Welcome to the Second 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, Senior Vice President, Investor Relations, Strategy and Corporate Affairs. You may begin.

Thanks, Christine. Well, good morning everybody. Welcome to Phillips 66 second quarter earnings conference call. With me this morning are our Chairman and CEO, Greg Garland; our President Tim Taylor; and Chief Financial Officer Greg Maxwell. The presentation material we will be using this morning can be found in the in Investor Relations section of the Phillips 66 website along with supplemental, financial and operating information we think you will find helpful. On slide 2, you can see our Safe Harbor statement. It’s a reminder we’ll be making forward-looking comments during the presentation and our question-and-answer session. Actual results may differ materially from today’s comments and factors that could cause these results to differ are included here on the second page of the presentation as well as in our filings with the SEC. That said, I’ll turn the call over to Greg Garland for some opening comments. Greg?

Okay. Good morning, everyone. Thanks for joining us. Second quarter earnings were solid, reflecting that we ran well and our Chemical segment had record earnings. However market factors negatively impacted results in our Refining and Midstream businesses. And corporate costs were higher mainly due to increased environmental accruals as well as tax impacts. Refining, we ran near record utilization rates for the quarter. However, our realized margins were lower than last quarter, largely due to weaker distillate margins along with pure commercial opportunities. Our Midstream business was negatively impacted by lower propane prices and less demand driven by seasonal factors. We think our disciplined approach to capital allocation is appropriate, given the volatility in our financial results. We are expanding our shareholder distributions while investing in the business with a focus on growing our higher valued segments. We’ll continue to increase shareholder distributions. Our board approved an additional $2 billion of share repurchases. And during the quarter, we paid an increased dividend of $0.50 per share, which is up 28% from the previous quarter. At the end of the second quarter, if you look at dividend, share repurchases and share exchange, from the last quarter we’ve returned nearly $7 billion to investors. At quarter end, our share-count was less than 560 million shares, down 11% since formation. We improved a $1.2 billion increase to our 2014 capital budget, bringing it to $3.9 billion in total. This increased spending were primarily fund the previously acquisitions of crude oil and refined products turned on the U.S. Gulf Coast and specialties lubricants company. In addition, the capital will be directed towards Midstream growth projects such as the Sweeny Frac and Freeport LPG Export facilities. You can see the progress we’re making on the frac in the picture on the slide. Our focus continues on Midstream organic growth, while we all would like to have more certainty around condensate exports. We continue while we wait options for condensate infrastructure and additional fractionation capacity. Our MLP Phillips 66 partners’ provides low cost of capital for additional investing. PSXP had a good quarter realizing the full impact of its first acquisition. EBITDA during the second quarter was twice the amount generated at the time of the IPO. We continue to look for opportunities within Phillips 66 externally and organically to grow PSXP and contribute to our Midstream growth strategy. Our joint ventures continue to grow. In June, CPChem successfully started up the world’s largest on-purpose 1-Hexene plant at Cedar Bayou facility in Baytown, Texas. Also, during the quarter CPChem improved expansion of its Normal Alpha Olefins production capacity at Cedar Bayou by 220 million pounds per year. At DCP Midstream, work continues on the Zia II plant which is located in the Permian Basin, anticipated startup first half of 2015. And DCP partners’ is constructing in return two plants in the DJ Basin and also expects operations begin in mid-2015. We’re executing our plans, we’re continuing with our commitments we laid out two years ago. We have a strong balance sheet, $5 billion of cash and a debt to capital ratio with the low end of our targeted range. We have confidence that we have the resources and the opportunities to deliver on our plans to grow our higher valued businesses, while rewarding the owners of our companies with secure and growing distributions. So, with that I’m going to hand it over to Greg Maxwell to review the quarterly results.

Thanks Greg, good morning. Starting on slide 4, first quarter earnings were $863 million or $1.51 per share, we had no special items this quarter. Cash from operations excluding working capital for the quarter was $937 million. And for the quarter we paid $281 million in dividends and we purchased 7.5 million shares of common stock for $616 million. Our debt-to-capital ratio was 22%, and after taking into consideration our end cash balance of $5 billion, our net debt to capital ratio was 5% at the end of the second quarter. And finally, our annualized adjusted year-to-date return on capital employed for 2014 was 13% as of June 30. Slide 5, provides a comparison of our second quarter adjusted earnings with that of the first quarter, this is based on a segment basis. Compared to last quarter, second quarter earnings were down $3 million driven by lower results in Midstream, as well as higher corporate segment expenses. The increased earnings in refining were primarily attributable to higher volumes following the completion of plan turnaround and maintenance activities. I’ll cover each of these segments in more detail as we move forward. The Midstream segment was negatively impacted in the second quarter by lower gains associated with DCP Midstream partners or DPM unit issuances and weaker NGL prices and demand. The annualized 2014 year-to-date return on capital employed for Midstream was 17% and this is based on an average capital employed of $3.6 billion. Slide 7, shows Midstream’s second quarter earnings of $108 million, a decrease of $80 million from last quarter. Transportation was in line with last quarter, as improved volume throughput was largely offset by increased planned maintenance activity. DCP Midstream’s earnings decreased by $50 million compared with the first quarter, the decrease reflects lower gains associated with DPM Unit issuances that were recognized by Phillips 66 along with lower NGL prices specifically propane. In addition, DCP had turnaround activity as several of its gathering and processing plants resulted in higher operating cost during the second quarter. And finally, our NGL business line also had lower earnings in the second quarter driven by weaker propane prices and lower demand due to warmer weather. In Chemicals, the global Olefins and Polyolefins capacity utilization rate for the quarter was 95%. The O&P business benefited from strong margins, while SA&S had impacts due to turnaround activity. The annualized 2014 year-to-date return on capital employed from our Chemicals segment was 29% and this is based on average capital employed of $4.3 billion. As shown on Slide 9, second quarter earnings for Chemicals were $324 million representing a record earnings quarter for our Chemicals business. In Olefins and Polyolefins, earnings were up mainly due to improved realized O&P chain margins, and this was slightly offset by higher maintenance cost as some of the plant’s first quarter maintenance activities shifted into the second quarter. The $17 million decrease in Specialties, Aromatics and Styrenics was primarily due to lower equity earnings as a result of plant turnaround activity during the second quarter. Next, I’ll cover refining. We ran our refineries well this quarter, the crude utilization rate was 96% and our claim product yield was 83%. The annualized 2014 year-to-date return on capital employed for Refining was little over 10% with an average capital employed of $13.5 billion. The Refining segment had earnings of $390 million and this is up from last quarter’s earnings of $306 million. This increase was mainly due to higher utilization rates across all of our regions, slightly offset by weaker realized Refining margins. Realized Refining margins decreased in all of our regions exception for the Western Pacific region. The decrease was driven by weaker distillate market cracks reduced seasonal blending activity, gasoline activity and also lower secondary product realizations. In addition, narrowing crude differentials negatively impacted our realized margins. In the Gulf Coast, the LLS Maya differential narrowed by $5.32 per barrel, impacting our Sweeny and our Lake Charles refineries. And on the East Coast the Bakken Brent differential narrowed by $1.43 per barrel impacting our Bayway refinery. Other refining was down $50 million compared to last quarter, mainly due to less location arbitrage and product blending upgrade opportunities available in the market compared to the first quarter, and also as well as narrowing WTI/WCS crude differentials. Next, let’s look at our market capture on slide 12. Our worldwide realized margin in the second quarter was $9.66 per barrel. This resulted in a market capture of 61% and compares with 79% in the first quarter. On a regional level, the biggest movements were in the Atlantic Basin Europe and Gulf Coast regions. You can find the regional slides in the Appendix of this presentation. Our Refinery configuration negatively impacted our capture this quarter by $2.73 per barrel, the decrease is a result of our configuration being weighted towards less gasoline and more distillate production than the marker implies. Secondary products were moreover hurt this quarter than in the past quarter due to NGL prices decreasing along with crude prices increasing. And finally, our feedstock advantage was $1 per barrel lower than last quarter due to narrower crude differentials. 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 second quarter 93% of the company’s U.S. crude slate was advantaged and this compares with 91% in the first quarter. This increase was largely due to less turnaround activity in the second quarter. In addition, refining processed a record 305,000 barrels per day of tide oil in the second quarter. And this represents a 48,000-barrel per day improvement over the previous high. This next slide covers our Marketing and Specialty segment. Both our Marketing and our Specialties businesses had higher volumes this quarter. The annualized 2014 year-to-date return on capital employed for M&S was 25% on an average capital employed of $2.4 billion. Slide 15, provides some additional detail on our M&S segment. Adjusted earnings for M&S in the second quarter were $162 million representing a $25 million increase from the first quarter. The improvement in marketing earnings primarily reflects higher volumes due to seasonal demand and also increased exports. We exported 181,000 barrels per day this quarter up from last quarter’s exports of 139,000 barrels per day. Specialties earnings were $43 million for the quarter, and in-line with the first quarter results. 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 and accruals that are not allocated to our operating segments. Corporate and Other costs were $121 million after-tax for the second quarter compared with $81 million last quarter. The increase in cost was largely due to change in effective tax rates as well as higher environmental accruals. And this brings us to the second quarter cash flow. Starting on the left, excluding working capital, cash from operations was $937 million. Cash from operations funded $561 million in capital expenditures and $281 million in dividends. In addition, we repurchased $616 million of our shares through our share repurchase program. The $150 million for proceeds from asset dispositions is largely related to distributions from WRB which is our 50-50 joint venture with Cenovus Energy. During the first quarter, Cenovus prepaid its partnership contribution payable to the joint venture. When WRB distributed these funds, our accumulated undistributed equity earnings were reduced to zero. This resulted in any additional distributions in excess of current earnings being accounted for as return of investment. And finally, we ended the quarter with a cash balance of $5 billion. This concludes my discussion of the financial and operational results. I’ll next cover a few outlook items. For Chemicals, in early July, there was a localized fire at CPChem’s Port Arthur plant. Our thoughts and our prayers are with the injured employees and their families. CPChem continues to evaluate the events of Port Arthur, and at this point it is still too early for us to provide some specifics regarding how long the facility will be down or the total financial impact. We do however expect global utilization rates for Olefins and Polyolefins to be in the low 80s during the third quarter. Also for the third quarter in Refining, we expect worldwide crude utilization rate to be in the low-to-mid 90s and pretax turnaround expense to be about $90 million. Turning to corporate and other, we expect this segment’s after tax cost to run about $110 million per quarter for the remainder of the year, and from a tax perspective, our overall effective income tax rate is expected to be in the mid-30s for the third quarter. With that, we’ll now open the line for questions.

Thank you. (Operator Instructions). And our first question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.

Thanks guys, I appreciate you taking my questions.

Hi Doug.

I’ve got a couple of big picture issues if I may. I mean, you started your prepared remarks Greg, talking about higher utilization rates and lower capture, it seems to be a trend that we’re seeing across a number of your peers. I’m just curious, is, the higher utilization rate and the higher use of light, light use of crude impacting you to the point where your secondary units are not as efficient as it used to be. I’m just trying to understand the deterioration in the capture rate it seems to be industry issue not necessarily a PSX issue? And I’ve got a follow-up.

As we, we spent a lot of time trying to buy at the well head for consistency of crude. So, one of our objectives is to avoid the more blended barrel if we can within PSX operations. So I’m not sure that we’re constrained in terms of any of our operations given the crude slate that we’re running today. So, but the market capture question, more broadly around the industry is a good one, I don’t know Tim, you want to?

Yes, I think, Doug, you’re looking at secondary coke prices relatively flat and actually declined a bit this quarter. So you’ve got that dynamic of coke and the pure grade competing essentially with coal. And then the LPG prices came down versus the first quarter, so that was a piece of that. So, but we haven’t really seen that the yield structure other than the value of the light components has really impacted our selection on crude slates.

And I would say the abundance of light fleet crude it didn’t translate into wider crude differentials in the second quarter and that had – that produced our capture rate as well.

Sure.

Thanks. My follow-up I guess, every quarter we tend to revisit the West Coast system. The reason I would like to bring it up again if I may fellows is my follow-up is, we thought you announce this Petrochemical project. And our understanding is that there could be more to come which ultimately has the impact of tightening up the gas fleet market, I expect over time in the West Coast. So, I’m just wondering, first of all, are you thinking along similar lines of, have you given thoughts to any – how Phillips could perhaps contribute to tightening the gasoline market by perhaps exporting Petrochemical feedstock? Or if the market did tighten up what would it mean for the strategic positioning of your West Coast system, could it improve enough to become by kind of core part to the portfolio and not altogether there? Thanks.

Yes, so, I don’t think that we’re looking at any chemicals investments on the West Coast. As we think about the West Coast, fundamentally we want to run well and optimize and that’s around getting advantage crude to the front of the refineries. We don’t have any big investments in front of us on the West Coast. Obviously, quarter-over-quarter, West Coast was better, second quarter than first quarter. We think it remains a challenged environment but given the position we have and the cost structure of our refineries and where they sit relative to the peers, I think we’re in a pretty good position on the West Coast.

All right. Thanks for taking the questions guys.

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

Hi, good morning guys.

Good morning.

I know you recently raised 2014 CapEx and the buyback authorization simultaneously. And maybe a general question on how you think about forward Midstream CapEx, I mean, given the percentage of Midstream spending, additional attractive organic opportunities. How does you MLP in the potential to monetize your Midstream spending at a much faster rate than the typical long-wide asset affect your view on future Midstream spending? And I have a follow-up please.

Well, I think at our Analyst Day, we kind of weighed out ‘14, ‘15 and ‘16 and we weighed out $12 billion of growth opportunities essentially seven of it to PSX level. And most of that was directed as Midstream. I think we see many opportunities in Midstream and we will be opportunistic. I think a recent announcement of the acquisition of the Gulf Coast crude oil and products terminal is an example of that. So, when we see an opportunity we’ll certainly, we’ll move on that. And then specifically around the MLP, we view that is a tool in the toolbox that we could use to execute our Midstream growth program and/or accelerate the growth at Midstream with that MLP. And certainly I think you’ll see us do that.

Maybe a similar question, I think it’s what you just showed us to put a finer point on it. But as you affect the portfolio shift that we – I guess, you and I believe would drive a re-rating in your EBITDA. Your CapEx also rises, I mean, do you see your balance sheet liquidity essential MLP liquidity speaking of dropdowns as a method for maintaining or increasing distributions despite a rise in CapEx number?

No, I think that we think about executing the plan, we think about our balance sheet and the capabilities of our balance sheet. We think we have $4 billion to $5 billion of capacity on the balance sheet, we could use. We have $5 billion of cash that we could use. And then certainly we have continued asset sales and/or going to the MLP. And so I think we have a robust funding mechanism to move this Midstream transformation board with our company.

Great, and then one last one from me if I could. I mean, the economics are really fantastic for your LPG facility project given the cost at over 6 turn cap rate, a potential sale of MLP to 10 turn cap rate and a recapture of a portion of the EBITDA for the GP and LP units, which will also improve your returns. I mean, any thoughts here, any kind of scope out of earnings potential second stage here or just kind of market depth of expansion and I’ll leave it there? Thanks.

Yes, I want you to take that.

Evan, we’ve continued to see solid demand around the export piece for propane, butane and pentane, that’s all part of that LPG facility. So, we’ve been encouraged in the market, we have said that – we’re looking at 8 BLGC carriers per month as our initial thinking. But currently they were able to go to 12, and I think as the market demand continues to grow and the options develop, I think that’s something that we look forward to expanding. So, as we look down the road that’s a key piece of where we’d like to continue to grow.

Great. Thank you.

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

Good morning everyone. First of all, just a bit of a follow-up as regards to throughputs, you’re at 96% utilization overall. But I think you had quite a few refineries that weren’t running full capacity. That would imply that some of your refineries ran over 100%, utilization? Does that is that a function of the light Sweep throughput? And can we expect you to go even higher in utilization for example in Q3 now, that’s part one? Thanks.

So, to answer the last one first, I think we just guided to low-90s to mid-90s in utilization on the third quarter call. I don’t think it’s a function of running more lights sweet crude necessarily. We did do at alliance turnaround some work that allowed us to run more Eagle Ford at Alliance but it really didn’t necessarily increase overall throughput at alliance. It was just avoiding some of the issues we had when we ran the Eagle Ford. So, you’re actually right. There were refineries that ran above 100% utilization. And the way we manage that internally, once we demonstrate our higher utilization rate for a period of time, we’re going – we’ll increase that effective capacity of that refinery in our numbers. But we need to be able to demonstrate that. But look across the system, the refineries ran well in the quarter. We expected that coming out of the turnarounds in the first quarter and generally you’ll see that performance coming out of turnarounds. But generally they ran well. And I think you’re always going to have some ups and some downs and in and outs and we did during the quarter. We had some issues, we had small fire at buildings and so we saw some reduced capacity and throughput at our billings facilities. But in generally I’ll tell you across the system, solid operations.

So, but you’re implying that your capacity will go up, I don’t quite understand if it’s not more light sweet crude was causing that to happen? I mean, if you’re running at over 100%, it implies you’re going to have a higher capacity?

It’s not the light sweet crude that’s allowing us to run it over 100%, I guess that’s what we’re saying.

Okay.

Yes, I think its two things Paul. Specifically maybe Ponca City as an example, a more consistent crude slate leads to more consistent operations. So we’ve made great strides there. And then we’ve continued to focus on how to improve reliability. And I think that shows up as well. So, it’s really the two-point approach. So, relatively minor I would say capacity creep that really driven off those two things versus, significant investments in terms of distillation capacity or other types of ways to do that.

Great, thanks. And then just for the MLP outlook you mentioned, you made an acquisition that you’re finding that there is plenty more stuff out there for you to buy, and can you just talk about the framework of what the asset market looks like to keep that growth going? Thanks very much and I’ll leave it there. Thank you.

Thanks Paul.

So, just generally Paul, we don’t comment a lot on M&A. Assets are pretty fully valued today. And so I think you have to look into that deeper value question about when you see the opportunity to expand around your system and drive the synergies to make that work. So, we’re always looking and we’ve had a couple of opportunities this last quarter. And we were able to do that. So, I think that’s – we’ll continue to look at that as we go forward.

Okay, thanks guys.

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

Yes, good morning. Couple of quick ones firstly on cash flow, $937 million before working capital I think was the number. I mean, obviously that’s a bit lower than what you’ve been doing recently, I mean, obviously earnings could be part of that. But two of the line items in the cash flow statement, one is deferred tax which last year was running sort of at a positive. And in the second – forget the first quarter because I think there was some one-offs. But in the second quarter a slight negative. Maybe talk a little bit about deferred tax? And then the other line item is the associates or equity investments seem to be investing a little bit above DD&A and obviously we’re expecting them to in order to drive some of the growth when we think about the Chemicals and Midstream associates. But it felt like that was a little earlier than they had in the plan? I thought that was more going to be 2015, so maybe just if you could help us walk through those particular line items in the cash flow statement? Thank you.

Yes, this is Greg. With regard to the deferred tax, we had some one-off things that hit that. And I don’t have all the details with me right now. And we can call you and give you that additional detail. With regard to the undistributed equity earnings and the cash flows that are coming out of our JVs, we had a bit of an anomaly as I talked about in the first quarter with regard to WRB pan out the dividend from the prepayment of the loan outstanding to Cenovus. So that was a bit of an anomaly of cash flow coming out from that perspective. And then, as we’ve talked about with CPChem and marking on their large project, building the cracker and the two polyethylene units down on the Gulf Coast, we expect them to be fully funded from cash from operating activities. But as a result of that spending, we will end up seeing less distributions coming out of CPChem during this period of time of heavy spending really in 2015-2016.

Okay, that’s helpful. And then, on the small Bolton acquisitions I mean, any idea of rough range of acquisition multiples?

Ed, roughly I would say they’re in the comparables and the specialty lubricants area of what you kind of see – I think as we said, they’re fully valued. And then, I think as we’ve looked just we can turn we just see great opportunities. So that’s a really key acquisition in terms of the pivot points around the Gulf Coast both in refined products and crude oil. And so, we see a lot of forward opportunity given our logistics infrastructure as well as our refining LPG and their products distribution in the Gulf Coast. So, I think that we feel that these are going to be very positive developments on both fronts from an earnings perspective and a good value.

So, if I understood correctly, typically the EBITDA multiples say year one but Phillips has ways to add value to the assets that it’s purchased over time?

Absolutely.

Okay, okay, great. And then, just a question obviously, with the BIS discussing the fact that I was down there last week, met those folks. If you distill oil and if it looks like it’s a product on Schedule B, then that doesn’t appear that they might stand in the way of that type of activity going on which is, makes sense to me. Now, some of the things that would then fit in that condensate exports, but as you go into deeper API crudes, I mean, obviously you could top API crudes down in the Gulf and then sell the intermediate products. Have you looked at any of that sort of topping type capacity and whether it would meet your hurdle requirements? Or does that fall under Greg’s 40% IRR, require because it’s refining investment?

We all like those.

Right.

So, I think we’re looking at a range of opportunities there in terms of just general condensate infrastructure Ed. So, I mean, it could be gathering, it could be pipeline, it could be export facility, it could be topping, it could be full range splitting into the more complex product slate. As you know, at our LPG facility we’re putting 350,000 barrel essentially condensate tanks it that were under construction. So, certainly that’s a piece of the equation that we’re looking at. I think there is some uncertainty around condensates and exports, they may be giving some people some pause around speculative splitters, we’ll see. But regardless of what happens there, there are four things you need to do and three of them are right down the fairway what we’d like to do in our Midstream business.

Great. Thanks very much.

Thank you. Our next question is from Jeff Dietert of Simmons. Please go ahead.

Good morning.

Good morning.

Hi, Jeff.

One broad question, a strategic question, and one more detailed question, if I could. You’ve talked about capital allocation being 60% reinvest, and 40% generously back to shareholders through dividends and buybacks. How rigid or flexible is this guideline? I guess it’s dependent on a number of considerations, including level of cash flow, attractiveness of investment opportunities, and level of the stock price relative to your view of intrinsic value. But could you talk about how you see this evolving over time?

Yes, I think – Jeff, I think that that was a broad statement in terms of how we think about cash. And cash could be funds from operations, it could be cash from the balance sheet, it could be raised through debt, it could be dropping assets in the MLP. And I think we’ve consistently said that we would use all of those vehicles for cash generation if we’re lower sources of cash to fund our forward program. So it’s a pretty aggressive program in terms of organic growth, it’s also rewarding our shareholders with secure growing distributions that’s growing the dividends. We talk about minimal 10% type double-digit dividend increases plus continuing our share repurchases as long as it’s our share price trades below our view of intrinsic value. So that’s kind of what we look at is we’re thinking about that.

Thanks. Secondly, Borger, you had some downtime, major turnaround in March, and then there was a lot in the press about 30-day-plus outage in July. Could you talk about what was down in July, was it planned, unplanned, what activity was going on there?

Yes, so I would just say that Borger hasn’t run well this year. And so we’re working on improving operational reliability at Borger really to me are expectations. But the July event, by the way Borger is back up and running today. But July then was unplanned outage.

Thank you.

You bet.

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

Hi guys, good morning. Greg, I presume, I know the answer, but anyway, just to confirm, Citco, seems like that they were trying to sell their refining asset in the U.S. We should assume that you guys would have absolutely no interest to further expand your U.S. refining capacity?

I don’t know, I think we’ve consistently said we have better opportunities to invest in our Midstream and our Chemicals business Paul.

Right. On the PSXP, any more internal prediction or forecast how quickly you could reach the high speed for the GP?

Yes. So Paul, we’re with this last distribution increase. We’re close we’re – so I think reasonable growth in EBITDA in that MLP would put us there. I think that we’re very close to that goal. So we’ve doubled the EBITDA in the MLP with this last acquisition. And that’s hard to push us toward that so as the earnings and distributions grow, we’re getting a much more close to being to the maximum high-split on the IDR.

And maybe that this is more for Greg, just as a request. Going forward, as you’re reaching the high speed, if you can actually somewhere in your press release, just how everyone had – what is your GP cash flow for the quarter, I think that would be really helpful in terms of highlighting the value of what is that GP may be? And also in your chemical for CPC, thank you very much for the information that you give out, the DD&A and all that. But I believe that is not including the corresponding share of CPC on some of the chemical joint ventures. In that, you would be able to also put that, so we can get a full picture of what is the full depreciation related to that business that would be great.

Okay. Well, first of all, on the first suggestion, great suggestion. We’ll do that in terms of the GP cash. On CPC, we’re working that, that’s a little more difficult. But we recognized that is a deficiency in terms of people seeing that through EBITDA that’s embedded down at the joint ventures within the joint venture.

One of the things we’re attempting to do on that Paul, is you’ve probably seen in the supplemental information is look at it from a proportionally consolidated perspective and look past the equity earnings and give you the different components. And I think that’s what you’re looking for right?

That’s correct. Yes. And because that’s a little bit complicated since we have joint venture within joint venture. So, if you guys can help us to get a better, full picture that would be great in terms of the valuation. Three other quick questions, first, Greg, do you have the market value of your inventory in excess of the bulk?

Paul that runs in the second quarter, it stood at about right at $8 million.

Secondly, that I think in your slide, you were talking about the secondary product related to the configuration or benchmark, there’s a drop in the Western Pacific region by about, say, $8-something. And that’s about $2.50 or $2.40 per barrel worse than that discount in the first quarter. Can you give us a little bit better understanding that what may have caused that? Which particular secondary product is causing that substantial deterioration?

So, I think again, that was almost $3.50 a barrel something like that. And what we saw, we actually saw coke prices go down and we saw LPG prices or NGL prices go down. So it was just a direct result of higher fleet stocks and lower costs for the products or lower values for the products.

Greg, are you talking about the thermal coke or that you guys selling a specialty coke?

Thermal, yeah.

It’s thermal coke?

Yes.

Okay. A final one, maybe this is for Tim. Tim, have you seen any evidence that oil ones, they travel down to South Texas being trapped in Houston and have not been able to very cost effectively move to Louisiana side or that you guys haven’t really seen that?

No, I think that’s continuing to be an issue that the infrastructure on the Gulf still is not sufficient to move some of these lighter crudes into Louisiana as much as we’d like to see. I think that’s what you’ve seen little bit with recent LLS move. So that’s still developing that will improve. But yes, I think that we continue to see that disconnect between the Texas and Louisiana side on the light side.

I see. Thank you.

You bet.

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

Yes, good morning.

Hi Roger.

Good morning.

I guess, maybe a specific question, getting back to a combination of things. Number one, your comments earlier about buying your crude direct as opposed to blended, how that fits in with some of the new pipeline capacity coming from West Texas. And then also how maybe this recent change in the condensate export rules plays into that in terms of the types of crude you’ve been buying that have been blended. I know that’s wide ranging but I’m trying to get a feel for what you may or may not see in terms of API and then just how much condensate is blended in at this point?

Yes, we don’t – I would say today the large proportion of condensate is in the crude piece. And you’ve certainly seen the blended barrel gravity start to come up. The value that we see is with particularly and you look at the mid-Con in Ponca City border being able – on top of the producing fields to go direct help. Similar approach we’re taking in the Eagle Ford expanding that. And so, and buying in the Bakken, where you canvas with segregated distinct batches all help that consistency. And we’ve actually increased that volume and we’ll continue look at ways to do that because we think that adds additional value on the refining side of our business. So, that’s actually a concentrated effort on our commercial side to increase that.

Okay. Thanks. And in terms of the change with the rules, I mean, what’s your expectation on how quickly that can actually have an impact? I mean, we know what the first two were, we know that there’s been some sort of a haul placed, at least in the near term. How are you thinking about, in terms of the ability for the industry to get this out of here that it will ultimately flow back into the impact on the type of crudes you are seeing running and in your ability to take advantage of that?

Well, first, we do expect condensate production to continue to grow. So I think that has to be dealt with. And then they still need particularly if you’re going to export, you just looked at that to say you got to get the infrastructure where you can segregate you can’t co-mingle. And so that’s still developing and that is the opportunity that Greg was talking about earlier about these opportunity to bring it from the field into the markets that we’re processing. So, I think it’s still early, still developing. I think that’s going to evolve. But I think that some type of distillation probably starts to sit up that play that length in condensate will eventually leave the U.S. in some form or another. Because that’s where the demand is going to be and that’s really what you got to serve. So the key is to figure out which pieces work right now. But if it stays in the crude we’re going to continue to find ways to drive that to the refineries. And there is still probably likely to be a more segregated system that drives it directly.

Okay, and then, just an unrelated follow-up question on the chemicals business. Greg, getting back to your comments on the cash flow side that overall that’s not a segment that’s going to deliver a lot of cash flow to the corporate level. If the Port Arthur facility is going to be off-line for a significant period of time and I’m not asking you to predict that, I’m just saying if that turns out to be the case, does that have a meaningful impact on the cash flows? Or, another way of asking the question is there any risk that your CapEx will actually have to increase to make up for any potential shortfalls in the chemicals side next year?

I would say from what we know now what we see now, we don’t think we’ll have to put equity into the CPChem. They’ll continue to fund their programs and distributing cash back to the owners.

Even with the unit down for a long period of time?

Yes, I don’t know, we don’t know how long the units are going to be down at this point. And I think anything we would do might just be speculative and so we’re probably not going to go there today. There was a localized buyer and so, I think we can probably give you more guidance in a month or so as we get there. But certainly our view is that that unit, there is no reason that unit would be down for a prolonged period of time, yes.

Yes.

Okay. Thank you.

You bet.

Thank you. Our next question is from Blake Fernandez of Howard Weil. Please go ahead.

Hi guys, good morning. Thanks for taking the question. I had two for you. The first, I’ve always viewed one of the real competitive advantages for PSX is your elevated distillate yield in the refining system. And just in reviewing your supplemental data here, I was looking at the yield on a worldwide basis. It looks like it’s trended a little bit lower here into 2Q at 38%, which had been trending around 39% or 40%. I’m just curious, as you begin to increase, or continue to increase the domestic advantaged runs of light sweet, do you expect that to have an impact on your distillate yield going forward?

I think I mean, we’re continuing to look for ways that we can increase distillate yield. Certainly in this quarter, that maybe would be wrong way to go directionally since gasoline crack was up $7 and distillate was down $3.75. But as you think about where the world is going and we think distillate continues to grow two to three times the gasoline demand globally, we think distillate – increasing distillate make sense. Having said that, we’re not going to spend a lot of money to do that, but we do think we’ve got a 1% to 2% yield capture and distillate that we can affect over the next year or two in terms of operations. And I think we probably wore down in the second quarter on distillate production.

Okay, great. Thanks, Greg. The second question, really the underlying question is on the pacing of buybacks. But, I guess, first and foremost, with the upward revision on CapEx in ‘14, is it fair to think that there’s an upward bias to the ‘15 numbers that you provided in April? And, I guess, secondly, obviously that would hurt free cash flow. Is it fair to think that the pacing of buybacks may slow a bit as you digest some of the M&A and some of the elevated spend here until you get a contribution from those assets going forward?

That’s not what we’re thinking today.

Okay.

I don’t think when we look at cash flow generation over the next two or three years, it looks like there is sufficient cash to fund the increase in capital that we’ve built into 2014 and continue a fairly significant reduction in share count through repurchase. So, the increase is predicated on just executing the plan that we’ve got in front of us. I don’t think we have any intention of reducing our share repurchase in order to fund additional CapEx.

Okay. And just to clarify is it fair to think of maybe some upward pressure in ‘15 compared to what you provided in April?

So, we gave guidance at the Analyst Meeting somewhere around $3.5 billion to $4 billion of capital in 2015 and ‘16. I think those are good numbers to work with right now. We’re just getting, we’re just getting indications from the businesses today as far as what they would like to spend. We still believe that having constrained capital programs make sense, forces the business is really to select the best projects. But I don’t really see us meaningfully increasing the capital spend in ‘15 or ‘16.

Okay, thanks Greg.

Of course we’ll give you updates on that as we get into the fall. We’ll be talking to our board about what they’re comfortable with as well. But there are a lot of things that we’re looking at today. I mean, we’re really building a nice queue of capital programs in the Midstream business that we’re interested in pursuing. And but, we certainly don’t want to pull back from our share repurchase program.

Fair enough. Thank you.

Thank you. Our next question is from Faisel Khan of Citigroup. Please go ahead.

Thanks, good morning, just a few questions on the midstream side. With the Beaumont acquisition, is Chevron the only customer, at least the majority of the revenues for that facility? And how do you envision running that facility for your own refineries and operations?

Faisel, I will get the customer but if there are other people in that terminal today and really as we’ve looked at it, we want to really expand that terminal and that base. And so we think about it A, you’ve got shown operations, you’ve got (inaudible) relatively close, you’ve got connections in the Texas. And then these new crude lines, all come into Beaumont area. And the connections you can make there, you’ve got a marine dock with that. So I think that we’ve thought about it that we just see tremendous third party as well as PSX activity that can be tied to that terminal both the crude side as well as the product side. So I think as we go forward, we’ll continue to develop that asset connectivity and drive really volumes and across our systems but also importantly opening that up and having a lot of third party opportunity there as well.

Okay. And just to clarify, that facility would definitely be eligible to be dropped into the MLP, is that right?

That’s correct.

Okay. And then on the accelerated development of the LPG export terminal and the Sweeny fractionators, in your analyst day presentation you talked about Sweeny Fractionator 1 coming on in ‘15 and I think the LPG export terminal coming on in ‘16. Does the accelerated capital spending that you guys got Board approval for, does that push the LPG terminal into ‘15 and maybe Sweeny the beginning of ‘15?

No, we’re really still on our target startup date we’re still on budget in terms of our total expected cost. This is really reflects a spending curve coming in faster than we expected. But total labor hours, material costs, all those things are just moving forward from where we were on that piece. And but we have not changed the schedule on that. But the good news is on target, on budget.

Okay. So, just earlier spending and then in the later years you’ll have less spending than what you thought, I guess?

Correct.

Okay. And then just going back to your comments around the splitters, not too long ago you guys had talked about possibly building a splitter around your facilities. It sounds like that’s on hold now, pending what happens with condensate exports. Is that a fair assumption?

I think we should that there is an infrastructure opportunity beyond just a splitter. So we’re still very active in looking at both the design on the splitter as an opportunity as well as infrastructure. And I think it’s really for us, it’s kind of the decision is simple as a complex splitter, what you want to but then how does that fit the refining operations that’s still ongoing. But we still see an opportunity there on the condensate side.

Okay, that’s fair. And then you guys talked about in the past a pipeline solution to move crude oil from west to east on the Gulf Coast. Have you guys moved that project forward, or is there any more clarity around what the scope of that project could be?

Yes, I think that Beaumont gives us additional access point and opportunity as you think about our system. And so that’s part of our thinking as we go forward as to how do we use that more effectively to really look at connections out that terminal to get into Louisiana. So, we’re actively studying marine as well as pipeline options around that.

Okay. And then last question to me. With Cushing inventories having been depleted more recently, and another drawdown today, does that have any impact on Ponca and Borger? Or do you do all, your inventory inside the refining fence, or do you look at the Cushing market, the Cushing storage tanks, also, to balance that?

I think actually having the refineries there actually gives us additional flexibility with the storage they have. So it is not impacted the operations. Clearly Cushing needs to replenish, its right at the minimum. But I think have the operations there actually gives us a degree of flexibility of we’re just having a market center source there. Remember again, we take a lot of that crude in Ponca border comes from locally gathered systems as well, particularly in borders. So that really, it’s a nice tie but it’s not an absolute must that we connect the two together to the operation.

Okay, understood. I appreciate the time. Thank you.

Thank you. (Operator Instructions). Our next question is from Bradley Olsen of Tudor Pickering. Please go ahead.

Hi, good morning everyone.

Hi Brad.

Good morning Brad.

A couple more questions. I think my questions have been pretty picked over but I did want to follow up on the Beaumont facility. Obviously we are seeing quite a bit of activity around the Gulf Coast on the storage side. And storage rates have been reported by some of your midstream competitors as being pretty attractive and improving. You guys certainly have a lot of storage, both inside and outside the refinery gate on the Gulf Coast. When you think about the valuations that you have seen in the market, and saw in the Beaumont process, does it really change the way that you think of your already-owned facilities and maybe the values that they could be dropped down into an MLP?

No, I mean, obviously we’re encouraged by valuation in the Midstream from our own perspective. And then we’d agree we see the opportunity. So, I think that’s been – we’ve talked about that, that’s part of our plan to grow. And then, on top of that organic and the acquisitions piece and I think we just put it all together and share great Midstream opportunity. But it does highlight the value of our Midstream assets that were initially embedded so to speak in our transportation reporting system.

Okay. Great. And the Beaumont facility, which was a combined terminal and dock facility, with all of the increased maritime activity along the Gulf Coast, are you getting to a point where you see the dock portion of that asset as being maybe somewhat of a scarce resource in the Texas Gulf Coast area?

Yes, we think the dock is going to be well utilized and that was part of the attracting for us is another option to either from a products or a crude standpoint to take advantage and capture that. But I think, product side, crude side, you just can see a lot of logistics moves and that’s why we like this particular location asset.

Okay. Great. And as we think about the still uncertain outcomes of the condensate decision, knowing that there is maybe potential for 700,000 barrels a day of condensate maybe hit the water at a lower cost, or more easily than maybe the market previously thought, does that increase opportunities for your existing Jones Act tankers? Does it make you more interested to get involved further in that market or change the way that you’re thinking about the usage of those vessels between Texas and Louisiana, or Texas and the East Coast?

We’ve continued to optimize that movement based on the relative value of refining. And so, condensate it’s a fuzzy definition. But the light crude utilization still makes a lot of sense. The condensate just spend how that goes, you can actually open up international opportunity with that perhaps on some of the product side. So I think we’ve kind of thought about it that way but I think we still like our utilization on marine vessels in that light even, lighter crude fraction. But just to be how things develop, we have a lot of flexibility around that.

I’ll just add, I think second quarter the MR vessels were fully utilized. The question is it’s just an optimization and how do you want to use them, Eagle Ford to Alliance or Eagle Ford to Bayway. And so I think we’ll always run those numbers and do the things that generate the most value on that. I think we’ve said previously we would have an interest in acquiring an additional Jones Act capability. So, we’re always looking around that.

Okay. And just a follow-up on the chemicals side of things. With the start up of the 1-Hexene facility, it’s always a little bit difficult to pin down the granular project cost at the JV level. But is there a good sequential EBITDA uptick number that we should think about? And will we see full EBITDA contribution reached later this year or early in 2015?

So, this is 550 million pound per year 1-Hexene plant. Still see good demand for that, it uses a kind of a smaller amount of raw material and polyethylene production. And so that’s going to have a ramp-up period. We have talked about the investment being in the order of $200 million or so. And I think that long range return of 15% to 20% on those is kind of the way that I look at that. And it will take a period of time to reach that. But I would say that we’re hitting the market I think at a pretty good time.

And that’s used to develop polyethylene at CPC facilities or is that going to be marketed to third-party consumers, as well?

Almost all polyethylene will use some type of command where they call it and Hexane being the big piece that butane being the smaller piece. So that’s a global market and it deals within CPChem as well as other producers.

Perfect. Thanks so much, guys.

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

Well, thank you very much for participating in the call this morning. We do appreciate your interest in the company. You’ll be able to find a transcript posted to our website shortly. And please feel free to give Rosy or me a call if you’ve got any follow-up questions. Thanks again. Good day.

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