菲利普斯66 (PSX) 2012 Q4 法說會逐字稿

Welcome to the fourth-quarter 2012 Phillips 66 earnings conference call.

My name is John, and I will be your operator for today's call.

At this time, all participants are in a listen-only mode.

Later, we will conduct a question-and-answer session.

Please note this conference is being recorded.

I will now turn a call over to Mr. Clayton Reasor, Senior Vice President, Investor Relations, Strategy and Corporate Affairs.

Mr. Reasor, you may begin.

Thanks, John.

Good morning.

Welcome to the Phillips 66 fourth-quarter earnings conference call.

With me this morning are Greg Garland, our Chairman and CEO; our CFO, Greg Maxwell; and EVP, Tim Taylor.

The presentation material we'll be using this morning can be found on the Investor Relations section of the Phillips 66 website, along with supplemental financial and operating information.

Slide two 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 these results to differ are included here on the second page, as well as in our filings with the SEC.

This slide also contains a reminder that any comments we make regarding the formation of an MLP are not an offer of securities.

So that said, I will turn the call over to Greg Garland for some opening comments.

Greg.

Thanks, Clayton.

Good morning, everyone.

Thanks for joining us today.

We are off to a good start, strong performance in 2012.

We had solid financial and operating results and we continue to deliver on the commitments that we set out to achieve when Phillips 66 was created.

We believe that our differentiated portfolio has allowed us to capture a number of market opportunities across the value chain, resulting in significant cash generation and shareholder value creation.

I am really pleased with what our employees have been able to accomplish.

They've executed the spin flawlessly, they've stood the company up, they've operated well, and they've managed to keep safety as a top priority.

We've had a strong track record of operating excellence, and when we talk about that, operating excellence is personal safety, it is process safety, it is environmental excellence, it is reliability, it is cost management.

This year was no exception.

We've turned in one of the best years ever, and Phillips 66 remains a leader in operations excellence.

That said, there is always room for improvement.

The goal is zero incidents at our facilities, to continue to reduce cost, improve our reliability and our environmental footprint.

Late last year, we announced our intent to form a Master Limited Partnership, which we expect will help highlight the value of our transportation, logistics and midstream businesses.

It also serves as an efficient vehicle for funding growth investments in these areas.

We also expect to start taking delivery of the first group of our 2000 newly-constructed railcars in early February.

In January, we've entered into a five-year transportation logistics contract with Global Partners to move about 90 million barrels of Bakken crude to our Bayway refinery.

This agreement provides a reliable, long-term alternative to more expensive Brent-based crudes.

On the Marine side, we've taken delivery of one of two Jones Act vessels that we chartered.

So all these steps support our plan to put advantaged crudes to the front end of our refineries.

We've got ways to continue to accelerate advantaged crude capture.

We've completely backed out imports of US light sweet crude into the Gulf Coast.

But we are also taking additional steps to enhance our returns.

We are going to remain very disciplined in our approach to capital spending.

We will continue to reduce costs, we will push yields and will continue to increase our export ability.

Product exports played a larger role in our results this year than last year as market opportunities opened up to us internationally.

December was a record month for us in terms of exports.

We had over 180,000 barrels a day of exports in the month of December.

Regarding distributions, we've said that we intend to return capital to our shareholders.

We've raised the dividend 56% to $1.25, and we've announced $2 billion of share repurchases.

In 2012, we bought over 7 million shares for about $350 million.

Late last year, we paid down $1 billion of debt.

This further strengthens our financial flexibility, it reduces risk, and our debt-to-cap is now 25% at year-end.

So now I'm going to hand to conversation over to Greg Maxwell.

He will take you through the quarterly results.

Greg.

Thank you, Greg.

Good morning, everyone.

During the quarter, we ran well, we benefited from strong Refining and Chemical margins, and we processed more advantaged crudes in our domestic refineries.

And this enabled us to increase our realized refining crack spreads, moving our market capture to 95% in the fourth quarter, and this is up from 72% last year.

On the earnings front, our reported earnings were $708 million, or $1.11 per share.

Excluding approximately $600 million in special items, adjusted earnings were $1.3 billion, or $2.06 a share.

On an adjusted basis, earnings for the quarter were up almost 250% compared to last year.

If we exclude changes in working capital, cash flow from operations for the quarter was $1.7 billion.

Our cash flow generation enabled us to fund our capital program, pay over $150 million in dividends and repurchase $245 million of common stock during the quarter.

And as Greg mentioned, we reduced our debt by $1 billion, from $8 billion to $7 billion.

And as you will see on a later slide, we ended the year with a cash balance of $3.5 billion.

On an adjusted basis, our full-year 2012 return on capital employed was 22%.

That is up from 14% in 2011, and this improvement was mainly due to higher earnings in our refining and marketing and chemicals segments.

Before we leave this slide, I'd like to touch on a few key items this quarter.

First, the special items of approximately $600 million included $564 million for the impairment of our equity investment in the Melaka refinery.

This impairment was based on significantly lower estimated future refining margins in the region, driven primarily by expected increases in future crude oil pricing over the long term.

As such, we determined that the fair value of our investment in Melaka was lower than our carrying value and that this loss in value was other than temporary.

Second, excluding special items, our adjusted effective tax rate was 29% this quarter compared to 33% last quarter.

The decrease in the effective tax rate is mainly due to income mix and different statutory tax rates across the various taxing jurisdictions in which we operate.

In other words, compared to last quarter, a higher proportion of our earnings this quarter were from foreign jurisdictions with relatively lower tax rates.

The next slide provides a high-level look at our fourth-quarter adjusted earnings.

Compared to the fourth quarter of 2011, our adjusted earnings increased by over $900 million to $1.3 billion.

As shown, Refining & Marketing generated $1.1 billion in adjusted earnings, and this excludes the impact of the Melaka refinery impairment, as well as Hurricane Sandy related costs, which primarily impacted our Bayway refinery, along with some nearby terminals.

The majority of the $900 million improvement in our R&M segment came from much stronger refining margins, due largely to improved market crack spreads and strong feedstock advantages.

Moving next to Midstream, Midstream adjusted earnings were $62 million, about $50 million lower than last year.

This decline in earnings primarily reflects the impact of lower NGL prices quarter over quarter.

Chemicals' earnings were $246 million, which were approximately $100 million higher than the corresponding quarter of 2011, and this is mainly due to higher margins especially in the olefins and polyolefins chain.

Excluding repositioning costs and corporate property impairment, Corporate and Other costs this quarter were $92 million.

The cost variance of $41 million is largely due to interest expense on debt associated with the repositioning that didn't exist in the same quarter last year.

I'll cover each of these operating segments in more detail later in the presentation.

Our fourth-quarter cash flow is shown on slide six.

During the quarter, we generated $1.7 billion in cash from operations, excluding working capital.

Changes in working capital negatively impacted cash flow by $400 million, with the net change primarily due to tax payments.

As shown on the chart, we paid down $1 billion of debt.

We also funded $900 million of capital expenditures and investments.

That includes approximately $500 million for our investments in the Sand Hills and Southern Hills pipelines that are being constructed by DCP Midstream.

And during the quarter, we returned $400 million to our shareholders in the form of dividends and share repurchases.

In summary, during the quarter, we generated sufficient cash to fund our capital program, along with our dividend and share repurchase programs.

And with the $1 billion debt repayment, we took our cash balance down to $3.5 billion at year-end.

As for our capital structure on slide 11 (sic -- see slides -- slide seven), our equity has increased almost $2 billion since the second quarter, and debt has decreased by $1 billion.

This has enabled us to reduce our debt-to-cap ratio to the middle of our targeted range of 20% to 30%.

And taking into account our $3.5 billion ending cash balance, our net debt-to-cap ratio is 14%.

Next, we will cover each of our operating segments in more detail, starting with Refining & Marketing on slide eight.

In Refining & Marketing, our refining realized margin was $13.67 per barrel, with a global crude utilization rate of 91% and a clean product yield of 83%.

Our utilization rate was negatively impacted by turnarounds at the Wood River, Borger and Los Angeles refineries, as well as Hurricane Sandy-related unplanned downtime at our Bayway refinery.

During the quarter, we continued our efforts to run more advantaged crudes, with 67% of our US crude slate being advantaged, and this compares to 57% in the fourth quarter of last year.

Our return on capital employed for the R&M segment, which includes over $3 billion in goodwill, improved to 22% this year, and this is up from the 12% return that we had in 2011.

Slide nine provides more detail on Refining & Marketing's earnings.

Adjusted earnings for R&M were $1.1 billion this quarter, and this is up $927 million from a year ago, reflecting improvements in all of our regions, especially in the Gulf Coast and Central Corridor regions.

Marketing, Specialties & Others were also up, driven largely by our international operations.

The earnings of all four of our refining regions increased, primarily due to improved refining margins.

The improvements in refining margins reflects not only higher market crack spreads, but also an improved feedstock advantage, especially in the Gulf Coast and the Central Corridor regions.

The improvements in feedstock advantage increased earnings in the Gulf Coast by over $200 million and by over $100 million in the Central Corridor.

Finally, other refining was up this quarter compared to last year, primarily due to movements of Canadian crude supply to several of our refineries.

As we move on to Marketing, Specialties & Other, the US was down by $2 million, primarily due to higher taxes and costs, and this was partially offset by higher US marketing margins.

Internationally, MSO was up $40 million, mainly as a result of higher margins.

The next few slides highlight our performance in Refining and provides more detail on Marketing, Specialties & Other.

On slide 10, you can see Refining's adjusted earnings increased almost $900 million compared to a year ago.

Improved margins were the key driver, with higher market cracks and greater feedstock advantages being partially offset by inventory impacts.

The inventory impacts were largely driven by gains recognized in 2011 that were tied to asset sales and shutdowns.

Lower volumes negatively impacted earnings by $42 million, mainly in the Atlantic Basin and the Central Corridor regions, reflecting unplanned downtime due to Hurricane Sandy and planned turnarounds.

Operating costs were up slightly, reflecting higher utilities and maintenance costs.

The Other category includes positive earnings impacts from lower effective tax rates, primarily due to income mix and federal tax adjustments.

Now let's take a look at our market capture, shown on slide 11.

On this slide, we compare the global market crack with our realized crack spreads.

Our realized margin for the fourth quarter of 2012 was $13.67 per barrel, and this resulted in a market capture of 95%.

This is quite a bit higher than the 74% that we've achieved over the last four years.

At a high level, market capture in the fourth quarter was exceptional, as feedstock advantages, product differentials and volume gains largely offset the negative impacts associated with the lower-valued secondary products.

Let's walk through the details on the slide.

The $0.58 configuration adjustment reflects the fact that our clean product yield of 83% is less than the 100% assumed in the market crack.

The negative configuration impact was improved this quarter, largely due to our strong distillate production, coupled with healthy distillate prices.

The $5.64 per barrel reduction related to secondary products reflects the fact that these products attracted a sales price that, on average, were lower than the cost of our benchmark crudes.

The positive $3.69 per barrel adjustment for feedstocks stems from running certain crudes and other feedstock that are priced lower than our benchmark crudes.

For example, our feedstock advantage this quarter was primarily related to running foreign heavy sour crudes at our Gulf Coast refineries, and Canadian crudes in our refineries in the Central Corridor.

In addition, our crude slate has increased to include more shale crudes, primarily Bakken and Eagle.

Finally, the Other category primarily reflects the impacts of volume gain and product differentials.

Slide 12 shows the percentage of advantaged crude runs at our refineries, as well as clean product yields for 2011 and 2012.

Many of our refineries have the complexity to run price-advantaged Canadian, Bakken and Eagle Ford crudes.

Shale crudes are being run in all four of our refinery regions.

And in addition, we have access to multiple transportation systems to reliably deliver these crudes to our US refineries, providing an overall competitive advantage.

For the year, our US advantaged crude slate increased from 52% in 2011 to 62% this year; and for the month of December, this average was up to 70%.

We'll discuss Marketing, Specialties & Other, or MSO, on the next slide.

MSO generated adjusted earnings of $180 million, which is $38 million higher than the same quarter last year.

As shown on the slide, higher margins where the main driver for the increase, making up almost $90 million of the variance.

Margins improved primarily due to better market conditions and favorable inventory impacts this quarter.

Volumes decreased $26 million quarter over quarter, primarily due to reduced production at our Immingham power plant in the UK, as well as lower US marketing volumes, primarily due to lower demand.

Volumes were also lower due to downtime at the Borger Refinery.

Operating costs increased $20 million in the fourth quarter, primarily due to higher environmental and legal costs.

Slide 14 shows our per-barrel metrics.

Refining & Marketing's income per barrel increased this quarter to $4.12 per barrel versus $0.59 a barrel a year ago, with cash contributions of $5.00 per barrel, up $3.57 compared to the fourth quarter of last year.

For the year, R&M's income per barrel was $4.28, and this is up $1.95 compared to 2011.

This completes our review of the Refining & Marketing business segment.

Next we will move to the Midstream segment.

Our Midstream segment had lower equity earnings from DCP Midstream, largely driven by depressed NGL prices.

NGL prices were down 36% compared to last year.

Although down compared to 2011, return on capital employed for the year was still strong at 22%.

We ended the quarter with $1.3 billion in capital employed in our Midstream segment.

And as I said earlier, during the fourth quarter, we closed our investments in the Sand Hills and the Southern Hills pipelines that are being constructed by DCP Midstream, and these pipes are scheduled for startup this year.

Slide 16 shows that Midstream's adjusted earnings of $62 million includes $38 million in earnings associated with our interest in DCP Midstream and $24 million for our other Midstream businesses.

The next slide provides additional variance detail for both DCP Midstream and our other Midstream earnings.

As shown on the top portion of this slide, earnings associated with our interest in DCP decreased by $21 million this quarter, due primarily to lower NGL prices.

This was partially offset by a reduction in the depreciation expense that is tied to an overall increase in the remaining useful lives of DCP's assets that was implemented in the second quarter of this year.

Our other Midstream business was down $30 million, primarily driven by positive inventory impacts in 2011, along with higher taxes.

On the next slide, we will move on to a discussion of our Chemicals segment.

Our Chemicals segment had another solid quarter, providing earnings of $246 million.

Overall, CPChem achieved a 90% capacity utilization rate in its O&P segment in the fourth quarter.

This was down somewhat from the third quarter due to unplanned downtime at the Saudi Polymers petrochemicals facility.

If we exclude this downtime at SPCo, CPChem's utilization rate was near capacity for the quarter.

2012 return on capital employed from our Chemicals segment increased to 31%.

This is up from 28% last year, and we ended the quarter with $3.6 billion in capital employed.

As shown on slide 19, fourth-quarter earnings increased by $98 million compared to the same period last year.

This increase in earnings was primarily in olefins and polyolefins due to stronger chain margins.

The drivers for this increase was primarily from reduced feedstock costs due to higher industry ethane and propane inventories, as well as continued strong demand for ethylene derivatives.

Looking at CPChem's operating segments on the next slide, olefins and polyolefins generated earnings of $216 million in the fourth quarter.

This $97 million increase was due primarily from higher olefins/polyolefins chain margins, partially offset by higher operating costs.

In addition, quarter over quarter, marketed sales volumes in O&P were up 8%.

Specialties, Aromatics & Styrenics' earnings increased by 73% compared to the same period last year, primarily due to higher benzene earnings.

This concludes our discussion of the financial and operating results for the fourth quarter.

Next, I'd like to provide a few outlook items for the first quarter.

In Refining & Marketing, for the first quarter, we expect our global utilization rate to be in the low 90s and our pretax turnaround expense to be approximately $100 million.

In Midstream, we expect our additional direct investments in the Sand Hills and the Southern Hills pipelines to be approximately $120 million in the first quarter.

In Chemicals, although there was some initial unplanned downtime with Saudi Polymers' petrochemical complex, it is now up and running.

Under normal operations, we expect SPCo to return roughly $175 million to $225 million per year to CPChem, with our share being 50%.

Corporate & Other costs are expected to be about $40 million a month on an after-tax basis, or approximately $120 million for the quarter.

And this includes after-tax net interest expense of about $40 million.

As for the Company's effective tax rate, we expect the rate to be in the low 30%s for the quarter.

Regarding share repurchases, we plan to complete the initial $1 billion of repurchases in 2013 and initiate the second $1 billion tranche prior to the end of the year.

We will continue to keep you advised on the status of our repurchase program on quarterly earnings calls.

With regard to our recently announced MLP, we are still on track with our plans to file the S-1 with the SEC by early in the second quarter.

Finally, starting with the first-quarter earnings call, we will provide you with updates on our Optimize 66 initiative.

Recall that this initiative includes capturing $200 million in pretax cost savings compared to what the costs would have been without implementation of this initiative.

This concludes our guidance for the first quarter.

With that, we will now open the line for questions.

(Operator Instructions) Ed Westlake, Credit Suisse.

Good morning, and congratulations on a strong quarter.

I guess there is a lot of focus on all the crude that is coming down into the Gulf, and obviously, you've got three refineries down there.

Sweeney looks like well-positioned.

But can you comment on maybe two aspects?

One, what is, as you look at the market, the sort of incremental costs or any constraints on moving crude from, say, the bottom of Seaway to Lake Charles and then along to Alliance?

And then the second question is as we look at tanker rates that are rising rapidly for Jones Act ships, can you comment a little bit on how to secure low-cost shipping access from the Gulf up to Bayway?

Thank you.

Thanks, Ed.

Good morning.

Let me make a couple of generic comments, and then I will let Tim fill in some of the details around that.

So we've backed out all light sweet crude imports into the Gulf Coast.

One of the reasons we took the two Jones Act vessels is we thought that was an opportunity.

We wanted to move quickly.

There is a very few of those vessels that are available.

And with the idea of really taking Eagle Ford volumes from Corpus around to Alliance and coming through a loop system and then going on around to Bayway.

So that was the basic premise that we acquired those vessels for.

There is very few of those out there.

They are difficult to attain.

We think there is probably 32 or so vessels that are in service today that are available to do this.

Most of them are taken or chartered.

Tim, I don't know -- you want to fill in a little more color on that?

As far as -- Ed, as far as the crude movements along the Gulf Coast, still primarily for us it is Marine, particularly at this point.

The pipeline capacity going east is going to improve (inaudible), and you've got the rail facilities at St.

James.

But for us, the primary mode that we've used to increase the shale runs has been through marine movements, primarily out of South Texas to the three Gulf Coast refineries.

That's very helpful.

And than just a second question on the ethane crackers.

You've got some negative chatter just coming out of the Gulf on execution issues.

Are there any updates in terms of the cost studies that you've done for that cracker and potential timing?

I would say that we are on track for the cracker, Ed.

We will take FID this year yet on that facility.

We are continuing to prosecute the engineering of the long-lead items on that, for moving the permitting process forward.

So we will take FID on that.

So the costs, we will see as we finish up kind of our pre-engineering, if you will, on that, where they come in.

But we are still thinking it is around the $5 billion range.

We've talked a lot about we think if there is four to five grassroots crackers built, we are concerned about execution capability for the contracting community.

Are there enough welders, pipefitters, electricians, et cetera, to execute all these projects?

One of the reasons we want to be first in the queue is to get the jump on that and make sure that we get our pick of the very best people in the industry to execute the project for us.

Thanks very much.

And well done, again.

Kate Minyard, JPMorgan.

Thanks for taking my questions.

Just a quick question on the crude slate that you are running.

Can you talk about whether there are any practical or logistical limitations within the refining system to how much sweet versus how much heavy crude you can run, what your flexibility parameters are there?

Okay.

We can certainly do that, Kate.

Good morning.

Thanks.

We can run about 350 a day in the Gulf Coast of light sweet crude.

And we can push the limits of that.

At Sweeney, primarily a heavy refinery, we can run, I guess -- I don't know -- 60 a day of light sweet there.

We've looked at running all sweet at that facility, and we would have to derate the facility by about 20% or so.

We know what the investment is to correct that.

It's probably less than $50 million at Sweeney for us.

So we will look at that and watch that.

But as you think about the opportunity set, you can't take that as a generic across the entire refining system.

Because refineries are different, they are configured differently, and so that is just one specific example for Sweeney.

But without question, I think we're up to about 130 a day of shale type crudes that we've run.

It is primarily Eagle Ford, with some Bakken coming in.

And currently, as we start taking delivery of the 2000 railcars with the Global deal, we are going to move more Bakken east and west, primarily Bayway and our Ferndale refineries, as we try to accelerate the advantaged crude capture.

We think we have quite a bit of room left to run in terms of accelerating advantaged crude capture around our refineries.

Okay, and then just another question on exports.

When you look at the export opportunity and the growth in exports, are your exported volumes actually enabling you to capture higher prices than you would get in the domestic market?

Or is it simply the fact that you are able to -- is it a volume uplift?

And that is where the benefit from exports is coming from?

Or is it a mix of both?

Well, it's both.

It is really -- it's the volumes going to allow us to run higher operating rates, but we've made 47% more net income exporting this year than we did last year because prices were better in the international market.

So it is a combination of both.

Okay, all right.

Thanks very much.

Doug Terreson, ISI Group.

Good morning, and congratulations on great execution since the spinoff, everybody.

My first question involved the comments that Greg Maxwell made a few minutes ago about the impairment at Melaka, and specifically the part about higher oil prices being envisioned in the region.

Meaning was there some type of crude oil procurement arrangement that lapsed, or was it within the context of a margin outlook or did I miss here?

So could you just elaborate on or clarify what you talked about there, Greg?

Let me comment on that.

I look at it as really the fact that, A, demand in Asia is growing, so you are putting pressure on both the light and the medium grades, which fit that refinery in Melaka.

And then you've had some effects post-tsunami in Japan.

So our fundamental view is that the demand picture in Asia has lowered those differentials, narrowed those differentials and has brought that base crude price up.

So it is primarily a margin issue.

I see.

And Tim, the next question may be for you, too.

Product demand in North America and Europe was pretty poor last year, and it looks like there might have been a modest uptick during November and December.

Because you guys have facilities in both areas, I wanted to see if you would provide your insight into current product demand in the US and Europe, and whether or not you are seeing any improvement.

I would say that basically, demand is still lackluster, but it is certainly not completely gone.

Clearly, I think we still see flat to declining demand on gasoline distillate.

We expect to improve with the economy in North America.

Europe, still relatively weak, but based on our refining positions and the nature of our retail market in central Europe and our Humber refinery with its focus on specialty, we've really not seen that to be an issue for us.

Okay.

Thanks a lot.

Faisel Khan, Citigroup.

This is actually (inaudible) for Faisel Khan.

I've got a question on the Gulf Coast crude runs.

If you guys could just give us the color on as far as the light crudes were concerned, how much below LLS benchmark those were priced, the crudes that you ran on the Gulf Coast.

And same for the heavy versus Maya.

Thanks.

This is Tim again.

So basically, on the light crudes coming out of South Texas, I think we would plan on, say, $5.00 to $8.00 a barrel advantage.

We have seen LLS begin to move a bit as that supply has increased.

So we think that will continue to improve that crudes position in our slate as well.

On the light-heavy differential, that was favorable in this quarter, and we still think that provides substantial uplift versus the light, given our refining configuration.

Do you have an estimate on some of the other barrels that you are floating around?

At least in the fourth quarter, versus Maya, what the differential was on the heavy side?

I really haven't gotten too specific to that.

We do buy a variety of those crudes, and so we are able to capture some of that differential that we've seen.

There is limitations as to what we can disclose, given the confidentiality clauses (multiple speakers).

Sure.

I understand that.

Thank you.

Paul Sankey, Deutsche Bank.

I was just wondering further to your split and then the first analyst meeting you had as a new company.

Greg, what do you feel the market understood well about the Company from the analyst meeting, and what do you think that was kind of misunderstood from the message you were trying to convey?

Thanks.

Thanks, Paul.

Well, we were pleased with the first analyst meeting, in general.

I think we were consistent with what we've been communicating to the market in terms of our strategy around improving our returns, growing our higher-returning, faster-growing businesses in Midstream and Chemicals, and really laying out a plan and strategy to improve the base returns of the Refining business through advantaged crude capture, reducing costs, driving yields, and ultimately a 400 basis point improvement in Refining.

So I think if there was a disappointment that day, it may have been around the MLP announcement and the fact that we couldn't talk about it as much as we would have liked to, or probably as much as you would have liked for us to do.

But we just reiterate, we think that is a value-creating proposition for Phillips 66 shareholders, and we will continue to prosecute that this year, and we plan to get it done this year.

I think the number was kind of the $700 million of EBITDA that would be associated with that business, whether or not that was at the high end of the range, low end of the range or a reasonable number.

I think we've said that we really can't say a whole lot about the EBITDA that we would consider putting in MLP until we get the S-1 filed.

So just have to be patient on that one.

I totally understand.

You've got some stuff on NGLs -- on NGL pricing being so weak.

Can you talk about -- I know you have great sensitivities and stuff, but can you just remind us again, firstly, the sensitivities now and how they impact you positively or negatively?

And secondly of how you expect that to change over time.

That's it.

First of all, sensitivity, $0.01 a gallon in NGL price is about $4 million of net income back to us.

So as you think across the Midstream space, the Chemicals space, we are a net buyer of NGLs, and so we are capturing that value in the Chemicals space.

Long term, we think that fundamentally the Midstream business is a good place to invest.

We've got aggressive growth plans in there.

I do think that we are going to be in for a period of volatile pricing in NGLs for the next four or five years until the petrochemical facilities come up, until the export facilities get billed for the propane/butane and heaviers, essentially.

So I think you've got this period of time that the demand side needs to kind of catch up with the supply side in the Midstream space, Paul.

But I think the other thing you have to think about, too, is what you're starting to see is, because of the investment, because of the need to clear these new basins, that a lot of the new investment is really evolving and moving to more fee-based type contracts around this infrastructure.

So you are -- what you're going to see is a reduced sensitivity longer term in the Midstream space as there is more fee-based assets put in service.

Yes, that was kind of what I was driving at.

So is there any way you can quantify how that might shift your sensitivity and in what specific timeframe?

Because obviously, if you are talking about only four to five years of oversupply, it is kind of a worrying outlook.

You would expect the sensitivity to fall over time in Midstream.

But in the Chemicals side, it actually goes the other way as we increase the amount of ethane that we run.

Right, I was just trying to be more specific.

I was wondering if there was some sort of idea of how much was fee-based and everything else and how it would shift over time, and the percent to which it would go down.

I think we talked about DCP having 70% of its contracts on a POP basis historically, and we are shifting that to 40%.

So if you look at the new pipes we are building, whether it is Sand Hills or Southern Hills or some of the other projects that we are considering, as Greg said, those are fee-based.

So we won't have the exposure there.

And traditionally, I guess, the gathering and processing business will be a POP type, but that will be a smaller percentage of the total business.

So whether or not that sensitivity is 50% of what it is today five years from now or --.

It's a good question, but ultimately NGL prices are going to recover, is our view.

And so I think you are going to still have a good mix of what I would call risk to commodity exposure in your natural gas and your NGL prices.

And then the (multiple speakers) I can't answer where it is exactly going, Paul, and we(multiple speakers) give guidance around that.

(Operator Instructions) Jeff Dietert, Simmons Inc.

You talked about product exports in your press release and having current capacity at 285,000 barrels a day, going up to 370,000 by the end of the year.

Could you talk about your fourth-quarter product exports, what you were actually exporting in the fourth quarter, and maybe how that compares to the fourth quarter the previous year?

In the fourth quarter we were impacted a little bit with some of the hurricane effects, but overall, exports were up to 180,000 in December, and on average for the year we were up slightly.

So I see that as probably a growing area for us.

I think December reflects what we will see as the trend, and I think the pricing incentives are there and certainly the run rate incentive is there.

Good.

You talked about, I guess that's an incremental increase in export capacity of about 85,000 barrels a day, and you talked about 20,000 of that being at Ferndale.

The other 65,000 barrels a day, where do you see the opportunity for incremental exports?

So really we still look at the Gulf Coast as really the region where we would see the logical place for exports, given proximity to markets and the access.

So the West Coast is going to be more incremental for us, but the primary bulk of that change will come in our three Gulf Coast refineries.

Okay, good, good.

Switching the topic to Sweeney, I guess your historical relationship with Seaway, I assume there is good access there.

Should we think about Sweeney feedstock making a step function improvement with this incremental phase of Seaway coming online in the first quarter of 2013?

Today, Sweeney on our light unit, we are running shale crudes today.

And so then it is just about a question of which particular grades make the most sense from the refinery.

So I actually think Sweeney is in really good shape, and then it really depends upon the economic substitution that we would have for the heavier piece of the unit.

So you are right, Sweeney is in a great location only from Seaway.

But if you think about it, very good access to South Texas crudes particularly Eagle Ford crudes.

And that is where the emphasis has been to this point.

Thank you.

Evan Calio, Morgan Stanley.

You know that you are backing out light sweet crude in the fourth quarter in the Gulf Coast, and I guess it's only a matter of time for the Gulf Coast industry, and making various Midstream investments around that.

Are you considering any condensate splitter or hardware investment versus Midstream to take advantage of the that growing and impending glut of light crude?

And then somewhat related, do you see your ship assess competing with rail, providing you just more optionality to the East Coast?

Or do you see a high utilization or kind of purpose for kind of both of what I would say are kind of more release valve assets?

I'd take it in reverse order.

We like the flexibility of rail and ship to move.

Clearly, we think there is a cost advantage in moving marine versus rail.

But the opportunity to acquire the Jones Act vessels is limited.

So that is one of the reasons we moved quickly on these two ships that we took.

So -- and yes, we would consider an investment.

I think that we would want to see where the spreads really go, where LLS really ends up.

We are still kind of quoting $2.00 to $3.00 a barrel diffential on LLS.

It is not a big investment for us, but frankly, we still have higher-returning projects we think we can invest in.

But we wouldn't hesitate to make that investment if the economics warranted it.

But we've got a lot of -- I would say, small, quick-hit type investments we can do in refining that are 30% and 40% return projects that you will see us do that help push yields, drive costs down and improve access.

So you will see us do those things, but we are not in a big hurry to make an investment in condensate splitter.

We still have additional capacity to penetrate without that, so that is our first priority.

And then as we get beyond that point, that is when I think you begin to think about do we need to do something else on the process side.

Maybe shift gears to some of those other projects on the Chemicals side.

A few questions.

Maybe you could help me with potential EBITDA uplift based on assumed margin levels from Sweeney fractionation expansion this year.

And secondly, help me understand better maybe this normal alpha olefins expansion project at Cedar Bayou.

It's less clear to me how to kind of evaluate the potential impact there.

This is Tim.

A couple comments.

On the Sweeney fracture, that is a debottleneck.

And the real value comes from increased volume throughput at the fractionation that feeds the cracking complex there.

But probably more importantly, it allows more ethane into the mix and so you capture value.

That is -- it is a relatively modest project in terms of capital of $100 million, and I would expect returns well above 20% on that.

So incrementally, it is a very attractive project; it is just not the same scale as you expect with a cracker.

So it makes a lot of sense.

On the NAO, the project there, if you think about it, we've got the 1-hexene that CPChem has announced that is separate from that announcement.

That is a 250,000-ton increment.

And what they are looking at NAO is a debottlenecking expansion of the existing NAO unit there at Cedar Bayou, as well.

So again, not a major new derivatives complex, but really debottlenecking what is there on the NAO side.

So similar -- I would expect that to be similar to what we talked about with the frac.

Similar size investment, you mean?

Yes, and that is all very preliminary, so I think it is very early in that stage.

But it is -- again, it is a relatively modest increase versus a major new plant.

Maybe lastly, if I could sneak one more in, just on rail to kind of get back -- take me back to maybe refining.

I know you have 2000 railcars layering in, number one.

What is -- how should we think about the delivery of that rail fleet?

Are they all general purpose and a heated coil?

And how do you think about -- in this kind of rail gold rush really, how do you consider transloading investments around your system to drive optionality?

Or is this primarily at this juncture a Bakken -- East Coast Bakken transit?

Thanks.

It's a great question.

These are general purpose cars, although I will say that we are looking at coiled tube cars to move Canadian heavy down to the West Coast, in addition to this.

So as you think about this, it was originally envisioned as a Bakken play to go east and west, without question.

Where we are investing in infrastructure is at our refineries for unloading, if you will.

And we are using third-party access in the Bakken itself.

I don't think we see the need to invest in terms of loading facilities in the Bakken at this point in time.

And frankly, the nice thing about the railcars is they can move over time as the opportunity moves.

But our view is that the next five-year window, Bakken crudes will probably move a lot of it by rail going east and west.

I agree.

What do you think the permitting track is for California rail?

The views is that that is going to take a long time (multiple speakers).

I wished I knew the answer to that one.

I think we are pushing it.

I think there is some resistance, given the heavy nature of the crudes and the carbon footprint of the crudes and AB 32 carbon cap and trade, et cetera, et cetara in California.

But I think it is an opportunity that certainly is worth exploring.

Great.

Appreciate (inaudible).

Thanks.

Doug Leggate, Bank of America.

A follow-up, I guess, on a couple of the questions that have been asked, particularly on the west coast, or the Western Pacific, to be more exact.

If you look at your earnings now that full-year is in, last year you did about $84 million adjusted versus $2.5 billion for the whole system.

This year, it looks about $300 million and $5.2 billion for the whole system.

I'm just kind of curious as to strategically how you are thinking about that part of your business on a go-forward basis, given that it seems to be somewhat challenged relative to everything else that is going on in the portfolio.

That is my first question, and I have a follow-up, please.

The West Coast, we talked about Melaka, so I think we've kind of answer the Melaka piece of it from the Pacific standpoint.

It is not strategic for us, non-core asset.

California is a challenged place to operate.

It is a high-cost environment.

There is a lot of things coming at us in California.

It is net income positive.

It is cash positive.

It is single-digit returns.

And so it doesn't fit the return profile that we see long-term in the business.

So what are we doing?

We are doing everything we can to improve it.

So this is looking at our costs, it's looking at our configuration, it is looking at how do we get advantaged crudes into these refineries to improve.

And at the same time, I would say we are studying all options for California in terms of where do we go long-term with the California asset.

I don't feel it is a distressed asset.

I don't think we have to move tomorrow on it.

I also think that we want to take our time and be thoughtful and make sure that whatever we do in California creates value for Phillips 66 shareholders.

Thanks for that.

My follow-up is actually a related question.

Not to try and predict what happens next, but could you help us understand what kind of inventory you have tied up across those two parts of the portfolio, I guess, Melaka and the West Coast?

And maybe there has been a little bit of chatter about at some point in the next few years, you might see some accounting changes as it relates to the accounting for -- LIFO accounting for inventory.

What kind of cash tax liability might you have or what kind of cash could be released from inventory if you decided to go down a monetization route?

I'll leave it there.

Thanks.

We watch this from an inventory perspective, and look at the different pieces of legislation that are coming out.

From a replacement cost perspective, over and above what we have recorded on our books on an inventory level basis, it is about -- runs about $7.5 billion to $8 billion.

And so one of the things that we saw on the legislation that that would be paid over a 10-year period is the latest we have seen on it.

So basically, you could look at the gain on that, divide by 10 times 35% to sort of give you a rough estimate of what the cash taxes would be on an annual basis.

And if you chose to monetize your inventory in that system, can you quantify what that would be?

Are you talking about just California?

(multiple speakers)

I'm sorry, Doug.

I'm talking about the entire system.

I don't think I have (multiple speakers).

Sure, sure.

But I'm trying to think more of what kind of value would be released if, for example, you decided to go down a monetization route on those assets.

I guess if you are looking for kind of a broad number, we would say 20% of it.

Yes.

Terrific.

That sounds great, guys.

Thank you.

(Operator Instructions) Blake Fernandez, Howard Weil.

Good morning.

Congratulations on the results.

I had a question for you on debt.

Obviously, it was reduced by about $1 billion this quarter.

As I understood it, a large portion of the debt balance actually contained a fairly low interest rate, and that was one of the things I think at the initial analyst dinner we had up in New York, you were grappling with, Greg, as far as do you pay that down or how do you manage to balance sheet going forward.

I'm just curious from here, is your bias to kind of leave the debt levels where they are and just distribute the remaining amount to shareholders, or maybe just build additional cash, or any thoughts there?

Appreciate it.

Thanks for the question.

So we said at the analyst day that we were going to pay down $2 billion of the debt, so we were going to go from $8 billion to $6 billion.

That takes us to about a 20%, which is at the lower end of the range.

That is still the plan, is to pay down another $1 billion of the debt.

There is no question it is very attractive financing.

But as we look -- I always like to remind people this was, it is, it always will be a volatile business.

And that is life in a commodity business.

And we accept that.

We think that -- we are comfortable operating in that space.

But I think you want to have a balance sheet that supports that.

So it reduces risk for the Company.

In our view, it creates capacity.

We are not going to hesitate to lever back up if we have to to continue our plans or pay dividends or do the things that we need to do.

But no question -- our view is that the next couple years, midcycle margins are going to be above historical midcycle margins.

I think we are going to have cash optionality.

So I think you will see us, one, pay a dividend, continue to increase that dividend.

You will see us then use excess cash to take in shares.

And we aren't going to take specials off the table.

Great, thanks.

And the second one was really more, I guess, big-picture, capital-allocation oriented.

But as I look at the return on capital employed in your slides, it looks like the R&M numbers moved up to 22%, which is equivalent to what you're getting in the Midstream.

I guess as you make decisions on allocating capital going forward, as I understood it, R&M was really going to be one of the smaller pieces of the portfolio going forward.

I'm just curious, does this blowout in returns in the downstream kind of change that theory going forward?

My view is that refining historically has been kind of a 10% to 12% business, let's say.

We think we Pam plans in place through advantaged crude capture yields, cost reduction, that we can move it 400 basis points.

So it is a 15% business going forward for us, versus a 30% return business in Chemicals.

And probably Midstream business, 15% to 17% returns is kind of what we are looking at that.

So to the extent that we have 30% and 40% return projects in Refining, we are going to do those.

I think that -- we do get challenged by people all the time -- are we underinvesting in Refining.

At this point, we don't think so.

I don't think there is any opportunities out there we feel that we've missed in terms of an investment opportunity in the Refining space.

Our focus is going to be very disciplined.

We are going to restrict capital in the space.

We're going to improve returns in the space.

So we don't see a change required in our strategy at this point in time.

Okay.

Fair enough.

Thank you.

We have no further questions at this time.

Do you have any closing remarks?

Great.

Thanks.

We appreciate the interest in the Company and the questions.

If there are follow-up questions, obviously, Rosy and I are available to handle those.

And you can find this information and a transcript of the call on our website in the near future.

Thank you very much.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.