Welcome to the Fourth Quarter 2012 Phillips 66 Earnings Conference Call. My name is John, 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 Mr. Clayton Reasor, Senior Vice President, Investor Relations, Strategy and Corporate Affairs. Mr. Reasor, you may begin. C. Clayton Reasor: Thanks, John. Good morning, welcome to the Phillips 66 fourth quarter earnings conference call. With me this morning are Greg Garland, our Chairman and CEO; our CFO, Greg Maxwell; and EVP, Tim Taylor. The 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. Factors that could cause these results to differ are included here on the second page, as well as in our filings with the SEC. This slide also contains a reminder that any comments we make regarding the formation of an MPL are not in offer of securities. So that said, I’ll turn the call over to Greg Garland for some opening comments. Greg? Greg C. Garland: Thanks, Clayton. Good morning everyone and thanks for joining us today. We are off to a good start, strong performance in 2012, we have solid financial and operating results and we continue to deliver on the commitments that we set out to achieve when Phillips 66 was created. We believe that our differentiated portfolio has allowed us to capture a number of market opportunities across the value chain resulting in significant cash generation and shareholder value creation. I’m really pleased what our employees have been able to accomplish; they’ve executed the spin flawlessly, they stood the company up, they’ve operated well, and they’ve managed to keep safety as the top priority. We’ve had a strong track record of operating excellence and when we talk about that operating excellence is personal safety, it’s process safety, it’s environmental excellence, it’s reliability, it’s cost management. This year was no exception. We turn it one of the best years ever and Phillips 66 remains a leader in operations excellence. That said, there is always room for improvement, the goal is zero instance, and our facilities continue to reduce costs, improve our reliability in our environmental footprint. Late last year, we announced our intent to form a Master Limited Partnership, which we expect will help highlight the value of our transportation logistics in midstream businesses. We also serve as an efficient vehicle for funding growth investments in these areas. We also expect to start taking delivery of the first group of our 2000 newly constructed railcars in early February. In January, we’ve entered into a five-year transportation logistics contract with global partners to move about 90 million barrels of Bakken crude to our Bayway Refinery. This agreement provides a reliable, long-term alternative to more expensive Brent-priced crudes. On the marine side we’ve taken delivery of one of two Jones Act vessels that we chartered. So all these steps support our plan to put advantage crudes to the front-end of our refineries, we’ve got ways to continue to accelerate advantage crude capture. We completely backed out imports of U.S. light sweet crude in the Gulf Coast. But we are also taking additional steps to enhance our returns. We’re going to remain very disciplined, and our approach to capital spending, we’ll continue to reduce cost, we’ll push yields and we’ll continue to increase our export ability. Product exports played a larger role in our result this year than last year as market opportunities opened up to us internationally. December was a record month for us in terms of exports. We had over 180,000 barrels of day of exports in the month of December. Regarding distributions, we said that we intend to return capital to our shareholders. We’ve raised the divided 56% to $1.25 and we’ve announced $2 billion to share repurchases. In 2012, we bought over 7 million shares for about $350 million. Late last year, we paid down $1 billion of debt, this further strengthens our financial flexibility, it reduces risk and our debt to cap is now 25% at year end. So now I’m going to hand the conversation over to Greg Maxwell, who will take you through the quarterly results. Greg? Greg G. Maxwell: Thank you, Greg. Good morning everyone. During the quarter, we ran well, we benefited from strong refining and chemical margins, and we processed more advanced crudes in our domestic refineries and this enabled us to increase our realized refining crack spreads moving our market capture to 95% in the fourth quarter and this is up from 72% last year. On the earnings front, our reported earnings were $708 million or a $1.11 per share. Excluding approximately $600 million in special items, adjusted earnings were $1.3 billion or $2.06 a share. On an adjusted basis, earnings for the quarter were up almost 250% compared to last year. If we exclude changes in working capital, cash flow from operations for the quarter was $1.7 billion. Our cash flow generation enabled us to fund our capital program, pay over a $150 million in dividends, and repurchase $245 million of common stock during the quarter. And as Greg mentioned, we reduced our debt by $1 billion from $8 billion to $7 billion and as you will see on a later slide we ended the year with a cash balance of $3.5 billion. On an adjusted basis, our full year 2012 return on capital employed was 22%. That’s up from 14% in 2011, and this improvement was mainly due to higher earnings in our Refining and Marketing and Chemical segments. Before we leave this slide, I would like to touch on a few key items this quarter. First, the special items of approximately $600 million included $564 million for the impairment of our equity investment in the Morocco refinery. This impairment was based on significantly lower estimated future refining margins in the region, driven primarily by expected increases in future crude oil pricing over the long-term. As such, we determine that the fair value of our investment in Morocco was lower than our carrying value and that this loss in value was other than temporary. Second, excluding special items, our adjusted effective tax rate was 29% this quarter compared to 33% last quarter. The decrease in the effective tax rate is mainly due to income mix and different statutory tax rates across the various taxing jurisdictions in which we operate. In other words, compared to last quarter, a higher proportion of our earnings this quarter were from foreign jurisdictions with relatively lower tax rates. The next slide provides a high level look at our fourth quarter adjusted earnings. Compared to the fourth quarter of 2011, our adjusted earnings increased by over $900 million to $1.3 billion. As shown, Refining and Marketing generated $1.1 billion in adjusted earnings, and this excludes the impact of the Morocco refinery impairment, as well as Hurricane Sandy related costs, which primarily impacted our Bayway refinery along with some nearby terminals. The majority of the $900 million improvement in R&M segment came from much stronger refining margins due largely to improve market crack spreads and strong feedstock advantages. Moving next to Midstream, Midstream adjusted earnings were $62 million, about $50 million lower than last year. This decline in earnings primarily reflects the impact of lower NGL prices quarter-over-quarter. Chemicals earnings were $246 million, which were approximately $100 million higher than the corresponding quarter of 2011, and this is mainly due to higher margins especially in the Olefins & Polyolefins chain. Excluding repositioning costs in a corporate property impairment, corporate and other costs this quarter were $92 million. The cost bearings of $41 million is largely due to interest expense on debt associated with the repositioning that didn’t exist in the same quarter last year. I’ll cover each of these operating segments in more detail later in the presentation. Our fourth quarter cash flow is shown on slide 6. During the quarter, we generated $1.7 billion in cash from operations, excluding working capital. Changes in working capital negatively impacted cash flow by $400 million with a net change primarily due to tax payments. As shown on the chart, we paid down $1 billion of debt. We also funded $900 million of capital expenditures and investments that includes approximately $500 million for our investments in the Sand Hills and Southern Hills pipelines that are being constructed by DCP Midstream. And during the quarter, we’ve returned $400 million to our shareholders in the form of dividends and share repurchases. In summary, during the quarter, we generated sufficient cash to fund our capital program along with our dividend and share repurchase programs. and with the $1 billion debt repayment, we took our cash balance down to $3.5 billion at year-end. As for our capital structure on Slide 11, our equity has increased almost $2 billion since the second quarter and debt is decreased by $1 billion. This has enabled us to reduce our debt to capital ratio to the middle of our targeted range of 20% to 30%, and taking into account our $3.5 billion ending cash balance, our net debt to capital ratio is 14%. Next we will cover each of our operating segments in more details, starting with refining and marketing on Slide 8. In refining and marketing, our refining realized margin was $13.67 per barrel with a global crude utilization rate of 91% and a clean product yield of 83%. Our utilization rate was negatively impacted by turnarounds at the Wood River, Borger, and Los Angeles refineries, as well as Hurricane Sandy related unplanned downtime at our Bayway refinery. During the quarter, we continued our efforts to run more advantaged crudes, the 67% of our U.S. crude slightly in advantage, and this compares to 57% in the fourth quarter of last year. Our return on capital employed for the R&M segment, which includes over $3 billion in goodwill improved to 22% this year and this is up from the 12% return that we had in 2011. Slide 9 provides more detail on Refining and Marketing’s earnings. Adjusted earnings for R&M was $1.1 billion this quarter, and this is up $927 million from a year ago, reflecting improvements in all of our regions, especially in the Gulf Coast and Central Corridor region. Marketing, Specialties and Others were also up driven largely by our international operations. The earnings of all four of our refining regions increased primarily due to improved refining margins. The improvements in refining margins, reflects not only higher market crack spreads, but also an improved feedstock advantage especially in the Gulf Coast, in the Central Corridor regions. The improvements in feedstock advantage increased earnings in the Gulf Coast by over $200 million and by over $100 million in the Central Corridor. Finally, other refining was up this quarter compared to last year, primarily due to movements of Canadian crude supply to several of our refineries. As we move on to marketing specialties and other, the U.S. was down by $2 million, primarily due to higher taxes and costs and this was partially offset by higher U.S. marketing margins. Internationally, MSO was up $40 million, mainly as a result of higher margins. The next few slides highlight our performance in refining and provides more detail on marketing specialties and other. On slide 10, you can see refining’s adjusted earnings increased almost $900 million compared to a year ago. Improved margins were the key driver with higher market cracks and greater feedstock advantages, being partially offset by inventory impacts. The inventory impacts were largely driven by gains recognized in 2011 that were tied to asset sales and shutdowns. Lower volumes negatively impacted earnings by $42 million, mainly in the Atlantic basin and the Central Corridor regions, reflecting unplanned downtime due to Hurricane Sandy and plant turnarounds. Operating costs were up slightly reflecting higher utilities and maintenance cost. The other category includes positive earnings impacts from lower effective tax rates, primarily due to income mix and federal tax adjustments. Now let’s take a look at our market capture shown on slide 11. On this slide, we compare the global market crack with our realized crack spreads. Our realized margin for the fourth quarter of 2012 was $13.67 per barrel, and this resulted in a market capture of 95%. This is quite a bit higher than the 74% that we’ve achieved over the last four years. At a high level, market capture in the fourth quarter was exceptional as feedstock advantages, product differentials, and volume gains largely offset the negative impacts associated with the lower valued secondary products. Let’s walk through the details on the slide. The $0.58 configuration adjustment reflects the fact that our claim product yield of 83% is less than the 100% assumed in the market crack. The negative configuration impact was improved this quarter largely due to our strong distillate production, coupled with healthy distillate prices. The $5.64 per barrel reduction related to the secondary products reflects the fact that these products attracted the sales price that on average were lower than the cost of our benchmark crudes. The positive $3.69 per barrel adjustment per feedstocks stems from running certain crudes and other feedstocks that are priced lower than our benchmark crudes. For example, our feedstock advantage this quarter was primarily related to running for an heavy-sour crudes at our Gulf Coast refineries and Canadian crudes in our refineries in the Central Corridor. In addition, our crude slate is increased to include more shale crudes, primarily Bakken and Eagle. Finally, the other category primarily reflects the impacts of volume gain and product differentials. Slide 12 shows the percentage of advantaged crude runs at our refineries, as well as clean product yields for 2011 and 2012. Many of our refineries have the complexity to run price advantage, Canadian, Bakken and Eagle Ford crudes. Shale crudes are being run in all four of our refinery regions and in addition, we have access to multiple transportation systems to reliably deliver these crudes to our U.S. refineries providing an overall competitive advantage. For the year, our U.S. advantage crude slate increased from 52% in 2011 to 62% this year, and for the month of December, this average was up to 70%. We will discuss Marketing, Specialties and Other or MSO on the next slide. MSO generated adjusted earnings of $180 million, which is $38 million higher than the same quarter last year. As shown on the slide, higher margins were the main driver for the increase, making up almost $90 million in variance. Margins improved primarily due to better market conditions and favorable inventory impacts this quarter. Volumes decreased $26 million quarter-over-quarter primarily due to reduced production at our Immingham power plant in the UK as well as lower U.S. marketing volumes, primarily due to lower demand. Volumes were also lower due to downtime at the border refining. Operating cost increased $20 million in the fourth quarter, primarily due to higher environmental and legal costs. Slide 14 shows our per barrel metrics. Refining and marketing income per barrel increase this quarter to $4.12 per barrel versus $0.59 a barrel a year ago, with cash contributions of $5 per barrel, up $3.57 compared to the fourth quarter of last year. For the year, R&M’s income per barrel was $4.28 and this is up $1.95 compared to 2011. This completes our review of the Refining and Marketing business segment. Next, we’ll move to the Midstream segment. Our Midstream segment had lower equity earnings from DCP Midstream, largely driven by depressed NGL prices. NGL prices were down 36% compared to last year. Although down compared to 2011, return on capital employed for the year was still strong at 22%. We ended the quarter with $1.3 billion in capital employed in our Midstream segment. And as I said earlier, during the fourth quarter we closed our investments in the Sand Hills and the Southern Hills pipelines that are being constructed by DCP Midstream, and these pipes are scheduled for startup this year. Slide 16 shows a Midstream’s adjusted earnings of $62 million, includes $38 million in earnings associated with our interest in DCP Midstream and $24 million for our other Midstream businesses. The next slide provides additional earnings detail for both DCP Midstream and our other Midstream earnings. As shown on the top portion of this slide, earnings associated with our interest in DCP decreased by $21 million this quarter due primarily to lower NGL prices. This was partially offset by a reduction in the depreciation expense that is tied to an overall increase in the remaining useful lives of DCP’s assets that was implemented in the second quarter of this year. Our other Midstream business was down $30 million primarily driven by positive inventory impacts in 2011 along with higher taxes. On the next slide we’ll move on to the discussion of our Chemical segment. Our Chemical segment had another solid quarter providing earnings of $246 million. Overall, CPChem achieved a 90% capacity utilization rate and its O&P segment in the fourth quarter. This was down somewhat from the third quarter due to unplanned downtime at the Saudi Polymers petrochemical facility. If we exclude this downtime in SPCo, CPChem’s utilization rate was near capacity for the quarter. 2012 return on capital employed from our Chemicals segment increased to 31%. This is up form 28% last year and we ended the quarter with $3.6 billion in capital employed. As shown on slide 19, fourth quarter earnings increased by $98 million compared to the same period last year. This increase in earning was primarily in Olefins and Polyolefins due to stronger chain margins. The drivers for this increase was primarily from reduced feedstock cost due to higher industry ethane and propane inventories, as well as continued strong demand for ethylene derivatives. Looking at CPChem’s operating segments on the next slide, Olefins and Polyolefins generated earnings of $216 million in the fourth quarter. This $97 million increase was due primarily from higher olefins, polyolefins chain margins, partially offset by higher operating costs. In addition quarter-over-quarter marketed sales volumes in O&P were up 8%. Specialties, Aromatics & Styrenics earnings increased by 73% compared to the same period last year, primarily due to higher benzene earnings. This concludes our discussion of the financial and operating results for the fourth quarter. Next, I’d like to provide a few outlook items for the first quarter. In Refining and Marketing, for the first quarter we expect our global utilization rate to be in the low 90s, and our pretax turnaround expense to be approximately $100 million. In Midstream, we expect our additional direct investments in the Sand Hills and the Southern Hills pipelines to be approximately $120 million in the first quarter. In Chemicals, although there were some initial unplanned downtime with Saudi Polymers, petrochemical complex, it is now up and running. Under normal operations, we expect SPCo to return roughly a $175 million to $225 million per year to CPChem with our share being 50%. Corporate and other costs are expected to be about $40 billion a month on an aftertax basis or approximately $120 million for the quarter. And this includes aftertax net interest expense of about $40 million. As for the Company’s effective tax rate, we expect the rate to be in the low 30s for the quarter. Regarding share repurchases, we plan to complete the initial $1 billion of repurchases in 2013, and initiate the second billion dollar tranche prior to the end of the year. We’ll continue to keep you advised on the status of our repurchase program on quarterly earnings calls. With regard to our recently announced MLP, we are still on track with our plans to file the S1 with the SEC by early in the second quarter. Finally, starting with the first quarter earnings call, we’ll provide you with updates on our Optimize 66 initiative, recall that this initiative includes capturing $200 million in pretax cost savings compared to what the costs would have been without implementation of this initiative. This concludes our guidance for the first quarter. With that, we’ll now open the line for questions.

Thank you. We will now begin the question-and-answer session. (Operator Instructions) Our first question comes from Ed Westlake from Credit Suisse. Please go ahead. Edward G. Westlake: Hey, good morning and congratulations on a strong quarter. I guess, there is a lot of focus on all the crude that’s coming down into the gulf and obviously you’ve got three refineries down there. Sweeny looks like well positioned, but can you comment on maybe two aspects; one, what is – as you look at the market that sort of incremental costs or any constraints on moving crude from say the bottom of seaway to Lake Charles and then along to Alliance. And then the second question is, as we look at tanker rates that are rising rapidly for Jones Act ships. Can you comment a little bit on how it’s so secure low cost shipping access to from the Gulf to Bayway? Thank you. Greg C. Garland: Well, thanks Ed. Good morning. So let me add a couple of generic comments and I’ll let Tim go in some of the details around that. So we’ve backed out all likes we proved important into the Gulf Coast. One of the reasons we took the Jones Act vessels is we thought that was an opportunity. We want to move quickly, there is very few of those vessels that are available. And with the idea really taking Eagle Ford volumes from corporate around to Haynes and coming in through loop system and then going on around the Bayway. So I mean, that was the basic premises we acquired those vessels for. Right, there is very few of those out there. They are difficult to attain. We think there is probably 32 or so vessels that are in service today, that are available to do this, most of them are taken or chart. So Tim, I know you will fill-in a little more color on that. Timothy G. Taylor: Ed, as far as the crude movements along the Gulf Coast, still primarily for us, it’s marine particularly at this point. The pipeline capacity going east is going to improve [Ho-Ho] and you’ve got the real facilities at St. James, but for us the primary mode that we’ve used to increase the shale runs has been through marine movements, primarily out of South Texas to the three Gulf Coast refineries. Edward G. Westlake: That’s very helpful. And then just my second question on the ethane crackers, you’ve got some negative chat that’s just coming out of the Gulf on execution issues, are there any updates in terms of the cost study that you have done for that cracker and potential timing? Greg C. Garland: I would say that we are on track for the cracker, Ed. We will take FID this year yet on that facility. We are continuing to prosecute the engineering long lead items on that. We are moving the permitting process forward and we will take FID on that. So the cost, we will see as we finish up kind of our pre-engineering if you will on that, where they come in, but we are still thinking it’s around the $5 billion range. We have talked a lot about we think if there is four to five grassroots crackers build, we are concerned about execution capability for the contracting community, are there enough welders, pipe fitters, electrician’s etcetera to execute all of these projects. So one of the reasons we want to be first in the queue is get the jump on that and make sure that we get our pick of the very best people in the industry to execute the project for us. Edward G. Westlake: Thanks very much and well done again. Greg C. Garland: Thank you.

Our next question comes from Kate Minyard from JPMorgan. Please go ahead.

Hi, good morning. Thanks for taking my questions. Just a quick question on the crude slate that you are running, can you talk about whether there were any practical or logistical limitations within the refining system to how much sweet versus how much heavy crude you can run? I mean, what your flexibility parameters are there? Greg C. Garland: Okay. We can certainly do that. Kate, good morning, thanks. So we can run about 350 a day in the Gulf Coast of light sweet crude, and we can push the limits of that, it’s Sweeny primarily a heavier refinery we can run I guess on our 60th day of light sweet there. We’ve looked at running off sweet at that facility, and we would have to derate the facility by about 20% or so. We know what the investment is to correct that is by less than $50 million, it’s Sweeny for us, so we’ll look at that and watch that. But as you think about the opportunities that, you can’t take that as a generic across the entire refining system, because refineries are different, they can figure differently, and so that’s just one specific example for Sweeny. But without question, I think we’re up about a 130 a day of shale pipe crudes that we’ve run, it’s primarily Eagle Ford or with some Bakken coming in. And currently as we start taking delivery the 2000 railcars with the global deal, we’re going to move more Bakken, East and West primarily Bayway and our Ferndale refineries, as we try to accelerate the advantage crude capture. We think we have quite a bit of room left to run in terms of accelerating advantage crude capture around our refineries.

Okay. And then just another question on exports. When you look at the export opportunity and the growth in export, are your exported volumes actually enabling you to capture higher prices than you’d get in the domestic market, or is it simply the fact that you are able to – is it a volume uplift, and that’s where the benefit from export is coming from, or is it a mix of both? Greg C. Garland: Well, it’s both. It’s really the volumes going to or allow us to run higher operating rates, but we’ve made 47% more net income exporting this year than we did last year those prices were better in the international market. So it is a combination of both.

Okay, all right. Thanks very much. Greg C. Garland: You bet.

Our next question comes from Doug Terreson from ISI Group. Please go ahead.

Good morning and congratulations on great executions and spin-off everybody. Greg C. Garland: Thanks, Doug. Greg G. Maxwell: Thanks, Doug.

My first question involved the comments that Greg Maxwell made a few minutes ago about the impairment at Malacca and specifically the report about the higher oil prices being envisioned in the region meaning. Were there some type of crude oil procurement arrangement that lapsed over the – within context of a margin outlook or did I miss here. So could you just elaborate on or clarify about what you talked about there Greg? Timothy G. Taylor: Doug, this is Tim. I may comment on that.

Okay. Timothy G. Taylor: I look at it as really the fact that a) demand in Asia is growing.

Right. Timothy G. Taylor: So you are putting pressure on both the light and medium grades, which fit that refinery in Malacca. And then you’ve had some effects posted only in Japan. So our fundamental view is that the demand picture in Asia has lowered those differentials, narrowed those differentials, and has brought that base crude price up. So it’s primarily a margin issue.

I see. And Tim, I may have – the next question maybe for you too. So product demand in North America and Europe was pretty poor last year. And it looks like there might have been a modest uptick during November and December. So of course, you guys have facilities in both areas, I want to see if you would provide your insight in the current product demand in the U.S. and in Europe, and whether or not you are seeing any improvement? Timothy G. Taylor: Yeah, I would say that basically demand still lackluster, but it’s certainly, not completely gone. Clearly, I think we still see flat to declining demand on gasoline distillate we expect to improve with the economy in North America. Europe, still relatively weak but based on our refining positions and the nature of our retail market in Central Europe and our Humber Refinery with its focus on specialty, we’ve really not seen that to be an issue for us.

Okay. Thanks a lot.

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

Hi, this is actually Mohit Bhardwaj for Faisel Khan. I’ve got a question on the Gulf Coast crude runs, if you guys could just give us a color on as far as the light crudes were concerned, how much are below LLS benchmark those were priced, the crudes that run on the Gulf Coast and same for the heavy versus lighter? Thanks. Timothy G. Taylor: This is Tim, again. So basically on the light crude coming out of South Texas, I think we would plan on say $5 to $8 a barrel advantage. we have seen LLS begin to move a bit as that supplies increased. So we think that that will continue to improve that crudes position or slate as well. And the light heavy differential, that was favorable in this quarter and we still think that that provide substantial uplift versus the light given our refining configuration.

And do you have an estimate on like in some of the other barrels that are just floating around at least in the fourth quarter versus mild, what the differential was on the heavy side? Timothy G. Taylor: Now I really haven’t gotten too specifics of that. We buy a variety of those crudes and so we’re able to capture some of that differential that we’ve seen. Greg C. Garland: There is limitations as to what we can disclose given the confidentiality club…

Sure. Yeah, I understand it. Thank you. Greg C. Garland: Okay.

Our next question comes from Paul Sankey from Deutsche Bank. Please go ahead. Paul B. Sankey: Hi, everyone. I was just wondering further to your split and then the first analyst meeting that you had as a new company. Greg, what do you feel that the market understood well about the company from the analyst meeting or what do you think that was kind of misunderstood from the message you were trying to convey? Thanks. Greg C. Garland: Thanks, Paul. Well, so that we were pleased with the analyst meeting. In general I think we were consistent with what we’ve been communicating to the market in terms of our strategy around improving our returns, growing our higher return in faster growing businesses and mainstream and chemicals and really lying out of plan and strategy improve the base of returns on refining business through advantage crude capture reducing costs, driving yields and ultimately 400 basis point improvement in refining. So I think if there was a disappointment that they may have been around the MLP announcement and the fact that we couldn’t talk about, it is as much as we would have like to or probably as much as you would have like for us to do. But we just reiterate, we think that that’s the value creating proposition for Phillips 66 shareholders and we’ll continue to prosecute that’s a share and we finally get it done this year. Paul B. Sankey: And when I think that the number was kind of $700 million of EBITDA that would be associated with that business whether or not that was at the high-end of the range, low end of the range or a reasonable number. Greg C. Garland: Yeah, I think we’ve said that we really can’t say a whole lot about the EBITDA that we would consider putting in MLP until we get the S-1 filed. So just have to be patient on that one. Paul B. Sankey: Yeah, I certainly understand. You got some stuff on NGLs around NGL pricing being so weak. Can you talk about – I know you have great sensitivities and stuff. But can you just remind us again, firstly, the sensitivities now and how they impact you positively or negatively? And secondly of how you expect that change over time. Greg C. Garland: So first of all, since of the $0.01 a gallon and NGL price is about $4 million of net income back to us. So as you think across the midstream space, the chemical space, we are a net buyer of NGLs, so we are capturing that value in the chemical space. Long-term, we think that fundamentally, the midstream business is a good place to invest. We have got aggressive growth plans in there. I do think that we are going to be in for a period of Baltimore pricing in NGLs for the next four or five years, until the petrochemical facilities come up until the export facilities get build for the propane, butane, and heavier essentially. And so I think you have got this period of time that the demand side needs to kind of catch up, with the supply side in the midstream space, but I think the other thing you got to think about too is, what you are starting to see is because of the investment, because of the need to clear these new basins, a lot of the new investment is really evolving and moving to more fee based type contracts around this infrastructure. So what you are going to see is a reduced sensitivity longer term in the midstream space as there is more fee based assets put in service. Paul B. Sankey: Yeah, that was kind of what I was driving at, so is there anyway you can quantify how that might shift your sensitivity, and in more specific timeframe, because obviously if you are talking about only 45 years of over supply, it’s kind of the worrying outlook. Greg G. Maxwell: Yeah. You would expect the sensitivity to fall overtime in midstream. Paul B. Sankey: Yeah. Greg G. Maxwell: But in the chemical side, it actually goes the other away as we increase the amount of ethane that we run. Paul B. Sankey: I was just trying to be more specific and I was wondering if there was some sort of idea of how much was fee based and everything else and how shift overtime, the time in which we got down? Greg C. Garland: I think we have talked about DCP having 70% of its contracts on a POP basis historically, and we’re shifting that to 40%. Paul B. Sankey: 40%, yeah. Timothy G. Taylor: So if you look at the new pipes we’re building whether it’s Sand Hills or Southern Hills, or some of the other projects we’re considering. As Greg said, those are free bays, so we won’t have the exposure there. And traditionally I guess the gathering and processing business will be a PLP type, but that will be a smaller percentage of the total business. So whether or not that sensitivity is 50% of what it is today, five years from now or…. Greg C. Garland: It’s a good question. But ultimately NGL prices are going to recover is our view and so, I think you’re going to have a still kind of good mix of what I would call risk to commodity exposure in your national gas and your NGL prices and then the fee. Paul B. Sankey: Yeah. Greg C. Garland: But I think where it’s exactly going off. Paul B. Sankey: Good guidance around that.

(Operator Instructions) Our next question comes from Jeff Dietert from Simmons & Cooperative. Please go ahead. Jeff A. Dietert: Good morning. Greg C. Garland: Hi, Jeff. Jeff A. Dietert: You talked about product exports in your press release and having current capacity of 285,000 barrels a day going up to 370,000 by the end of the year. Could you talk about your fourth quarter product exports, what you’re actually exporting in the fourth quarter and maybe how that compares to fourth quarter of the previous year? Greg C. Garland: So in the fourth quarter, we were impacted a little bit with some of the hurricane effects, but overall exports were up to 108,000 in December and on average for the year, we were up slightly. So I see that as probably a growing area for us. I think December reflects what we’ll see as the trend and I think the pricing incentives are there and certainly the run-rate incentive is there. Jeff A. Dietert: You’ve talked about, I guess such a incremental increase in export capacity of about 85,000 barrels a day, and you’ve talked about 20,000 of that being at Ferndale, the other 65,000 barrels a day, where do you see the opportunity for incremental exports. Greg C. Garland: So really we still look at the Gulf Coast as really the region where we would see the logical place for export given proximity to markets, and the access. So the West Coast is going to be more incremental for us, but the primary bulk of that change will come in our three Gulf Coast refineries. Jeff A. Dietert: Switching the topic to Sweeny, I guess your historical relationship with Seaway, I assume there is good access there, should we think about Sweeny feedstock making a step function improvement with this incremental phase, as Seaway come in online in the first quarter of ‘13. Greg C. Garland: Today Sweeny on our light unit, we are running shale crudes today, and this is just about a question of which particular grades make the most sense from refinery. So I actually think Sweeny is in really good shape, and it really depends upon the economic substitution that we have for the heavier piece of the units. So you’re right, Sweeny is in a great location, only from Seaway, but when you think about it very good access to South Texas crudes particularly the Eagle Ford crudes, and that’s where the emphasis has been to this point. Jeff A. Dietert: Thank you. Greg C. Garland: Thank you.

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

Good morning, guys. Greg C. Garland: Good morning, Evan.

You noted that you’re backing out light sweet crude in the fourth quarter in the Gulf Coast and it’s only a matter of time for the Gulf Coast industry in making various midstream investments around that, I mean are you considering any consign splitter or hardware investment versus midstream taking advantage of that growing and impending a lot of light crude, and then somewhat related, I mean do you see your ship assets competing with rail, they are going to providing you just more option out of East Coast or do you see a high utilization or kind of purposeful or kind of both, what I would say, kind of more leased out assets? Greg C. Garland: So, yeah – I’d take in reverse order, we like the flexibility of rail and ship to move clearly, we think there is a cost advantage, and moving marine versus rail, but the opportunity to acquire, to transact vessels is limited, so that’s one of the reasons we move quickly on these two ships that we took, and yes we would consider an investment, I think that we’d want to see, where the spreads really go where LOS really ends up. We’re still kind of quoting $2 to $3 a barrel differential on LOS, it’s not a big investment for us, but frankly we still have higher returning projects. We think we can invest in, but we wouldn’t hesitate to make that investment if the economics wanted it, but we’ve got a lot of – I would say small quick type investments we can do in refining that are 30% and 40% return project, that you’ll see it too, that help push yields, drive cost down, and improve access. So you’ll see us do those things, but we’re not in a bit hurry to make an investment and condensate for them. Greg G. Maxwell: We still have additional capacity to penetrate without that so that’s our first priority and then, as we get beyond that point that’s where I thing you’ll be able to think about it that we need to do something else in the process side. Yeah?

Great, let me shift gears to some of those other projects on the chemical side, a few question, now you could help me with the potential EBITDA uplift based on assumed margin levels from Sweeny fractionation expansion this year? And secondly, help me understand better maybe this normal also Olefins’s expansion project exceed volume kind of value add gentle impact there? Greg C. Garland: Yeah, go ahead. Timothy G. Taylor: This is Tim. It’s couple of comments on the Sweeny fraction, it’s a debottleneck and the real value comes from increased volume throughput at the fractionation that feeds the cracking complex there. But probably more importantly, it allows more ethane into the mix, and she capture value that’s – it’s a relatively modest project in terms of capital of $100 million, and I would expect returns well above 20% on that. So incrementally it’s a very attractive project, it’s just not the same scale as you expect with the cracker.

Sure. Timothy G. Taylor: So makes a lot of sense. On the NAO the project there you think about, we’ve got the (inaudible) announced that separate from an announcement, that’s a 250,000 ton increment. And what they are looking at with NAO is a debottleneck and expansion of the existing NAO unit there at [Shigar Valley] as well. So again not a major new derivatives complex, but really debottlenecking what’s there on the NAO side, so similar, I would expect that to be similar to what we talk about with the frack.

Similar side investment you mean? Timothy G. Taylor: Yeah, and I doubt, that’s all very preliminary. So I think it’s very early in that stage, but again it’s a relatively modest increase versus a major new plan.

Maybe last if I could speak one more on just on rails to kind of get back to the piggyback refining. I mean I know you have 2000 railcars layering in number one, what’s the kind of how we should we think about the delivery of that rail fleet, is it all general purpose on unique oil, and how do you think about in this kind of rail gold rush really, how do you consider translating investments around your systems drive optionality or is this a primarily at this juncture a Bakken, the East Coast to Bakken transit? Greg C. Garland: It’s a great question. So these are general purpose cars, although we will say that we are looking at coil steel cars to move Canadian heavy down to the West Coast in addition to this. So as you think about this, it was originally envisioned as a Bakken play to go east and west without question, where we are investing in the infrastructure is our refineries for unloading if you will and we are using third party access in the Bakken itself. I don’t think we see the need to invest in terms of loading facilities in the Bakken at this point in time. And frankly, when I think about the railcars is, they can move over time as the opportunity moves, but our view is that the next five year window Bakken crudes will probably move a lot of it by rail on east and west.

I agree. What do you think that permitting track is for California rail, that’s going to take a long time, do you have any…? Greg C. Garland: Yeah, which, I knew the answer to that one. I think we are pushing in. I think there is some resistance giving the heavy nature of the crudes in the carbon footprint of crudes and AB32, a carbon cap-and-trade etcetera in California, but I think it’s an opportunity to certainly its worth of exploring.

Appreciate it. Thanks.

Our next question comes from Doug Leggate from Bank of America. Please go ahead.

Thanks fellows. Good morning. Follow-up I guess on a couple of questions been asked, particularly on the West Coast of the Western Pacific to be more exact. If you look at your earnings now the full year is in, late last year you’ve had $84 million adjusted versus $3.5 billion for the whole system, this year it looks about $300 million on $5.2 billion for the whole system. I’m just kind of curious as to strategically how you’re thinking about that part of your business on a go-forward basis, given that it seems to be somewhat challenge if everything else is going on the portfolio, that’s my first question and I have a follow-up please. Greg C. Garland: Okay. Hi, Doug. So the West Coast well, we talked about Melaka, so I think we kind of answer the Melaka piece of it from a specific standpoint. It’s not strategic for us non-core asset. California is a challenge place to operate, its high-cost environment, there is a lot of things coming at us in California. It’s net income positive, its cash positive, and its single-digit returns. And so it doesn’t fit the return profile that we see long-term in the business. So what are we doing? We’re doing everything we can to improve it. So it’s looking at our costs, it’s looking at our configuration, it’s looking how do we get advantage crudes into these refineries to improve and at same time, I would say we’re studying all options for California in terms of where do we go long-term with the California asset. I don’t feel it’s a distress that, I don’t think we have to move tomorrow on it, but also think that we want to take our time and be thoughtful and make sure that whatever we do in California creates value to our Phillips 66 shareholders.

Thanks for that. My follow-up is actually a related question, not to try and predict what happens next, but could you help us understand what kind of inventory you have tied up across the first two parts of the portfolio I guess Melaka and the West Coast? And maybe there has been a little bit of talk there about at some point in next few years, we might see some accounting changes as it relates to the accounting for – LIFO accounting for inventory. What kind of cash tax liability might you have, or what kind of cash could be released from inventory if you decided to put them on the monetization, I will leave it there? Thanks. Greg C. Garland: Okay, Greg? Greg G. Maxwell: Yeah, Doug, this is Greg Maxwell. We watch this from an inventory perspective and look at the different pieces of legislation that are coming out. From a replacement cost perspective over and above what we have recorded on our books on the inventory level basis, it’s about – runs about $7.5 billion to $8 billion. And so one other things that we saw in the legislation that would be paid over a 10-year period is the latest we have seen on it. So basically you could look at the gain on that divided by 10 times, 35% sort of give you a rough estimate of what the cash taxes would be on an annual basis.

And if you choose to monetize your inventory not just on, can you quantify what that would be? Greg C. Garland: Are you talking about just California?

Yeah… Greg C. Garland: I’m sorry Doug. I’m talking about the entire system. I don’t think…

Sure, sure. I’m trying to think more like, what kind of value would be released, for example, you decided to go down to monetization on those assets? Greg C. Garland: I guess if you’re looking for kind of a broad number, we say 20% of it. Greg G. Maxwell: Yeah.

Terrific. That sounds great, guys. Thank you.

(Operator Instructions) Our next question comes from Blake Fernandez from Howard Weil. Please go ahead.

Yes, good morning. Congratulations on the results. I had a question for you on debt. Obviously, it was reduced by about $1 billion this quarter. As I understood the large portion of the debt balance actually contained a fairly low interest rate and that was one of the things I think at the initial analyst we had up in New York, you were grappling with Greg as far as, do you pay that down, or how did you manage the balance sheet going forward? I’m just curious from here. Is your buyers do kind of leave the dead levels where they are, and just distribute the remaining amount to shareholders, or may be just build additional cash or any thoughts there appreciated. Greg G. Maxwell: Right, thanks for the question. So we said at the Analyst Day that we’re going to pay down $2 billion of the debt, so we’re going to go from a $8 billion to $6 billion that takes us to about a 20%, which is a lower end of the range. That’s still, the plan is to pay down another $1 billion of the debt, there’s no question its very attractive financing. But as we work, we always like to remind people what it is, always will be a volatile business. And that’s life in the commodity business and we accept that, we think that we are comfortable operating that space. But I think you want to have a balance sheet that supports that. So it reduces risk for the company, in our view it creates capacity. We’re not going to hesitate to lever back, that if we have to, to continue our plans, or pay dividends, or do the things that we need to do. And, but no question our view is that, the next couple of years midcycle margins are going to be evolved, historical midcycle margins I think, we’re going to have cash optionality. So I think, you’ll see us one pay a dividend, continue to increase that dividend, you’ll see us then use excess cash to take in shares and we aren’t going to take specials off the table.

Great, thanks. And then second one was really more I guess big picture capital allocation oriented, but as I look at the return on the capital employed in your slides, it looks like the R&M numbers moved up to 22%, which is equivalent to what you are getting in the midstream. I guess as you make decisions on allocating capital going forward, as I understood R&M was really going to be one of the smaller pieces of the portfolio going forward. I’m just curious this is blowout and returns in the downstream kind of change that theory going forward? Greg C. Garland: So my view is that, refining historically has been kind of a 10% to 12% business let’s say. We think we have plans in place to advantage crude capture, yields, cost reduction, that we can move it 400 basis points. So it’s a 15% business going forward for us versus a 30% return business in Chemicals. And probably Midstream business 15% to 17% returns is kind of what we’re looking in fact. So, to the extent that we have 30% and 40% return projects in refining, we’re going to do those. I think, I mean we do get challenged by people all the time or we under investing in refining. At this point, we don’t think so. I don’t think there’s any opportunities out there, we feel that we’ve missed in terms of an investment opportunity in the refining space. Our focus is going to be very disciplined. We’re going to restrict capital in this space. We’re going to improve returns in this space. And so we don’t see a change required in our strategy at this point in time.

Okay, fair enough. Thank you.

We have no further questions at this time. Do you have any closing remarks? Greg C. Garland: Great, thanks. Well, we appreciate the interest in the company and the questions. And if there are follow-up questions, obviously Rosy and I are available to handle those. And you can find this information and a transcript of the call on our website in the near future. Thank you very much.

Thank you ladies and gentlemen. This concludes today’s conference. Thank you for participating. You may now disconnect.