersfield, California to put advantaged crudes into their pipeline system for delivery to our refineries.

This facility will also be commissioned later this year.

For pipelines we've entered into an agreement providing more access deep into the Eagle Ford.

We have secured 30,000 barrels a day of turn space on the South Texas crude pipeline, which includes capacity through a Corpus Christi marine terminal further enabling us to shift Eagle Ford to our Gulf and East Coast refineries via our Jones Act vessels.

In addition this agreement complements the commitment we already have on the Kinder Morgan pipeline that supplies up to 65,000 barrels a day of Eagle Ford to Sweeny.

We believe that returning capital to our shareholders is fundamental to creating value and it's an important part of our strategy.

Since the formation of Phillips 66 we've returned $6 billion to our shareholders.

This includes $3.2 billion in share repurchases, $1.4 billion for the PSPI exchange and we've almost doubled our dividend.

Our board has authorized 5 billion of share repurchases, we have 1.8 billion remaining.

Through this quarter we've purchased about 42 million net shares and with the PSPI exchange we reduced our outstanding shares by close to 10%.

As we disclosed in our analyst meeting, we expect 40% of our capital allocation to be for shareholder distributions while reinvesting 60% back into our businesses.

Including our share of expected capital spending by DCP, CPChem and WRB, over the next three years our capital program is expected to be $16 billion with over 70% directed towards Midstream and Chemicals opportunities.

So with that, I'm going to hand the call over to Greg Maxwell.

He'll take you through the quarter results.

Greg?

Thanks Greg.

Good morning everyone.

We start on slide 4. First quarter adjusted earnings rate $866 million, or $1.47 per share.

A $696 million non-cash gain recognized in the exchange of Phillips specialty products, or PSPI, was the main adjustment to earnings this quarter.

In addition consistent with last quarter, PSPI results are included in discontinued operations and as such are not part of our discussion today.

Adjusted cash from operations for the quarter were $1 billion.

We will cover this in more detail when we get to the cash flow chart.

For the quarter we paid $229 million in dividends and we repurchased 8.4 million shares of our common stock for $640 million.

We also took in another 17.4 million shares through the PSPI exchange.

On an adjusted basis our annualized 2014 return on capital employed was 13%.

Slide 5 provides a comparison of our first quarter adjusted earnings with last year's fourth quarter on a segment basis.

Compared to last quarter our earnings increase of $58 million was driven by improved results in Midstream, Chemicals as well as Marketing and Specialties.

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

The Midstream segment posted higher earnings this quarter compared with the fourth quarter as all of our Midstream businesses had improvements.

The annualized 2014 adjusted return on capital employed from Midstream was 22%, and this is based on an average capital employed of $3.5 billion.

Slide 7 shows Midstream's first-quarter earnings of $188 million, an increase of $67 million from last quarter.

Transportation made $62 million this quarter, and this is up from last quarter due to higher throughput fees and higher railcar rates.

Operating costs were lower as well contributing to the improved earnings.

DCP Midstream's earnings increased by $46 million primarily due to equity gains from DPM's unit issuances to the public, lower operating costs and also higher natural gas and NGL prices.

In addition our NGL business line was also improved due to stronger propane prices.

In Chemicals CPChem ran well overall.

The global olefins and polyolefins capacity utilization rate for the quarter was 93% and benefited from strong margins, while the SA&S business was able to capture higher earnings following last quarter's benzene turnaround.

The annualized 2014 return on capital employed from our Chemicals segment was 30% and this is based on average capital employed of $4.2 billion.

As shown on slide 9, first-quarter earnings for Chemicals were $316 million and this represents a record quarter for our Chemicals business.

In olefins and polyolefins earnings were up mainly due to improved realized O&P chain margins and higher earnings from CPChem's equity affiliates.

And this was partially offset by lower ethylene volumes.

The $29 million improvement in specialties, aromatics and styrenics was primarily due to higher benzene production from the absence of turnaround activity completed in the fourth quarter of last year as well as stronger margins in the first quarter.

Moving on to Refining.

Our realized margin was $9.88 per barrel, the global utilization rate was 90%, and our clean product yield was 84%.

The annualized 2014 adjusted return on capital employed for Refining was 9%, and again this is based on an average capital employed of $13.5 billion.

The Refining segment had earnings of $306 million and this is down from last quarter's earnings of $418 million.

This decrease is mainly due to lower volumes as a result of planned turnaround and maintenance activities as well as overall weaker realized Refining margins.

The Atlantic Basin region was up as Bayway was back online following a major scheduled turnaround last quarter.

This allowed us to capture the higher crack spreads in this region.

In the Gulf Coast earnings were down largely due to planned turnaround at our Alliance Refinery.

The decrease in the Central Corridor was mainly driven by the narrowing of Canadian crude differentials as well as downtime at the Borger and Wood River refineries.

Western Pacific's decrease is primarily due to narrowing crude differentials of domestic sour crudes relative to ANS and planned turnaround activity at our San Francisco facilities.

Other Refining had a positive earnings impact of $38 million this quarter compared to a loss of $49 million last quarter.

The first quarter earnings were largely driven by improved commercial results and lower costs.

Next let's look at our market capture on Slide 12.

Compared to the market our realized margin was 79% this quarter.

This is down from 109% in the fourth quarter.

On a regional level the biggest movements were in the Central Corridor and the Western Pacific regions.

And you can find additional regional information in the appendix.

As many of you know our refineries are configured to produce more distillate than the marker assumes.

With the overall strength in the crack spreads more weighted towards gasoline than diesel this quarter, our configuration was a negative impact compared with the market.

The secondary products losses of $5.14 were lower by $0.40 per barrel this quarter compared to the fourth quarter and this was driven mainly by improved NGL prices in the Central Corridor.

The positive feedstock impact of $4.18 was about $0.40 per barrel less than last quarter and this was largely resulting from the overall narrowing of crude differentials.

The largest swing compared to last quarter is in Other.

The $0.91 per barrel negative impact shown on the chart compares to a positive impact of $1.52 per barrel last quarter.

Included in Other are impacts from product realizations, inventory and RINs.

These first two items were the main drivers for the change due to the seasonal activities.

We had negative inventory impacts this quarter as we built inventories compared to inventory draws in the fourth quarter.

And clean product differentials were less favorable as blending of intermediates and butanes were reduced.

Slide 13 shows the comparison of advantage crude runs at our US refineries by quarter on the left and by year on the right.

During the quarter 91% of the company's US crude slate was considered advantaged and this compares with 94% last quarter.

The decrease was mainly due to processing less coastal domestic crudes in the Gulf Coast due to planned turnaround activity and also lower heavy crudes in the Central Corridor region.

These decreases were partially offset by increases of Bakken crude that was processed at our Bayway refinery.

This next slide covers our Marketing and Specialties segment, or M&S.

Worldwide marketing margins were $0.037 per gallon in the first quarter.

Our Specialties business had lower margins, and we'll cover this in more detail in the next slide.

However, before we move on I wanted to make you aware of a reporting change we made impacting both the Refining and the M&S segments.

Specialties previously only included our finished lubes business, but effective January 1, 2014 we moved a base oil joint venture as well as the commission revenues related to needle and anode coke into this business line.

These specialty businesses were previously reported in Refining.

We've also made these changes retrospectively so that our prior period results reflect these changes.

In addition as mentioned earlier, PSPI results are reported in discontinued operations versus being included in the M&S segment.

The annualized 2014 adjusted return on capital employed from M&S was 22% on average capital employed of $2.4 billion.

Slide 15 provides some additional detail about the M&S segment.

Adjusted earnings per M&S in the first quarter were $137 million, representing a $32 million increase from the fourth quarter.

The increase is driven from earnings in Marketing and Other, largely due to improved US margins that were partially offset by higher costs and lower volumes.

During the quarter our refined product exports totaled 139,000 barrels per day, down from 197,000 barrels per day in the fourth quarter.

This decrease was mainly driven by the Alliance Refinery turnaround as well as more attractive inland prices.

Specialties earnings were $44 million this quarter, a $7 million decrease from the fourth quarter.

This decline reflects lower base oil margins, partly offset by improved lubricants margins.

Moving onto Corporate and Other.

This segment includes net interest expense, it includes corporate overhead costs and it also includes technology and other costs not allocated to our operating segments.

Corporate and other costs where $81 million after-tax for the first quarter.

And this compares with $97 million last quarter.

The improvement of $16 million was partly due to lower environmental accruals and tax impacts.

Moving next to our first quarter cash flow.

Starting on the left, adjusted cash from operations was $1 billion.

Note that this excludes working capital and the impacts of the WRB special distribution.

Adjusted working capital changes were a negative impact this quarter largely due to building inventory.

The $1.2 billion special distribution from WRB resulted from Cenovus prepaying it's partnership contribution obligation to the joint venture.

During the quarter we funded $572 million in capital expenditures and we paid $229 million in dividends.

In addition we repurchased $640 million of our shares through the share repurchase program and an additional $450 million of cash was associated with the PSPI share exchange.

And we ended the quarter with a cash balance of $5.3 billion.

As for our capital structure shown on the next slide, we ended the quarter with equity of $21.8 billion and debt at $6.2 billion resulting in a debt capital ratio of 22%.

After taking into consideration our ending cash balance of $5.3 billion, our net debt to capital ratio was 4% at the end of the quarter.

This concludes my discussion on the financial and operational results.

I'll now cover a few outlook items.

In Midstream, DCP Midstream has started work to build the Zia II plant, a 200 million-cubic-feet-per-day sour natural gas processing plant that's located in the Permian Basin region.

For the second quarter we expect global utilization rates for both Chemicals O&P and Refining to be in the mid-90s.

With regard to turnarounds our pretax turnaround expense is expected to be about $400 million to $450 million for 2014 and about $70 million in the second quarter.

In Corporate and Other we expect this segments after-tax costs will run about $100 million per quarter and the overall effective income tax rate is expected to be in the mid-30%s for the second quarter.

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

(Operator Instructions)

Jeff Dietert, Simmons.

Good morning.

Good morning.

Westlake announced its plans to drop three ethylene plants into an MLP and I was just curious if you could update us on your thoughts as far as that potential outlook involving -- obviously you've got the ethylene plants and experience with MLPs.

Jeff, yes, thanks.

We saw that announcement.

I think it probably makes sense.

I think you'll see more people considering that as a vehicle and a tool to use in the portfolio.

I'm not sure we would completely rule that out as a value creation opportunity for CPChem, but as you know we have a partner there and it would take agreement on both sides for us to proceed on something like that.

I understand.

Secondly, on condensate splitter economics I was wondering if you could share your thoughts on how economic those splitters are at this point based on the discounts you're seeing for condensates and perhaps provide an update on your potential interest in a project there?

Let me make a couple general comments while Tim gathers his thoughts and I'll let him give you some of the details.

We continue to be interested in conde splitters.

We think there's a place for them.

When you look at the asset infrastructure that we have and what we're contemplating building I think we're in a great zip code to create value by doing that.

I think the other thing I would say around condensate splitting is point in time forecasts are always dangerous.

So we always try to look to see where is it going and we think over the long-term that we can create value by doing that.

Yes Jeff, I think we looked at condensate splitting and there are a number of options, one's within the refinery system itself at a refinery and as the light content goes up in the blender there there may be an opportunity and a need to address that.

But what we're really focused on and we talked about was our initial thinking around a larger condensate splitter in the Sweeny area where you're close to the increasing condensate production in West Texas and the Eagle Ford.

There we just look at it and say that a splitter that goes into products provides a larger margin than one that just tops that and exports or uses the top crude so to speak in the system.

I think we are still looking at both of those options, but we like the idea of a splitter that really separates the condensate into components and you get quite a yield of naphtha and distillate cut with lesser amounts of LPG and heavier fractions off of that kind of system.

Still in evaluation.

I think Greg said it well.

We're going to look at the margin opportunity and the collection system, but collectively we see condensate production increasing and we see an opportunity there on both the transportation, the splitting side to be a piece of that.

Thanks for your comments.

Thanks Jeff.

Ed Westlake, Credit Suisse.

Yes, obviously you just had the analyst day and laid out a wealth of opportunities in the MLP space and also in the chemical space.

But the Refining performance I guess in the first quarter was a little weak and the slides you've released are helpful, but if I look at the slides you've laid out you do all the regional stuff as well.

There's that swing in Other but it doesn't include the opportunity costs from maintenance.

So I'm just wondering do you have a number for the fourth quarter of what you think the opportunity cost that you lost was for maintenance particularly in the regions which underperformed?

I think the margin loss is around $90 million, just south of $100 million, Ed.

Right.

That's helpful.

And any particular split mainly in the -- I guess Alliance was down but also some Central Corridor as well?

It's on the Gulf Coast.

Because we had the crude tower down at Lake Charles also.

So we bought VGO to keep the refinery running and you can question how much value we created by doing that, but I think at the time we set the plans in place that looked like the right things to do.

Then we had some weakness in California.

We also had, Ed, a major turnaround at Borger.

So really when you look at both the MidCon and Gulf Coast you had major turnarounds there and we've come back from there.

But those were big impacts both on the cost side as well as the margin side.

Right.

And then coming back to this condensate theme.

Borger, Ponca, probably Sweeny, you're probably buying what's marketed to you as WTI and then it turns up and it is not your old WTI they used to buy because the components of the feedstock are getting much lighter.

Can you comment a little bit about where we are, you think it terms of the tipping point in terms of WTI becoming maybe even above the spec of 42 API and therefore the need to have separate infrastructure for some of the super light stuff?

Are we at a stress point today, do think you that that's going to occur as you look out?

I don't think there's any question that people are blending condensate into TI as a way to move those volumes to market.

We have not cut rates at any of our facilities.

As you know we have strong quality control.

We know what we're buying and we typically get what we want and we go directly to lease and buy and we think that's one of the strengths of our system that we have in terms of running those MidCon facilities.

And we'll see.

I think it's probably early to say you need a separate infrastructure for condensate and condensate movement.

I think we'll continue to watch that.

But at this point in time I think we're getting the right feeds to the front end of our refineries and we don't see an issue with it.

Thanks, very helpful.

Doug Leggate, Bank of America.

Good morning.

I appreciate you taking my questions.

Maybe I could start off with the standard boilerplate portfolio question with -- then I had a couple of data points this morning with yourselves seeing the Whitegate processes coming to an end.

We also had one of your competitors saying they've got some interest on the West Coast, so I'm curious what was the next step now for Whitegate?

Do you move that to a terminal, liquidate the inventory?

What's the process now and latest thoughts on the West Coast and I've got a follow-up please.

Okay.

We said at the Analyst Day that we had limited interest from people wanting to buy the Whitegate facility.

We have an obligation to run that facility via contract through mid-2016.

So I think we'll continue to work options around that facility.

As you know it's the only refinery in Ireland.

It produces 40% of the Irish fuel needs.

I suspect that there's an answer out there for Whitegate and we'll continue to work that with the Irish government.

The other thing we said around Whitegate is there was some interest in splitting Whitegate and Bantry Bay, and so we're continuing to run a second step process around Bantry Bay and we'll see where does that go.

But I suspect we get that done this year.

And then West Coast, our focus around West Coast is running it well.

I think we're a good operator, we operate well.

I think our assets are well-positioned.

So our focus really is on improvement and getting advantaged crude to the front of those refineries.

And we gave you some data points today on some of the work we're doing to get advantaged crudes to those firms, refineries who are making progress and there's -- but there's more to do.

We are not through yet.

Okay.

My follow-up is you guys are obviously very unique on a number of levels but particularly because you're not putting a lot of money to work in your Refining business.

I guess that's still the biggest driver of your cash flow I would argue.

And so when I look at your prospective buyback, your outlook to basically sustain the buybacks, I know it's a little inexact so to speak in terms of being able to predict it, but as things stand today looking forward under the current environment, do you see a scenario where the buybacks really don't -- you need to slow them down or do you think you can sustain these buybacks for an extended period, given where your balance sheet is?

As long as our shares trade below our intrinsic value we're going to take shares in.

And so we're buyers of the shares today.

Would you be prepared to see your balance sheet move up to the top end of your range if you sustain that?

I think given -- if we have a 2008, 2009 I think we've said consistently we're willing to go the balance sheet to fund our growth and our shareholder distributions.

But if we're at mid-cycle type conditions we're going to gen $4 billion to $5 billion of cash a year and we think that sufficient to do the programs that we've laid out.

All right.

Thanks, I appreciate the answers.

Evan Calio, Morgan Stanley.

Good morning.

Big quarter in Chemicals.

I have a macro question there.

Recently Enterprise announced an ethane export facility, it's targeted to be online before your cracker comes online.

So do you have any comment on ethane exports and whether these facilities alter your longer-term ethane surplus view?

Or maybe your competitive advantage versus exports on a cost curve and first mover status?

We continue to look at ethane exports closely.

We just don't think they make sense economically.

I go back to the past decade in the Middle East where ethane was free and no one could make it work with free ethane.

And now we're talking about playing an arb between Henry Hub gas and European prices.

So we'll see where does that go.

You may see more ethylene exports and more interest in ethylene exports and certainly I think the European pet-chems are interested in propane and butane for feedstocks as they're trying to access North American energy revolution as you think about that.

But let's just say you can make it work and you can put ethane to the facilities in Europe that could absorb it.

In our view it's between maybe 200,000 to 300,000 barrels a day, which is about what we think is being rejected today.

So our view is it doesn't offer the balance in the US in terms of ethane.

Tim, if you want to go any deeper, it's fine.

No, I think the only thing, Evan, is if you have ethane exports it probably does provide some support on the pricing side to bring it up.

And so I think it provides another option, but we don't see that level really driving a whole new supply/demand balance on the ethane side of the business to really force that.

So some narrowing perhaps, but still a substantial advantage in North America.

Great.

I appreciate that.

And my second is a few refining questions if I could.

Any color on the Wood River debottlenecking project announced by your partners today?

And secondly, Borger utilization going forward, should we see that as higher?

I know there's been heavy turnaround, but it's been heavy turnaround for -- or planned/unplanned for the last year or so.

I just want a status of how we should think about that.

Is it going forward?

I think we've got work to do at Borger.

I think that's one asset we can run better.

We've got a lot of focus around that internally.

I'll make a couple comments on the Wood River expansion.

As we premised the coker refinery expansion project, we actually premised that on syn-bit.

And because of economic reasons we've been running on dil-bit.

So we've hit condensate limits and haven't got the capacity expansion that we expected for all the right reasons.

So there's some what I would say is modest capital that they can go in to remove those constraints that would allow us to get to another 20,000 barrels day of capacity out of that asset.

We think it makes fundamental sense.

It's good economics around that project and that's something that we want to do.

Is that 2016, is that 2015 or what time frame on that?

Wood River?

I'll come back to you on that, Evan.

I'm not quite sure

It is in that range.

We'll find out and get back to you at the end.

Fair enough.

I appreciate it guys, thank you.

Paul Sankey, Wolfe Research.

Good morning, everyone.

I was just checking my watch, thought maybe it was afternoon.

It's been a long day so far.

Feels that way.

Going back to some of the stuff you were talking about specifically on assets for sale.

The general message I've heard from you is that you want to reduce the relative share of Refining in your overall portfolio.

Does that mean that we should think about the whole asset base as potentially for sale?

And I know you haven't been long from an analyst meeting, but things do change fast in Refining.

Would we consider you as potential seller of anything that the price is right?

Or is it going to be limited to trying to rationalize in California and Ireland and the stuff that you've been more specific about?

I think we've been pretty specific around the assets that we're interested in going to market with.

The core assets we have are solid assets.

They generate tremendous cash flow and we can take that cash flow and execute our strategy of transforming the company into a midstream logistics chemical company with a great refining business in it.

So I wouldn't say that we would continue to go through and wholesale sell the assets.

We like our position.

We like the legacy infrastructure and frankly they're in the right zip code to create value.

And as we look across these value creation opportunities, Sweeny creates an opportunity for the hub, for an NGL center as you think about that and an export center at Freeport.

And I think having the assets at Sweeny is an enabler for us to do that.

And so as we said we're looking for value creation opportunities where we can leverage existing core infrastructure that we have.

I guess what I was driving at is just the general idea that you are trying to rebalance the capital employed in the company and therefore the extent to which you would do that additionally opportunistically in order to get towards that rebalanced level.

But you answered the question, Greg.

On the market, could you talk a little bit about the demand side of the equation?

I think you've referenced some of the more -- some of the ethane stuff, but if you could also talk about what you're seeing for gasoline and distillate?

It looks strong and if you could give us your export numbers and the very latest on how much product you're sending out that would be great.

Thank you.

I think on the demand side we're encouraged by what we see on gasoline.

It's been a tough winter in the mid-Atlantic and Northeast, but I think as it's warmed up you'll see that.

But across the US you look at the numbers and you're seeing some improved demand here as the economy picks back up.

And then exports continue to be an opportunity and I think we look at it as opportunity from the standpoint that we'll supply the markets with the best value.

So we continue to see good opportunities in the export business.

We were down, as we said, this quarter from the fourth quarter to 137,000 and that really reflected less coastal production in the Gulf Coast for us up at Alliance, and it reflected the fact that we had some better opportunities in the US.

So I think that we're still pushing forward with our plans to get up to 550,000 barrels a day of export capacity and I think you'll continue to see us over time have an increasing proportion of our production go into the export markets.

And that I think reflects what you have to say will be probably, if you've got good market crack, strong operating rates in the business.

So I think the industry as a whole will continue to push exports into that market because of our cost advantages.

When you have -- it sounds like you're somewhat supply constrained and so your exports were lower, but you also said there were better opportunities elsewhere within the US.

Is that typically in East Coast trade that you are undertaking from the Gulf Coast to the East Coast, or is it Gulf Coast to MidCon or where are the outlets, where does the product go when it's got a better offer somewhere else within the US?

I still think the East Coast is still a clearing market certainly into the Midwest a bit.

But the strong part is -- continues to be the Colonial system and the waterborne opportunities to the east.

And on a macro level you think about imports and where that comes.

That's also make sense that we push out the imported piece of that and supply out of the US.

That's great.

Just finally for me, other non-conventional -- not the right word, but non-gasoline, non-distillate product trade.

Can you talk a little bit about the extent to which you are exposed to that?

I'm thinking propane and everything else.

Yes, so the LPG output, the refineries, we have an NGL business world yet, so propane is an important component for midstream and for the refining piece.

Clearly we saw first quarter movement propane prices with the winter demand, that's come off and then as we've increased the connection of propane to export markets, I think that provides another outlet as the length in propane grows with NGL production.

So I think that that will continue to pull someone on that one.

Coke demand, or coke is the other big product, co-product so to speak, and that really trades off of fuel value in most instances on some of that.

But then we have the upgrades to anode coke and those are still premium markets for us.

I would say that we're seeing relatively stable demand there and pricing moves in a much different dynamic than it does in relation to crude.

But the coke is not for export, right?

Coke, we do supply global markets as you look at our coke business, particularly for our needle coke, which is a very high specialty coke that's got high strength for recycled steel production.

And that's really Humber and Lake Charles, that's a global market.

And then we do have coke markets that are really global around the world for both anodes and in the fuel markets kind of clear where it makes sense.

And asphalt is not a big deal for you?

Asphalt is not a large piece of our operation.

Okay, great.

Thanks very much.

You'd think it'd be at Wood River once the core project was completed that really chewed up a lot of the asphalt that we had to produce it with.

My channel check is actually a lot of people mending roads around these parts.

(laughter) All right guys, thanks a lot.

Thanks Paul.

Paul Cheng, Barclays.

Good morning.

Greg earlier that you were talking about and doing your Analyst Day 40% cash distribution for the cash flow.

Do you have any long-term targets between the split on dividend and buyback?

We haven't really -- we haven't been specific on what percentage of that 40% would be dividends versus repurchases.

Obviously in the near term the majority has been on share repurchase.

We would expect over time dividends to be a greater piece of that 40%.

But there's no internal target that --

We definitely have some internal targets, we just haven't shared.

Never disclosed it.

Okay.

That's fair.

We have not disclosed it, no.

For Bayway, is the yield going to be any meaningful difference between you running Eagle Ford or running Bakken?

And how that economic may be different?

Yes, I think we can run both clearly.

I look at it first we've got more capability to deliver the Bakken crude by rail and it actually fits the Bayway kit very well.

So we like that.

Eagle Ford depends on the grade, but clearly lighter.

Probably has limits faster and so I think we'll continue to supplement Bayway with Eagle Ford, but really Eagle Ford for us we like the runs in the Gulf Coast on that crude.

But increasingly we'll keep thinking about that.

But we'll typically run into probably more constraints on Eagle Ford before we will on Bakken.

This is on the LPG side, Tim?

Is it LPG handling when you run -- you're saying that you --

It's the light piece.

It's the relative value of the yields that you get on the two and clearly as LLS becomes advantaged in the Gulf, it creates another option for us to look at in Bayway.

And we've done a bit of that and so that's really driven off the economics of shipping and relative value in the refinery.

But that's been a -- that could be a nice crude fit for Bayway as well.

People asked about earlier I think on the chemical side whether is MLP or both for you guys.

Of course at that you run into some constraint with your partnership with Chevron.

But there's other asset like the wholesale of some other people, there's also dumping it into the MLP.

Have you look at that given you have a pretty large base off of EBITDA sitting there?

In the wholesale business?

Yes.

We've looked at that.

So I think that that's probably on the list of things we consider.

We have a lot of assets that are MLP-able and we're working our way down the list there, Paul.

But that you would not have any resistance in that it could belong to a MLP structure if you believe that there's better valuation.

We wouldn't put in there.

Is just a question is that the right value?

I see.

There's also, if you think about it, there's some variation or variability in wholesale marketing earnings that we don't have in any other assets that are currently in PSXP.

So will you assume that that, even if you're going to do it will be two ways to tell then after you done with more of the traditional logistic output?

I think there are probably better assets that we're looking at to drop first before we get to wholesale marketing.

We've got pretty big inventory of things we can work through, plus the things that we're investing in that should come on.

I don't see it close to the top of the list.

No.

We haven't included that in our estimates -- EBITDA either.

Frankly there's other things within the refining system too that we have the opportunity to think about also.

In the Gulf Coast I think you are currently buying on average a feedstock 70,000 to 80,000 barrels per day.

And Bayway is probably about 40,000, maybe 50,000 barrels per day up to.

I think that one of your peers that as a result decide that they want to expand their crude units so that they don't need to buy the feedstock.

Is that something that you guys is currently consider or that is different in your system?

Paul, I missed the first part of the question about what we're buying.

I think that if we're looking at that between your crude oil intake and your total throughput it seems to suggest that in the Gulf Coast you are buying a VGO or other feedstock by about 70,000, 80,000 barrels per day in the Gulf Coast.

And Bayway I believe you are probably buying about 40,000, 50,000 barrels per day.

So in other words that's a real -- you could expand your crude unit so that you can eliminate the feedstock purchase.

One of your peers definitely is doing it.

Just wanted to see whether those are the investment you guys are currently considering or not?

You're correct, we do buy supplemental feed to fill out the units, but we have not really advanced to point that we say we'd like to make additional investment in crude distillation capacity to supplement that.

It is an opportunity as we go forward, but we'd like to get little more, deeper view I think on what we think that value is going long term.

That's something too that's tied to that conde splitter.

If you think about the bottom end of that.

It is supplemental feed.

The bottom end is gas oil that comes off and so you could use that as a -- impact the economics.

So Paul, as you know we've been reluctant to invest in Refining.

I think I'd point people probably challenge us to say are you underinvesting in Refining?

But it still as we look across the opportunity set of investments that we have we like this opportunity set and we're just prioritizing and going after the higher valued investments first.

Sure.

And do you -- I'm curious that in the second quarter West Coast margin is phenomenal because a number of your peers that have downtime.

In the second quarter do you have any meaningful downtime in your refinery in the West Coast?

We don't really provide guidance on where we're going to be down.

But if you just look at the turnaround expense for the second quarter guidance I think it was $70 million.

So it's about one-half of what it was in the first quarter.

We typically take our big turnarounds in the first and the fourth quarters.

And final one, any rough estimate what is the total PADD three crude storage capacity?

(Laughter) What about it, Tim?

Pipeline fills and lots of storage tanks.

I think that you're going to continue to see that.

But I have not done the exact math on that, Paul.

You don't have everything on the fingertip?

(laughter) Alright, thank you.

We suspect it's filling up.

We're not positive.

(laughter)

Thank you very much.

Thanks Paul, take care.

Roger Read, Wells Fargo.

Good morning.

I guess maybe keeping on with the theme here on the light sweet side, maybe not specific numbers barrels of storage, but what do you -- what are you running today versus what do you think your capacity is across your system for the light barrel?

Even if you include California where maybe you can't quite get the barrels there today, how do you look at the future opportunity of price advantaged barrels?

Light sweet for us is we've got on the global side light medium 65% of our input.

And really if I look around the system we're running light where it make sense today.

You look at the blending where you can do to increase that and probably the place where I like to think about it though is Bayway where can we continue to push out additional imported light at that system?

But the Gulf Coast it's really now mostly domestic light for us.

And so it's a question of which grades and then do we start to work on the kit to increase that?

But we still have a lot of innate capability I think to absorb more into Bayway.

And that's been our first thinking about how do we increase the access to that.

Continue to push those into the West Coast, particularly into Ferndale as well.

And then California for us is really a heavy type of market.

So we're increasing the connectivity there.

But I think we've got capability to keep ramping that up, but it's -- so it's something we really haven't seen that says we've got to constrain what we want to run to make them right values in our Refining system.

That's really what drives us is heavy -- heavy and heavy probably makes the most sense.

And I think you've got the dynamic between light and medium and right now I think that we've had a lot of optionality on the light side and we just kind of optimize around that.

We've said somewhere that there may be 100,000 to 150,000 barrels a day of incremental domestic light sweet crude capacity that we're trying to get to that hasn't been filled.

Okay.

And then light against medium would be an additional number of barrels beyond that number?

That's right.

Just assume that we'll continue to run medium based on what we see in the structure today, but should that change that could push on that.

Okay.

Then I was a little late onto the call.

The Midstream business had a great quarter.

Have you addressed why that was and what the sustainability of that performance was?

I apologize, but if not, can you walk us through what helped that performance out this quarter?

I think it's in several different buckets.

Obviously a strong NGL price is $1.06, volumes are up at DCP about 10% I think as you think about that.

A lot of it is driven by equity gains at DCP.

They did a $1.1 billion acquisition at the DPM level which created equity gains that pulled back up.

So that was a big piece of that.

Our transportation business had a better quarter.

Essentially volumes were about equal I think, but certainly rising revenue as we continue to work the fee structure.

Okay.

But in terms of thinking of this it's a high point at least in the near term.

We should see something more like the back half of 2013 in terms of a sustainable performance from Midstream?

I think we expect that NGL prices do come off some because they're driven by seasonal propane demand for the most part.

But yes, I would think it would return to something more normal.

Roger, you wouldn't expect the unit gains to continue.

You know they read at $23 million for selling the -- again as Greg said that's associated with the big drop.

Right.

Okay.

Then final question just on the rail capacity side.

So you've got 1,200 cars.

We've obviously had the announcement of some changes and what's required in terms of railcar design, but it's not necessarily a given what that's going to be.

Can you give us an idea of where you stand, not just on the crude moving side, but also on products if we have an issue with cars?

When your overall fleet would be compliant with the DOT 111A kind of design, if that's what is ultimately going to be the car that gets used everywhere?

The new crude cars do meet that standard.

So that increment.

And then within our existing fleet the thing and where it would go that they're looped in other services.

If something came there could be some need to change or modify those cars, but it's a relatively small percentage on the product side.

We've got a lot of cars that are in service in terms of bulk movements of solids as well as tank cars.

So it's really the crude cars.

We feel very good about the ones we've purchased.

And then we would have some amount of our fleet, a relatively small amount that if there were a change that would not meet that current spec.

Okay, thanks.

Your joint venture partners, what do their crude tank cars look like?

Do you have a feel for whether those are compliant at this point or will be?

Yes, it's a mix and that's certainly an area that we're working with them to make -- we want those in the compliant cars and certainly we will be compliant, but we want them to meet the newest spec.

And so we're continuing to work with that and making good progress.

Those are more around third party.

That's the third party.

Versus a joint venture.

Hopper cars.

CPChem.

Is that what you're talking about, CPChem, Roger?

No, actually I'm sorry.

I meant where you're using -- you had talked about earlier the agreements with -- at Hardisty and then in Casper where it sounds like it's a third party or a joint venture.

I wasn't sure which.

I know there's the Global, which I believe that is a joint venture to bring into Bayway?

That's a contractual relationship on unloading capacity and loading.

So that's -- those were all I think collectively as an industry looking to how do we get to that?

And that's part of what we're doing is working on our supply chain is to make sure that we're bringing the crude cars up to that spec.

That's what we want and so we're working through that.

But we're in pretty good shape on that.

Okay.

I guess what I was just trying to get at is whether or not we had to be concerned that your car fleet is fine but theirs is not and that could have an impact on crude coming into those units.

It's not -- at this point we haven't determined that that's a really large impact for us.

We feel pretty good about that.

Okay.

Great.

Thank you.

Faisel Khan, Citigroup.

Thanks, good morning.

Just a few questions.

On the -- in the quarter you guys discussed how in the transportation segment you saw some of the increases in margins from railcar rates.

As you ramp up the ownership of more railcars, can you discuss a little bit what the transfer pricing or what the rate and volume sort of rate mechanism is to understand how those margins and revenues grow over time?

Yes, so those rail rates, we basically just take those to a market rate and so that's what you're seeing is we talked about within the company before we formed the MLP and the Transportation as a separate business unit, those were really cost centers.

So this is all part of the process to get to market-based rates.

Frankly the rail component of that is a relatively small amount of the Transportation revenue.

So we'll continue to run those to market rates and that's really that stream.

But it shouldn't be-- it's not going to be a large driver or big increase in the transportation income.

Okay.

And does that also include the unloading terminals and loading terminals as well?

Loading terminals and unloading will be done at a market-based rate well.

So as the new rail terminals at Bayway and Ferndale come in those are operating agreements with the refinery where we charge a market rate for those services.

And that was part of what we included in our qualifying income that we talked about at the Analyst Day.

Okay.

Just wanted to make sure.

Thanks.

And then just to clarify on the Sweeny hub for the propane exports, the 150,000 a day in the initial phase you guys talk about building.

Is 100% of that spoken for by UNIPEC or is there some -- I think you guys discussed this a little bit, but I don't remember.

Is it 100% of that's spoken for by UNIPEC or was there some open capacity?

No, there is some open capacity.

We'll likely use some of that within PSX and then we still have the opportunity to look for additional third-party.

But we were very pleased to get a key tenant so to speak, or key contract with UNIPEC to underpin that.

Okay.

Got you.

The guidance you gave, the $400 million to $500 million of EBITDA, that only includes the revenues from UNIPEC, it doesn't include any sort of marketing component or open -- some sort of spread between propane prices here in the US and somewhere else, does it?

The $400 million to $500 million is largely fee-based.

I think we indicated it's probably in the range of $300 million, $350 million that would be fee-based.

That's based on the capacities of the frac and the export terminal.

So that would leave some amount then that says that that would be commodity exposure, arb opportunity that we see as a key piece of the project to add value for PSX.

It's a mixture but predominately fee-based.

Okay, got it.

That's helpful.

On the marketing segment, you guys have been putting in the export volumes in there for quite some time.

I just want to make sure I understand.

In that business when you discussed the exported volumes, so for example in the first quarter export numbers were down versus the fourth quarter.

How do we look at the margin impact from that volume downtick from fourth quarter to first quarter in marketing?

I looked at the numbers across the last four fourth quarters and so we're generally $1 to $2 a barrel better than our next best alternative domestically.

And so that's how it gets captured in the marketing business through that --

Correct.

Understood.

Fair enough.

Thanks guys, I appreciate the time.

Thank you.

I will now turn the call back over to Clayton Reasor.

Great.

Really appreciate all the questions and interest in the company.

We're off to a great start in 2014 and if you've got any additional questions feel free to give me or Rosy a call.

Thanks a lot.

Thank you ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.