Welcome to the first quarter 2013, Phillips 66 Earnings Conference Call. My name is Tresheda, 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’d now like to turn the call over to Clayton Reasor, Senior Vice President of Investor Relations, Strategy and Corporate Affairs. Please go ahead.

Thank you. Good morning, welcome to Phillips 66 first quarter earnings conference call. With me this morning are Chairman and CEO, Greg Garland; CFO, Greg Maxwell; and EVP, Tim Taylor. Presentation material we’ll be using this morning can be found on the Investor Relations section of the Phillips 66 website, along with supplemental, financial, and operating information. Slide 2 contains our Safe Harbor statement. It’s a reminder that we will be making forward-looking statements during the presentation and our question-and-answer session. Actual results may differ materially from today’s comments and factors that could cause actual results to differ are included here on the second page of this presentation as well as in our filings with the SEC. Also you may know that on March 27, our registration statement relating to the securities of Phillips 66 Partners LP was filed with the SEC. As this statement has not became effective our remarks about the MLP will be limited and we will not take questions on this proposed offering during today’s call. That said, I’ll turn the call over to Greg Garland for some opening remarks, Greg?

Thanks Clayton, good morning everyone. Thank you for joining us today. It’s hard to believe that just a year ago that we launched Phillips 66 as an independent company. We are pleased with our performance today. We are a new company, but we are built on a 130 years of experience. We have a portfolio of business that is as uniquely positioned to benefit from the significant growth in American oil, gas, natural gas liquids production. First quarter 2013, we operated safely. And our financial results reflect the fact that we captured positive market conditions in our refining and chemicals businesses. Operating excellence continues to be our top priority. We aspire to be a company where employees work their entire careers without getting hurt. In the first quarter, we continued our improvement in our safety and environmental performance. We continue to pursue growth in high value businesses while maintaining our capital discipline. Our plans for a new natural gas liquids fractionator in the Gulf Coast region demonstrate investment opportunities we have in the American energy landscape as well as highlight our unique position across the downstream value chain. The plans DCP has announced are additional important sources of growth within our midstream segment. The Sand Hills and Southern Hills pipelines will deliver NGL to the growing Gulf Coast markets and are expected to be fully in service by mid-2013. CPChem continues to advance its Gulf Coast ethane cracker and polyethylene facilities, once complete these facilities are estimated to create about 400 long-term direct jobs and about 10,000 temporary engineering, construction jobs. Growth in our chemical segment also comes from an NGL frac expansion at Sweeny, our 1-hexene project, and our Saudi Polymers project. Ultimately the growth in capacity allows for growth of dividends and share repurchases. Shareholder distributions remain a priority for our company. During the quarter, we paid an increased dividend and we repurchased $382 million of stock, as part of our $2 billion share repurchase program. Since the company’s inception a year ago, we’ve returned $1.2 billion of capital to our shareholders through dividends and share repurchases. We have a diverse portfolio that provides us earnings durability as well as a balance sheet that give us financial flexibility. These are two very important traits that are needed in our industry to be well positioned to weather the cyclicity that’s inherent in our business and continue to grow shareholder distributions and value through the cycles. With that said, I’ll hand the call over to Greg Maxwell to take you through the quarter results.

Thanks, Greg and good morning everyone. We had a very solid first quarter driven by strong refining and chemical margins. Reported and adjusted earnings both came in at the $1.4 billion level with earnings per share at $2.23 on a reported basis and adjusted earnings per share at $2.19. Excluding changes in working capital, cash from operations for the quarter was $1.8 billion, our cash flow generation enabled us to fund our capital program, pay $194 million of dividends and repurchased $382 million of common stock during the quarter. On an adjusted basis, our annualized 2013 return on capital employed was 20%. Before we leave this slide, I’d like to mention one key item. As outlined in our earnings release we made a few changes to how we report our operating segments. This is in response to changes in our internal reporting processes and is designed to increase transparency and ensure better alignment with how we think about operate and manage our business. We are moving from having four segments to five with our Refining and Marketing segment being split into two new operating segments, Refining standing on its own and Marketing and Specialties. In addition a portion of our transportation assets that were previously reported in our refining and marketing segment had been separated and are being reported as a part of midstream. Our slides reflect this new segmentation and prior year numbers have been recast for comparative purposes. In addition the quarterly information for 2012 has been recast and is included in our supplemental pages provided with the earnings release. Full year 2009 and 2010, as well as quarterly 2011 recast numbers will be available later in the second quarter and will be posted to our website. Slide 5 provides a look at our first quarter adjusted earnings…

Thank you, Greg. I'd like to take a couple of minutes to review our expectations for the remainder of 2013. We continue to focus on growth and returns enhancements centered on opportunities created by the rise of oil and gas production in North America. In our midstream business, we are pursuing developments at 100,000 barrels per day NGLs fractionator to be located in the Gulf Coast region. And this project would enable us to take advantage of existing midstream transportation and storage infrastructure. We see excellent market facing opportunities to grow the NGL business and the chance to supply 30 NGLs and liquefied petroleum gas to the petrochemical industry as well heating markets. If approved, we would expect construction to start in the first half of 2014 with the operations commencing in the second half of 2015. Our 2013 budgeted capital expenditures and investments are currently expected to be about $1.9 billion of which $1 billion is dedicated for maintenance capital. As we’ve said before, we see this level set right around our DD&A amount going forward. Included in our maintenance capital are our capital requirements for Tier 3 implementation. During the quarter, we funded nearly $400 million of our capital program and nearly $800 million if you include a portion of our major joint venture expenditures. This capital was spend mainly on the growth plans that we have outlined before where we are expanding our higher value businesses. As Greg said in his opening remarks, we are in a cyclical business and we are well positioned to capture opportunities caused by both short-term price dislocations, as well as medium and long-term fundamentals. The Brent WTI differential will be dynamic as infrastructure progresses and trade flows adjust over the coming months and we expect LLS to move back to a discount versus Brent. Although we may see some narrowing of crude differentials as takeaway capacities build, we still have an advantage position. With seven coastal refineries, three each in the Gulf and the West Coast and one on the East Coast, we are well-positioned to grow product exports, and this past quarter we exported an average of 150,000 barrels a day of refined products which is a significant increase over last year. With that, we’ll now open the line for questions.

Thank you. We will now begin the question-and-answer session. (Operator Instructions) And our first question comes from Ed Westlake from Credit Suisse. Please go ahead.

Hey, good morning. Congratulations on the results and thanks for all the disclosure. It’s going to keep me up tonight, so my wife is going to be happy that I’m inside an Excel spreadsheet, so let’s start-off with some questions around that disclosure. Just on the midstream, you’ve broken it out and you said you transferred all the assets in that. So you’ve got $175 million in the first quarter of earnings before tax, you’ve got around $19 million of DD&A, but there will be some see-through DD&A the why I think about it atleast in DCP Midstream, which doesn’t come through say another $40 million. You got to sort of over, maybe call it $230 million of EBITDA see-through for that division for the quarter implying around $900 million to a $1 billion for the year. Is that a fair way to think about the overall Midstream EBITDA at PSX?

Yeah, I think Ed, you’re correct. When we look at that, we think that’s about with the combined results about the right amount of EBITDA for that segment.

Right, okay, thanks, just walking through some Maths there. And then a totally separate topic, RINs, it’s come up obviously on every conference call. Where do you see the exposure if you assume that the current RIN price persisted say into next year or into this year? Do you have a dollar million assessments at this point? Thanks.

Yeah, this is Tim and I’ll start with that. I think that, when I think about RINs to me it’s obviously a cause to the impacts the way we go to market in our sales channel. And so, I think fundamentally we manage that through our commercial business, we have a lot of options. We’ve taken lot of actions to increase blending on bio-diesel at our terminals et cetera to mitigate that that said when you look out what the blend wall going forward you realize that that’s still an issue yet to be addressed, it has be addressed really from a macro standpoint, but to this point we find that manageable it does effect our planning, but I think that the real issue really starts to surface in 2014 with the additional requirements and a need for advanced cellulosics that’s just are not there.

I mean, if I could push you a little obviously, Valero has given some numbers where they bracketed around a range of 500 to 750 from memory. Is there a number you feel comfortable sharing if and then I say basically persisting market conditions from here to the end of the year?

This is Greg. I would say first of all, as we look out, we think it’s just an unworkable program. And we have seen this coming since 2007 and we have been trying to position ourselves for this. I think the industry is working hard on solutions in Washington. But that said, we are trading RINs and like any other commercial activity, we really don’t want to expose our positions because we think it puts our traders at a disadvantage. But I will say, our view is that the industry and particularly us we believe, we are capturing most of the cost of the RINs in the market today.

Thank you.

Our next question comes from Evan Calio from Morgan Stanley. Please go ahead.

Hi, Good morning guys. The new disclosure is definitely helpful. First question, one of the two areas I think where you are differentiating growth profile is in the midstream and you mentioned Sand Hills and Southern Hills are set to ramp in mid 2013 which is pretty soon with aggregate 375,000 barrels a day of [white] [ph] grade capacity in the Mt. Belvieu. I mean, can you discuss, are you taking to, are you planning on taking some of those post fractionated volumes at your facilities and displacing third party purchases and I just, how you see the demand for these volumes and how does it work in your system?

So, a lot of the volumes or 70% of the volumes are DCP controlled volumes and the balance is third-party volumes on Sand Hills. We don’t see that displacing any of the internal volumes that we have. As we go to market with those volumes, as you know DCP is a large supplier to CPChem and we like that relationship and we see that relationship continuing going forward. But we look at those projects kind of on a standalone basis. We think we got good value capture. We think we get the assets loaded over some period of time, but relatively quickly and those are going to be good solid assets for us.

That’s great. And switching gears into chemicals, Saudi Polymers facility continues to ramp. I mean, should we expect the full contribution in the third quarter? And I guess I’m trying to assess where you are in that 10% to 15% earnings lift once the plant is fully ramped.

So, I think we talked on the last call that we’re working through operational problems. It’s running much better this past quarter. So it continues to progress. So our view is that, yes, in the second half of this year you really start to see the impact from the Saudi Polymers plant startup.

Right. Maybe a last one if I could. I know you gave a global utilization in O&P at 91% and you mentioned that the U.S. is affected by downtime at Sweeny. I mean, can you give us the U.S. rate and kind of where we think that might normalize?

Yeah, looks like in this last year, 96% and I would, our view is ethylene unit rates up 95% to 100%. That’s pretty much on a sustained basis running flat out. So, I think on the U.S. side that really we would expect that to run at capacity in that 95% to 100% range.

Right. And where did you run in the first quarter?

In the U.S. we were in, I believe the, 90%, 95%.

Great. Appreciate it, guys.

Our next question comes from Jeff Dietert from Simmons. Please go ahead.

Good morning

Good morning.

In the press release this morning you mentioned that you took delivery of 400 railcars. I believe that’s out of 2,000 expected. Are these general purpose railcars or [coil] [ph] tubes and could talk about how you plan to deploy these cars, and where the greatest opportunities are in the current market?

So they are general purpose cars. This is order we placed shortly after we formed as the new company and we expect to kind of get the 2,000 cars ratably over the balance of this year. I think the plan really hasn’t changed for us. It really was primarily envisioned to be Bakken East and West and I think our view is that we’ll continue to do that.

Secondly, on a second topic quarter-to-date many of the regional cracks are down sequentially and most are down year-on-year. Some of the crude differentials have softened a bit. Perhaps they are bringing in some incremental imports opening for Gulf Coast imports. What do you think the major drivers of the softness in cracks are and do you expect this weakness to continue to the summer?

So, on the crack spread, I think you’ve got both that work. You’ve had some market fundamentals on the product side that have continued. First quarter is typically not the strongest and second quarter should see some seasonal uplift on the product side. But so really I think what’s moving around are the crude dips and you’ve looked at the first quarter. They’ve come in and you looked recently you started to see some widen and back out. So I think our fundamental view is that that the fundamentals haven’t changed, that we still see the discounts with Inland crudes, we still see the Canadian discounts. We do believe though that it will remain volatile and that we wouldn’t be surprised to see those come back out a bit from where they’ve been in the last month, may not be as high as what we saw or as much volatility as last year, but we still believe that those dis on the Canadian and the Inland crudes are very sustainable, and I think we’re in a period of readjustment here in the Gulf Coast as those crudes make their way into Texas and then ultimately find their way into the rest of the refining system on the Gulf Coast.

Thank you.

Our next question comes from Arjun Murti from Goldman Sachs. Please go ahead.

Thank you. And I guess my thanks as well for the disclosure and I had a question as well on it. On the transportation segment, I appreciate your breaking that out. It looks like last year on a full year basis you had just over $250 million of EBITDA. If we annualize the first quarter you’re over $360 million. Is the delta there just taking some of the tariffs to a market-based tariff from an internal cost accounting? And then, can you also discuss what may or may not be included in that transport segment. I’m pretty sure it does not include all your, what we may call, logistics assets, but if you have any color there that would be great.

So, Arjun, part of the 2012 result included impairments around the REX pipeline.

Yeah.

So you probably need to add those back in if you want to get a more reasonable number, but you’ve got what $170 million in the second quarter and $160 million, I guess. So what is that $300 million, $330 million of earnings you probably need to add back. I don’t know. If Greg, if you

From an asset perspective, Arjun, I think it was the other question. Some of the, what you would consider storage tanks and pipes that are inside the refinery gates, are still aligned with the refining segment. We’re continuing to look at that, but you can imagine it’s a little bit more integrated from an asset basis in that refinery aspect. So we’re looking at that, but a lot of the storage and pipes inside the refinery gates are still being reported in the Refining segment.

Got it. So, yes. So those storage tanks and terminals might still be within the Refining segment. That makes sense. Did you change though the account of it from an internal cost accounting to a market-based tariff as you moved from 2012 to 2013 or is there no delta on that point?

Arjun, it’s Tim. There are some adjustments that have been made. Some of those were obviously at market. Some were more focused on the cost side. So this does reflect that movement now to, really across that system we’re going to be going to the market-based adjustment rate.

Got it.

So there was an uplift from that.

Yeah, great. And then, on the crude slate slide, I think it’s slide 15. You described WTI-based in shale. I presume the shale is midcontinent and therefore effectively a WTI-based product or is there some reason you have it separated?

Well, we like to really, WTI traditional mid-con production, I think we like to separate the shale, very focused thinking about Bakken, Eagle Ford and some of those that are really probably better described as light tide oil. And so, I think that’s a distinction that we use to kind of help draw the distinction and really bring in new plays. Cleary WTI may have some expansion as well with the EMP activity, but that really helps, I think, highlight where the new source comes from.

Got it. And then, just a quick final one. Have you guys given any consideration or plans to investing at the front-end to be able to process more light oil at some of the otherwise heavier refineries or do you not have an interest in doing that?

So, Arjun, it’s Greg. Good morning.

Hi.

Yeah, we’re looking at that. We’ve done preliminary engineering around condensate splitter, standalone and also within the refineries. I think we’re moving towards utilizing underutilized equipment in our refineries today to cheaply find a way to process more lights and we do have some projects identified, but these are small projects that I would say $50 million and less that are really kind of quick-hit projects that we can get implemented and get paid out fast. We don’t envision, at this point, doing a standalone condensate splitter at some point.

That’s great. Thank you so much.

You bet.

Our next question comes from Bradley Olsen from Tudor Pickering. Please go ahead.

Hi. Good morning, everyone.

Good morning.

Question on your, you’ve obviously done a lot to access more on sort of sales crudes that’s coming through in the slides that you had in your presentation this morning, but there has been a pretty significant compression between Brent and WTI, and Brent and Bakken prices, which some previous questions hit on. Is there a price level or is there a sensitivity to your crude by rail operations or a price level or a price spread where it’s no longer interesting economically to ship Bakken crude to Ferndale or to Bayway?

Yeah, certainly there is a point, which, again we’ve said in the past that we look at Bakken to the East Coast, the West Coast maybe in that kind of all in from the well [that had] 12 to 16. So if you start getting that to come in too far obviously we’d want to do that, but fundamentally that crude needs to go that direction. That’s the right place I think for that crude to go. So I would see that as short-term dislocation versus really a fundamental, we still believe Bakken will price to be competitive and it’s got to taking account where needs to go the price itself into the market.

Great, thanks. In the LLS market, we’ve seen this rally where LLS despite the increasing in Eagle Ford production and the flow is coming south down the Seaway. We’ve seen LLS rally recently above current levels. Any comments as to what you’re seeing in the market and whether or not Phillips has been able to maybe access crudes on the Gulf Coast at a discount to what we’re seeing on our screens, when it comes to LLS pricing?

Yeah, so LLS is our marker crude that we talked about in the Gulf Coast region and we’ve been successful really having additional penetration particularly with Eagle Ford crudes as well as some supplements from some of the other mid-con crudes into that region. And I think the way, I would be explain that is that I think you look back at our Marine option that we’ve taken on the MR tankers put in service. And that’s drilling as access Texas crude over to Alliance and Lake Charles. And so I think really what you’re still seeing is probably some reduction in LLS over the past quarter. And then you got the transportation bottleneck from Texas to Louisiana that ultimately get solved. But I think as a result of that you’re relatively indifferent right now on LLS versus some of the imported grades. But we still think fundamentally as that crude shows up into the Gulf Coast that you’ll begin to see that discount.

Great. And a question on the chemical side, the $8 billion opportunity you said that was sighted in the presentation. I might have my numbers wrong. But that sounded a little bit higher than the roughly $6 billion figure that I think have been discussed in the past, are there any specific projects on the chemical side that’s driving that number up to $8 billion.

That’s a multi year look the big piece of that is the new ethylene cracker and associated derivative plans on the petrochemical space but it also includes smaller interim closuring projects with the fractionator expansion at Sweeny, the 1-hexene plant, and some other kinds of more smaller project, but the big driver is that project in the petrochemical complex here in the Gulf Coast.

And Brad of course that’s a gross number, CPChem level right.

Correct, right,

Yeah, sure and just one last one, you guys announced midstream a project on the midstream side to help tackle the fractionation shortage that’s developing on the Gulf Coast, as you look into the NGL market, where you guys are obviously very active. Do you have any thoughts on potentially addressing the lack of export capacity that we have been experiencing on the Gulf Coast especially in light of recent announcements by companies out there to bring large batches of Marcellus LPGs down to the Gulf Coast and that’s it for me, thanks guys.

So, yeah I think we said previously that we’re looking at a multi product export facility on the Gulf Coast, it could include condensate LPG, even refined products, and so I would say we are in the feasibility stage on that project and looking to move that forward.

Our next question comes from Paul Cheng from Barclays. Please go ahead.

Hey good morning guys.

Good morning.

Good morning.

A number of quick question on East Coast your deal with global partner, do you have any flexibility not to take the oil to Bayway, but to other location or that 50,000 barrel per day have to go to Bayway contractually?

It’s really focused on Bayway. It makes a lot of sense that I think ultimately you can have some flexibility, but we’ve certainly seen the advantage and that where we would intend to use that.

All right. Tim, on when that contract startup?

So that became effective right at the beginning of the year.

Beginning of this year, right?

Correct.

And that on, I think that you guys have been discussing about bringing the heavy oil to California wherein some of your competitor that are looking at somewhat different option by rail, the heavy oil maybe into or that the light oil into Pacific Northwest and then budget on. So wondering that, whether that maybe an option you guys will be interested or that you will stick to primarily looking at to well heavy oil from Canada to California. And if that is still option that you’re current expect to, any status update that you can provide?

Sure, it’s really a multifaceted approach on in looking at bidding different crude slate to the West Coast. So today we are doing some large movements down the coast into California on heavy Canadian. And you can look in the Northwest to do that, so that’s an option that we’re going to continue to use, and that we’re looking at expanding an opportunity with some of the logistic things we’re putting in place, and we’re also continuing to move crude by rail in smaller amounts into California and looking at projects really to increase that as well.

And well maybe this is for Greg, Greg can you give me some balance sheet data, what is your working capital, the inventory, market value in excess of the both and also the long term, I’d presume that is long-term.

The replacement value and excess of LIFO Paul is $8.1 billion at the end of the first quarter, and then working capital?

Yes.

We had at the end of the first quarter $16.4 billion of current assets and right at $15 billion of current liabilities.

And all of that is now long-term debt, right?

That excludes the long term debt, long-term debt sat at, right at $7 billion. We did reclassify some of that I think, now we left at $7 billion.

Okay, so long-term debt is $7 billion. Greg, and given that expected pretty heavy capital only from CPC so we assume that any dividend payment from CPC to the parent corporation will be quite minimum until that order at least that Gulf Coast cracker is complete.

Yeah, Paul so I mean we had given guidance I think in our December meeting that the capital expenditure program for CPChem is going to be the neighborhood of $1.2 billion if you look at their EBITDA, last year it was about $3 billion, so we think there is going to be nice distributions back from the chemical company to both of the owners this year.

Okay, two final question. Greg can you remind me what is the liquidity need for you to run your business? What is the level that you feel comfortable.

That we are honing in on that Paul, we look at leading cash in somewhat in the neighborhood of $3 million to $4 billion. We’re comfortable with our current liquidity uncommitted credit facilities that are $5.2 billion, $4 billion on revolving credit facility and $1.2 billion associated with our account receivables securitization facility, and you’re are aware that we use some of that liquidity to as a basis for back stopping our letters of credit. I think at the end of the first quarter, we had about $200 million associated with LCs.

So, with your cash position at 4.7 though I think that is clearly that you’re in excess of what you need to run your position and even though margin have come down, you’re still generating tons of free cash, wondering that is there any plan of accelerating the cash return to the shareholder.

First, now I’ll turn to Greg, I recall that we’ve committed to paying $1 billion of our short-term debt eliminating the short-term debt by the end of the year. So, that’s $1 billion of expected cash usage, and then I’ll let Greg respond to the distribution aspect.

So, dividends are highly important to us, Paul and I know you’re a big supporter of dividends, and I think you should what expect us to increase the dividend this year, we do want to get on annual cycle of dividend increases. We’ve always said, we want to pay a competitive dividend when never we want a back up from it, when we look back in 10 years and say we’ve increased the dividend every year very important to us. We’ve confirmed our previous guidance on capital expenditures at the P66 level this year. So I think, then when you think about the capital discipline around what were going from capital investment standpoint, to the extend that we’re going to generate excess cash, then it will go against our existing $2 billion share repurchase program that we’ve talked about.

A final one. Tim, I think that there is one potential option in terms of the transportation side to well the bitumen directly down to the Gulf Cost and then return [core] to bring the condensate up to their broader area given there’s a natural position there. Have you guys looked at that as a possibility and if you have any kind of cost estimate, if you do a wrong shipping like that, what maybe the cost compared to pipeline cost may look like?

I haven’t done it specifically for that. But we are, that I could recall, but we are looking at that. Clearly you give (inaudible) on the way down. You can send it back up for the pipeline movement and so you get a better look. But we really haven’t looked specifically at that as something that we’re really pushing on hard at this point. The pipeline solution still longer-term is the right solution of our marine movement on the Canadian.

Thank you.

I think you let me factor for us, Paul, is really the heated, the coal cars and that’s true probably for the industry.

I see. Very good. Thank you.

Our next question comes from Faisel Khan from Citigroup. Please go ahead.

Yeah, thanks. Good morning. Faisel from Citi. Just a question on the refining side, the other refining income. You guys talked about it a little bit in your prepared remarks, but it’s a big swing in the fourth quarter, the first quarter from $58 million to $182 million and can you talk about that little bit. I think you said it was related to selling excess Canadian heavy into the market and can you discuss how that works now that’s going to trend going forward?

This is Tim. So basically, I think that that results from our positions on our Canadian takeaway. And so we’re the largest importer of Canadian crudes and so when we have an excess we’re able to capture that value and that’s really was a very significant factor in the first quarter for us.

And because those benefits go across several regions rather than attributing it to the mid-con or Gulf Coast, we spread it over the entire segment.

Okay. So was that mostly a spread benefit or was it the fact that you ran less Western Canadian crude in the quarter in your system.

Primarily a spread benefit, that group also contains some of our commercial activities beyond that as well. So it’s a combination of things in that matter.

Okay. Got it, and just looking at your cash flow statement your undistributed earnings swung to a positive number, is that what you talked about earlier that you expect to take distributions from CPChem during the course of this year even though you’re investing heavily in the business? Is that a trend we should see throughout the entire year for a positive sort of impact from undistributed earnings?

At CPChem we’re moving. Remember last year we paid off the debt at CPChem and so distributions were significantly reduced last year from CPChem. And this year given what we think the chemicals business is, the margin of the chemicals business, we think there is going to be good cash generation in that business. We’ve got $1.2 billion at the CPChem level, capital spend. And so, I think you would continue to see distribution in excess there from what we’ve seen previously last year.

Okay. Got it. And back at CPChem with the expansion of your facilities. Do you have all the permits now in place or how much longer are we waiting for the permits to proceed with the expansion that you guys talked about in the Gulf Coast for the base chemical, commodity chemical crackers?

Yeah, so the permitting process has been well underway for sometime and we made good progress for kind of reaching the end, because we’re looking to take final investment decisions that in the third quarter. So, I think I’d give you some indication of where we are on that and to this point, that’s not been an issue.

Okay, got it. And then with the NGL fractionation project that you guys are talking about is that designed to coincide with the chemical facility to supply feedstock facilities. So I guess is there kind of an agreement. Will there be any potential agreement between the fractionator and that chemical project within the joint venture?

So, I think we’ve said in the past we’re kind of look at balances, we’re pretty balanced. There is obviously an increased demand, but it doesn’t specifically tie to that Chem project, but it certainly on the macro level is a nice matchup when we do that.

Okay, got it. And as going back to the midstream questions from earlier in the call, there were kind of a lot of numbers that were throwing out. But I just want to make sure, I understand the numbers. So excluding DCP Midstream, if I am looking at the midstream income before taxes, I see NGL operations are $50 million, transportation income of $73 million, and D&A of roughly $19 million. So it seems like it’s roughly $100 million of EBITDA kind of associated with the NGL operations and transportation excluding DCP Midstream is that the right number. As I heard a $200 million number and $300 million number earlier on the call, I just want to make sure looking at that correctly.

So looking just at Phillips 66 operations, you would want to take the NGL Ops and the transportation number, that’s very specific to the P66.

That’s $20 million of depreciation right.

Okay, got it and then last question from me, just on tax, just what’s your guidance for the tax rate for the rest of this year.

We’re looking at the low 30s I would suggest something at 30%, 32% range.

Okay, understood, is that a sustainable tax rate sort of all has been equal for the business?

Yeah,, I think it’s a fair raid at least as we look out through 2013, sometimes as you are aware, some adjustments come in and introduce some release, but I think 32% is a fair number.

Okay, got it. I really appreciate the time, thank you.

No, problem thank you.

Our next question comes from Paul Sankey from Deutsche Bank. Please go ahead.

Hi, everybody, and just a second everyone, thanks for the disclosure that you offer. Could I just slightly pick around in slide 15 please, which is very interesting summary. You said and I think you remain committed to this idea that you’ll keep your CapEx in line with your DD&A, is that the correct way of looking on a go forward basis?

We’ll make our maintenance capital at…

Maintenance capital….

Right, and then, so the overall levels that would be $1 billion and then the overall level of CapEx, could you talk a little bit, are you still going to turnkey that within the sort of $2 billion range or…

Yeah. We said 1.8 and I think 1.8., 1.9 something like that. I think 1.8 is on a cash basis.

And $3.7 billion.

And of course that excludes the capital that’s been spend by DCP or CPChem.

Which is self financing, right?

Exactly, exactly, but if you roll it all up, it’s about $3.7 billion with…

Proportionally consolidated with $1.8 billion being the Phillips 66 capital.

So, I guess the point is that the previous levels of CapEx are about the same as what you’re anticipating spending going forward. That was kind of my point.

Yeah.

Okay. So, allowing for that and you bring to the debt pay down and sensing about what you may do with cash, it sounds shareholders. I was just wondering in terms of the way this slate of crudes is shifted on the left hand side, and then to an extent on the right hand side, the yield is shifted. Would it be fair to say, that’s a low hanging fruit kind of move and it would be hard to see an equivalent kind of continuation of the shift that you’ve achieved going forward or do you anticipate that you can kind of continue those dynamics of obviously rising WTI based rising, Canadian rising, were actually down on the heavy, but then rising shale and collapsing Brent based. I guess what I am trying to get to is, is there a terminal point there?

There is, but we’re not there yet, Paul. So our targets are 100% advantage crude and then you start taking advantage crudes and replacing it with more advantage crudes, i.e., in the Mississippi line or doing around Ponca City or displacing a WTI barrel with a better barrel, more consistent quality, better pricing. There is a theoretical limit on the clean product yields and so we’re approaching that limit, but and then yeah, we’re already high on distilled yields, industry leading distilled yield. So but there is still lot of room left in the fairway for us in terms of the advantage crude and the value capture for advantage crude.

Would the LLS I am assuming is in Brent basis?

Yes.

So, I guess, the next big thing is going to be, can you give us a sense to how much that’s actually LLS and how much of that is actually Brent, the 32% that you got running burn rates?

Sure, LLS clearly on the Gulf Coast and so very specifically, we haven't disclosed it by refinery, but I think if you think about our refining system you could see where that is. So that's really down the Gulf Coast and the Brent base for us would be [A&S]. It would be the other non-Bakken kind of crudes that we some times bring into Bayway, plus the LLS so it's kind of a mixture of things that really, rather California crudes are A&S based which ultimately is Brent-based as well. So I think you kind of look at regionally, you say, California, Bayway and then a portion of the Gulf Coast is where we see the Brent-based exposure in the U.S.

Yeah, that’s helpful. Thanks. And then you’re saying, it’s going to get to 100% advantage but would A&S be in that advantage target or...

Yeah, so I think that we look at it and ultimately as we talk, we believe LLS with the movement of Mid-con to the Gulf Coast probably, just to be competitive will have to, will change. And then A&S, I think as now as the Bakken continues to move to northwest, as Canadian access to the West Coast improves you will see that as well. So that is certainly, as we talked about 100% target, there is a premise either to substitution or competition that we begin to get the advantage in those other crudes as well.

Yeah, that makes sense. I mean, and just and my point was that you think you can deal with this without any great expansion and capital, I mean, I think what you said is more or like $50 million type projects of changing access as opposed to any major surge in CapEx is required.

That's correct.

Was the timeframe on the 100% advantaged?

It keeps getting shorter.

Yeah, that’s correct.

I keep pressing it, yes it will take us a couple of years to probably get there I think all the way for us.

And basically I guess it will be a little bit, I mean you can see here there is a bit more gasoline than it was in 2011, but it’s of the nature of like 0.5% more. Obviously that would…

No, that’s really I think that little bit of shift that you see in the first quarter is probably more to do with Sweeny down.

Yes.

That’s correct first quarter versus running more light sweet crudes, where you would expect higher gasoline yields. That directionally, we don’t want to give up this 41%, 42% distilling yields that we’re generating in the refinery. So…

Yeah, probably work to our advantage because gas fracs were little better than they expanded.

Yeah, that’s interesting. Okay, so, it’s not a crude driven changing yields.

We had Sweeny down 49 days in the first quarter, for a turnaround and then the power outage that hit us there brought the whole complex down.

Yeah, what was that by the way because it’s now looking like $1 million barrels of capacity down at that point right?

So, we lost all three feeds into this whole complex. So it impacted the refinery, it impacted the CPChem facilities and the frac, and to some degree actually impacted DCP also as we were trying to bring volumes down the easy line, which terminates at Sweeny, the frac, so…

Something we will do it, correct

We had a scheduled turnaround for February and that turnaround went well. And then as we were coming backup, we lost power and we were down for another week. So I think the number actually 47 days, when it was down, had a negative impact.

What cause the outage?

System work that our utility supplier was going to actually upgrade their systems past the trip.

Yeah, okay. That’s enough. Guys, thanks a lot. I appreciate your time. Thank you.

Our next question comes from Cory Garcia from Raymond James. Please go ahead.

Good morning, fellows. One quick follow-up to this idea of bringing heavies into California, specifically the rail, the barge opportunities. Clearly some more associated costs with that element as well as the coal railcars is bit of an issue. But wondered how we should think about ultimately the cost structure on that aspect. Clearly the 12 to 16 of rail Bakken to Washington makes sense, but where does that go and even if you are able to pride up some sort of order of magnitude, where does that go and actually bring in those heavies from Canada into California?

Yeah, so you saw Atlanta in the supply chain. Clearly cost can move with time too as we do out the solution. So I think you’ve got to see those discounts on the heavy, for instance, enough to offset that transportation, provide the quality differential and the incentive to run. So I still think it’s in that range. You’ve seen the WCS discount move out here recently, but I think that for Canadian crude it’s probably still one of the further destination. So I think that just still continues to play in, but you’ve got to see a significant discount to make that move that way, the transportation.

Okay. So we’re talking probably $20 plus type of discounts to be able to make it…

It certainly works at that, yeah.

Okay, okay. And then, the Ferndale unloading facility that you guys are constructing, I guess, still in the permitting phase. Would that be a sole purpose for that thing or finally are you guys looking at expanding that into sort of a barge opportunity as well?

So once it gets to Ferndale, certainly can support that operation, but then we have the opportunity to do barge as well or some of the vessel movement down the Coast if that made sense.

Okay. So we’ll have a multipurpose flexibility to it. Perfect. Thank you, guys

Okay. Thanks.

And we have no further questions in queue. I’ll turn the call back over.

Okay. Thank you very much. Appreciate the interest. You can find the transcript of the presentation, also the Q&A. And certainly Rosy and I are available for any further follow-up questions. Thank you for the interest in the company.

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