菲利普斯66 (PSX) 2013 Q1 法說會逐字稿

Welcome to the first-quarter 2013 Phillips 66 earnings conference call.

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

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

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

Please note that this conference is being recorded.

I would now like to turn the call over to Clayton Reasor, Senior Vice President of Investor Relations, Strategies, and Corporate Affairs.

Please go ahead.

Thank you.

Good morning.

Welcome to Phillips 66 first-quarter earnings conference call.

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

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

Slide 2 contains our Safe Harbor Statement.

It's a reminder that we'll be making forward-looking statements during the presentation, and our question-and-answer session.

Actual results may differ materially from today's comments, and factors that could cause actual results to differ are included here on the second page of this presentation, as well as in our filings with the SEC.

Also, you may know that on March 27, a registration statement relating to the securities of Phillips 66 Partners LP, was filed with the SEC.

As this statement has not become effective, our remarks about the MLP will be limited, and we will not take questions on this proposed offering during today's call.

That said, I'll turn the call over to Greg Garland for some opening remarks.

Greg?

Thanks, Clayton.

Good morning, everyone.

Thank you for joining us today.

It's hard to believe that just a year ago that we launched Phillips 66 as an independent company.

We're pleased with our performance to date.

We're a new company, but we're built on 130 years of experience.

We have a portfolio of businesses that is uniquely positioned to benefit from the significant growth in American oil, gas, and natural gas liquids production.

First-quarter 2013, we operated safely.

Our financial results reflect the fact that we captured positive market conditions in our Refining and Chemicals businesses.

Operating excellence continues to be our top priority.

We aspire to be a company where employees work their entire careers without getting hurt.

In the first quarter, we continued our improvement in our safety and environmental performance.

We continue to pursue growth in high-value businesses, while maintaining our capital discipline.

Our plans for a new natural gas liquids fractionator in the Gulf Coast region demonstrate the investment opportunities we have in the American energy landscape, as well as highlight our unique position across the downstream value chain.

The plans DCP has announced are an additional important source of growth within our Midstream segment.

Sand Hills and Southern Hills Pipelines will deliver NGLs to the growing Gulf Coast markets -- are expected to be fully in service by mid-2013.

CPChem continues to advance its Gulf Coast ethane cracker and polyethylene facilities.

Once complete, these facilities are estimated to create about 400 long-term direct jobs, and about 10,000 temporary engineering and construction jobs.

Growth in our Chemicals segment also comes from an NGL frac expansion at Sweeny, our 1-hexene project, and our Saudi Polymers project.

Ultimately, the growth in capacity allows for growth of dividends and share repurchases.

Shareholder distributions remain a priority for our Company.

During the quarter, we paid an increased dividend, and we repurchased $382 million of stock as part of our $2 billion share repurchase program.

Since the Company's inception a year ago, we have returned $1.2 billion of capital to our shareholders through dividends and share repurchases.

We have a diverse portfolio that provides us earnings durability, as well as a balance sheet that gives us financial flexibility.

These are two very important traits that are needed in our industry to be well-positioned to weather the cyclicality that's inherent in our business, and to continue to grow shareholder distributions and value through the cycles.

With that said, I'll hand the call over to Greg Maxwell to take you through the quarter results.

Thanks, Greg.

Good morning, everyone.

We had a very solid first quarter, driven by strong Refining and Chemical margins.

Reported and adjusted earnings both came in at the $1.4 billion level, with earnings per share at $2.23 on a reported basis, and adjusted earnings per share at $2.19.

Excluding changes in working capital, cash from operations for the quarter was $1.8 billion.

Our cash flow generation enabled us to fund our capital program, pay $194 million in dividends, and repurchase $382 million of common stock during the quarter.

On an adjusted basis, our annualized 2013 return on capital employed was 20%.

Before we leave this slide, I'd like to mention one key item.

As outlined in our earnings release, we've made a few changes to how we report our operating segments.

This is in response to changes in our internal reporting processes, and is designed to increase transparency, and ensure better alignment with how we think about, operate, and manage our business.

We are moving from having four segments to five, with our Refining and Marketing segment being split into two new operating segments -- Refining, standing on its own, and Marketing and Specialties.

In addition, a portion of our transportation assets that were previously reported in our Refining and Marketing segment have been separated, and are being reported as a part of Midstream.

Our slides reflect this new segmentation, and prior-year numbers have been recast for comparative purposes.

In addition, the quarterly information for 2012 has been recast, and is included in our supplemental pages provided with the earnings release.

Full-year 2009 and 2010, as well as quarterly 2011 recast numbers will be available later in the second quarter, and will be posted to our website.

Slide 5 provides a look at our first-quarter adjusted earnings.

Compared to the first quarter of 2012, adjusted earnings increased by over $600 million to $1.4 billion.

Midstream adjusted earnings were $83 million, and this excludes a $27 million gain from the issuance of additional limited partner units by DCP Midstream Partners, which is DCP's MLP.

The majority of the $25 million decline in earnings is driven primarily by lower NGL prices.

Chemicals earnings were $282 million.

This is up $65 million, mainly due to higher margins, especially in olefins and polyolefins.

Refining generated over $900 million in adjusted earnings, and the $455 million increase was mainly due to stronger margins that benefited from higher market spreads for distillates and gasoline, along with improved feedstock advantage.

Marketing and Specialties had adjusted earnings of $202 million, an improvement of nearly $150 million over last year.

Higher margins were responsible for most of this improvement.

And finally, corporate and other costs this quarter were $95 million, and this is $25 million higher, largely due to interest expense on debt taken on in 2012 related to the separation.

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

Moving next to our first-quarter cash flow, during the quarter we generated $1.8 billion in cash from operations, excluding working capital changes.

Changes in working capital were a positive impact of $400 million, with the net change primarily due to the timing of tax payments.

We funded about $400 million in capital expenditures and investments, and during the quarter, we returned $576 million to the shareholders in the form of dividends and share repurchases.

We ended the quarter with cash and cash equivalents of $4.8 billion.

As for our capital structure, on Slide 7, at quarter end we had equity of $21 billion and our debt was at $7 billion, resulting in our debt-to-capital ratio remaining in the middle of our targeted range of 20% to 30%.

Taking into account our $4.8 billion ending cash balance, our net debt-to-capital ratio was 9% at the end of the first quarter.

Next, we'll cover each of our operating segments in more detail, starting with Midstream on Slide 8. As mentioned earlier, the Midstream segment now includes our transportation assets, in addition to our equity interest in DCP Midstream and our NGL operations.

The transportation business includes pipelines, terminals, rail cars, and trucks that were previously embedded as a part of our R&M segment.

The annualized return on capital employed for Midstream was 11% based on an average capital employed of $3.1 billion.

Slide 9 shows Midstream's adjusted earnings of $83 million, along with the variances from the prior year for the three main business lines.

Adjusted earnings from DCP Midstream decreased by $31 million this quarter, primarily due to lower NGL prices, and to a lesser degree, reduced volumes.

NGL prices continue to be challenged, down 26% compared to the first quarter of 2012.

The volume decrease was in part due to mechanical, and also to weather-related issues.

NGL operation's earnings were down $10 million, partly due to inventory impacts from exiting the wholesale propane marketing business that occurred during the first quarter of 2013.

Transportation was up $16 million, mainly due to new and increased throughput fees, as we started converting our pipelines to market rates.

Additional information on the transportation business line can be found in the Midstream section of our reporting supplement.

On the next slide, we'll move to a discussion of our Chemicals segment.

Our Chemicals segment had another solid quarter.

The olefins and polyolefins business continued to benefit from strong margins.

The capacity utilization rate this quarter for O&P was 91%, and it was negatively impacted by the power outage at the Sweeny facility and the continuing ramp up of operations of the Saudi Polymers Company joint venture.

In Specialties, Aromatics, and Styrenics, benzene margins improved.

However, this was mostly offset by additional turnarounds during the quarter.

The annualized return on capital employed for our Chemicals segment was 31%, and this is based on an average capital employed of $3.6 billion.

As shown on Slide 11, first-quarter earnings increased by $65 million compared to the same period last year.

The increase in earnings was primarily in olefins and polyolefins, due to stronger margins, as well as higher equity earnings from CPChem's Middle Eastern joint ventures.

This increase was slightly offset by higher costs, partly due to the power outage at the Sweeny facility during the first quarter.

As mentioned earlier, Specialties, Aromatics, and Styrenics earnings were flat compared with last year.

The improvement of $12 million noted in corporate and other is due to lower SG&A costs, along with reduced interest expense as a result of CPChem's debt retirements in 2012.

As we move next to refining, our realized margin was $13.94 per barrel, with a global crude utilization rate of 90%, and a clean product yield of 84%.

Our utilization rate this quarter was negatively impacted by turnarounds at the Sweeny and Wood River refineries, as well as the power outage at Sweeny.

We increased our advantaged crude slate in the US during the quarter to 68%, and this is up from 60% in the first quarter of 2012.

The annualized return on capital employed for the refining segment was 25%, with an average capital employed for the segment of $14.3 billion.

Slide 13 provides more detail on earnings in our Refining segment.

Adjusted earnings for Refining were $909 million this quarter.

This is up $455 million from a year ago, reflecting improvements in all of our regions, especially in the Central Corridor and the Gulf Coast.

The earnings of all four of our refining regions increased, and in total, this was primarily due to improved refining margins.

The improvement in refining margins reflects not only higher market crack spreads, but also positive feedstock advantage.

Atlantic Basin/Europe reflects improved margins due to higher market cracks, and also feedstock advantage at our Bayway refinery, as we increased our effort to run more Bakken crude in place of Brent.

Gulf Coast improved as we achieved 114% market capture rate, up from 77% in the first quarter of last year.

Central Corridor reflects higher market cracks, and wider Canadian crude differentials, as well as benefits from running additional low-cost domestic crudes in our Wood River, Borger, Ponca City, and Billings refineries.

Western Pacific's improvement of $61 million over last year is largely due to the fact that the first quarter of 2012 was a heavy turnaround period for our West Coast refineries.

Ferndale, Los Angeles and San Francisco all had turnarounds in the first quarter of 2012.

Finally, other refining was up this quarter compared to last year, primarily as a result of margin improvements on movements of Western Canadian crude that was in excess of our refinery needs.

Let's now take a look at our market capture, shown on Slide 14.

Here, we compare the weighted average market 3-2-1 margin against the actual margin we captured, along with the factors that drove the differences between them.

The realized margin for the first quarter of 2013 was $13.94 per barrel, and this is our best first-quarter realized refining margin in recent history.

Market capture for the quarter was 90%, down from our fourth-quarter high of 97%, but well above the 81% utilization achieved in the first quarter of 2012.

Market capture in the first quarter was strong, as feedstock advantage, product differential impacts and volume gains more than offset the negative impacts associated with lower-price secondary products.

Slide 15 shows the comparison of advantaged crude runs at our refineries, as well as clean product yields for 2011, 2012 and year-to-date 2013.

In the US, advantaged crudes increased from 62% in 2012 to 68% in 2013.

The decrease in other heavy crude from 27% in 2012 to 23% for the first quarter of 2013 was largely due to our Sweeny refinery being down during part of the first quarter.

As shown on the graph to the right, we continue to focus on improving our clean product yields, achieving an overall 84% yield across our refining system this quarter.

This next slide covers Marketing and Specialties, or M&S.

M&S includes Phillips 66's wholesale and retail fuel marketing, as well as our lubricants, power generation and flow improver businesses.

In Marketing and other, worldwide marketing margins improved to $0.03 per gallon in the first quarter.

This is up from $0.01 per gallon in the first quarter of 2012.

In Specialties, compared to last year, our flow improver sales increased by 16% on a volume basis.

The annualized return on capital employed for M&S was 22%, and the average capital employed was $3.7 billion.

Slide 17 provides some additional detail about the Marketing and Specialties segment.

M&S generated adjusted earnings of $202 million.

This is $147 million higher than the same quarter last year.

Marketing and other's adjusted earnings increased over $150 million, largely due to improved margins over the prior year.

Both US and international marketing margins contributed to this increase, with the US representing approximately 75% of this improvement.

For Specialties, the $6 million decrease over last year was mainly attributed to inventory impacts.

This concludes my discussion of the financial and operational results for the quarter.

I'll now cover a few outlook items before handing the call over to Tim Taylor for some closing remarks.

In Refining, for the second quarter, we expect our global utilization rate to be in the high-90%s.

With regard to turnarounds, our pretax turnaround expense is expected to be approximately $90 million in the second quarter.

Corporate and other costs are expected to be approximately $105 million after tax for the quarter, and the total Company's effective income tax rate is expected to be in the low-30%s.

Now, I'll turn the call over to Tim.

Thank you, Greg.

I'd like to take a couple of minutes to review our expectations for the remainder of 2013.

We continue to focus on growth and returns enhancements centered on opportunities created by the rise of oil and gas production in North America.

In our Midstream business, we're pursuing development of a 100,000-barrel-per-day NGL fractionator to be located in the Gulf Coast region, and this project would enable us to take advantage of existing Midstream transportation and storage infrastructure.

We see excellent market-facing opportunities to grow the NGL business, and the chance to supply purity NGLs and liquefied petroleum gas to the petrochemical industry, as well as heating markets.

If approved, we would expect construction to start in the first half of 2014, with operations commencing in the second half of 2015.

Our 2013 budgeted capital expenditures and investments are currently expected to be about $1.9 billion, of which $1 billion is dedicated for maintenance capital.

As we've said before, we see this level set right around our DD&A amount going forward.

Included in our maintenance capital are our capital requirements for Tier 3 implementation.

During the quarter, we funded nearly $400 million of our capital program, and nearly $800 million, if you include our portion of our major joint venture expenditures.

This capital was spent mainly on the growth plans that we've outlined before, where we're expanding our higher-valued businesses.

As Greg said in his opening remarks, we're in a cyclical business, and we're well-positioned to capture opportunities caused by both short-term price dislocations, as well as medium- and long-term fundamentals.

The Brent WTI differential will be dynamic, as infrastructure progresses and trade flows adjust over the coming months, and we expect LLS to move back to a discount versus Brent.

Although we may see some narrowing of crude differentials as takeaway capacity is built, we still have an advantaged position.

With seven coastal refineries, three each on the Gulf and the West Coast, and one on the East Coast, we're well-positioned to grow product exports.

And this past quarter, we exported an average of 150,000 barrels a day of refined products, which is a significant increase over last year.

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

(Operator Instructions)

Our first question comes from Ed Westlake from Credit Suisse.

Good morning.

Congratulations on the results.

Thanks for all the disclosure.

It's going to keep me up tonight.

My wife is going to be happy that I'm inside an Excel spreadsheet.

Let's start off with questions around that disclosure.

Just on the Midstream, you've broken it out and you said you transferred all the assets in there.

You've got $175 million in the first quarter of earnings before tax.

You've got around $19 million of DD&A, but there will be some see-through DD&A, the way I think about it, at least in DCP Midstream, which doesn't come through, say, another $40 million.

You get to over, maybe call it, $230 million of EBITDA see-through for that division for the quarter, implying around $900 million to $1 billion for the year.

Is that a fair way to think about the overall Midstream EBITDA at PSX?

Yes, I think, Ed, you're correct.

When we look at that, we think that's about what the combined results, about the right amount of EBITDA for that segment.

Right, okay.

Thanks.

Just walking through some math there.

And then a totally separate topic.

RINs.

It's come up obviously on every conference call.

Where do you see the exposure, if you assumed the current RIN price persisted into next year or into this year?

Do you have a dollar million assessment at this point?

Thanks.

Ed, this is Tim.

I'll start with that.

I think that, when I think about RINs, to me, it's obviously a cost that impacts the way we go to market and our sales channel.

And so I think fundamentally, we've managed that through our commercial business.

We have a lot of options.

We've taken a lot of actions to increase blending on biodiesel, at our terminals, et cetera, to mitigate that.

That said, when you look out with the blend wall going forward, you realize that that's still an issue yet to be addressed.

It has to be addressed really from a macro standpoint.

But to this point, we find that manageable and it does affect our planning but I think that the real issue really starts to surface in 2014 with the additional requirements and the need for advanced cellulosics that just aren't there.

If I could push you a little, obviously Valero has given numbers where they bracketed around a range of $500 million to $750 million, from memory.

Is there a number you feel comfortable sharing, if and then basically persisting market conditions from here to the end of the year?

Yes, this is Greg.

I would say first of all, as we look out, we think it's just an unworkable program.

And we've seen this coming since 2007 and we've been trying to position ourselves for this.

I think the industry's working hard on solutions in Washington.

But that said, we're trading RINs and like any other commercial activity, we really don't want to expose our positions because we think it puts our traders at a disadvantage.

But I will say, our view is that the industry, and particularly us, we believe we're capturing most of the cost of the RINs in the market today.

Our next question comes from Evan Calio from Morgan Stanley.

Hey, good morning, guys.

Your disclosure is definitely helpful.

First question.

One of the two areas where your differentiated growth profile in the Midstream and you mentioned sandhills and southern hills are set to ramp in mid 2013 which is pretty soon with aggregate 375,000 barrels a day of y-grade capacity into Mont Belvieu.

Can you discuss, are your planning on taking some of those post fractionated volumes at your facilities and displacing third-party purchases?

How do you see the demand for these volumes and how's it work in your system?

Yes, a lot of the volumes, or 70% of the volumes, are DCP-controlled volumes, and the balance is third-party volumes on Sand Hills.

We don't see that displacing any of the internal volumes that we have.

As we go to market with those volumes, as you know, DCP is a large supplier to CPChem and we like that relationship and we see that relationship continuing, going forward.

We look at those projects on stand-alone basis.

We think we've got good value capture.

We think we get the assets loaded over some period of time, but relatively quickly, and those are going to be good, solid assets for us.

That's great.

Shifting gears into Chemicals, Saudi Polymers facility continues to ramp.

Should we expect full contribution in the third quarter?

And I guess I'm trying to assess where you are in that 10% to 15% earnings lift once the plant is fully ramped.

I think we talked on the last call that working through operational problems, that it's running much better this past quarter.

So that continues to progress.

Our view is that, yes, in the second half of this year, you'll really start to see the impact from the Saudi Polymers plant startup.

Right.

Maybe last one if I could, I know you gave global utilization in O&P at 91% and you mentioned that the US is affected by downtime at Sweeny.

Can you give us a US rate and where we think that might normalize?

Yes, looks like this last quarter, 96%.

Our view is ethylene unit rates, up 95% to 100%.

That's pretty much on a sustained basis running flat out so I think on the US side that really we would expect that to run at capacity in that 95% to 100% range.

And where did you run them in the first quarter?

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

Great.

Appreciate it, guys.

Our next question comes from Jeff Dietert from Simmons.

Good morning.

In the press release this morning, you mentioned that you took delivery of 400 rail cars.

I believe that's out of 2,000 expected.

Are these general purpose rail cars or coil tubes?

And could you talk about how you plan to deploy these cars and where the greatest opportunities are in the current market?

They are general purpose cars.

This is an order we placed shortly after we formed as the new company, and we expect to get the 2,000 cars rateably over the balance of this year.

I think the plan really hasn't changed for us.

It was primarily envisioned to be Bakken East and West, and I think our view is that we'll continue to do that.

On a second topic, quarter to date, many of the regional cracks are down sequentially and most are down year-on-year.

Some of the crude differentials have softened a bit.

Perhaps they're bringing in some incremental imports, opening the arb for Gulf Coast imports.

What do you think the major drivers of the softness in cracks are and do you expect this weakness to continue into the summer?

So on the crack spread, I think you've got both at work, you've had some market fundamentals on the product side that have continued.

First quarter's typically not the strongest and second quarter should see some seasonal uplift on the product side.

Really, I think what's moving around are the crude diffs.

You look at the first quarter, they've come in, and you looked recently, started to see some widen back out.

I think our fundamental view is that the fundamentals haven't changed, that we still see the discounts with inland crudes.

We still see the Canadian discounts.

We do believe, though, that it'll remain volatile and that we wouldn't be surprised to see those come back out a bit from where they've been in the last month.

It may not be as high as what we saw or as much volatility as last year.

But we still believe those [diffs] on the Canadian and inland crudes are very sustainable and I think we're in a period of readjustment here in the Gulf Coast, as those crudes make their way into Texas and then ultimately find their way into the rest of the refining system on the Gulf Coast.

Thank you.

Our next question comes from our Arjun Murti from Goldman Sachs.

Thank you, and I guess my thanks as well for the disclosure and had a question as well on it.

On the transportation segment, I appreciate your breaking that out.

It looks like last year on a full year basis, you had just over $250 million of EBITDA.

If we annualize the first quarter, you're over $360 million.

Is the delta there, just taking some of the tariff to a market-based tariff from an internal cost accounting?

And then, could you also discuss what may or may not be included in that transport segment?

I'm pretty sure it does not include all your, what we might call, logistics assets, but if you have any color there, that'd be great.

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

So you probably need to add those back in if you want to get a more reasonable number.

But you've got, what, $170 million in the second quarter, $160 million, so what is that?

$300 million, $330 million of earnings you probably need to add back.

I don't know, Greg, if you want to --

From an asset perspective, Arjun, I think was your other question some of the, what you would consider, storage tanks and pipes that are inside the refinery gates are still aligned with the Refining segment.

We're continuing to look at that, but you can imagine that they're a little bit more integrated from an asset basis in that refinery aspect.

We're looking at that, but a lot of the storage and pipes inside the refinery gates are still being reported in the Refining segment.

Got it.

So, yes, those storage tanks and terminals might still be within the Refining segment.

That makes sense.

Did you change, though, the accounting of it from an internal cost accounting to a market-based tariff, as you move from '12 to '13, or is there no delta on that point?

Arjun, it's Tim.

There are some adjustments that have been made.

Some of those were obviously at market.

Some were more focused on the cost side, so this does reflect that movement now to really across that system.

We're going to be going to the market-based adjustment rate.

So there was an uplift from that.

Yes, great.

And then on the crude slate slide, which I think is Slide 15, you described WTI-based and shale.

I presume the shale is Mid Continent and therefore effectively a WTI-based product, or is there some reason you have it separated?

WTI traditional, Mid Con production, I think we like to separate the shale and very focused, thinking about Bakken, Eagle Ford, and some of those are really probably better described as light tight oil.

And so I think that's a distinction that we use to help draw the distinction of really bringing in new plays.

Clearly, WTI may have some expansion as well with the E&P activity, but that really helps highlight where the new source comes from.

Got it.

And a quick final one.

Have you guys given any consideration or plans to invest at the front end to be able to process more light oil at some of the otherwise heavy refineries, or do you not have an interest in doing that?

So Arjun, it's Greg.

Good morning.

Yes, we're looking at that.

We've done preliminary engineering around condensate splitters, stand-alone, also in the refineries.

I think we're moving toward utilizing, underutilized equipment in our refineries today to cheaply find a way to process more lights and we do have some projects identified.

But these are small projects that I would say $50 million and less that are really quick hit projects that we can get implemented and get paid out fast.

We don't envision at this point doing a stand-alone condensate splitter at some point.

That's great.

Thank you so much.

Our next question comes from Bradley Olson from Tudor Pickering.

Hi.

Good morning, everyone.

You've obviously done a lot to access more on-shore shale crudes.

That's coming through in the slides that you had in your presentation this morning.

But there has been a pretty significant compression between Brent and WTI, and Brent and Bakken prices, which some previous questions hit on.

Is there a price level, or is there a sensitivity to your crude by rail operations, or a price level, or a price spread where it's no longer interesting economically to ship Bakken crude to Ferndale or to Bayway?

Yes, certainly there is a point.

We've said in the past that we look at Bakken to the East Coast, West Coast, maybe in that all-in from the well head out, 12 to 16.

You start getting that to come in too far, obviously, we'd want to do that.

But fundamentally, that crude needs go that direction.

That's the right place, I think, for that crude to go.

So I would see that as short-term dislocation versus really a fundamental.

We still believe Bakken will price to be competitive and it's going to take into account where it needs to go to price itself into the market.

Great, thanks.

In the LLS market, we've seen this rally where LLS, despite the increase in Eagle Ford production and the flows coming southbound on Seaway, we've seen LLS rally recently above Brent levels.

Any comments as to what you're seeing in the market and whether or not Phillips has been able to maybe access crudes on the Gulf Coast at a discount to what we're seeing on our screens when it comes to LLS pricing?

LLS is our marker crude that we talk about in the Gulf Coast region.

And we've been successful really having additional penetration, particularly with Eagle Ford crudes, as well as some supplements from the other Mid Con crudes into that region.

I think the way I would explain that is I think you look back at our marine option that we've taken on the MR tankers, putting it a bit in service and that's letting us access Texas crude over to Alliance and Lake Charles.

I think really what you're still seeing is probably some reduction in LLS over the past quarter and then you've got the transportation bottleneck from Texas to Louisiana.

That ultimately gets solved, but I think as a result of that, you're relatively indifferent right now on LLS versus some of the other imported grades.

But we still think, fundamentally, as that crude shows up into the Gulf Coast that you'll begin to see that discount.

Great, and a question on the Chemicals side, the $8 billion opportunity set that was cited in the presentation, I might have my numbers wrong but that sounded a little bit higher than the roughly $6 billion figure that I think had been discussed in the past.

Are there any specific projects on the Chemicals side that's driving that number up to $8 billion?

Well, that's a multiyear look.

The big piece of that is the new ethylene cracker and associated derivative plants on the petro chemical space.

But it also includes some smaller interim, more closer-in projects for the fractionator expansion at Sweeny, the 1-hexene plant, and some other kinds of more smaller project.

But the big driver is that project in the petro chemical complex here in the Gulf Coast.

And Brad, of course, that's a gross number at the CPChem level.

Right.

Sure.

And just one last one.

You guys announced a project on the Midstream side to help tackle the fractionation shortage that's developing on the Gulf Coast.

As you look into the NGL market where you guys are obviously very active, do you have any thoughts on potentially addressing the lack of export capacity that we've been experiencing on the Gulf Coast, especially in light of recent announcements by companies out there to bring large batches of Marcellus LPGs down to the Gulf Coast?

And that's it for me.

Thanks, guys.

Thanks.

Yes, I think we've said previously that we're looking at a multiproducts export facility on the Gulf Coast.

It could include condensate, LPGs, even refined products.

And so I would say we're in the feasibility stage on that project and looking to move that forward.

Our next question comes from Paul Cheng from Barclays.

Good morning, guys.

A number of quick questions.

On the East Coast, your deal with Global Partners, do you have any flexibility not to take the oil to Bayway, but to other locations?

Or does that 50,000-barrel per day have to go to Bayway contractually?

It's really focused on Bayway.

It makes a lot of sense.

I think ultimately you could have some flexibility, but we've certainly seen the advantage.

And that's where we would intend to use that.

Right.

Tim, when did that contract start up?

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

So beginning of this year, right?

Correct.

I think that you guys have been discussing about bringing the heavy oil to California, where (inaudible).

Some of your competitors are looking at somewhat different options by rail the heavy oil may be into, or that the light oil into the Pacific Northwest and then barge it down.

I'm wondering whether that may be an option you guys would be interested in, or that you will stick to primarily looking to, rail the heavy oil from Canada to California?

And if that is the option that you'd currently stick to, is there a status update that you can provide?

Sure, it's really a multifaceted approach in looking at bidding different crude slate to the West Coast.

Today, we are doing some barge movements down the coast into California on heavy Canadian.

You can look in the Northwest to do that.

So that's an option that we're going to continue to use and we're looking at expanding that opportunity with some of the logistics things we're putting in place.

We're also continuing to move crude by rail in smaller amounts into California and looking at projects really to increase that as well.

Well, maybe this is for Greg.

Greg, can you give me some balance sheet data?

What is your working capital, the inventory of market value in excess of LIFO?

And also the long-term debt.

I assume that is long-term?

The replacement value in excess of LIFO, Paul, is $8.1 billion at the end of the first quarter.

And then working capital?

Yes.

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

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

That excludes the long-term debt.

Long-term debt's right at $7 billion.

We did reclassify some of that, I think.

No, we left it at $7 billion.

Okay.

So long-term debt is $7 billion.

Greg, given the expected pretty heavy capital outlay from CPC, should we assume that any dividend payment from CPC to the parent corporation would be quite minimum until that order, at least at the Gulf Coast cracker, is complete?

Yes, Paul, so we'd given guidance I think in our December meeting that the capital expenditures program for CPChem's going to be in the neighborhood of $1.2 billion.

If you look at their EBITDA last year, it's about $3 billion.

So we think there's going to be nice distributions back from the chemical company to both of the owners this year.

Okay.

Two final questions.

Greg, can you remind me what is the liquidity need for you to run your business?

What is the level that you feel comfortable?

We're still honing in on that, Paul.

We look at needing cash somewhere in the neighborhood of $3 billion to $4 billion.

We're comfortable with our current liquidity, uncommitted credit facilities that are $5.2 billion, $4 billion on a revolving credit facility, and $1.2 billion associated with our accounts receivable securitization facility.

And you're aware that we use some of that liquidity as a basis for back-stopping our letters of credit.

I think at the end of the first quarter, we had about $200 million associated with LCs.

So with your cash position at $4.7 billion, I think that is clearly that you are in excess of what you need to run your business.

And even though margins have come down, you are still generating tons of free cash.

I was wondering is there any plan of separating the cash return to the shareholder?

Well, first, I'll turn to Greg.

Recall that we committed to paying $1 billion of our short-term debt, eliminating the short-term debt by the end of the year.

So that's $1 billion of expected cash usage.

And then I'll let Greg respond to the distribution aspect.

Yes, dividends are highly important to us, Paul, and I know you're a big supporter of dividends and I think you would expect us to increase the dividend this year.

We do want to get on an annual cycle of dividend increases.

We've always said when we pay a competitive dividend, we never want to back up from it.

We went back in 10 years and say we've increased the dividend every year, very important to us.

We've confirmed our previous guidance on capital expenditures at the P66 level this year.

So I think then when you think about the capital discipline around where we're going from a capital investment standpoint, the extent that we're going to generate excess cash, then it will go against our existing $2 billion share repurchase program that we've talked about.

And a final one.

Tim, I think that's one potential option in terms of the transportation side, to well the bitumen directly down to the Gulf Coast and then in return car to bring the condensate up to the Alberta given that's a [natural] position there.

Have you guys looked at that as a possibility?

And if you have, any type of cost estimate if you do a round trip like that, what may be the cost comparing to the pipeline cost may look like?

I haven't done it specifically for that, that I can recall, but we are looking at that.

Clearly, you get rid of diluents on the way down.

You can send it back up for the pipeline movements so you get a better load.

We really haven't looked specifically at that, as something that we're really pushing on hard at this point.

The rail pipeline solution's, longer term, is the right solution, or marine movement on the Canadian movement.

I think the limiting factor for us, Paul, is really the heated coil cars.

I think that's true probably for the industry.

I see.

Very good.

Thank you.

Our next question is from Faisel Kahn from Citigroup.

Good morning.

It's Faisel from Citi.

A question on the Refining side, the other Refining income.

You had talked about it a little bit in your prepared remarks but it's a big swing from the fourth quarter to the first quarter, from $58 million to $182 million.

Can you talk about that a little bit?

I think you said it was related to selling excess Canadian heavy into market?

Can you discuss how that works and how that's going to trend going forward?

Faisel, this is Tim.

So basically, I think that results from our positions on our Canadian takeaway and so we're the largest importer of Canadian crudes.

When we have an excess, we're able to capture that value and that's really a very significant factor in the first quarter for us.

And because those benefits go across several regions.

Rather than attributing it to Mid Con or the Gulf Coast, we spread it over the entire segment.

Okay.

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

Primarily a spread benefit.

That group also contains some of our commercial activities beyond that as well.

It's a combination of things in that other.

Okay.

Got it.

And just looking at your cash flow statement, your undistributed earnings swung to a positive number.

Is that what you talked about earlier, that you expect to take distributions from CPChem during the course of this year, even though you're investing heavily in the business?

Is that a trend we should see throughout the entire year for a positive impact from undistributed earnings?

At CPChem, remember last year we paid off the debt at CPChem.

Distributions were significantly reduced last year from CPChem.

And this year, given where we think the Chemicals business is, the margin in the Chemicals business, we think there's going to be good cash generation in that business.

We've got a $1.2 billion, at the CPChem level, capital spend.

And I think you would continue to see distributions in that excess there, from what we've seen previously last year.

Okay.

Got it.

Back at CPChem, with the expansion of your facilities, do you have all the permits now in place?

How much longer are we waiting for the permits to proceed with the expansions you guys talked about in the Gulf Coast for the base chemical, commodity chemical, crackers?

So the permitting process has been well underway for some time and we've made good progress.

We're reaching the end because we're looking to take final investment decision at the third quarter.

I think that gives you some indication of where we are on that, and to this point that's not been an issue.

Okay.

Got it.

And then would the NGL fractionation project that you guys are talking about, is that designed to coincide with the chemicals facility to supply feedstock to that the facility?

Would there be a potential agreement between the fractionator and that chemical project within the joint venture?

I think we've said in the past, we're looking at balances, we're pretty balanced.

There's obviously increased demand, but it doesn't specifically tie to that pet chem project, but it's certainly, on the macro level, a nice matchup when we do that.

Okay, got it.

And going back to the Midstream questions from earlier in the call, there were a lot of numbers that were thrown out but I just want to make sure I understand the numbers.

So excluding DCP Midstream, if I'm looking at the Midstream income before taxes, I see NGL operations of $15 million, transportation income of $73 million, and D&A of roughly $19 million.

It seems like it's roughly $100 million of EBITDA associated with the NGL operations and transportation, excluding DCP Midstream, is that the right number?

I heard a $200 million number, $300 million number around the cause.

I want to make sure I'm looking at that correctly.

Looking just at Phillips 66 operations, you would want to take the NGL ops and the transportation number.

That's very specific to the P66.

That's $20 million of depreciation.

Yes, yes.

Okay.

Got it.

And then last question for me, just on tax.

What is your guidance for the tax rate for the rest of this year?

We're looking at the low 30s.

I would suggest something in the 30%, 32% range.

Okay.

Understood.

Is that a sustainable tax rate, all else being equal for the business?

I think it's a fair rate, at least as we look out through 2013.

Sometimes, as you're well aware, some adjustments come in and introduce some noise.

But I think 32% is a fair number.

Okay, got it.

I really appreciate the time.

Thank you.

Our next question comes from Paul Sankey from Deutsche Bank.

Hi, everybody.

And just a second thanks for the disclosure that you offer.

Could I slightly dig around in Slide 15, please, which is a very interesting summary.

You said, and I think you remain committed to this idea, that you'll keep your CapEx in line with your DD&A.

Is that a correct way of looking, on a go-forward basis?

We'll keep our maintenance cap.

Maintenance capital.

So the overall level, that would be $1 billion.

Then the overall level of CapEx, are you still going to try and keep that within the $2 billion range?

Yes.

We said, we said $1.8 billion.

$1.8 billion.

Or $1.8 billion, $1.9 billion, something like that.

I think $1.8 billion is on a cash basis.

Of course that excludes the capital that's being spent by DCP or CPChem.

Which is self-financing, right?

Exactly, exactly.

But if you roll it all up, it's about $3.7 billion.

Proportionally consolidated.

With the $1.8 billion being the Phillips 66 capital.

So I guess the point is that the previous levels of CapEx are about the same as what you're anticipating spending going forward.

That was my point.

Yes, I think that's right.

Okay.

Allowing for that and you've been clear on the debt paydown and about what you may do with cash return to shareholders, I was just wondering, in terms of the way this slate of crudes has shifted on the left-hand side and then to an extent on the right-hand side, the yield has shifted.

Would it be fair to say that's the low hanging fruit move and it would be hard to see the equivalent continuation of the shift that you've achieved going forward?

Or do you anticipate that you can continue those dynamics of obviously rising WTI base, rising Canadian, down on other heavy, but then rising shale, and collapsing Brent-based.

I guess what I'm trying to get to, is there a terminal point there?

There is, but we're not there yet, Paul.

Our target's 100% advantaged crude and then you start taking advantaged crudes and replacing them with more advantaged crudes, i.e., the Mississippi lime we're doing around Ponca City, where we're displacing a WTI barrel with a better barrel.

More consistent quality, better pricing.

There is a theoretical limit on the clean product yields.

We're approaching that limit.

And then we're already high on distillate yields, industry leading distillate yields.

But there's still a lot of room left in the fairway for us in terms of the advantaged crude and the value capture for advantage crude.

Would the LLS, I'm assuming, is in Brent-based?

Yes.

Can you give us a sense of how much it's actually LLS and how much of it is actually Brent, of the 32% that you've got running Brent-based?

LLS, clearly on the Gulf Coast, and so very specifically, we haven't disclosed it by refinery, but I think if you think about our refining system, you could see where that is.

That's really down the Gulf Coast and the Brent base for us would be ANS.

It would be the other non-Bakken kinds of crudes that we sometimes bring into Bayway, plus the LLS.

It's a mixture of things that really -- a lot of the California crudes are ANS-based which ultimately are Brent-based as well.

I think you look at regionally and you say California, Bayway, and of course from where the Gulf Coast is where we see the Brent-based exposure in the US.

Yes, that's helpful.

Thanks.

You're saying you're trying to get to 100% advantaged, but would ANS be in that advantage target?

Yes, so I think that we look at it and ultimately as we talk, we believe LLS with the movement of Mid Cons to the Gulf Coast probably just to be competitive will have to change.

And then ANS I think now, as the Bakken continues to move to Northwest, as Canadian access to the West Coast improves, you'll see that as well.

As we talk about 100% target, there is a premise either through substitution or competition that we begin to get the advantage in those other crudes as well.

Yes, that makes sense.

My opening point was that, you think you can do all of this without any great expansion in capital?

I think what you've said is it's more like $50 million-type projects of changing access, as opposed to any major surge in CapEx that's required.

That's correct.

Was there a timeframe at 100% advantaged?

It keeps getting shorter.

Yes, I keep pressing it.

It will take us a couple years, Paul, to get there, all the way across.

And basically I guess there will be a little bit, you can see here there's a bit more gasoline than there was in 2011, but it's the nature of half a percent.

I assume that would--

I think that little bit of shift that you see in the first quarter is probably more to do with Sweeny being down.

Yes, that's correct.

First quarter versus running more light sweet crudes where you'd expect higher gasoline yields.

Directionally, we don't want to give up this 41%, 42% distillate yields that we're generating at refineries.

Although it would probably work to our advantage because gas cracks were a little better.

They expanded.

Yes, that's interesting.

Okay.

So it's not a crude-driven change in yield.

Yes, we had Sweeney down 49 days in the first quarter for turnaround and then the power outage that hit us there brought the whole complex down.

Yes, what was that, by the way?

I know there was like a million barrels there of capacity down at that point, right?

So we lost all three feeds into the whole complex.

So it impacted the refinery.

It impacted the CPChem facilities and the frack, and to some degree, actually impacted DCP also, as we were trying to bring volumes down the EZ line, which terminates at Sweeny at the frack.

But we had a scheduled turnaround for February and that turnaround went well.

Then as we were coming back up, we lost power and we were down for another week.

I think the number is actually 47 days Sweeny was down, had a negative impact --

What caused the outage?

So some work that our utility supplier was doing to actually upgrade their systems caused a trip.

Okay.

That's enough.

Guys, thanks a lot.

I appreciate your time.

Thank you.

Our next question comes from Cory Garcia from Raymond James.

Good morning, fellas.

One quick follow-up to this idea of bringing heavies into California, and specifically the rail-to-barge opportunities, clearly some more associated costs with that element, as well as the coiled rail cars is a bit of an issue.

But I wonder how we should think about ultimately the cost structure on that aspect, clearly the 12 to 16 of rail Bakken to Washington makes sense.

But where does that go, and even if you're able to pry it up some order of magnitude, where does that go and actually bring in those heavies from Canada into California?

You start laying in the supply chain.

Clearly, cost can move with time as we develop the solution.

I think you've got to see those discounts on the heavy, for instance, enough to offset that transportation and provide the quality differential and incentive to run so I still think it's in that range.

You see the WCS discount move out here recently.

But I think that for Canadian crude, it's probably still one of the further destinations so I think that still continues to play in.

You've got to see a significant discount to make that move that way.

The cost of transportation.

Okay.

We're talking probably $20 plus discounts to be able to make it --

It would certainly work at that, yes.

The Ferndale unloading facility that you guys are constructing, or I guess it's still in the permitting phase, would that be a sole purpose for that single refinery?

Are you guys looking at expand that into a barge opportunity as well?

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

We'll have the multipurpose flexibility to it.

Thank you, guys.

Thanks.

We have no further questions in queue.

I'll turn the call back over.

Okay.

Thank you very much.

Appreciate the interest.

You can find the transcript of the presentation, also the Q&A, and certainly Rosie and I are available for my further follow-up questions.

Thank you for the interest in the Company.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.