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 Phillips 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 will be using this morning could be found on our website in the Investor Relations section along with supplemental, financial and operating information we think you will find helpful. Slide 2 contains our Safe Harbor statement. It’s a reminder we will 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. It’s 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 are glad you are 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 Refining. Also in the 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 are 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 are already looking into other factionator 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 will 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 U.S. Gulf Coast Petrochemicals project, which it consist 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 U.S. Gulf Coast petchem project and expect the startup to be in 2017. In addition, CPChem’s 1-Hexene project and a small specialty chemicals expansion in Belgium are expected to startup 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 and our Ferndale refinery at 30,000 barrel a day rail rack will start up later this year. We have 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 will increase our crude by rail capacity to about 160,000 barrels per day. We have also reached agreements with several third-party logistics companies to deliver more advantage crude to our refineries. We have 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 20,000 barrels a day agreement with Plains in Bakersfield, California to put advantage crudes into their pipeline system for delivery to our refineries. This facility will also be commissioned later this year. For pipelines, we have 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 Corpus Christi marine terminal further enabling us to ship Eagle Ford to our Gulf and East Coast refineries via our Jones Ax 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 for creating value. And it’s an important part of or strategy. Since the formation of Phillips 66, we have returned $6 billion to our shareholders. This includes $3.2 billion in share repurchases, $1.4 billion for the PSPI exchange, and we have almost doubled our dividend. Our board has authorized $5 billion in share repurchases. We have $1.8 billion remaining. Through this first quarter, we have purchased about 42 million net shares and with the PSPI exchange, we have 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 am going to hand the call over to Greg Maxwell, who will take you through the quarter results. Greg?

Thanks, Craig. Good morning, everyone. We start on Slide 4. First quarter adjusted earnings were $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 our earnings this quarter. In addition, consistent with last quarter, PSPI results were 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 yet 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 the 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 will 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 for 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 stronger margins, while the SA&S business was able to capture higher earnings following the 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 plant turnaround and maintenance activities as well as overall weaker realized Refining margins. The Atlantic Basin region was up as Bayway was back on line following a major scheduled turnaround last quarter this allowed us to capture the higher crack spread in this region. In the Gulf Coast, earnings were down largely due to plant 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 shale crudes relative to ANS and plant 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 cost. 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 spread 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 is largely resulting from the overall narrowing of crude differentials. The largest swing compared to last quarter is another. 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 claim product differentials were less favorable as blending of intermediates of butanes were reduced. Slide 13 shows the comparison of advantage crude runs at our U.S. refineries by quarter on the left and by year on the right. During the quarter 91% of the company’s U.S. 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 processed at our Bayway refinery. This next slide covers our Marketing and Specialty segment or M&S. Worldwide marketing margins were $3.07 per gallon in the first quarter. Our specialties business had lower margin and we will cover this in more detail in the next slide. However, before we move on I want 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 the needle and anode coke into this business line. These specialty businesses were previously reported in refining. We have 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 operation 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 for 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 U.S. 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 is 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 margin. Moving on to 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 were $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 its 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 the 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 in debt at $6.2 billion resulting in a debt to 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 discussions of the financial and operational results. I will 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 expenses 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 segment’s after-tax cost to run about $100 million per quarter. And the overall effective income tax rate is expected to be in the mid-30s for the second quarter. With that we will now open the line for questions.

Thank you. We will now begin the question-and-answer session. (Operator Instructions) And our first question is from Jeff Dietert of Simmons. Please go ahead.

Good morning.

Good morning.

Westlake announced its plans to drop three ethylene plants in an MLP and I was just curious if you could update us on your thoughts as far as that potential outlook you have obviously got the ethylene plants and experience with MLPs?

So, Jeff, yes, thanks. Yes, we saw that announcement and I think it probably makes sense. I think you will see more people considering that as a vehicle and a tool to use in the portfolio. I am not sure we would completely rule that out as a value creation opportunity for CPChem, but as you know, I mean 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 are seeing for condensates and perhaps provide an update on your potential interest in a project there?

Well, let me make a couple of general comments while Tim gathers his thoughts. And I will let him give you some of the details. I mean, we continue to be interested in condi splitters. We think there is a place for them. When you look at the asset infrastructure that we have and we are contemplating building, I think we are 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 forecast 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. No, I think if you look at condensate splitting and there are a number of options ones within the refinery system itself at a refinery. And as the life content goes up and the blender there, there maybe an opportunity and the need to address that, but what we are really focused on and we talked about was our initial thinking around a larger condensate splitter in the Sweeny area, where you are close to the increasing condensate production in West Texas and the Eagle Ford. And 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 crudes so to speak in a system. So, I think we are still kind of 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. So, still in evaluation, I think as Greg stated, well we are going to look at the margin opportunity in the collection system, but collectively, we see condensate production increasing and we are seeing opportunity there on both the transportation and the splitting side to be a piece of that.

Thanks for your comments.

Thanks, Jeff.

Thank you. Our next question is from Ed Westlake of Credit Suisse. Please go ahead.

Yes. So, I mean, obviously you just have 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 have released are helpful, but if I look at the slides you have laid out and you do all the regional stuff as well, there is that swing in other, but it doesn’t include the sort of say the opportunity costs from maintenance. So, I am just wondering do you have like a number for the fourth quarter or what do you think the opportunity costs that you lost was for maintenance, particularly in the regions which underperformed?

I think the margin loss was around $90 million is just south of a $100 million.

Right, that’s helpful. And any particular split, mainly in the – I guess Alliance was down, Central Corridor as well?

Yes, it’s on the Gulf Coast, because I mean we have the crude tower down at Lake Charles also. And so we bought BGO to keep the refinery running. And you can question how much value created by doing that, but I think that the time that we set the plans in place, it looked like the right things to do and then we had some weakness in California.

We also had a major turnaround at Borger. So really, when you look at both the MidCon and the Gulf Coast, you had major turnarounds there and we have come back from there, but that would – those are 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 are probably buying what’s marketed to you as WTI? And then it turns up and it’s not your old WTI that you used to buy, because obviously the components of the feedstock are getting much lighter. Can you comment a little bit about where we are you think in terms of the tipping points in terms of WTI becoming maybe even above the spec of 42 API and therefore the need to have separate infrastructure for some of this super light stuff, all we had to stress point today, do you think that that’s going to occur as you look out?

I don’t think there is 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 we have strong quality control, we know what we are 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 will see, I think it’s probably early to say you need a separate infrastructure for condensate and condensate movement, but I think we will continue to watch that. But at this point in time, I think we are getting the right feed to the front end of our refineries and we don’t see an issue with it.

Yes, thanks, very helpful.

You bet.

Thank you. Our next question is from Doug Leggate of Bank of America. Please go ahead.

Thanks. Good morning, fellows. I appreciate you taking my questions. Maybe I could start off with the standard kind of boilerplate portfolio question, then I had a couple of data points this morning I guess with yourself saying the Whitegate process is kind of coming to an end. We also had one of your competitors saying that we have some interest on the West Coast. So, I am just kind of curious as to what was the next step there for Whitegate that you moved out to a terminal, liquidate the inventory, what’s the process now and latest thoughts on the West Coast and I have 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 will 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 is an answer out there for Whitegate and we will continue to work that with the Irish government. And the other thing we said around Whitegate is there was some interest in splitting Whitegate and Bantry Bay. And so we are continuing run a second step process around Bantry Bay and we will 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 are good operator – we operate well. I think our assets are well positioned. So, our focus really is on improvement and getting advantage crude to the front of those refineries. And we gave you some data points today on some of the work we are doing to get advantage crudes, those firms, refineries were making progress and there is – but there is more to do. We are not through yet.

Okay. My follow up is you guys are obviously very unique in the number of levels, but particularly because you are not putting a lot of money to work in your refining business, and 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 unexact so to speak in terms of being able to predict the book. And 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?

Yes. As long as our shares trade below our intrinsic value, we are going to take shares in. And so we are buyers of the shares today.

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

So, I think given, if we have a 2008/2009 I think we have said consistently we are willing to grow the balance sheet to fund our growth in our shareholder distributions. But if we are at mid-cycle type conditions, we are going to gain $4 billion or $5 billion of cash a year and we think that’s sufficient to do the programs that we have laid out.

Alright, thanks. I appreciate the answers.

You bet.

Thank you. Our next question is from Evan Calio of Morgan Stanley. Please go ahead.

Hi, good morning guys.

Good morning.

Big quarter in Chemicals and I have got a macro question there, recently enterprise announced ethylene export facilities targeted to be online before your cracker comes online. So, do you have any comment on ethylene exports and whether these facilities alter your longer term ethylene surplus for you or maybe your competitive advantage versus exports on the cost curve and first mover status?

So, we continue to look at ethylene exports closely. We just don’t think they make sense economically. I kind of go back to the past decade in Middle East where ethane was free and no one could make it work with free ethane and now we are talking about playing between Henry Hub gas and European prices. So I mean what we will see where, does that go, you may see more ethylene exports and more interest in ethylene exports and certainly I think European petchems are interested in propane and butane for feedstocks as they are trying to do access North American energy revolution as you think about that. But let’s just say you can make it work and the – you can put ethane to the facilities in Europe, they 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 U.S. in terms of ethane. Tim if you want go into deeper, it’s fine.

No, I think 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’s provides another option that we don’t see that level really driving us on this supply-demand balance on the ethane side of the business to really force it, so some narrowing perhaps but still a substantial advantage in North America.

Great. And I appreciate that. 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 has been heavy turnaround, but it has been heavy turnaround for – or planned, unplanned outage for last year, so I just wanted some status of how that – how we should think about that asset going forward?

Yes. So I think we’ve got work to do at Borger. I think that’s one asset we can run better. We got a lot of focus around that internally. So I will make a couple of comments on the Wood River expansion. So as we premise the coker refinery expansion project we actually premise that on (indiscernible). And because of economic reasons we have been running on drill bit. So we have hit the condensate limits and haven’t got the capacity expansion that we expected for all the right reasons. And so there is some what I would say is modest capital that can go in to remove moving those constraints that allow us to get to another 20,000 barrels a day of capacity out of that asset. We think it makes a fundamental sense. It’s a good economics around that project and that’s something that we want to do.

Is that 2016, 2015 or timeframe on that Wood River?

I will come back to you on that. I am not quite sure exactly…

It’s in that range,

I don’t know. Yes, let’s look find out and get back to you again.

Fair enough. I appreciate you guys. Thank you.

You bet.

Thanks Evan.

Thank you. Our next question is from Paul Sankey of Wolfe Research. Please go ahead.

Hi, good morning everyone.

Good morning.

Checking my voice for maybe this afternoon, it’s been a long day so far.

It’s clear that way.

Yes. Just going back to some of the stuff you are talking about specifically on assets for sale, the general message I have 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 did things do change fast in refining, would we consider you as a 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 have been more specific about? Thanks.

So I think we have been pretty specific around the assets that we are interested and going to market. Whereas the core assets we have are solid assets they generate tremendous cash flow and we can take that cash flow and that’s our key to our strategy of transforming the company into a Midstream logistics chemical company with a great refining business in it. And so I wouldn’t say that we would continue to go through and sell the assets. We like our position. We like the legacy infrastructure. And frankly they are 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 and an export center at Freeport. And I think we have an asset that Sweeny is an enabler for us to do that. And so as we said we are looking for value creation opportunities where we can leverage existing core infrastructure that we have.

Yes, I guess what I was driving as is the general idea that you are trying to rebalance the capital employed in the company and therefore the extent to which you would do additionally opportunistically in order to sort of get towards that rebalanced level, but you have answered the question correct. On the market, could you talk a little about the demand side of the equation I think you have referenced some of the more – some of the ethane stuff, but if you could also talk about what you are seeing for gasoline and – it looks strong and if could just give us your export numbers and the very latest on how much product you are sending out that would be great? Thank you.

Yes, I think on the demand side we are 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 U.S. you kind of look at the number, you are seeing some improved demands here as the economy picks back up. And then exports continue to be an opportunity. And I think we looked at it there was opportunity from the standpoint that we will 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 at Alliance and it reflected the fact that we had some better opportunities in the U.S. So I think that we are going to – we are still pushing forward with our plans to get to 550,000 barrels a day of export capacity. And I think you will continue to see us over time, have an increasing proportion of our production go into the export markets and that really I think reflects we would say will be probably you have got good market crack strong operating rates in the business. So I think the industry as a whole we will continue to push exports into that market because of our cost advantages.

Yes, so when you have – it sounds like you were somewhat supply constrained and so your exports were lower but you also said there were better opportunities also within the U.S., is that typically an East Coast trade that you are undertaking from the Gulf Coast to the East Coast or is it Gulf Coast to Mid-Con or where are the outlets, where does the product go when it’s got a better offer somewhere else within the U.S.?

Yes I still think the East Coast is still kind of a clearing market certainly into the Midwest a bit, but the strong part is continue to be the Colonial System and the water born opportunities to the east. And on a macro level, if you think about imports and where that comes that’s also makes sense that we kind of push out the imported piece of that and supply out of the U.S.

That’s great. And just finally for other non-conventional is not the right word but non-gasoline non-distillate product trade, can you talk a little bit about the extent at which you are exposed to that and I am thinking propane and everything else? Thanks.

So yes, so the LPG, I will put the refineries, we have an NGL business where the actual 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 have 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 tradeoffs of fuel value in most instances on some of that, but then we have the upgrades the anode coke and those are still premium markets for us. So I would say that we are seeing relatively stable demand there and pricing moves in 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 gets high strength for our recycle steel production and that’s really Humber and Lake Charles, that’s a global market. And then you do have coke markets that are really global around the world for both anodes and then 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.

Yes, and once the core project was completed that really chewed up lot of the asphalt that we have basically.

Yes, my channel check is I have seen a lot of people mending roads around these parks. Alright guys, thanks a lot.

Thanks Paul.

Thank you. Our next question is from Paul Cheng of Barclays. Please go ahead.

Hi guys.

Good morning.

Greg earlier that you are talking about and during you Analyst Day 40% cash distribution for the cash flow, do you have any long-term target between the split on dividend and buyback?

So, 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 that’s no internal say target…

Yes, no, I would say, we definitely have some internal targets, we just – we decided to share.

(indiscernible). Okay, that great.

We cannot disclose it now.

Okay. For Bayway, is the yield going to be any meaningful different between your running Eagle Ford or running Bakken and how is that the economy maybe different?

Yes. I think we can run both clearly. I look at first that more capabilities to deliver the Bakken crude by rail and it actually fits the Bayway kit very well. So, we like that. Eagle Ford, it is 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 kind of like the runs in the Gulf Coast on that crude, but increasingly we will be keep thinking about that, but I will typically run through probably more constraints on Eagle Ford before we roll on Bakken.

Just on to the LPG side, Tim, you said the LPG handling, when you run you are saying that, which is…

Yes, it’s the light piece. It’s the relative value of the yields that you get on the two. And clearly as LLS becomes advantage in the Gulf, it creates another option for us to look at in Bayway and we have 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 from Bayway as well.

Greg, people ask about early I think on their Chemicals side whether it is MLP for you guys, of course at that you went into some constraint with your partnership with Chevron, but there is other asset value, the wholesale some other people is also coming into the MLP. Have you look at that given you have a pretty large space of EBITDA sitting there?

Oh, in the wholesale business?

Yes.

Yes. We have looked at that. So I think that’s probably on most of the things we consider, but we have lot of assets that are MLP along we are working our way down the list there, Paul.

But I mean that you will not have any resistance saying it could belong to a MLP structure if you believe – now that’s better valuation?

Yes, we believe we can put it in there.

Yes. It’s just a question that provides value, right.

I see.

Also if you think about there is some variation or variability in wholesale marketing earnings that we don’t have in the other assets that are currently in PSXP.

Right.

So, we have assumed that, that even if you are going to do it will be two days to tell after you done with more of the traditional logistic output?

I think they are probably better assets that we are looking at to drive the first.

Yes.

We get to wholesale marketing. We got a pretty big inventory of things we can work through plus the things that we are investing in that should come on.

I don’t see it in the top or close to the top of the list, no.

So, we haven’t included that in our estimates as EBITDA either and there is other, frankly there is other things within the refining system to that we have the opportunity to think about also?

And 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?

Well, Paul, I missed the first part of the question about what we are buying?

I think that if we are looking at that between your crude oil intake and your total throughput, it seems to suggest that in the Gulf Coast you are buying (indiscernible) 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 and so that you can eliminate their feedstock purchase, one of your peers definitely is doing it. Just want to see whether those are the investment you guys currently consider or not?

So, you are correct we do buy supplemental feed to fill out the units, but we have not really advanced to a point that we say we like to make additional investment in crude distillation capacity to supplement that. So, it is an opportunities to go forward, but we would like to get little more a deep review I think on what we think that value is growing long-term.

That’s something too that’s tied to the condi splitter if you think about bottom end of that, I mean the bottom end is gas oil that comes off and so, you could use that also impacts the economics.

So, Paul as you know we have been reluctant to invest in refining. I think I’d point people probably challenge us to say are you under-investing in refining. But still as we look across the opportunity side of investments that we have, we like this opportunity set and we are just prioritizing in going after the high valued investments first.

Sure. And do you, clear with that, in the second quarter West Coast margin has been nominal, because a number of you 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 are going to be down. I mean, if you just look at the turnaround expense for the second quarter guidance I think which maybe was 70.

70.

And so it’s about half of what it was in the first quarter. We typically take our big turnarounds in the first and the fourth quarters.

A final one, any rough estimate what is the total factory crude storage capacity?

What about it, Tim?

Pipeline fills and lots of storage tanks, so I think that you are going to continue to see that, but I have not done the exact math on that, Paul.

Tim, you don’t have anything on the fingertip? Alright, thank you.

That we suspect it’s filling, we’re not profitable.

Alright, thank you very much.

Thanks Paul. Take care.

Thank you. Our next question is from Roger Read of Wells Fargo. Please go ahead.

Very good morning.

Hey Roger.

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

Sure. 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 are light where it makes sense today, you look at the burning we could 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. In Gulf Coast it's really now mostly domestic light for us and so that's a question of which grades and do we start to work on the kit to increase that, but we’ve still have a lot of innate capability I think that to fuel 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 and do we’re increasing connectivity there but I think we have got capability to keep ramping that up but it’s something that we really haven’t seen that says we have got a constraint in what we want to run to make them right values in our refining system. So, that’s really what drives us is heavy and heavy probably makes the most sense, I think you got the dynamics between light, medium and right now I think that we have had a lot of optionality on the light side and we are just going to optimize around that.

Yes, we have said somewhere that there may be 100,000 to 150,000 barrels a day of incremental domestic light sweet crude capacity that we are trying to get to, but still that hasn’t been filled.

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

That’s right. I would just assume that we will continue to run medium based on what we see in the structure, should that change that could push on that.

Okay. And then I was a little late on to the call, the Midstream business had a great quarter if you addressed why that was and what the sustainability of that performance was and what the sustainability of that performance was, I apologize, but if not, could you kind of walk us through what helped that performance out this quarter?

So I think that it’s in several different buckets, obviously strong NGL prices $1.06, volumes were up at DCP by 10% I think as you think about that all of it is driven by equity gains at DCP. They did $1.1 billion of acquisition, the DPM level which created equity gains that pull backup. So that was the big piece of that. Then our transportation business had a better quarter, essentially volumes were about equalizing but certainly rising revenues as we continued 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 kind of performance from Midstream?

Yes, I think we expected NGL prices to come off some. They are driven by seasonal propane demand for the most part. But yes, I would think of return to something more normal.

And Roger you won’t expect the unit gains to continue, that was something that grew to $23 million, we are selling, again as Greg said they are associated with the big drop.

Right, okay and then I guess final question just on the rail capacity side, so you have got 1,200 cars we have obviously had the announcement of some changes in what’s required in terms of railcar design, but it’s not necessary given what that’s going to be. Can you give us an idea 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 is that’s what is ultimately going be the car that gets used everywhere?

So the new crude cars do meet that standard. So that increment and then within our existing fleet depending on where it would go they are moved to some other services if something came there could be some need to change or modify those cars which are relatively small percentage on that on the product side. We got lot of cars that are in service in terms of bulk movements of solids as well as paint cars. So it’s really the crude cars we feel very good about the ones we have purchased. And then we would have some amount of our fleet relatively small amount that if there was a change that would not meet that current spec, but they’re not…

Okay, thanks. I am sorry and then your joint venture partners what are their crude tank cars look, 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 are working with them to make – we want those in the compliant cars and certainly we will be compliant. And we want them to meet the newest spec. And so we are continuing to work with that making good progress.

Those are more around third party…

That’s a third party versus a joint venture.

Corporate cars.

Okay, yeah.

I thought we talked about CPK.

No, actually I am sorry I mean where you are using or you talked about earlier the agreements with – at Hardesty and then in Casper where it sounds like it’s a third party or a joint venture I wasn’t sure which there is the global which I believe that is a joint venture to bring at the Bayway or?

That’s a contractual relationship on unloading capacity and loading. And so that’s – those were all I think collectively as industry looking to how do we get to that and that’s part of what we are doing is working on our supply chain is to make sure that we are bringing those that crude cars up to that spec, that’s what we want. And so we are working through that, but we are in pretty good shape on that.

Okay. So we don’t, I guess well I just trying to get as well and now we have to be concerned that your car fleet is fine but their is not and that could have impact on crude coming into those units?

And its not – at this point we haven’t determined that’s a really large impact for us. We feel pretty good about that.

Okay, great. Thank you.

Thanks.

Thank you. And our next question is from Faisal Khan of Citigroup. Please go ahead.

Thanks. Good morning guys.

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

So, those rail rates we basically just take those to our market rate and so that’s what you’re seeing as we talked about within the company before we form the MLP and the Transportation is separate business unit, those were really cost centers. So this is all part of the process to get to market base 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 its not going to be a larger driver or big increase in the transportation income.

Okay. Does that also include the loading terminals, unloading terminals as well?

Loading terminals and unloading will be done at a market based rate as well. So as the new rail terminals at Bayway and Ferndale come in those are operated 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 just to clarify on the Sweeny Hub for the propane exports that sort of 150,000 a day in the initial stage you guys talked 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?

Yes.

Was that 100% that booked on support by UNIPEC or was there some open capacity?

No, there is some open capacity, we’ll likely to 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 it. And then 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 U.S. and somewhere else, does it?

So, that $400 million to $500 million is largely fee based. I think we indicated it’s probably in the range of $300 million to $350 million that would be fee based that’s kind of based on the capacities of the frac and the export terminal.

Right.

So that would leave some amount in that says that would be commodity exposure (indiscernible) opportunity that we see as a key piece of the project to add value for PSX. So it’s a mixture that’s predominantly fee based.

Okay guys. That’s it. That’s helpful. And just on the Marketing segment you guys have been putting in the export volumes and therefore for quite some time as I make sure 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 sort of the margin impact from that sort of volume sort of downtick – from fourth quarter to first quarter in Marketing?

So I mean, looked at the numbers across – the last four quarters or so, we’re generally $1 to $2 a barrel better in our next best alternative domestically.

And so that’s how it gets sort of captured in the marketing business through that sort of growth?

Correct.

Okay, understood. Okay, fair enough. Thanks, guys. I appreciate the time.

Thanks.

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

Great. Well, I really appreciate all the questions and interest in the company. We are off to a great start in 2014 and if you got any additional questions, feel free to give me or Greg a call. Thanks a lot.

Thanks.

Thank you. And thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.