Phillips 66 (PSX) — Q1 2018 Earnings Call Transcript

Good morning, and welcome to Phillips 66 first quarter earnings conference call. Participants on today's call will include Greg Garland, Chairman and CEO; and Kevin Mitchell, Executive Vice President and CFO. The presentation material we will be using during the call can be found on the Investor Relations section of the Phillips 66 website, along with supplemental financial and operating information. Slide 2 contains our Safe Harbor statement. It is a reminder that we will be making forward-looking statements during the presentation and our Q&A session. Actual results may differ materially from today's comments. Factors that could cause actual results to differ are included here, as well as in our SEC filings. With that, I'll turn the call over to Greg Garland for opening remarks.

Thanks, Jeff. Good morning everyone, and thank you for joining us today. Adjusted earnings for the first quarter were $512 million, or $1.04 per share. We generated $1.3 billion in operating cash flow excluding working capital. Our solid earnings reflect the benefit of our diversified portfolio and we've seen positive impacts from U.S. tax reform. Our strategy is designed to generate long-term value for our shareholders, and our employees are executing the strategy well. We've achieved significant growth milestones and completed return enhancement projects. We're developing new projects with attractive returns that complement our strategy, and by doing all this well, we can continue to reward our shareholders with solid distributions. During the quarter, we bought back 35 million of our shares in a single transaction and continued with our share repurchase program. All in, we'll return $3.8 billion to shareholders. Since our company formation in 2012, we've returned over $20 billion through dividends, share repurchases, and share exchanges. To put this in perspective, our market cap at inception was $20 billion. Today our market cap is over $50 billion; we repurchased and exchanged close to 30% of our shares outstanding at the time of the spin. CPChem start-up is a new cracker at Cedar Bayou, which is one of the largest and most energy-efficient crackers in the world. This milestone caps a completion of its U.S. Gulf Coast petrochemicals project. The cracker reached full design rates in April. CPChem also operated well during the quarter and is fully recovered from the hurricane downtime at Cedar Bayou. With major capital spending now complete and contributions from the new petrochemicals project, we expect increased distributions from our chemicals joint venture. In midstream, Phillips 66 Partners recently announced it will proceed with the construction of the Gray Oak pipeline system. The pipeline will provide crude oil transportation from the Permian Basin to Gulf Coast destinations, including our Sweeney Refinery. An extension open season is underway and will determine the ultimate scope and capacity of the pipeline, which could be up to 700,000 barrels per day or more. Assuming the pipeline is fully subscribed, the capacity could be expanded to about one million barrels per day. The pipeline is backed by long-term take-or-pay commitments with primarily investment-grade customers and is expected to be complete by the end of 2019. Phillips 66 Partners will be the largest equity owner in this joint venture project. Construction continues on the Bayou Bridge pipeline extension from Lake Charles to St. James, Louisiana. Commercial operations are expected to begin in the fourth quarter of 2018. The existing segment of the line from our Beaumont Terminal to Lake Charles is operating well and is providing crude optionality to our Lake Charles refinery. PSXP has a 40% ownership in Bayou Bridge. Phillips 66 continues to expand the Beaumont Terminal, where we're adding 3.5 million barrels of fully contracted crude oil storage. This project will bring our total crude and product storage capacity at Beaumont to 14.6 million barrels by year-end. The Sand Hills pipeline capacity was closed to 400,000 barrels per day at the end of the first quarter; further capacity expansion to over 450,000 barrels a day is anticipated in the second half of 2018. The pipeline transports natural gas liquids from the Permian Basin to the Gulf Coast of Texas and is owned two-thirds by DCP and one-third by Phillips 66 Partners. DCP continues to progress the construction of two 200 million cubic feet per day gas processing plants in the high growth DJ Basin. The Mewbourn 3 plant is expected to start up in the third quarter of 2018, and the O'Connor 2 plant is scheduled for completion in mid-2019. DCP is also participating in the Gulf Coast Express pipeline project in which it holds a 25% interest. The pipeline will provide an outlet for natural gas production in the Permian Basin to markets along the Texas Gulf Coast. The pipeline has a total design capacity of approximately 2 billion cubic feet per day and is nearly fully subscribed. The pipeline is expected to be completed in the fourth quarter of 2019. In refining, we recently completed SEC unit modernization projects at the Bayway and Wood River refineries. At both facilities, we replaced the FCC reactor system with state-of-the-art technology. The projects were completed on time and on budget. Units have been operating as planned and early operating data is showing an increased yield of high-value clean products as promised. At the Lake Charles refinery, we completed crude unit modifications to run more domestic crudes, which improves our supply optionality. Additional improvements are planned to be completed in the fourth quarter. Finally, we're very honored that four of our refineries were recently recognized by the AFPM for excellent safety performance in 2017. Our Bayway refinery received the Distinguished Safety Award, which is the highest annual safety award given by our industry. The Sweeney, Alliance, and Woodward refineries were also recognized for their top-tier safety excellence. I'm very proud of the people of Phillips 66 and their strong commitment to our safety culture. So with that, I'll turn the call over to Kevin to review the financials.

Thank you, Greg. Hello, everyone. Starting with an overview on Slide 4, first quarter earnings were $524 million. We had special items that netted to a gain of $12 million. After excluding special items, adjusted earnings were $512 million or $1.04 per share. Operating cash flow excluding working capital was $1.3 billion. Capital spending for the quarter was $328 million, with $171 million spent on growth projects. First-quarter distributions to shareholders consisted of $3.5 billion in share repurchases and $327 million in dividends. Slide 5 compares first-quarter and fourth-quarter adjusted earnings by segment. Quarter-over-quarter adjusted earnings decreased by $36 million, driven by lower refining results, mostly offset by improvements in chemicals, midstream, and marketing; highlighting the benefit of our diversified portfolio. Slide 6 shows our midstream results; transportation adjusted net income for the quarter was $136 million, up $28 million from the prior quarter. The increase was primarily due to lower taxes and operating costs. Volumes were lower in the first quarter due to the impact of turnarounds at certain of our refineries. NGL and other adjusted net income was $73 million compared with $20 million in the fourth quarter. Our first quarter earnings reflect improved realized margins and positive inventory impacts. We continue to run well at our Sweeny Hub this quarter, averaging about nine cargos a month at the export facility, and 95% utilization at the fractionator. However, U.S. Gulf Coast to Asia margins remain challenged. DCP Midstream had adjusted net income of $24 million in the first quarter. The $10 million increase from the previous quarter was due to the timing of incentive distributions, hedging gains, and lower taxes. The increase was partially offset by lower volumes. DCP has steadily improved its financial condition; EBITDA is growing, it's generating positive cash flow and making distributions to our owners. Turning to Chemicals on Slide 7; first quarter adjusted net income for the segment was $232 million, $111 million higher than the fourth quarter. In olefins and polyolefins, adjusted net income increased $129 million from higher margins and volumes reflecting the Cedar Bayou facilities return to full operations. Global O&P utilization was 96%, up from 79% in the fourth quarter. Adjusted net income for SA&S decreased by $16 million due to turnarounds. In Refining; crude utilization was 89% compared with 100% in the fourth quarter. Clean product yield was 83%, a decrease of 4 percentage points. Both our utilization and clean product yield were lower due to turnaround impacts. Pre-tax turnaround costs were $245 million, an increase of $146 million from the previous quarter; this excludes the turnaround costs for our joint venture WRB. Realized margin was $9.29 per barrel, up from $8.98 per barrel last quarter. Although the market crack decreased 6%, our actual realized margins improved 3% from wider crude differentials, specifically heavy Canadian. The chart on Slide 8 provides a regional view of the change in adjusted net income. In total, refining's first quarter adjusted net income was $89 million, down $269 million from last quarter due to lower volumes and higher costs associated with turnarounds; this decrease was partially offset by higher realized margins. In the Atlantic Basin, the $193 million decrease in adjusted net income was mostly due to a major turnaround at the Bayway refinery. The Gulf Coast adjusted net income decreased $71 million mainly due to turnarounds at the Sweeney and Alliance refineries. Adjusted net income in the central corridor was $203 million, an increase of $11 million from higher realized margins driven by Canadian crude oil differentials. The impact from the fourth quarter completion of Ponca City refinery turnaround was more than offset by first quarter turnarounds at the Wood River and Boga refineries. In the West Coast, adjusted net income decreased $16 million from the previous quarter mainly due to lower volumes. Slide 9 covers market capture; the 3:2:1 market crack for the first quarter was $13.12 per barrel compared to $13.98 in the fourth quarter. Our realized margin for the first quarter was $9.29 per barrel, resulting in an overall market capture of 71%, up from 64% in the fourth quarter. Market capture is impacted in part by the configuration of our refineries. We made less gasoline and more distillate on premise in the 3:2:1 market crack. Losses from secondary products of $1.47 per barrel were lower than the previous quarter by $0.52 per barrel. Feedstock advantage improved realized margins by $1.63 per barrel, which was $0.81 per barrel better than the prior quarter from the widening WTI/WCS differential. The other category mainly includes costs associated with RINs, outgoing freight, product differentials, and inventory impacts. This category reduced realized margins by $2.08 per barrel compared with $2.39 per barrel in the prior quarter. The improvement was driven by lower RINs costs. Let's move to marketing and specialties on Slide 10. Adjusted first quarter net income was $174 million, $50 million higher than the fourth quarter. In marketing and other, the $42 million increase in adjusted net income was due to improved realized margins and lower taxes and operating costs; this was partially offset by lower volumes. During the first quarter, we exported 190,000 barrels per day of refined products, and we continue to see strong export demand during the quarter. Specialties' adjusted net income was $45 million, an increase of $8 million from the prior quarter, mainly due to lower taxes. During the first quarter, we completed the restructuring of our XL Power Loops joint venture; both partners contributed their base oil businesses to the venture to create an integrated manufacturing and marketing business. The JV restructuring provides XL Power Loops with greater agility to provide quality base oil solutions to our customers. On Slide 11, the corporate and other segment had adjusted net costs of $162 million this quarter compared with $140 million in the prior quarter. The $22 million increase reflects the ongoing impact of lower tax rates on our corporate costs. Slide 12 highlights the change in cash during the quarter. We entered the year with $3.1 billion in cash on our balance sheet. Cash from operations, excluding the impact from working capital, was $1.3 billion. Working capital changes reduced cash flow by about $800 million, largely due to normal seasonal inventory builds. We funded approximately $300 million of capital expenditures and investments, and we distributed $3.8 billion to shareholders through dividends and the repurchase of over 37 million shares, and in the quarter with 466 million shares outstanding. We also received $1.5 billion from the issuance of debt. Our ending cash balance was $842 million. This concludes my review of the financial and operational results. Next, I'll cover a few outlook items. In the second quarter in chemicals, we expect global O&P utilization rates to be in the mid-90s. In refining, we expect the worldwide crude utilization rate to be in the mid-90s and pre-tax turnaround expenses to be between $90 million and $120 million. We anticipate second quarter corporate and other costs to come in between $170 million and $190 million after tax. The increased guidance reflects interest expense associated with our first quarter issuance of debt. With that, we'll now open the line for questions.

Good morning, everybody and congratulations on having the financial strength to be able to repurchase 7% of your equity in one quarter; we don't see that often, that's pretty impressive. So my question is about AMO 2020 and specifically, how you guys are thinking about the type of products that are likely to be provided to the market as it seems that many of these deals are still in the design phase and there are still a lot of unknowns in that area? And when you think about marine fuel blends, how challenging the issues of compatibility and stability are likely to be? And also availability along the marine fuel network as the market goes through the transition in coming years. So two questions on AMO 2020.

While we know the sulfur content of marker fuels, we don't have the detailed specifications yet; they're still evolving. We do expect a significant increase in diesel demand of about 2 million to 3 million barrels a day in the bunker category. Additionally, low sulfur cat cracker feed is expected to be a strong option for bunker fuels, which will also support gasoline markets. We anticipate the turnover of tanks and blending infrastructure to begin next year, possibly around mid-year, indicating a major shift that we are preparing for. Our existing refining assets are well positioned for this IMO transition, with a high distillate yield of approximately 41% last year, and a $1 per barrel change in distillate margin translating to about $300 million in EBITDA. Moreover, we expect fuel oil to exert pressure on heavy crude prices. We handle about 700,000 barrels a day of heavy crude, accounting for around 35% of our total portfolio. We also have more coking capacity than our competitors at 470,000 barrels a day; every dollar per barrel change in heavy crude discount equates to about $250 million in EBITDA, which means our portfolio is well positioned as it currently stands.

I wanted to follow up on your point about diverting vacuum gas either around the crack or directly to the marine fuel pool. It seems that this could enhance the marine fuel supply, but it also appears that it might reduce gasoline supply, which could make it a zero-sum game. Would you disagree with that? Additionally, how often has this practice been used in the industry? Is this something you have done frequently, or is it something we have seen before?

This is something that we expect to be more of a new activity; we're converting from max gasoline to max diesel during the summer months as well as pulling some of the cat cracker feed. I think we'll support gasoline margins as well as supporting diesel cracks.

My first question is about capital spending. I understand it's early in the year, but it appears that capital expenditures were below the annualized run rate that you had projected. Can you discuss the guidance and if there are any factors that might lead to a decrease in it, as well as the timing of the spending?

Neil, I think we're consistent with the guidance around the 2 to 3. I think that we were a little light the first quarter and we knew we were going to be when we put the plan in place, but 2 to 3 is still good guidance for us this year.

Second question on the quarter; Midstream big part of the beat, NGL and other was a driver of that and there were some inventory benefits there. Can you just kind of speak to what some of those dynamics were and how we should think about the run rate going forward?

As you look at that, I think the NGL segment reported $73 million of income in the quarter. About $20 million of that is associated with inventory LIFO related items; nothing specifically unusual in what happened, it's just the magnitude and it's positive in the quarter and these things will happen from time to time, and it can go in the opposite direction also. But as you look at that and try and think about our run rate going forward, you probably ought to back out somewhere in the order of $20 million from what we reported in the first quarter.

That's helpful. And last question for me; on Permian differentials you guys have a good perspective on this, it's just over the next two years, their absence of major pipeline is still the back half of 2019; how do we get the crude to market from West Texas?

I think it's a good question. You're correct, the next major pipelines are scheduled for the back half of 2019. We saw about 750,000 barrels a day of new capacity that was added late last year and early this year, and it certainly appears that that pipeline capacity is filling up more rapidly than anticipated. As we look at alternative route options, trucking is one. That's kind of a $12 a barrel movement at this point although that's not going to be a steady number. A typical truck can haul about 180 barrels of crude; it's roughly a 500-mile haul from the Permian to the Gulf Coast, it's a 2-day round trip, so you need 100 trucks to move 10,000 barrels a day. It's not really realistic to expect to move 100,000 barrels a day or 200,000 barrels a day; it's just not really practical. From a rail perspective, there are not a lot of rail facilities. Most of the rail facilities in the Permian Basin are now designed for frac sand and not crude movement, and so that's not a great option. So we are in need of new pipeline capacity serving the Permian Basin. I think there's a lot of talk on the crude side, and when you look at the Midland differential to East Houston, it's out to $9 a barrel; when there was enough infrastructure it was kind of a $3 a barrel differential. When you look at natural gas as well, Waha prices have declined about $1 in MMBTU relative to where they were last year, and that sets a lower price for natural gas and ethane rejection; so we may see some additional ethane production coming out of the Permian Basin as well.

First one is just more housekeeping, probably for Kevin. The tax rate seemed really low in the quarter; I'm just trying to figure out if that's maybe some one-off issues driving that or if that's kind of sustainable?

Yes, Blake, the tax rate is indeed a bit low and it reflects the mixed effects of certain items in the portfolio. There's a higher proportion of international earnings than usual, partly due to the significant U.S. refining turnaround activity, which has resulted in a relatively low contribution from U.S. refining earnings. Additionally, in the chemical segment, the Middle East joint ventures that CPChem has in Qatar and Saudi Arabia are accounted for using the equity method at the CPChem level, and these equity earnings are after tax. The entities themselves pay taxes, and that affects the overall effective tax rate. This impact is more noticeable during periods when pre-tax income from other sources is lower, such as during turnaround activities. Also, the effect of non-controlling interest in the effective tax rate calculation is factored into our overall guidance, but when the rest of the portfolio experiences a low earnings quarter, its impact is magnified. Looking ahead, we expect the effective tax rate to remain in the low 20s.

Got it, thank you. Greg, I'll go out on a limb and assume that the buyback level of $3.8 billion in the first quarter is not sustainable. As we kind of get our bearings straight after that big slug; do you have any thoughts around the way we should think about that moving forward?

Yes, I think we'll stick with our guidance of $1 billion to $2 billion of share repurchases in 2018. We may be towards the lower end of the range given what we've done in the first quarter, but yes, we'll still be buying shares; we're buying today.

First question is on some of the cash flow items, which I believe is for Kevin. Considering the repurchase in the quarter, how do you view managing the cash balances and where would you like them to be? Additionally, should we consider dropdowns to PSXP as a potential source of cash that might flow to the parent company this year, or with the organic opportunities at PSXP, is that not necessarily something we should be considering?

Yes, Phil, I have a few comments on that. The decrease in cash was primarily due to the $3.3 billion buyback with Berkshire, along with the issuance of $1.5 billion in debt, which significantly impacted our cash reserves. One reason we could undertake this is that tax reform allowed us better access to cash that was previously more costly to retrieve, enabling us to take advantage of that situation. Moving forward, this means we will have increased access to our overall cash balances. As for the year ahead, we typically don't provide guidance on dropdown plans, but as mentioned in the PSXP earnings release, we are close to our 2018 EBITDA guidance at the MLP level. With ongoing organic growth projects at the MLP, the need for dropdowns will be minimal, and we don’t anticipate forcing any drawdown to fund the parent company; all decisions will be focused on long-term MLP growth.

That's very helpful, thanks. I guess the second question; a bit more of a strategic one for Greg. Just thinking about the current environment for chemical margins, obviously your cracker coming on-stream sounds like it's going really well in terms of the startup. If you look at the margin profile out there, ethylene margins are challenged, but the full chain margins are still holding in pretty strongly. So how do you think about the chemical environment and what it might mean for the timing of a second cracker?

First of all, it was a great startup; I believe it's one of the better startups we've had recently. Kudos to the CPChem team for successfully getting that cracker operational at full capacity. In the fourth quarter of last year, derivatives were up, Dow is up, and we've been performing well since the fourth quarter. The market-facing aspect of those projects is evident, and when considering the full chain margins, that spread between ethane and polyethylene, especially high-density polyethylene, is what we focus on. Those margins remain quite similar. We have managed to move products into the markets without significantly impacting the margins currently, which reflects the strong demand we're experiencing. There is good fundamental demand growth for petrochemicals, particularly polyethylene, across North America, Europe, and Asia. ExxonMobil is expected to come online later this year, with two additional crackers set to launch in 2019. Initially, we anticipated these crackers would start in 2017, but that did not happen, resulting in a staggered rollout that the market can absorb, alongside strong global demand growth. As we consider the next cracker, we are encouraged by the increasing NGL supply, especially from the Permian and the U.S. Gulf Coast, making it a suitable location for our next cracker. We are likely looking at 2019 for a final investment decision on that facility.

I had a quick question on the Mitcon results which were very strong. So I'm trying to understand how much of WCS you were running in the Mitcon and did you actually uptake the intake of WCS in your Mitcon system which got reflected in those very high capture?

We imported an average of 550 million from Canada in 2017, which totals 1,000 million. Some of that was for our net, which was about 450 million, with 80% being Canadian heavy. This indicates the range we expect to operate annually. We don't plan to update this quarterly, but we will continue to import Canadian heavy as needed.

Jeff, my follow-up is on the question that Phil also asked; I'm trying to understand were you actually short ethylene in 1Q '18 because what I'm trying to get to is the $232 million net income you reported; would that have been like $250 million and $260 million had your ethylene cracker actually been running and you were not short of ethylene in that period?

No, we weren't short of ethylene. We had an ethylene inventory, and there was plenty of ethylene available in the industry, and I think that's what you're seeing in terms of just say ethylene margin itself.

I'd like to revisit the midstream segment. It has faced significant challenges over the past year and a half until recently in the fourth quarter and now the first quarter. Could you explain how much of the changes are due to improving market conditions, such as recovering oil prices, and how much is attributed to new projects launching and internal restructuring? Additionally, could you provide insight into the sustainability of this momentum moving forward, especially with Exxon oil prices continuing to rise while stabilizing at these levels?

NGLs have definitely recovered compared to a year ago in terms of pricing. First-quarter volumes were lower than in the fourth and third quarters due to seasonal and weather-related impacts, particularly on the NGL side. The Sweeny Hub is performing, although not at the expected level. Analyzing the first-quarter results, we anticipate an annualized EBITDA of 130 million to 140 million from the Hub. We had previously set a plan for 150 million of EBITDA for this year, which is against an expectation of 300 million to 400 million without the ARB. I believe that this asset still has potential for growth, and as we observe the NGLs coming in from the Permian this year, we expect these to increase in the second half of the year and into next year, indicating continued improvement. The new Stapel pipeline and the Bayou Bridge are operational, and much of this progress stems from the new assets we have been bringing online.

Roger, I want to emphasize that, as you may already know, our supplemental reports on Page 6 highlight midstream adjusted EBITDA. Specifically, PSXP and other midstream operations generated approximately $363 million of EBITDA in the first quarter. If that were annualized, it would amount to about $1.45 billion. Additionally, we have around $300 million in refining assets, which corresponds with the $1.8 billion to $2 billion of EBITDA we have discussed in our presentation materials. This supplemental report will serve as a scorecard to monitor our progress.

And then maybe you could just make a complete change of direction here; RINs, you mentioned in the presentation part that lower RINs help out a little bit. Just curious what your expectation is for potential RINs reform as we see 2018 unfold.

So I'd answer the question this way; we're hopeful. I'm just not sure we're going to get there. There is a lot of good work that's going on, AFPM, API; management teams are in Washington talking to Congress about potential reform. Our view is that it's broke; the system is broke; we need to fix it, and so we'll see, but I don't hold a lot of hope for 2018. Now some of my friends in the business are a lot more optimistic than I am that we'll get something done in 2018. I guess the other impact that you're seeing is the small refinery exceptions, and that has certainly had an impact on the RINs prices. So we'll continue to follow, we'll continue to work it, and continue to be hopeful we get to a resolution there.

I guess maybe in midstream with the Gray Oak projects; not sure how far I'll get here but have to try. Can we get a ballpark of maybe total capital costs for the range on that project? And then along that line maybe the confidence you had to push the spend down directly to PS 60 at the outset here?

Yes, so two parts. First part is really can't comment, we're in an extension open season and the actual volumes that we end up with will dictate the size of the pie, the actual capital cost. You should expect that I would say 45 to 60 days will get this wrapped, and then we'll come back and we'll tell you what the capital cost is going to be on the line. And we started at kind of 380 in the open season; I would just tell you we obviously got more interest than that, and that really encouraged us to move on with the extension of the open season. So I think we're really optimistic on the line and the ultimate capacity, it lands on that line. And then as you think about the decision of where to place it, we've always said we want to execute as many of the organic projects as we can at PSXP. And given this pipeline, we have increased the budget of PSXP for this year and Gray Oak is part of the reason we increased that. But you shouldn't look at that increase as the total cost of the pipeline if you want to think about it that way. So anyway, I think that Gray Oak is a great opportunity for our Company; it's certainly a great opportunity for Phillips 66 Partners; and we'll continue to make decisions about where we place these projects, either PSX or PSXP obviously. But we'll continue to put as much as we can to PSXP and execute as much organic growth as we can at the MLP, and that's very consistent with what we've been saying for the past couple of years.

And I guess shifting gears maybe on cash returns; I understand you answered Phil's question earlier about the buyback but how should we think about maybe the mix of returns going forward? Here we've got a good problem to have with the dividend yield, maybe as low as we can remember in a while, but the mix of the buyback versus dividend growth or maybe faster dividend growth going forward?

I believe that with our cash generation projected at around $5 billion to $6 billion at mid-cycle, we have the capability to manage our $1 billion in outstanding capital and the $1.04 billion in dividends. This scenario allows us to grow the dividend significantly while also pursuing a growth program and a share repurchase program, each in the range of $1 billion to $2 billion. As we look at mid-cycle, we anticipate that the new projects will contribute an additional $1 billion to $1.5 billion in EBITDA, which will enhance our ability to reinvest in the company. However, we are maintaining our 60:40 guidance. Achieving that this year will be challenging since we've already reached $3.8 billion in distributions against a capital budget of $2 to $3 billion, and we do not foresee making significant changes to our capital guidance at this stage in the year. While we will see distributions increase in 2018, we remain committed to the long-term 60:40 balance.

And just to add, Justin, on the dividend; no change from what we've said in the past in terms of secure, competitive, and growing. So we'll continue to grow the dividend; just because we did the big share buyback this year doesn't preclude us from increasing the dividends as well this year.

A couple of follow-ups actually on that last question Greg, if I may. Obviously your share price is substantially above when you set the original distribution policy I guess. What about the mix between dividends and buybacks as part of that 60:40 split? Do you see yourself skewing more to back to the dividend or are you kind of agnostic to the share price as it relates to where you're buying back shares?

No, I wouldn't say we are focusing on that. Regarding share repurchase, it's entirely about intrinsic value. We're utilizing historical multiples along with our projection of EBITDA for the next couple of years. As long as our shares trade below that valuation, we will continue to buy them. When it comes to the dividend, as Kevin mentioned, it's secure and growing. Investors need to understand that we have the capacity to keep increasing the dividend, and our goal is to raise it every year. We aim to remain competitive, looking at factors like the S&P 100 yields and those of our competitors, ensuring that our dividend stays attractive. We will always aim to grow the dividend, but we will do so within those parameters. If we are balancing between reinvestment and share repurchases, we will prioritize buying back shares.

So is it dividends per share or dividends per se; in other words, when you buy back stock, is that counted as part of the dividend growth per share or not?

We're looking at dividends per share.

My follow-up question is more about the bigger picture, Greg, and it relates back to the dinner you hosted in December. You mentioned the IMO issues might be more transitory rather than something that persists over time. I'm curious if your perspective on this has changed. I know you're well positioned for whatever occurs, but do you perceive it as being more long-lasting or still somewhat temporary when it is implemented in 2020?

Yes, I have my own opinion, and Jeff can jump in if needed. I’m not sure if this situation will be brief, but I believe that within a couple of years, it will be effectively resolved.

I was wondering on the crude export front, since you guys have Belmont and so on. We're exporting over 2 million barrels a day now; most people are expecting a million barrels a day of growth in the U.S. So is there the infrastructure in place to or will be in place to export 3 million plus barrels a day next year? And then 4 million in 2020 and on down the line?

Yes, you're right; we've seen a number of weeks over 2 million barrels a day of exports. We've expanded our capacity at Belmont to go from 400,000 barrels a day to 600,000 barrels a day. You saw we're participating in the Buckeye facility in Corpus as well associated with the Gray Oak pipeline. We are seeing the expansion of export capability; it's one part of the value chain that's going to have to grow in order to continue to export, and we think the majority of the incremental production is going to be exported. So we think maybe there's 3 million barrels a day capacity today, but that number is growing; we don't see an immediate issue there at this point.

And then maybe for Kevin; you guys gave the mid-90s utilization guidance for CPChem. I assume that that's off of a new base, so if you could just clarify that if that's the case and if that's for the whole quarter and sort of what the new capacity number is that that 95% is based on?

Brad, you're correct that with the crackers starting up, the declared commercial operations on it in April, and so that adds it into the denominator from a total capacity standpoint. So the new polyethylene units were already reflected in the denominator; the new cracker is effective second quarter; so that 96% includes our assumptions around what all the new units will be running.

Maybe I want to start off on product exports. I mean can you talk about the dynamics that you're seeing right now in product exports due to the sequential decrease I think quarter-on-quarter. But it seems like we're also seeing reports that demand to ship is colonial has dropped to very low levels. I mean what are you seeing in terms of sequential drivers? What are you seeing in terms of relative netbacks, so that you can see domestically versus export and your ability to kind of capitalize on that going forward?

You're right, our product exports were down 190,000 barrels a day this quarter; about 90,000 barrels a day of that was gasoline and 100,000 barrels a day was diesel. We had refinery maintenance at Alliance in particular that reduced the availability of product that we could put into the export market. We are continuing to see strong demand, continued struggles with refining capacity in Latin America, and so we expect that to hold up longer-term.

Could you elaborate on your views regarding the duration of the IMO benefits? How do you see the ARB being competed away? I understand it will happen eventually, but so far, independent refiners have maintained a solid position in terms of incremental investment. Are you planning any significant investments to offset the ARB? Who do you think will be the competitors in this space? Is it the major oil companies and global national oil companies in Asia that are driving this competition? How do you envision this scenario unfolding?

I believe we will continue to invest in refining capacity in Asia since it is a significant fuel market. I anticipate that we'll maintain discipline and do not plan on making large investments, focusing instead on adjusting the portfolio. We currently have sufficient capability, and there may be minor adjustments over time. Historically, our industry has demonstrated an ability to maintain strong margins, despite fluctuations. I can't predict whether the distillate crack will be at $5 or $15, but it will likely be on the lower end for the next couple of years. However, looking ahead to 2019 or 2020, we should be optimistic about the refining business, its margins, and cash flow. Beyond that, projecting further out becomes quite challenging.

One other thing I would add is we're not seeing the adoption of scrubbers at the pace that we anticipated a few months ago. I think it's been much lower, and depending on the availability of the 3.5 fuel; after the changes are implemented, perhaps there may be a more rapid adoption of scrubbers, but that's going to depend on the availability of the fuel and a number of items that are just hard to predict at this time.

I guess the other thing longer-term too in terms of new builds in the shipping industry; if you relate the high end of the range, I think people have to start talking about LNG and other options too. So I mean these things always come into balance by many factors really; we're working on that equation; it's not just going to be refining capacity; it's going to be the choice of the ship owners and we'll see where it goes.

I wanted to ask this in a different way. We have discussed IMO and the discrete window, and I agree that this is something that gets competed away. However, if we consider increasing clean product yields, especially with a few projects in the fourth quarter and some trials that you have already undertaken, there is a baseline growth in clean product demand globally and in export demand. This seems like something that can be built upon. So, aside from IMO, I would like to know your thoughts on how this ramps up over multiple years. How do you plan to invest incrementally towards this growth, separate from the impact of IMO, which seems to represent just an upside shock, but rather focusing on the secular growth that we have observed over several years? What kind of incremental investment can we anticipate in relation to that?

From our perspective, we are investing around $300 million a year in refining to either improve yields or access more advantageous crude. Another aspect we haven't discussed today, which we could have addressed in previous conversations, is our shift towards higher octane fuel. Over the next 10 to 15 years, assuming progress is made within the next year, the industry will invest in developing higher octane fuel. This will create investment opportunities for refiners and for PSX in the form of solid, high-returning projects rather than just multi-million dollar investments. The industry consistently shows its ability to enhance performance during turnarounds by replacing bottleneck components, which allows a 1% to 2% improvement per year. I believe we will continue to see this trend in the industry as we advance. Therefore, expect a mix of targeted investments to improve yield and access better crude, along with the gradual improvements we typically see in the industry.

There aren't attractive projects to invest in; we'll continue to buy back stock and reduce the share count and make it accretive that way.

Greg, you provided a lot of detail about the timing for the second cracker, but I want to shift the focus towards the timing of how major companies are announcing their plans for petrochemical investments. Over the past few months, how have the industry's project book and valuations been changing, and are those dynamics influencing your plans for another cracker in the Gulf? I'm interested in the timing aspect, as there are many factors to consider, rather than just discussing margin recoveries.

Well, I mean certainly it's a joint decision between the owners of CPChem, and I think we have to have an agreed view on when the appropriate time for that cracker is. At the CPChem level, we're thinking about how do we move our products into the market in the most efficient manner, and we're the world's largest producer of high-density polyethylene, and these projects are generally geared towards that. Although we've added quite a bit of NAO capacity over the past couple of years also. So we're thinking about how do we efficiently move these products into the market; and so that's one thing we think about in terms of the timing decision. Obviously, NGL supply feedstock supply also factors into those decisions of where you're going to build it and what you're going to build, ethane or some LPG cracker. And so I think that there are multiple decision points that we go through when we're thinking about the timing on a cracker. One other thing we wanted to make sure that there was some daylight in between when this Gulf Coast cracker project one came out and when we would do the second one. And so you kind of think of coming up in '18 and having most of '19; it seems like appropriate timing to us for an FID in late '19 and really getting started in earnest in '20 and '21 on the construction.

I have a few quick questions. Kevin, I recall that last year or a couple of years ago, you mentioned the goal of keeping consolidated debt flat to reduce some of the C-corp level at the MLP level. Is that still the plan moving forward? It seems like over the past couple of years, that has increased. Should we expect cash flow to rise further in the next 12 to 18 months? Will you allocate a portion of that to pay down your debt?

Some of this has been due to an increase in debt at a consolidated level over the past year or two, largely driven by the transaction we completed in the first quarter with the significant share buybacks, which added $1.5 billion of debt that we had not anticipated. However, looking ahead, we see a period of reasonably strong margins, with new projects being launched and chemicals with new assets becoming operational, leading to expected increased distributions. We believe we will have the capacity to pay down some of that debt in the next couple of years. We could potentially reduce debt by about $1 billion or $1.5 billion within that timeframe if margins perform as we anticipate.

But you don't want to do even more than just $1 billion, $1.5 billion from the current rate?

It depends on the available alternative opportunities. The $1.5 billion we just added is clearly additional debt, so it would be beneficial to address that over the next couple of years. After that, it will be about finding the best use of our cash, which will rely on the investment opportunities we encounter, the share price, and any potential for share buybacks. This will involve a constant balancing act in our capital allocation decisions.

I think one thing that hasn't changed is really our view that we want to maintain a strong investment-grade rating. So I think that really comes into play; we've always said around 30% debt to capital or 31% or so today, so we're slightly over that. But we'd use the 30% as kind of a proxy for a strong investment-grade rating. But as we look at the debt and the capacity that we have today, we're comfortable with this level of debt at the Company. And as we said, we've got strong investment-grade ratings today.

Greg, it seems that my understanding of the chemical is as you comment, you know as much as anyone; can you just give us a maybe easy way. With the new cracker, if we're looking at today's margin, what is the contribution off the net income to you guys going to be?

Well, from an EBITDA basis, kind of at today's margins at the CPChem level, kind of $1 billion to $1.2 billion. So $500 million to $600 million of EBITDA back to us is an easy way to think about that.

Okay. So if today's margin holds, the ethylene margin is quite low, and it would need to improve from last year. So incrementally, based on the ethylene margin, is that $1.2 billion solely related to the ethylene margin?

No, that's a full chain margin.

But you already have the PE margin from last year, right. So yes, I'm looking at incrementally with these clean crackers coming on-stream; so what is the additional uptake that we should assume?

First of all, we were in startup mode during the fourth quarter of last year. We were using ethylene that was either in inventory or purchased, so we didn't fully experience the impact of the new cracker being operational. The new cracker is likely our lowest cost addition when considering our value chain and the other crackers in our system. Therefore, I believe that the $1.2 billion is a reasonable estimate if you want to think about this year on an annual basis.

Final one for me; how much can you assess by pipeline into your refinery?

For commercial reasons, we don't talk about individual sourcing of feedstock for individual refineries.

Can you tell us which refinery you have mostly won contracts with in Berga, and what about Ponca City and the others? Can you share any insight on which ones might have access?

Well, I think as you look at the Phillips 66 portfolio, we're roughly 35% heavy, 35% medium, and 30% light on the portfolio as a whole.

And some of that light is imported.

Thank you, Sharon. And thank all of you for your interest in Phillips 66. If you have additional questions, please call Rosie or me. Thank you.