菲利普斯66 (PSX) 2015 Q4 法說會逐字稿

Welcome to the fourth-quarter 2015 Phillips 66 earnings conference call. My name is Sally and I will be your operator for today's call.

(Operator Instructions)

Please note that this conference is being recorded. I will now turn the call over to Clayton Reasor, Executive Vice President Investor Relations, Strategy, Corporate and Government Affairs. Please go ahead, Mr. Reasor.

Thank you, Sally. Welcome to Phillips 66 fourth-quarter earnings conference call. With me today are Chairman and CEO, Greg Garland; President, Tim Taylor; and Chief Financial Officer, Kevin Mitchell.

The presentation material we'll be using during the call 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 Operating statement. It's a reminder we'll 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 these changes or these actual results to differ are included on the second page as well as in our filings with the SEC. So with that said, I'll turn the call over to Greg for some opening remarks.

Thanks, Clayton. Good morning, everyone. Thanks for joining us today.

We had a good year in 2015, adjusted earnings were $4.2 billion, which was our highest since 2012. We generated $5.7 billion in cash from operations. This allowed us to maintain a strong balance sheet and exponential flexibility, while funding our capital program and returning $2.7 billion to shareholders through dividends and share repurchases.

We made significant progress on our growth projects in midstream and chemicals and we continued to improve returns in our refining and marketing businesses. Despite the difficult environment experienced throughout the energy industry, our diversified asset portfolio has performed well. We continue to execute our plan. For us, it all starts with operating excellence.

We spent $1.2 billion in sustaining capital in 2015 and from an operating reliability perspective, our businesses ran well. 2015 was a very safe year for us. We tied our best year ever for recordable injuries. And refining, chemicals and midstream were top performers in injury rates. We also maintained the improvement in our environmental performance demonstrated in previous years.

We ended 2015 with a solid quarter, especially when considering the current commodity price environment. Adjusted earnings were $710 million or $1.31 per share. Market cracks were down significantly in the fourth quarter from the highs that we saw last summer but our global refining business continued to run well with 94% utilization.

Marketing earnings were healthy and this continues to be a high return business for us. 2015 adjusted return on capital employed was 35% for this segment.

In midstream, we commenced operations of the Sweeny Fractionator One and supporting Clemens Storage Caverns. 2016 will be another busy year for us with several other midstream projects scheduled for completion. Our Freeport LPG Export Terminal is now 80% complete. It's on track, on budget, with an expected start up in the fourth quarter of 2016.

The Dakota Access, and ETCOP pipeline projects, also continue to make good progress and remain on schedule for completion by the end of this year. Our master limited partnership, Phillips 66 Partners, remains an important part of our midstream growth strategy. The fee based assets within PSXP's portfolio continue to perform well and are not impacted by the current market conditions.

PSXP continues on track to achieve its stated growth objective of a five-year, 30% distribution compound annual growth rate through 2018. Adjusted EBITDA was up nearly 90% for the year at PSXP while distribution growth and coverage were also strong. In addition, PSXP was able to raise $1.5 billion of low cost capital through the debt and equity capital markets in 2015.

DCP continues to work on reducing cost and converting contracts to fee-based structures to improve its financial strength and flexibility. Equity contributions from the owners in the fourth quarter helped in that regard. We expect that DCP will be self-funded going forward.

In chemicals, cash margins fell during the fourth quarter; however they remain strong by historical standards. CPChem's geographically advantaged footprint allows it to remain profitable and able to self-fund its growth projects. Development continues on CPChem's US Gulf Coast petrochemicals project which will increase CPChem's US ethylene and polyethylene capacity by over 40%.

Overall progress on the project is approaching 70% complete with start up planned in mid-2017. This project remains on time and on budget. We had another strong cash-flow quarter, we generated $1.5 billion in cash from operations.

We used $1 billion of that cash flow on capital spending to support midstream growth and maintaining operating integrity in our refining system. We'll also continue to return capital to our shareholders. During the fourth quarter we returned over $700 million through dividends and share repurchases.

Over the last three years, shareholder distributions have totaled more than $9 billion. Looking forward to 2016, our focus remains on operating well and executing our $3.9 billion capital budget.

We continue to target a 60/40 split between reinvestment and distributions and we have targeted a dividend increase in 2016 of at least 10%. So now I'd like to turn the call over to Kevin Mitchell to take us through the quarter's results.

Thanks, Greg. Good morning. Starting on slide 4, fourth quarter adjusted earnings were $710 million or $1.31 per share. Reported net income was $650 million including several special items excluded from adjusted earnings.

These special items decreased earnings by $60 million and included $104 million in impairments at DCP and a $33 million lower of cost or market write-down of inventory at our Wood River-Borger joint venture offset by an $88 million gain tied to favorable changes in German tax law.

Excluding negative working capital changes of $300 million, cash from operations was $1.8 billion. Capital spending for the quarter was $1 billion, excluding the $1.5 billion contribution to DCP Midstream.

Dividends and share repurchases in the fourth quarter totaled $704 million, and excluding special items, our adjusted effective income tax rate was 31%. Slide 5 compares fourth quarter and third quarter adjusted earnings by segment. Quarter-over-quarter, adjusted earnings were down $937 million. All segments had lower earnings but refining accounted for most of the reduction.

Next we'll cover each of the segments. I'll start with midstream on slide 6. Transportation benefited from higher equity earnings and volumes.

In NGLs, Sweeny Fractionator One came online during December. Included in the transportation and NGL results is the contribution from Phillips 66 Partners. During the quarter, PSXP contributed earnings of $37 million to the Midstream segment and increased its quarterly LP distribution by 7% over the third quarter.

DCP Midstream continues to work on its self-help initiatives to reduce costs, manage its portfolio and restructure contracts. 2015 adjusted return on capital employed to the midstream segment was 5% based on an average capital employed of $6.8 billion. The return for this segment continues to reflect the impact of increased capital employed driven by our significant growth investments as well as the impact of low commodity prices on DCP earnings.

Moving to Slide 7. Midstream's fourth quarter adjusted earnings were $42 million, down $49 million from the third quarter. Transportation adjusted earnings for the quarter were $78 million, up $1 million from the prior quarter. NGL adjusted losses were $2 million for the quarter.

The $34 million decrease from the prior quarter was largely driven by the timing of adjustments related to the tax extenders bill signed in December as well as additional costs associated with the Sweeny hub. Adjusted losses for DCP Midstream were higher in the fourth quarter mainly due to lower natural gas and natural gas liquids marketing margins as well as the impact of lower commodity prices.

In chemicals, the global olefins and polyolefins capacity utilization rate for the quarter was 92% and margins trended lower. SA&S was negatively impacted by plant turnaround activity. The 2015 adjusted return on capital employed for our chemicals segment was 19%, based on an average capital employed of $4.9 billion.

As shown on Slide 9, fourth quarter adjusted earnings for chemicals were $182 million, down from $272 million in the third quarter. In olefins and polyolefins, the decrease of $80 million was largely due to lower cash margins; however demand for polyethylene and normal alpha olefin products remained healthy during the quarter.

Adjusted earnings for SA&S declined to $9 million on lower equity earnings driven by lower volumes due to turnaround activities at CPChem's equity affiliates and lower margins. This was partially offset by higher volumes in specialty chemicals. In refining, realized margins were $9.41 per barrel for the quarter as market crack spreads decreased significantly.

Market capture increased from 72% to 74% in the fourth quarter as we saw improvements in clean product differentials and lower losses on secondary products. Refining crude utilization was 94%. Clean product yield was 85% representing a record quarter.

Pre-tax turnaround costs were $130 million compared to guidance of approximately $150 million, due primarily to the deferral of some planned maintenance. 2015 adjusted return on capital employed for refining was 19%. This is based on average capital employed of $13.6 billion.

Slide 11 shows a regional view of the change in adjusted earnings compared to the previous quarter. The refining segment of adjusted earnings of $376 million, down $676 million from last quarter. The reduction was primarily due to lower market cracks in all regions.

Atlantic Basin adjusted earnings were lower this quarter due to lower gasoline and distillate margins, partially offset by higher volumes as capacity utilization exceeded 100%. The Gulf Coast region saw lower margins and had lower volumes due to down time at Lake Charles and Sweeny. In the central corridor, market cracks dropped by more than $8 per barrel which accounted for approximately 90% of the $251 million reduction in adjusted earnings from the third quarter.

In addition, Wood River and Ponca City also had down time due to turnaround activity. In the western region, gas cracks fell nearly $15 per barrel. Volumes and controllable costs were also impacted by a major turnaround at our LA refinery that we completed in the Fourth Quarter. Santa Maria continued to be impacted by the plains pipeline outage.

Next we will cover market capture on slide 12. Our worldwide realized margin was $9.41 per barrel versus the 3:2:1 market crack of $12.77 per barrel, resulting in an overall market capture of 74%. Market capture is impacted in part by the configuration of our refineries as it relates to our production relative to the market crack calculation, with 85% clean product yield for the quarter, we made less gasoline and slightly more distillate than premised in the 3:2:1 market crack.

Losses due to secondary products were lower this quarter as the price differential between crude oil and lower valued products such as coke and NGLs narrowed. Feedstock advantage was somewhat higher than the third quarter but still below average as crude differentials generally remain tight. The other category mainly includes costs associated with RINs, outgoing freight, product differentials and inventory impacts.

Let's move to marketing and specialties, where we posted a solid quarter thanks to favor global marketing margins, however specialties saw reduced earnings on lower lubricants margins. The 2015 adjusted return on capital employed for M&S was 35% on average capital employed of $2.7 billion.

Slide 14 shows adjusted earnings for M&S in the fourth quarter of $227 million, down $117 million from the third quarter. In marketing and other the $93 million decrease was largely due to lower margins in both domestic and international marketing which decreased from the notably high margins in the third quarter. This was partially offset by the renewal of biodiesel tax credits. Specialties adjusted earnings decreased to $29 million due to narrowing base oil and finished lubricants margins and lower finished lubricants volumes.

On slide 15, the corporate and other segment had an after-tax net cost of $117 million this quarter, an increase of $5 million from the third quarter. Net interest expense increased by $4 million primarily due to lower capitalized interest while corporate overhead and other expenses were in line with the prior quarter.

On Slide 16 we summarize our financial results for the year. 2015 adjusted earnings were $4.2 billion or $7.67 per share. Excluding negative working capital changes of $200 million, cash from operations was $5.9 billion.

Capital spending for the year was $4.3 billion excluding the $1.5 billion contribution to DCP Midstream. Total shareholder distributions were $2.7 billion. At the end of the fourth quarter, our adjusted debt-to-capital ratio, excluding Phillips 66 Partners, was 25% and after taking into account our ending cash balance, our adjusted net debt-to-capital ratio was 17%. The adjusted return on capital employed for 2015 was 14%.

Moving to slide 17, 2015 adjusted earnings were higher than 2014 as lower earnings from midstream and chemicals were more than offset by improvements from our refining and marketing and specialties businesses. We had an 11% increase in adjusted earnings and adjusted earnings per share increased by $1.05 or 16%.

Slide 18 shows cash flow for 2015. We began the year with a cash balance of $5.2 billion. Excluding working capital impacts, cash from operations was $5.9 billion, working capital changes reduced cash flow by $200 million.

In the first quarter, $1.1 billion in debt and approximately $400 million in equity was issued by PSXP. We also retired 800 million in Phillips 66 senior notes. During 2015, we funded $5.8 billion of capital expenditures and investments.

This included $4.3 billion of capital spend including $3 billion in midstream and $1.1 billion in refining. We also distributed $2.7 billion to shareholders in the form of dividends and share repurchases. We ended the year with 529 million shares outstanding.

Excluding the DCP contribution, 61% of our available cash went to reinvestment and 39% to distributions. At the end of 2015, our cash balance was $3.1 billion. This concludes my review of the financial and operating results.

Next I'll cover a few outlook items. For 2016 we expect full year turnaround expenses to be between $525 million and $575 million pre-tax. We expect corporate and other costs to come in between $480 million and $500 million and we expect full year D&A of about $1.2 billion.

In the first quarter, chemicals, we expect the global O&P utilization rate to be in the mid-90s. In refining, we expect the worldwide crude utilization rate to also be in the mid-90s and pre-tax turnaround expense to be approximately $150 million. In corporate and other we expect after-tax costs to be between $120 million and $125 million and Company-wide we expect the effective income tax rate to be in the mid-30s.

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

Thank you.

(Operator Instructions)

Faisel Khan from Citigroup.

Thanks, guys, good afternoon.

Good afternoon, Faisel.

Just a couple questions. On the midstream projects, DAPL and ETCOP, given that some of the partners look like they may need capital over the next couple of years as their cost of capital gets higher, I just want to understand would you be willing to take sort of a bigger interest in those assets if the opportunity presented itself?

Yes, this is Tim. You know I think that with our partners on DAPL, ETCOP, have been exploring various options on that. I think our commitment is where we would like it to be at this point but certainly will consider that it's all about what delivers the best value for us.

Okay, got you, and then you talked in your prepared remarks you're targeting a dividend growth rate for 10% for this year. Is that locked in or is there sort of a wiggle room if markets change or if things become a little bit more dynamic?

Yes, we said at least 10%. We had a 12% last year but we'll take a look at that. Obviously, need the Board to approve this too, but we had given guidance three years ago that we would do double digit increases in 2014, 2015 and 2016 and we stand by that guidance.

Last question for me. In the Atlantic Basin, you guys ran over 100%, throughput was strong and so was up time. Is this sort of a new set of reliability in the Atlantic Basin or is this an unusual circumstance where things just ran at a higher level for the quarter?

You know, when you look at that, you'll remember we just came out of the Humber turnaround, really came out of that in good shape, good clean refinery, so I think that it reflects that and then at Bayway we continued to run a lot of processed inputs to fill out our downstream units in that facility. So it was really good quarter and I would anticipate (technical difficulty) obviously the market conditions that we continue to try to run as full as we can.

Got it. Thanks, guys.

Thank you.

Paul Cheng from Barclays.

Hi, guys, good morning.

Hi, Paul.

Just, maybe this is for Greg. With the changing market conditions related to the market acceptance for the funding model in the MLP sector, how that is going to impact your [way] of the drop down that I think previously that you've been looking for up to $2 billion a year, I don't know that whether you have changed.

And also that from the CapEx that you spend $3.9 billion in dividends about $1.3 billion, with your cash flow from operations you don't have much for the buyback, so should we assume that you can't do much of the drop down, you will correspondingly the scale down your buyback or are you going to increase your balance sheet to maintain the buyback at a certain rate?

Well okay, so let me kind of start with the question around it and certainly, we understand the question, Paul. As we look out there, there's a lot of stress in the space with people that are over-levered and will have difficulty accessing the capital equity markets given their prohibitively high cost of capital.

When we look at PSXP, strong sponsorship, strong investment grade rating, you might even call us the drop down Titan maybe, but a great portfolio of existing EBITDA that can be dropped and we've got these projects lined up in the queue that are in flight, that really add to that. And then you look at where PSXP is trading, kind of around 3%, so I think the investors look at [PSP], they get the growth story, they understand the growth story and I think it's a confidence in our ability to execute that and so we would say that we think the Capital Markets are going to be open to us in 2016. Our plan is to be out there, in there.

And you've got the number about right. We've said kind of $2 billion a year that we need to be through the capital markets and the debt markets to hit this $1.1 billion of EBITDA in 2018 at the MLP, so we stand by that guidance and we stay there. We should generate $4 billion to $5 billion mid-cycle of cash and you add another $1.5 billion to $2 billion coming out of the MLP, so I think we're fine in terms of funding our capital program and in terms of funding -- growing distributions through increasing our dividends and we'll have -- as long as our shares are trading below intrinsic value we're going to take shares in.

The second question, Greg, on did DCP, you guys have that capital restructuring in with your partner in the fourth quarter but the market conditions continue to deteriorate in that business. So is there a possibility that later this year, whether it's due to if there's anymore debt that's being mature, do we need to do additional capital infusion into that or that you're really as confident that you already fixed the problem at this point?

Well, I think that the contributions by both SE and ourselves have gone a long way towards fixing the balance sheet issues at DCP. The other thing you've got to give the folks at DCP a lot of credit.

They've done a great job of pulling cost out, restructuring contracts where they can in the portfolio and so if you look pre-2015 cash break-even, we needed about $0.60 to breakeven on cash on NGLs. And it's kind of -- we exited 2015, we had moved that down to about $0.40 a gallon breakeven and then the actions that are being further taken in 2016, we expect that the cash breakeven will be somewhere mid-$0.30s. So I think DCP will be fine in this environment we're in for 2016.

The other thing I'd say is DCP doesn't have a debt due until 2019. DPM actually has one due in 2017, but DPM is in pretty good shape. So I think our view is that DCP is on pretty strong footing. We've purposely set them up for success in this low commodity price environment.

You might want to say something about capital.

The other thing is, we haven't really announced the capital, but DCP Capital this year is going to be down about 50% from what it was last year. I think our share of DCP capital is about $233 million this year, thereabouts, give or take. So we're continuing to manage capital at DCP. We'll be more costs taken out of DCP this year, more work around the restructuring of the contracts this year, so I think they are in pretty good shape.

Can I have a final question? One last one?

Sure.

If I look at why now you're investing a number of projects that you commit on the midstream, so that's why your CapEx last year and this year for total Corporation is not very high. $4.3 billion and $3.9 billion, and yet we base on -- you suggest that you're still targeting on the long haul 60/40 between reinvestment and the pay out to the shareholder.

At 60%, if we say $3 billion that would translate into a $5 billion cash flow, so from that standpoint should we assume after the next one or two years we should see your CapEx drop back down to within to the $2.5 billion to $3 billion range or when you say 60/40 you're also including the drop-down proceed in that calculation?

Yes. Well, yes to both. I think capital probably does come down in the years. We've always said 2015 would be a peak year for us, and so you see that coming down at PSX, you see it coming down at DCP and also at CPChem, their capital budget for this year is going to be down about 20%, so they'll be $1.45 billion will be our share of the CPChem capital for 2016. So truly I think 2015 is a peak year for us. But you need to add in the proceeds from the drops in the MLP to the cash and think about that in terms of total amount for distributions.

All right. Thank you.

Doug Leggate with Bank of America Merrill Lynch.

Thanks, good morning, everybody

Hi, Doug.

I guess I'll start with -- Can you hear me?

Yes.

Yes, sorry I thought you couldn't hear me there. I'll start with chemicals if I may. I think Kevin mentioned that there had been some down-time. It looked to us that, given you're vertically integrated chemicals business has normally been somewhat resilient compared to some others, it looked a bit weaker this quarter to us. Was it just the down time? In which case can you quantify the opportunity cost or is there something structural there you see is changing in this lower commodity environment?

Doug, this is Tim. You know, I looked at delta between Q3-Q4, it's about $90 million. I would say that about $50 million of that or so was compression in the margin in the olefins/polyolefins chain margin and the other remaining amount was largely the impact of turnaround costs and some impact from the volumes as a result of that.

Okay, so are we done now or did we bounce back in terms of operating activity in Q1?

Yes, so I think we've got it to higher operating rate in Q1 with that. These were actually turnarounds in polymer units so there's always some of that but generally volumes come back. The real question about the margins, I think, largely depend on where you think crude prices end up but as prices fall, and gas price doesn't fall as much and the ethane price then you get some compression there but I will that say we continue to see good demand. We don't see inventories building in that and that demand really is around the globe. So for us, we've been looking at the underlying fundamentals and still see the demand piece there. The moving piece really is going to be around the energy price and what happens. But barring a significant change, we would expect similar industry margins that we saw in the fourth quarter.

So, Tim, I don't want to belabor the point but you said the down time of the turnarounds were in your polymer units so would that mean that you didn't have the vertical integration benefit in Q4 that would normally have cushioned you a little bit?

Yes, if you're thinking about when you don't have the pull on the derivative units you can't impact the total output on the total integrated between ethylene and polyethylene specifically.

That's what I was getting at. That was helpful thank you. This thing with chemicals, for a second. So, Sweeny is up and running now. I think you're previous guidance was $400 million to $500 million of EBITDA. What does that look like in today's environment in terms of the contribution.

In the export facility.

Oh, export LPG terminal?

Right.

Yes, I think that we're at the lower end of that because there was some commercial opportunity, we've said about 80% fee-based in that number, and so we're still in that range when you look at both the frac and the dock and the caverns and the services that, that provides. And then what's happened today, the [arbs] between the US and other markets in the world are narrower but I would also say that we see shipping constraints being alleviated, so I think we're kind of in flux about what the arb ultimately will be.

But we still look at the market here and know that the NGLs need to find another home outside the US. So I think are still fundamental drivers that will push that and the real question is, how much of the arb? Do we have $100 million of EBITDA from the arb or something different? But on the long term, I think we feel there's going to be a significant commercial opportunity as well as the fee-based but the primary driver on those projects are the fees.

Last one for me if I could follow Mr. Cheng's lead and squeeze another one in. (Laughter) The heavy/light differentials, obviously spreads have come in for light crude. You guys are heavy relatively resilient. You made you spent a lot of time telling us how much effort you were moving to maximize your light sweet crude throughput. What are you doing today and how much flexibility do you have to swing back if you chose to? And I'll leave it there, thank you.

Yes, we talked a lot in fact all last year about how much more lights could we run. I think the amazing thing about our system is we have the ability to flex. Even in the fourth quarter we probably ran 3% more medium sours. We didn't run quite as much heavy sours because of turnarounds at Los Angeles and Lake Charles during the quarter as we probably would have liked to. We ran a little bit more Canadian heavy during the quarter. But yes, I think we have the ability to flex that. I think we're still in max-gasoline mode as you want to think about it that way.

But yes, I think the important spreads for us this year are going to be the light/heavy, the sweet/sour and the TI/WCS spreads. I think Brent and LS can trade near parity and it's going to be a very volatile market and things are going to move around in terms of the TI/Brent differential so we'll just have to watch that.

Doug, actually we have a project at Billings to continue to go to even heavier sour grades there that would improve and kind of capitalize on that light/heavy and then at Wood River we're doing some work around lights debottlenecking that will allow us to push more heavies into that facility, so we're taking some incremental steps to increase our ability to handle heavy and medium sour crudes.

Thanks guys, I look forward to seeing you in a couple weeks.

Okay take care.

Roger Read from Wells Fargo Securities.

Yes, good morning.

Hi, Roger.

I guess a couple of the things we always like to talk about, product exports, what are you seeing in that market here Q1 and thoughts on what a lot of people are focusing on in terms of some softness in the diesel side?

Well, I think globally, just to comment on distillate inventories, that's always something that we're watching and clearly with the warm winter, you know, and less industrial activity seeing softness in that demand we still expect growth on the distillate. On the export side out of the US, we have the options to either place product in the US or export and we just simply picked the best value at the time, when we make that decision. But we still feel there's still good demand that when we look across the globe for both gasoline and distillates out of the US.

Okay, great and then shifting gears to the midstream segment. The new fractionator online, the export facility later this year. Can you give us an idea of how we should think about the impacts of those two events as we look at the EBITDA guidance originally for those projects, kind of thinking Q1 this year probably to Q1 of next, and what's the reasonable progress of how that works its way in?

So the first step on those is the fractionator, a relatively minor piece of that total $400 million to $500 million of EBITDA guidance that we gave. The next big step is later in the year when you really reach what the LPG export terminal, a larger fee-based component as well as some commercial opportunities. So smaller impact in the beginning and then toward, you know, assuming that we start up on time in the third quarter, in the fourth quarter you'll begin to see then that full impact of that $400 million to $500 million.

And just a quick follow-up on that. Once the export facility is available, is that something where you ramp to full utilization fairly quickly or should we think of that as a step process? I'm not familiar with those type of units so I'm just wondering what the expectation should be.

Yes, well we're connected both to our fractionator and it's say it's 150,000 barrel-a-day equivalent initially, roughly 40,000 barrels or so of propane comes off of our new frac and then we're connected to Mont Belvieu and other facilities to supplement that. So it really is about getting the capacity in place, the commercial agreements and then you've got the capacity to not only take the output from our frac but also supplement that with feeds out of the NGL system on the Gulf Coast.

I think we said, though, we expect about eight cargoes a month coming through the terminal and I would say we've made great progress on contracting those eight cargoes.

And has margin on that been affected at all by the change in pricing or is that, since it's more tariff-related we don't have to worry as much about the lower prices today?

Tariff, the tariff impact has been where we thought in terms of the fee. That's about 80% of that. What is narrower today is the commercial opportunity, although we expect that to widen again with shipping constraints removed and as markets begin to equilibrate when you establish that.

Okay, great thank you.

Blake Fernandez with Howard Weil

Hi, guys, good morning. Greg, you mentioned max gasoline mode and I guess historically we've always viewed PSX as having kind of one of the highest distillate yields and that's been an advantage until just recently where the market's obviously shifted in favor of gasoline. Are there any opportunities that you're looking at to maybe reconfigure or change your opportunities to capture some of the gasoline strength that we've been seeing?

Yes, at the margin, but I think we ran 44% gasoline in the fourth quarter and I think that's pushing the max of what we can do.

Okay, so there's no capital investment projects or anything that you're evaluating?

We do have a project that we've authorized at Bayway to improve the yield on the FCC there that would incrementally add some volume to that. And as we go around our system we're looking at that but those take a bit longer because they are capital. But I think, as Greg said, in terms of optimization a day, we're doing all we can to push that given where the market is today.

I think the FCC upgrade at Bayway is 2018, so we're a couple years out on that project but we're executing it right now.

Got it, okay. The second one, this may go nowhere quickly but I'll ask it anyhow. So Buffet continues to increase his stake holding and I'm just curious what, if any, dialogue you're having in any sense of what the longer term intentions are?

You're right. It's going nowhere. (Laughter) You know what, Blake? We don't comment on conversations with shareholders.

It's a good question though. (Laughter)

Fair enough, thanks.

Take care.

Ed Westlake with Credit Suisse.

Hi there, good afternoon. Congrats on everything you've achieved last year and looking forward. Quick question on risk. Really, in the midstream area, obviously oil prices, gas prices are low. Volumes are going to be coming down across the piste, so maybe just give us, I don't know if you've done an assessment of volume and counter-party risk. And I'm thinking less about your new projects which obviously you spent a lot of time working on but more maybe in some of the legacy and DCP area.

Well, I think that we look across the DCP portfolio and 90% of it is kind of investment grade so I think they have good counter-parties on the other side of that. As we think through the volume-risk side of it and the portfolio, we think Permian is probably going to do a little better, we think D-J will do good, SCOOP is going to do good, Eagle Ford will decline as we think across that. And so I would say just from a pure volumetric perspective, we're probably going to be flat to maybe slightly lower in 2016 at DCP.

We think that gasoline demand is going to be good. We think distillate demand is going to grow although we have challenged inventories there. We think petrochemical demand is going to grow. So on balance as we think across the portfolio, midstream kind of flat to down at DCP, of course we're growing our midstream is what we're doing, with the frac coming up, export facility, Bayou Bridge, DAPL coming on late 2016, so we'll see increased volumes in the transportation segment there that flow through. And then we think petrochemicals will be okay. Tim if you want to add-on that?

I think that really is and I just think we're looking at the macro-environment, with the production breaking over in the US there's not a lot of extra volume drive through that and so I think it's just a question of how much decline occurs around that.

We do think the gas markets will continue to have a pretty good pull and that's a piece of what underlies DCP as well and so to this point we've not been concerned and I think, to reiterate, the counter parties on our midstream business look very solid.

You might just talk a little bit about our view and what that does to PSXP and the investment portfolio that we're thinking out 2018 and beyond?

To date we've done -- we've expanded on the NGL chain, major crude [line] with DAPL, ETCOP, related to kind of new production, good counter party, solid volumes on that on the T&D side. But as we go forward, as we look at our portfolio I think that we're shifting our attention to things that support our refining business logistically, that touch existing midstream assets or add value, perhaps as the chemicals value chain. So we're shifting more to the downstream, the demand-side as we think about the midstream options versus a heavy focus initially on that upstream part of that.

So less on production growth and more around liberating higher returns in our existing assets.

Okay, clear. And then just a smaller point. Your refining turnaround expense, I mean I thought it would maybe come down a bit this year. It's still a healthy chunk maybe just talk through what the key plans are on the refinery and turnaround side for this year.

From an expense side, Ed, we actually spent quite a bit less in 2015 than we originally planned and so the outlook for 2016 is somewhat higher than we previously talked about so that reflects the timing of the activity that ended up moving from 2015 into 2016. As you know, we don't give specific guidance on exactly what we're doing and when. We give cost guidance for the upcoming quarter and the full-year outlook on that.

Right but it's a shifting so we can look into that. Okay, thank you.

Yes, right.

Paul Sankey from Wolfe Research.

Good morning, all. Can you just update us on how the changes in oil price and the effects on the US E&P industry are coming through from your point of view. I'm particularly interested, the toughest one for us is always the NGL market. Can you talk about the dynamics there and if there's a shift in where supply coming from, shift in the oversupply? And then update us on how you're getting on with the exports which you have partly done but it would just be interesting if you could give it more from a macro perspective. Thanks.

Paul, on the NGL side, we continue to see growth in the NGL supply but there's no question that it's going to be at a slower pace as we look out. The other interesting thing is that there's a lot of ethane rejection today, as the values don't pull it forward, so I think as the crackers start up there's going to be an influx of ethane so to speak into the NGL piece. But I think that certainly causes us some pause when we think about how large and how much increase beyond today we see in the NGL. Still see it but probably not to the extent that we had seen a couple years ago with all of the E&P activity.

On the export side, a lot of interest still in LPG cargoes for both petrochemical operations and heating markets, Asia, Latin America, and even Europe. So I think we're still seeing a lot of interest around the world as people look at alternate supply, so to speak, on both the fuels and petrochemicals side. So as Greg mentioned earlier, a lot of good progress on the contract sides and just a lot of interest there that we're working to continue to [load].

We look at the balances and we're going to be long propane so we think we're going to have to export propane to make everything work for the next few years in this country.

Got it. And forgive me if you've given these numbers but did you say how much gasoline and distillate you exported and how much in fact may be crude? I don't know.

We have in the past. I don't know if we did for the quarter.

In the quarter, it's like 122,000 for the quarter and it's a typical 80% distillate, 20% gasoline.

Okay, and again I guess what -- I assume that the demand there is robust?

Yes, I would say demand is robust but we've actually exported fewer barrels this year than we did last year and it's because we've had better placement opportunities in the domestic Markets.

Understood, and -- oh, yes, sorry. The crude export thing, does that make any difference and I'll leave it there. Thanks guys.

We'll see. Taylor wants to answer the question. (Laughter) I don't think it really matters. I don't think you're going to see a lot of crude exports out of the US. I don't think the numbers work all that much. I think it probably caps the differential and you're not going to see the big blowouts that we saw in 2013 and 2014. But I think 2016 is going to be a really volatile year. And there's going to be times where it's just hard to call what that differential is going to be. We think 4-6 long term, it ought to be in that. That's what it's going to take to export barrels of crude out of the US.

Could create opportunities for us at Beaumont.

I think the other way to look at that we're -- with Beaumont and even with Sweeny and Freeport, we have options to capitalize on should they develop. But I think generally our view is there's just kind of a balancing point today where excess crude in the world is trying to push in and then we've got local productions here. So I think it just narrows that dip at the coast and I think that's going to continue and I think that's a significant change from over the last two years.

Great.

Thanks, Paul.

Bye.

Jeff Dietert with Simmons & Company.

Good afternoon.

Hi, Jeff.

You talked a little bit about shifting your organic growth away from meeting production needs towards maybe better integrating existing assets. What about M&A, asset M&A, corporate M&A, where does that fall in the pecking order?

Well certainly, I think we look at everything that's out there and we think about build-multiple versus a buy-multiple and as long as the build-multiples are better I think you'll see us do that. But we'll certainly take a look at what comes across and everything out there, Jeff.

And I saw -- I had read that Whitegate may be back on the market. Can you talk about the process there, if there is one, and perhaps any other assets you may consider divesting?

Here is what I can tell you, that, yes, we are in a process in Whitegate and we're kind of well into that process so we obviously can't talk about the specifics. But we have people that are interested and so there's a list of people there that we're going through with that asset. I think that on balance that's the only process we have going on right now in terms of assets.

People get asked a lot about the West Coast and the US. And West Coast is, we've said it, it's an option on the future but we have no current programs or there's nothing in our way today in terms of the West Coast. And margin had been pretty good there the last year or two and we've got good assets out there. We've got great people running those assets and so it's an option on the future is the way I look at the West Coast.

Got you, and finally, as far as Sweeny frac Two is concerned, should we think about that project just being on hold until drilling activity re-accelerates?

Well as you know, we pushed frac 2 FID from last year into this year so we're still doing engineering work on that and we'll make a decision on that later this year, mid year third quarter. But we won't proceed unless we get it fully contracted and we're long NGL today but it's not fully contracted so we aren't going to build a speculative frac.

Got it. Thanks for your comments.

Phil Gresh from JPMorgan.

First question is just on chemicals, given the compression of the gas-to-oil price ratio, as you look ahead are you still considering a second cracker at this point? Would the economics work at this stage if we were just indeed stay at these types of levels?

Phil, it's Tim. We continue to do engineering work and, again I'll reiterate, this is a global view with a global business. North America still looks attractive long term and today's margins do work. It's obviously not the same return that we would have if it was $0.10 a pound better. So I think that, for us, it's really about continuing to meet the customer demand, the opportunity and then structurally our view of the long term advantage on US or Middle East relates to ethane cracking in the case that the ethylene chain still, to us, has the greatest appeal and we think long term a competitive advantage. Although it's less than it was, it's still quite good by historical standards.

Okay, so is there a period of time in which you're trying to make a decision on a second FID or is it open ended at this point?

So doing engineering work, anything you start now puts it out post-2020 and I think we just continue to evaluate the options, siting, permits all those kind of things, to look at it here and then look at options that we might have available in other parts of the world as well.

Okay got it. Second question is just on the specialties business. You mentioned lower margins in the step down sequentially. Would you say that a component of that is seasonal or do you think that, that's more of a structural step down from increased competition in that business that we should think about as a more of a new run-rate or maybe some combination of the two. How would you think about that?

A couple of things, you have a lag effect in that business in prices so as prices come down you tend to hold it then it catches up. And so I think this quarter there was a piece of that. But if you think about finished lubricants price versus VGO feedstock into the base oil business, the one segment that we see in the US that's weaker is oil and gas as you might expect. But generally strong automotive business that when you're looking at what's going on in Detroit, and so our view is volumes are still pretty good this year versus last. And not a lot of growth inherently in that business by the nature of it but we see nothing fundamental there.

And I think we would say next year, to us, probably looks a lot like, or this year looks a lot like last year, in terms of how we look at the lubricants. But it's a business we like, good returns. I think this quarter just had some noise around it and I would also say that you can imagine customers don't particularly like to buy a lot when they see the price falling. So we don't see a lot of inventories building the chain but they don't want to get caught on higher cost inventory so there's always some effect when you'll see that in any quarter in which that occurs.

Okay, understood. Last question is just on the global gasoline supply demand outlook for 2016. Where do you guys stand on that? Because if we have global demand growth in the 400,000 to 500,000 barrel-a-day range, is there enough global supply to keep up with that and what's your view on gasoline cracks for this year?

Well, I think we are fairly well supplied today but basically if I break the components we would expect stronger gasoline growth globally than distillate. We're thinking it's less than this year but in total the two, probably in the million barrel-a-day range or so with 2/3 or so of that being on the gasoline side and 1/3 really coming from the distillates. Clearly, distillate has more headwind, I think, because of the general economic conditions and less capital spend as you think about industrial activity whereas we still see a pretty strong consumer market around the world that pulls along gasoline and to some extent the chemicals business as well.

Okay thanks.

Ryan Todd with Deutsche Bank.

Great thanks. Good afternoon, everybody. Maybe a couple, if I could ask one on, you gave a little bit of color on Bayou Bridge and DAPL pipes. Could you maybe give a little bit more granularity in terms of the timing of the ramp on each and maybe what the impact that you're looking for, both to the slates in your refining business or potential impact on differentials?

Yes, so let's start with the Bayou Bridge because it's closest to being in service. So there are two segments. One is Nederland, the Beaumont area over to our Lake Charles refinery and then from Lake Charles to St. James. That first leg to Lake Charles will be in service at the end of this quarter and that will have some initial impact in terms of the midstream earnings. And then later this year we'll complete the leg into St. James. So those are both under way.

I think it clearly connects the West, the Texas market with Louisiana. There's still a drive for that. That line is underwritten on the commitment side with T&D, so there's been interest in that on the refining side to get a new source of supply. And I think that's still a piece of what needs to happen so I think that just continues to make crude options more available now to the Eastern Gulf versus what we've seen just really in the Western Gulf.

If you look at DAPL, ETCOP, the Bakken to Patoka and then Patoka to Beaumont, I think there's a pretty good call on the northern tier on the Bakken today. Again that line's underwritten with T&Ds by very good counter parties and so I think you'll continue to see when that comes in service at the end of this year, early next year, the ability to move those crudes then into the markets that want that and then ultimately down into the Beaumont area as an option as well. And ultimately, for us, we think about DAPL, ETCOP as a potential way to supply Bayway via the pipe and around with the Jones Act tanker into Bayway to make it very competitive with the rail option that exists from the Bakken to Bayway today.

So I think it's all about creating more options on the refining side for ourselves as well as others and it does also, once you get to Beaumont, creates the opportunity to export should that develop. So I think just a lot of good options and that project we look is going to continue to be the lowest cost option to get Bakken to the markets we're talking about serving.

What's your expected cost from Bakken to the Gulf via that route?

We've not disclosed that. I think we just simply say that it's the most competitive but it's substantially less than rail and look at other piping system, it's still more effective way to move.

Great thanks and maybe one final one. We've seen some of your peers either talk about or actually invest in various ways, you know, capital in various ways to address perceived octane shortages. What's your outlook on this regard and is there any interest in your or ability within the organization to invest, to address the shortages?

So we have incremental opportunities that we're going to pursue. They're value creative but small projects and they don't add a lot. We're looking at standalone alky and trying to see if that makes sense. On other hand I don't want to be the last one if everyone else builds alky, probably be no reason for us to do it so we'll have to assess that against our other opportunities. The small incremental things that we'll do this year and next year make a lot of sense and we'll do those.

Great. Thanks a lot I'll leave it there.

Brad Heffern from RBC Capital Markets.

Good morning, everyone. Thanks for taking my questions.

Greg, I just wanted to go back to an earlier question around DCP. I think you explained it relatively well but I was hoping you'd put a finer point on it. If you just take strip pricing, do you think DCP just does not require any further equity injections?

If you take current pricing? No, we don't expect. They have a balance sheet they can work from. They are working to get their cash break-even down in the mid $0.30 this year so I think DCP will be fine in 2016.

Okay thanks for the clarification. And then just talking about Santa Maria, I was curious if you had any update or timeline around crude sourcing there? Obviously, its been impacted by the plant's down time?

So we've increased truck unloading at Santa Maria to mitigate that. We do run more processed inputs at San Francisco to supplement. The pipe is still something we would like to see so we continue to work on more trucks, other options. We would like to get the pipe back but I think that is out somewhat based on permits and public and government acceptance of that, so I think we're in this mode for awhile so we continue to look at new ways to get more options in there but until we get that pipe back in service or an alternate it's harder to get the full volume that we need.

The pipe's the preferred route but we don't control that. So I think folks have done a great job of mitigating it but it's kind of [20-25] today impact at Santa Maria. We probably cut that in half with trucks and then we made up the volumetrics on process inputs at Rodeo, but obviously the margin [tells us] not as good.

Great. I'll leave it there, thanks.

Thank you.

Thank you. We have come to the end of the allotted time. I'll turn the call back over to Clayton Reasor.

Well, thank you very much for your interest in Phillips and participating in the call today. You'll be able to find a transcript of the call posted on our website shortly and if you've got additional questions don't hesitate to reach out to either CW or me. We would be happy to take your call. Thanks again.

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