菲利普斯66 (PSX) 2016 Q4 法說會逐字稿

Welcome to the fourth-quarter 2016 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 Rosy Zuklic, General Manager, Investor Relations.

Rosy, you may begin.

Thank you, Sally.

Good morning, and welcome to the Phillips 66 fourth-quarter earnings conference call.

With me today are Greg Garland, Chairman and CEO; Tim Taylor, President; and Kevin Mitchell, Executive Vice President and CFO.

The presentation material we will 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 Harbor statement.

It is 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 actual results to differ are included here, as well as in our filings with the SEC.

With that I will turn the call over to Greg Garland for some opening remarks.

Greg?

Thank you, Rosy.

Good morning, everyone.

Thank you for joining us today.

Total adjusted earnings for the fourth quarter were $83 million or $0.16 per share.

Market conditions continued to be challenging, as refining, marketing, and chemicals margins were all lower.

We also had significant turnarounds during the quarter.

These factors contributed to our disappointing earnings.

For the full year 2016, adjusted earnings were $1.5 billion or $2.82 per share.

We operated well and continued to execute on our projects, and we maintained financial strength and flexibility while continuing to return significant capital to our shareholders.

We believe that operational excellence is fundamental for generating and protecting shareholder value.

2016 was our safest year ever, and we ran our refineries at 96% utilization, which was a record for our Company.

Our Marketing & Specialties business also delivered solid results for the year and achieved record volumes.

We managed costs well across our organization, holding controllable costs flat despite our significant growth activities.

We reached several milestones in our midstream growth program in 2016.

At Freeport we completed our 150,000-barrel per day LPG Export Terminal.

Commissioning went smoothly, and the facility is operating as designed.

We shipped our first commercial cargo in mid-December, and we expect the facility to be loading to near capacity this month.

The Dakota Access ETCOP System is expected to complete in the quarter.

Phillips 66 has 25% interest in these projects.

In the Gulf Coast, the Beaumont Terminal expansion is ongoing.

We commissioned 1.2 million barrels of contracted crude storage in the fourth quarter and 2 million barrels of additional crude and product storage is expected to be available by mid year.

We have plans to ultimately expand this facility to 16 million barrels.

Phillips 66 Partners remains an important part of our midstream growth strategy.

In 2016 the partnership raised more than $2 billion in debt and equity capital markets, which it used to grow its business by acquiring assets and developing organic projects.

During the fourth quarter we completed our largest drop-down to date, contributing $1.3 billion of logistics assets to PSXP.

The partnership remains on pace to achieve its growth objective of having $1.1 billion in run rate EBITDA by the end 2018.

At the start of this year DCP Midstream contributed its assets and existing debt to its MLP, simplifying the organizational structure, increasing its ownership of a publicly traded partnership.

This transaction should enable better capital allocation, position DCP growth, and allow for increased cash distributions to its owners.

In chemicals, CPChem is advancing the US Gulf Coast petrochemicals project.

The polyethylene units are on track to start up in mid-2017, and the ethane cracker in the fourth quarter of 2017.

We expect to he see increased distributions from CPChem starting this year, as capital spending is reduced following the completion of the project.

In refining, we continue to pursue high-return, quick-payout projects.

At the Billings refinery we're increasing Canadian heavy crude processing capability to 100%.

This project is expected to be complete in the first half of this year.

At the Bayway and Wood River refineries we're modernizing the FCCs to increase clean product yield.

Both projects are expected to be completed in the first half of 2018.

During 2016 we generated approximately $5 billion in cash from operations and drop-down proceeds from PSXP.

This enabled us to fund $2.8 billion of capital expenditures and return $2.3 billion to shareholders through dividends and share repurchases.

We remain committed to our strategy, executing our growth plans, enhancing returns, and rewarding our shareholders.

The projects we have coming online are well-positioned to increase cash flow.

In 2017 we expect to increase our dividend again and to spend $1 billion to $2 billion on share repurchases.

We believe our portfolio remains a differentiating factor that provides upside in a rising US production environment.

With that I'm going to turn the call over to Kevin to go through the quarter results.

Thank you, Greg.

Good morning, everyone.

Starting on slide 4, fourth quarter earnings were $163 million.

We had several special items that netted to a benefit of $80 million.

Included in these special items were several tax adjustments across our businesses that benefited earnings.

These were partially offset by Railcar lease termination costs in refining and a charge related to the DCP restructuring in Midstream.

After removing these items, adjusted earnings were $83 million or $0.16 per share.

Cash from operations for the quarter was $667 million and included a $31 million working capital benefit.

In addition, PSXP raised approximately $1.1 billion from the issuance of long-term notes during the fourth quarter.

Capital spending for the quarters was $813 million with $452 million spent on growth, mostly in midstream.

Distributions to shareholders in the fourth quarter totaled $558 million, including $328 million in dividends and $230 million in share repurchases.

Our adjusted effective income tax rate was negative 11% due in large part to the mix of losses in our US operations and gains in our European businesses.

Slide 5 compares fourth-quarter and third-quarter adjusted earnings by segment.

Quarter-over-quarter adjusted earnings were down by $473 million, driven by decreases across all of the segments.

There were several factors impacting the fourth quarter's results compared with the third quarter beyond normal market sensitivities.

DCP had higher integrity and maintenance spending.

In addition, higher NGL prices were partially offset by DCP's hedging activities to reduce its exposure to market price volatility.

Together, these items lowered fourth-quarter Midstream adjusted earnings by approximately $20 million relative to sensitivities.

In Refining, the impact of pricing of product shipped on certain Gulf Coast pipelines reduced adjusted earnings by about $50 million compared with monthly average prices assumed in the 3-2-1 market crack.

Additionally, the West Coast was significantly impacted by major turnaround activity at the Los Angeles refinery.

And Refining and Marketing & Specialities were both affected by lower margins from our commercial activities, which moved results away from market indicators as well as impacts from hedges on discretionary inventory.

Together, these items lowered Refining and Marketing and Specialties adjusted earnings by approximately $75 million in aggregate, relative to sensitivities.

I'll now cover each of the segments individually.

I'll start with Midstream on slide 6. After removing non-controlling interest of $36 million, Midstream's fourth-quarter adjusted earnings were $33 million, $42 million lower than the third quarter.

Transportation adjusted earnings for the quarter were $44 million, down $19 million from the prior quarter, driven by an increase in non-controlling interest related to the October drop-down of assets to PSXP and lower equity earnings from Rockies Express Pipeline due to the third-quarter receipt of a $10 million settlement net to us.

In NGL, we had an adjusted loss of $5 million for the quarter.

This represented an $8 million decrease from the prior quarter and was largely driven by higher expenses associated with placing the Freeport LPG Terminal into service.

Our adjusted loss associated with DCP Midstream was $6 million in the fourth quarter, a $15 million decrease compared to the previous quarter.

This was primarily due to higher reliability and maintenance spending and lower equity earnings.

Turning to Chemicals on slide 7. Fourth quarter adjusted earnings for the segment were $124 million, $66 million lower than the third quarter.

In Olefins and Polyolefins, adjusted earnings decreased by $60 million from the prior quarter, driven largely by lower margins and turnaround activities at Cedar Bayou and one of CPChem's joint ventures.

Global O&P utilization was 86%, 7% lower than the prior quarter and in line with guidance.

Adjusted earnings for SA&S decreased by $7 million on lower Aromatics margins, as well as lower equity earnings.

In Refining, crude utilization was 93% for the quarter, in line with guidance.

Clean product yield was 86%, our highest ever.

The higher clean product yield was partially due to the sale of the Whitegate refinery and increased butane blending during the quarter.

Pretax turnaround costs were $205 million.

Realized margin was $6.47 per barrel, $0.76 lower than in the third quarter.

The chart on slide 8 provides a regional view on the change in adjusted earnings compared to the previous quarter.

In total, the refining segment had an adjusted loss of $95 million, down $229 million from last quarter.

Regionally, the Atlantic Basin had capacity utilization of 102% and saw higher earnings in the fourth quarter, reflecting improved market cracks.

The other regions were all impacted by lower margins.

The Gulf Coast clean product realizations were negatively impacted by the rise in prices relative to the timing of shipments during the quarter.

Margins were down in the Central Corridor, where the market crack fell $3.62 per barrel.

In the West Coast region, the Los Angeles refinery ran significantly below capacity during October and November.

This contributed to our 71% regional crude capacity utilization and higher costs versus the third quarter.

West Coast capture was also hurt by product differentials between the benchmark Los Angeles market and other West Coast markets.

Next we will cover Market capture on slide 9. The 3-2-1 market crack for the quarter was $12.10 per barrel, down from $12.96 in the third quarter.

Our realized margin for the fourth quarter was $6.47 per barrel, resulting in an overall market capture of 53%, down slightly from 56% in the prior quarter.

Market capture is impacted in part by the configuration of our refineries and our production relative to the market crack calculation.

With 86% clean product yield for the quarter, we made less gasoline and slightly more distillate than premised in the 3-2-1 market crack.

Losses from secondary products of $2.69 per barrel were $0.25 per barrel improved this quarter despite rising crude costs, as NGL prices increased more than crude.

Feedstock advantage was $0.45 per barrel higher than the third quarter.

The other category mainly includes costs associated with RINs, outgoing freight, product differentials, and inventory impacts.

This category was $1.36 per barrel worse than the third quarter, due in part to lower product differentials.

Let's move to Marketing and Specialities on slide 10.

Adjusted earnings for M&S in the fourth quarter were $140 million, down $127 million from the third quarter.

In Marketing & Other, the $114 million decrease in adjusted earnings was largely due to lower domestic and international realized marketing margins, reflecting the impact of seasonality and rising product prices.

Specialties' adjusted earnings decreased by $13 million, primarily as a result of seasonally lower lubricants volumes and costs associated with a brand refresh.

On slide 11, the Corporate and Other segment had adjusted after-tax net costs of $119 million this quarter compared to $110 million in the third quarter.

The increase in net costs reflects higher interest expense due to the October bond offering by Phillips 66 Partners and lower capitalized interest from placing the Freeport LPG Export Terminal into service, as well as higher environmental costs.

On slide 12 we summarize our financial results for the year.

2016 adjusted earnings were $1.5 billion or $2.82 per share.

At the end of the fourth quarter, our debt to capital ratio was 30%, and our net debt to capital ratio was 24%.

The adjusted return on capital employed for 2016 was 5%.

Slide 13 shows full-year cash flow.

We began 2016 with a cash balance of $3.1 billion.

Excluding working capital impacts, cash from operations for the year was $2.5 billion.

Working capital increased cash flow by $500 million.

Phillips 66 Partners raised approximately $1 billion in public equity offerings and $1.3 billion in debt.

We funded $2.8 billion of capital expenditures and investments, including third-party acquisitions by PSXP, that totaled approximately $260 million.

We distributed $2.3 billion to shareholders in the form of dividends and share repurchases.

We ended the fourth quarter with 519 million shares outstanding.

On the cash flow chart, included in the Other category, our advances to equity affiliates and distributions to PSXP LP unit holders.

At the end of December, our cash balance stood at $2.7 billion.

This concludes my review of the financial and operational results.

Next I'll cover a few outlook items.

In the first quarter in Chemicals, we expect the global O&P utilization rates to be in the high 80%s.

In Refining, we expect the worldwide crude utilization rate to be in the low 80%s, and before-tax turnaround expenses to be between $300 million and $350 million, as this is expected to be a heavy turnaround quarter for us.

We expect corporate and other costs to come in between $125 million and $140 million after-tax.

For 2017, we expect full-year turnaround expenses to be between $625 million and $675 million pre-tax.

We expect corporate and other costs to come in between $490 million and $510 million.

We expect full-year D&A of about $1.3 billion, and Company-wide, we expect the effective income tax rate to be in the mid-30%s.

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

Thank you.

We will now begin the question-and-answer session.

(Operator Instructions)

Your first question comes from the line of Paul Sankey with Wolfe Research.

Your line is open.

Good morning, everybody.

Thank you.

Could you update us on the contribution that the Freeport LPG Export Terminal made in Q4?

I assume it was nothing, if not negative -- and what the anticipated contribution EBITDA-wise is for this coming year or this current year of 2017?

And can you do the same for the crude storage that you added?

And finally, could you just update us on the very latest on how the major petrochemical project is going on the Gulf Coast?

Okay.

On the LPG Export Facility, we premised eight cargoes a month.

I think we did about five and a half in December.

We essentially had a full quarter worth of cost, which is somewhere around $12 million-ish, I guess.

We probably did not offset the cost with the cargoes during the fourth quarter.

Moving into the first quarter, in January, we did eight cargoes.

I think we have the same laid in for February and March.

And so I think as you think about that project, we've never really broken down what the export facility is going to be.

We've said the total Sweeny hub, which is kind of the frac, LPG Export Caverns, et cetera, is $500 million of EBITDA and we've said there's about $200 million or so of ARB in there.

That leaves you $300 million-ish.

The frac is up and running.

That's somewhere $65 million to $70 million of EBITDA.

That leaves you the balance what it will be at LPG Export facility.

I will say we premised $0.12 in the economics for the fee across the dock, Paul.

And we have some contracts above that and some below that, and then we're doing at least two to three cargoes a month of spot, and the spot is about 70% of what we premised.

I think that kind of covers -- Tim's acting like he wants to come in.

On the volume side, it's been strong demand.

We're seeing good pull out of Asia, good demand out of Europe, as well as some demand out of Latin America.

So heating season in the northern hemisphere has been a pull.

Petrochemical demand has been good as well.

The good news is that on the volume side -- and we'll see where the ARBs go -- I think we started up very smoothly, got it loaded, and now we've got to work on optimization of that value.

Thank you.

And the very latest on the Gulf Coast?

And petrochemical side -- two projects really.

At Sweeny, we've got the derivative units and polyethylene.

Those are coming up mid-year.

So it's on target and just as we expected.

So we're in the commissioning phases and those kinds of things now.

The ethane cracker is fourth-quarter -- is how we look at the completion.

So behind in terms of where they are but still feeling with the contract interventions we've made to additional resources that, that project's holding well for the end of the year.

So you get a partial value uplift with the polyethylene start-up in the summer, and then you really move into where the full value uplift, though, will really come in 2018, as the cracker really comes online at that point.

Understood.

Thank you, gentlemen.

Thank you, Rosy.

Your next question comes from the line of Jeff Dietert with Simmons.

Your line is open.

Good morning.

Hello, Jeff.

Phillips 66's leverage to NGLs through the Sweeny hub and NGL pipeline [interest] fractionators in the LPG Export Facility -- NGL production has really held up better than oil or natural gas production, which fell with the reduced activity last year.

Would you discuss your outlook for NGLs with the relatively strong performance on the production side, and what opportunities you might see for additional infrastructure?

Well, I'll start high-level then Tim can come in.

I think that we're probably pleased by the way the NGL volumes held up in 2016.

Our view is rig count is going up: bottomed somewhere just over 300, up over 500 rigs.

We're seeing increasing activity, particularly coming out of the Permian.

I think that bodes well for NGLs.

As you know, we have an expansion announced at our Sand Hills line, from [285] to at least [350], maybe a little more than that.

High interest, I would say, from producers in moving their liquids to market, so we're interested in that.

In our capital budget this year, towards the end of the year, we have laid in plans to FID frac 2. We're in, I would say, very serious discussions on the volumes for that frac, and I think we're feeling pretty good about that at this point in time.

So I think we see increasing need for infrastructure around the NGL side of it.

Our plan was always to not stop with frac 1 at Sweeny but do frac 2 and frac 3 at Sweeny.

I think we start laying in those plans as we see increased opportunities for infrastructure development around what we view is going to be an increasing NGL environment.

I think I would just say -- and Tim can probably talk to this, too, a little bit more -- crude prices have certainly recovered.

NGL prices have been on a rip here in the last quarter, I would say, certainly towards the first part of this year also.

But we think that the ARBs tend to open back up.

We think with increased production, we're not going to have enough demand in the US to clear either the heating markets or petrochemical markets, and you're going to have to export.

We do think that ARBs do open up and certainly in 2017, particularly the back half of 2017.

Just a couple comments, Jeff, on that.

First of all, as the crackers start up, the ethane comes out of rejection back down the pipes, so you've got a natural load on both fractionators as well as the pipe.

I think that's a direct upside of both at DCP and at PSXP and PSX.

And then as Greg mentioned, the industry's running very light right now on ethane because it's strongly favored in the petrochemical crack.

So the propane has really pulled with both the heating demand here and then some good demand out of those export markets.

And as we look out, the balance is -- we still feel very confident, butane, propane, now ethane even, needs to balance to the export markets in the future.

So we think that continues to be structurally a very good play.

With the [real] strength almost spiking prices in propane and butane, that obviously helps frac margins, but with butane it's typically a winter-grade gasoline component.

How is that influencing gasoline production and gasoline margins?

Well, we saw it in the fourth quarter in our system.

We're up actually about 2 points on clean product yield, and a lot of that is due directly to butane blending in our system.

That's going to wind down.

That certainly underpinned the butane price in the short term was that play into the gasoline pool.

Our expectation is it's seasonal, and that begins to come off.

As we get into the summer season, you make summer grade gasoline, you can't blend as much butane in it.

Thank you for your comments.

Thank you, Jeff.

Your next question comes from the line of Ed Westlake with Credit Suisse.

Your line is open.

I'm on mute.

Sorry.

Good morning.

(laughter)

Good morning.

Hello, Ed.

It was a great question I just asked.

(laughter) I've forgotten it now.

We gave a great answer, too.

Thank you.

Just on chemicals, as you obviously start up the downstream plant and then the cracker, you're going to get OpEx costs, some you can capitalize.

Maybe just walk through a little bit about how we should think about how this is going to hit earnings, and then obviously distributions in perhaps a little bit more detail as we go through the quarters here and into 2018.

As you start up, you've obviously got now to the extent that you've got loading up in the operations side and you start up, that will actually begin to hit.

So you need the production to offset that.

So you've got a couple of months where you'll see that before you get the contribution on the margin.

So as you go, on the chemicals side, you would expect in the summer the increase in the OpEx -- running the units then will contribute the earnings.

You see that.

We think that's a relatively smaller piece of the total project because the margins in the polyethylene with purchased ethylene or the ethylene upgrade is relatively small.

As you get to the fourth quarter, you'll see those start-up expenses and stuff on the cracker, those are larger.

And then as you get into the first quarter of 2018 on that, if the start-up occurs in the fourth quarter, you begin to see the earnings.

I think you've got exposure -- higher expenses without full coverage on the earnings side during that start-up period.

But normally that's a relatively short period of time or a month or two.

And then on the distribution side, because the CapEx will be coming down as the project comes closer, yes.

Yes, so I really think that the CapEx is the big driver.

So you're on the part now where compared to last year it's down significantly.

And so I think we need to complete the project.

The owners will look at that.

But we're still thinking that the operating rate and the margin environment in chemicals will be pretty constructive this year.

So we're thinking that there's a good chance that we should be able to begin to see the CapEx, so to speak, that's not there available for distribution -- say that's $1 billion or so, roughly.

And then in 2018, you then get the earnings contribution which would then add additional distribution -- so we take 50% of that, Ed.

The CapEx is certainly going to be there this year.

I just think it's a good time to make sure that we cover that expenditure from the project side as owners.

And then on the DCP, the simplification or the change in structure, maybe just walk through a little bit about how that's going to affect cash distributions back to PSX.

And some people still think that the debt burden is still too high, so maybe some comments on your opinion there, given that there is an exciting growth opportunity in that asset for the upstream producers in the Permian.

Ed, this is Kevin.

So as you think about the new structure at the entity up top, which is where us and Spectra have the 50/50 ownership, all you have there is now are the LP and GP interests, which attract the LP distributions and the IDRs that come with that.

There's some debt.

There's about $400 million of debt there.

So there's debt service expense, and then those distributions coming up.

So what that means is we should see a path to distributions back out to the owners much sooner than we would have previously.

So with we would expect to see cash coming out in 2017.

As you know, through that restructuring we put in place some conditional IDR givebacks if needed at the MLP level.

But with the way the markets have gone and NGL prices, that doesn't look so likely that would be needed in the current environment.

So we do expect we'll start seeing cash coming back to the owners this year.

From the standpoint of growth, with the simplification, clearly any growth activities will take place at the MLP.

And so they need to look at their overall capital structure, cost of capital from the standpoint of the ability to issue debt and equity.

Clearly with the leverage that's there at this point in time, you wouldn't expect to see debt be an issue without some equity as well, because they're kind of at the high end of the range from a leverage standpoint.

But the encouraging news is they're seeing opportunities as well.

So the growth opportunities are starting to surface again.

They announced a little bit of that at the time of the restructuring.

Thank you.

Your next question comes from the line of Doug Leggate with Bank of America-Merrill Lynch.

Your line is open.

Than you, everybody.

Good morning.

Good morning, Doug.

Guys, there was obviously an awful lot of moving parts in the quarter, especially with the start-up costs.

I wonder if I could ask one of the other questions slightly differently.

To the extent you can, is it possible to quantify what the -- I guess the combination of opportunity costs and sort of one-off start-up events -- if that hadn't been there, what was the EBITDA lost to those issues that on a normalized quarter would not normally have been there?

I don't know if that's something you would be able to quantify.

Doug, this is Kevin.

The items that I ran through that were the kind of outside of the normal market sensitivities -- so on DCP, that was about $20 million -- and these are net income effect.

So not EBITDA, you'd have to gross up for an EBITDA equivalent.

So $20 million on DCP between the integrity maintenance spending and the impact of the hedges.

And the refining, the effect of the realized -- the product differentials -- about $50 million.

And then the commercial activities, including some of the hedges on discretionary inventory, about $75 million.

So if you add those up, you're at $145 million of out-of-the-ordinary items that are pretty difficult to model without having all the detail in front of you.

I guess I was thinking more about start-up costs and the opportunity costs of having down time in West Coast, those kind of issues as opposed to what you called out, Kevin.

Can you put some numbers around that or no?

This is Rosie.

What I was going to say for the West Coast, you could probably just think about the LA refinery, which is the one where we had the significant down time.

And that was the vast majority of our turnaround expense.

So we had about $205 million of turnarounds, so call it $100 million.

The other thing that was happening there is LA was down in the month of October completely and then half of the month of November.

And in all-in for the quarter, it ran at roughly 45% utilization rate.

So the way I look at it is the margin capture really wasn't there for LA.

The San Francisco market is very different and so is the Ferndale -- where Ferndale is up in Seattle is very different.

So we can't really quantify that piece of it, but there's roughly $100 million from the turnaround cost, and then above that you've got the margin that's missing.

Okay.

We can take the rest offline.

Thanks for that, Rosie.

My follow-up is -- I'm afraid is a policy question.

You guys are one of the biggest importers obviously of Canadian crude.

We've heard from some of your peers that they are seeing real allocations from OPEC suppliers.

I'm just wondering if you could walk us through what [can produce your] flexibility options you would have in the event that there is a border tax or how you guys are thinking about that and whether you can confirm you're also seeing OPEC allocations.

I'll leave it there.

Thanks.

Maybe let me address the broader border tax.

First of all, you're correct.

I think we've probably imported 1 million barrels last quarter.

Right.

Of crude.

And we are probably the largest importer of Canadian crude within that 1 million barrels.

We support tax reform.

We think it's important.

We think it ought to be fair to all industries.

You shouldn't pick winners and losers with your tax policy.

Our view is that there's a lot of ground left to cover and that getting this tax change through is going to take more time than what people think.

It looks like the Senate's going to have their own plan against the Republican plan.

But if just border tax goes through in the form as we understand it, we would pay more taxes on the refining business at 20% than we pay at 35% today -- that's a negative.

We think crude prices go up 25%.

We think gasoline prices go up $0.30, $0.40 a gallon in that scenario.

We're worried about demand destruction in that case and what happens.

So we're concerned about second-, third-order, fourth-order impacts beyond just that.

You think about increased domestic production that gets incented with higher prices, probably more Midstream infrastructure, so directionally it's probably good for our Midstream business.

You think across the chemicals platform, historically we've exported between 15% and 25% of the ethylene produced in the US and derivative equivalents, and I think that, that's probably similar to what people are thinking going forward.

And so from an export perspective, the border tax adjustment would be good for the chemicals business.

So we have to think about it across all three of our platforms and how it impacts those platforms.

Specifically to the Canadian crude question and how we might substitute that, I'm going to let Tim dive into that one.

I think about our system, and you think about our imports today.

If you just took light -- say, US crude largely light -- probably got 400,000 barrels a day that we can put into additional light.

Most of that could be US in terms of rather than importing a light crude.

You get to heavy crudes, the availability is not really there.

So I think our view would be is that you'll still have to do that and that import is the marginal barrel, and that's why we see pricing would probably be parity in terms of a US barrel versus an import barrel ultimately.

And so I just think we continue to optimize.

But it's unlikely that you could cover the entire US refining need without imported barrels, even the border tax.

I think as we look at it, everything re-equilibrates, and the impacts vary across our business lines.

Short-term, I'm not sure where the Canadian crude goes, I think it's got to drain south.

Longer-term, I think options can be developed for that.

So I don't think we're worried about the Canadian crude going away, but it will have to price such that the refiners run it.

To be clear, Greg, your comment about gasoline prices, my read of that is you're suggesting you would be able to pass that cost through.

Is that a fair read or no?

Well, yes.

$70, it's $14 a barrel.

Our mid-cycle net income is probably $250 million.

It just doesn't work.

It's going to get passed, or mostly passed through.

Okay.

And sorry, on the OPEC issue, just could you confirm whether you're seeing allocations there?

I'd say a that we've seen minimal impact in our business from our perspective.

Certainly we see that when you just look at the macro data that the cuts are there.

I think it just takes time for that to work its way into the system and if you go through the first quarter, heavy turnarounds, particularly for heavier grades here in the US, it may take a while until that shows up.

But generally if the [KETs] are really centered around heavy production, you would expect the light-heavy dip to narrow a bit.

I think that's an effect that you would see now over the next several quarters, and it's really going to show up in terms of will the inventories in global crude fall and where do you pull that.

I think it's kind of early with that, and we've not seen impacts with that yet.

Appreciate your answers, guys.

Thank you.

Your next question comes from the line of Phil Gresh with JPMorgan.

Your line is open.

Hello, good afternoon.

Hello, Phil.

Hello.

Greg, last we talked, you were pretty conservative on your views for the refining outlook, and we've had a tough start to the year.

I thought maybe you could just talk about your views maybe for the first half on refining and then for the other parts of the business chemicals, how you're thinking about that for 2017 as well.

I'll start with we've got a lot of inventory with crude and products.

And so for us the first half of 2017 feels about like 2016 to us at this point in time.

I think as you start moving into the back half of 2017, we see some opportunities certainly for margins to improve.

But I think we need to pull down some inventories, and that also assumes that demand's going to be fairly good.

And it's been fairly robust in 2016.

We expect, I would say, good demand growth in 2017 in refining.

The other thing I would say -- heavy turnaround quarter, it looks like, in the first quarter globally across the refining space.

So we'll see how that actually plays out.

But there is a lot of turnaround activity across the globe.

That may back up some crude, but I think it will give us a chance to pull down some of the product inventory.

So as we start of moving into the second quarter, back half of the second quarter, we think things start to get better.

On chemicals, we're still pretty bullish about demand growth.

We think that we're still growing at 1.5 times GDP in the chemicals business, and I think we see good opportunities in 2017.

I think you're going to see the crackers that come up, so we're already signaling that we're kind of towards the end of the year in 2017.

All these crackers won't come up in 2017, they'll be up in 2017 and 2018.

I think the market impact of those crackers coming in is muted.

I don't think we're going to see the depression in margins in 2017 that I think that a lot of people had anticipated, although we've always been probably more bullish on margins in 2017 than everyone else for the chems.

I think chems is set up for a pretty good year in 2017.

I would say also constructive on chemicals is if crude oil continues to rise relative to ethane, say in the US, then that creates additional upside.

There will be adjustments as the crackers come up, but generally operating rates look pretty strong and we're seeing really good demand around the world.

Got it.

Thank you.

And then my next question is just if I look at your CFO number for 2016, strip out the working capital tailwind of $500 million, it was sub-$2.5 billion, and I know the long-term target, Greg, you talked about often is $4 billion to $5 billion.

I was trying to think about 2017 in the context of those two numbers in light of what your view is on the macro environment, the projects, et cetera.

It feels to me like it might be difficult to get above $3.5 billion this year, but I don't know if you've got you any thoughts on that, that you could share.

We typically don't forecast cash flows for the year.

I do think that you're going to see more cash generated in 2017 than in 2016 with these projects coming on, reduced capital expenditures.

We started $3.9 billion last year, came down at $2.8 billion end of 2016.

We got a $2.7 billion target this year.

I will say that as we look across the capital portfolio that we have, we're finishing up the big projects.

And so a lot of what we have is a lot of smaller projects, and we think they're good return projects.

But we have a lot of discretionary room that we can move the capital budget.

We probably have $500 million to $750 million of discretion in our capital budget this year that we could move if we needed to.

So I think that on balance that we'll be able to manage that.

We are committed to increasing the dividend this year.

We are committed to $1 billion to $2 billion of share repurchases.

But you look at the growth profile we have at PSXP.

We'll probably do somewhere around $2 billion-ish of, let's say, debt and some form of equity in 2017 just like 2016 to hit our 2018 run rate number.

I don't know, Kevin or Tim, you want to step in.

Just one additional point.

Tim touched on it earlier.

You think about the equity affiliates.

So in 2017, we should see some cash coming back from DCP.

We should see more distributions from CPChem, and then of course that builds up, becomes even more significant when you get into 2018 and you've got a full year of operations on the cracker.

There is a line of sight to increase in operating cash flow, although of course it's also heavily dependent on the margin environment as well.

Kevin, if I could just ask one more to you.

The deferred tax piece big tailwind in 2015 and 2016, could you elaborate on what the source of that deferred tax benefit has been and if it's something that's sustainable?

That derives from the -- it's really part of the benefit of the heavy investment we've been going through.

As these assets go into operation, we get to take bonus depreciation.

That effectively cuts your cash tax bill, and that's reflected through that deferred tax on the cash flow statement.

We had benefit in 2015.

We had benefit in 2016.

And we'd expect to see some benefit in 2017 again as well.

Got it.

Okay.

Thank you.

Your next question comes from the line of Blake Fernandez with Howard Weil.

Your line is open.

Hello, folks, good morning.

I wanted to ask you about the guidance for utilization in Q1.

It looks to be pretty well below what you had been trending.

I was curious if you could help us out with understanding maybe regionally where some of those reductions are coming, and also if you could confirm -- I guess one of your peers had alluded to potential for economic run cuts.

I didn't know if maybe any of that included economic cuts, or if it was purely planned maintenance.

It's all planned maintenance.

We typically don't go into where because we feel like it disadvantages our commercial folks when we do that.

But it's going to be a heavy year for us in 2017.

We try to do five-year turnaround cycles, and what's happening, they're just kind of lining up and then you -- of course you have regulatory targets you have to hit in terms of bringing assets out of service for inspection, et cetera.

So I think we're going to -- 2016 was about where we were in 2015.

We're going to be a little bit higher in 2017 in terms of total turnaround cost.

The first quarter, it's a big lift for us, and you can see that in the core path we give you in terms of op rates.

Okay.

Fair enough.

Just a real quick comment on that.

That's on the refining side.

It's probably around four of those major turnarounds going on around our system.

Chemicals as well has a heavy turnaround schedule, one in the US and one in the Middle East joint venture.

That's why that operating rate's guided lower in chemicals as well.

It's not demand-driven.

It's really the turnaround that drives the chemicals outlook.

Got it.

The second question was on Beaumont.

If I am not mistaken, I believe that was providing a step change in your export capacity.

I was just hoping you could help me.

It looks like the expansion is coming on in phases.

I didn't know if the export capability is tied to when that comes on or just any color there.

There's good demand for storage right now, as you might guess.

So we've done those projects.

We're also in the process of really going through an engineering project to get our dock rate utilization up, to go from [300,000 to 600,000].

That's particularly important for crude.

And so that's a project that would come on here in the next 12 to 18 months, to be able to do that.

As we step back, I think that, that's going to continue to be a benefit as producers look for options beyond just domestic consumption but also to tie into those export markets.

It sounds like that is more of an end of Q1.

In other words, that capacity is not open right now.

That capacity -- we're limited on that, Blake.

We're going to de-bottleneck that piece as part of our de-bottleneck plan at Beaumont and the master plan that we have.

Okay.

Thank you very much.

On the export.

Your next question comes from the line of Brad Heffern with RBC Capital Markets.

Your line is open.

Good morning, everyone.

Hello, Brad.

As a follow-on to the last question about exports, I was just wondering if you could go through what you're seeing in the export markets for products right now, [other than] the demand is looking.

Demand was really good.

We ramped up in the fourth quarter.

You've seen that really around industry data.

So I think it's still there.

I think Latin American refining system on the clean products side has continued to have issues, and that's created an opportunity.

That continues -- we still feel bullish in terms of the export side on the clean products.

Okay.

Thank you for that.

And then Greg, I think during this call you've said a couple times you're committed to a dividend increase in 2017.

I think in the past, the guidance had always been for double-digit.

Am I to assume that because you're not saying double-digit, that it's just an increase in the dividend at this point and not necessarily that?

We really haven't given guidance on exactly how much.

You should expect it will be in-line with our desire to have a strong, secure, growing, and competitive dividend.

We'll look at all those things when we make the decision around the dividend later this year.

Okay.

Thank you.

Your next question comes from the line of Neil Mehta with Goldman Sachs.

Your line is open.

Hello, guys.

How are you?

Good.

Thank you.

So a question on slides 19 to 22 where you do the refining margin walk and -- the market capture was softer than what we would have expected across a number of the different regions.

Can you talk about how you're thinking about that capture rate on a go-forward basis?

There's two bars in particular: Secondary Products and Other.

If you could help us understand what's driving some of the movement in both of those bars, that would be great.

Thank you.

Neil, this is Kevin.

The Secondary Products line is simply a function of the delta between your crude cost and the non-clean products.

So the 15% or so of non-clean production, which typically doesn't track with crude to the same extent.

So as a rule of thumb, as crude prices increase, then the losses on Secondary Products on a per-barrel basis will increase, and that will hurt capture.

You see the opposite apply when crude prices decline.

That drag on capture tends to be reduced.

In the other you have a whole series of items that can actually go in either direction relative to overall capture.

So you've got the RINs expenses is recorded there.

The freight costs for outbound product is in there.

Any of these product differentials -- so when we talk about the actual realized product price versus the marker, then that will manifest itself in that part of the calculation.

Appreciate that, Kevin.

The follow-up is earlier this week one of your peers was commenting that they were seeing same-store sales through their gas station network down 3% to 4% in January on a year-to-date basis.

As you look at your marketing business -- recognizing you don't have a gas station business, but your marketing business -- are you seeing negative gasoline demand trends here in the US to start 2017?

Well, I think seasonally, Neil, you see that this is a weaker driving time.

If you're looking sequentially over, say, the third quarter, you do see an impact.

If you look at year-ago, we continue to see on the same-store growth in that.

I think that our anticipation is as you get back now into the spring and the driving season, that you should begin to see that.

But still, gasoline to us -- we had good growth as an industry.

We saw it in our chains.

This year we would expect some gasoline growth as well but probably not as strong as we start to -- the impact of pricing and vehicle miles driven, et cetera, begin to saturate.

We're still thinking it's there.

What's interesting, maybe as an aside, is that we're seeing a pickup in distillate on the transportation side, which is I think very important to help bring some strength back into that market, too.

Great.

Thank you, Greg.

Your next question comes from the line of Roger Read with Wells Fargo.

Your line is open.

Thank you.

Good morning.

Good morning, Roger.

Maybe as a follow-up to I think it was Phil's questions on cash flow, if we think about the projects you're talking about in the future here in terms of Frac 2 and 3, how should we think about maybe a beyond-2017 CapEx run rate?

And obviously we don't go back maybe to the 2015 levels of spending, but is what we've seen last year and expectations for this year the right way to think about it?

I think that a $3 billion run rate is something we're comfortable with.

And that's $1 billion-ish of sustaining capital and $2 billion of growth capital.

And we think we can get done what we need to get done within those boundaries.

Okay, and then in a situation like that I would expect -- and let's assume a normal price environment, whatever that really is -- you'd be cash flow positive.

What would be the plan after that?

That it would be to reduce debt?

To up-share repurchases?

Is it that you'd favor dividend?

I'm just curious which direction we should think about things going.

As we think about the hierarchy of how we allocate cash, the first thing is sustaining capital.

That's $1.1 billion or so.

The next goes to our dividend, and that's $1.3 billion.

We'll grow that every year going forward.

Then we think about our investable opportunities and the returns that we can generate from those investable opportunities versus what we think the returns we can generate by buying our shares back can.

We've got a natural tension there, but there's kind of a competition there for that.

And at this point in time, I don't think we see anything different from the guidance we've given in terms of the 60/40 allocation of reinvesting in the business versus distributions back to our shareholders.

Okay.

Thank you.

Your next question comes from the line of Corey Goldman with Jefferies.

Your line is open.

Hello, guys.

How's it going?

Great.

Thank you.

How you doing this morning?

Not bad.

I just wanted to get some more color on slide 17, the new sensitivity table you guys outlined and specifically that for DCP.

So DCP sensitivity in NGLs looks as though it's about 80% lower than what it was in 2016.

Assuming some of those were just self-help initiatives or re-contracting, can you comment on what drove the rest of that reduction?

Are there hedges in place there, and if so, are they direct products?

This is Kevin.

You're exactly right.

The delta there is driven by the hedges that are in place at DCP, which mean from an earning standpoint, you're not going to see the same -- as much upside or downside to changes in commodity prices.

And so there's hedges on NGLs and crude, if I've got those details right in my mind.

Of course, the accounting drives it to be not always quite intuitive because the hedges are in place through the end of 2017.

So at the end of each quarter, you're marking those future volumes through the end of the year.

So there may or may not be an offset relative to the gain on the physical versus the paper that you're hedging out through the end of the year.

Obviously as you progress through the year, that effect is muted somewhat.

You can think about the total equity link that we have at the new DCP enterprise -- we probably hedged a third of that or so.

That's right.

About 30%.

The other thing is that LLC used to be 100% or 50/50 owned with -- and now it's down -- the ownership percentage is effectively 38%.

So there's some of that commodity exposure now that's moved into that piece of that, along with the hedge effects.

Okay, interesting.

All right.

And then maybe as a follow-up, given just how large DCP is in the overall NGL market in terms of overall production, did you see an impact on the price itself while you were out making the purchases for the hedges?

No, I'm not aware of any -- no, not aware of anything there.

Okay.

And maybe just one last one if I could.

I think you had somewhat answered it in a previous answer.

There are no hedges in 2018?

Are we correct in stating that?

I believe that's correct.

Okay, that's it for us.

Just wanted to make sure.

Thank you, guys.

Take care.

Your next question comes from the line of Paul Cheng with Barclays.

Your line is open.

Hello, guys.

Good morning.

Good morning, Paul.

Maybe this is for Tim.

Tim, for the NGL Fractionator 2 or 3, if you do decide to go ahead, should we assume it's a carbon copy of the Fractionator number 1, so is going to cost about $1 billion?

If that's the case, is that going to be housed by PSX or is going to be in the MLP for the Phillips 66 Partners, given that it should be getting big enough that they may be able to do it?

What sort of timeline on FID you may be thinking about at this point.

Okay, so the capital -- I think the beauty of a second frac is you can leverage some of the infrastructure you've put in place.

I think our view is the next increment of capital will be lower because you've got all the utilities and some of the caverns, et cetera, pipes in place, and we planned for that.

So that's a beneficial incremental project.

And then in terms of when we could do that, as Greg mentioned earlier, we're seeing a lot of NGL looking at the [deramp] or the ramp-up on Sand Hills and the Permian, so producers are beginning to ask that.

I think we're looking to develop that.

Ultimately you look at the Permian, the Eagle Ford, and the recovery that we're seeing in the Mid-Continent as well, and you believe that there's going to be a need for the fractionation.

So the timing we'd like to have, we'd say maybe later this year, but it's one we're always going to keep on the front burner as we develop that.

But we don't want to do that until we're contracted around that.

And is it going to be housed by PSX, or is it going to be by the partners?

Well, the current frac is owned by the partners.

And so I think they are getting much bigger.

They're doing a CapEx spend today that's over $400 million.

And so it's getting into a point where they can do that.

It may be a bit early on that, Paul, depending on the timing.

But ultimately we'd like to move as much of the Midstream spend into PSXP that it makes sense to do and they can manage.

So I think getting bigger, they've already taken on significant amount of our consolidated capital budget already.

Tim, you guys going to do the second -- I think Greg mentioned previously, I think at one point was talking about 2018 and then talking about 2019.

Are we still talking about 2019 probably for the next FID, or that also has been changed?

No, I think it's post-2018.

I think the soonest you see FID, based on engineering and where we are working at the CPChem level, that would likely become now 2019, 2020 decision on FID.

When I looking at the turnaround or the utilization rate you guys mentioned in the refining -- low 80% in the crude -- should we assume that your total throughput is also going to be in the low 80%, the total throughput capacity?

Or that the turnaround is really more in the crude, and your conversion unit is [running pretty fragile], so as a result your total throughput is not going to be down that much?

Fundamentally, as you look at these, these are major turnarounds, Paul, so it's roughly going to approximate that utilization that we guided to.

Okay.

And finally I just wanted to confirm, Tim, you mentioned earlier that you guys still seeing gasoline demand growth in January in your system.

Because if we're looking at the [dealing] number that they talking about a 5% to 6% drop -- Marathon Petroleum was talking about in their network dropping about 3% to 4% -- just want to confirm whether I understand you correctly saying in your wholesale system that in January you're still seeing year-over-year gain.

I said sequentially, you see a decline but year-on-year, same period, you've seen the growth.

We have seen decline sequentially in January, as you would expect from a seasonal input.

Yes, but I'm talking about year-over-year, say January of this year comparing to January of last year.

No, we still -- from our system, our view is that we still see a small increase in the gasoline through our same stores year-on-year.

Interesting.

1%.

Pretty small, but still.

That looks like a rock star comparing to the [DOE] number.

Thank you.

Take care, Paul.

Thank you.

We have now reached the time limit available for questions.

I will now turn the call back over to Rosy.

Thank you, Sally, and thank you for your interest in Phillips 66.

If you have additional questions, please give C.W. or me a call.

Thank you, ladies and gentlemen.

This concludes today's conference call.

You may now disconnect.