Phillips 66 (PSX) — Q3 2017 Earnings Call Transcript

Welcome to the Phillips 66 Third Quarter Earnings Conference Call. Participants on today's call will include Greg Garland, Chairman and CEO; Tim Taylor, President; Kevin Mitchell, Executive Vice President and CFO. The presentation material we will be using during the call can be found on our Investor Relations section of our Phillips 66 website along with supplemental financial and operating information. Slide two contains our Safe Harbor statement. It is a reminder that we will be making forward-looking statements during the presentation and our 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.

Okay. Jeff. Thank you. Welcome, everyone, and thank you for joining us today. During the quarter, the Gulf Coast region was impacted by Hurricane Harvey. We're very proud of how our employees responded to the challenges caused by this storm. They did extraordinary things to help their families, friends, and neighbors, and they worked to safeguard our assets and communities. Through these efforts we were able to ensure critical energy products were supplied to first responders, businesses and consumers. For the third quarter, adjusted earnings were $858 million, or $1.66 per share. Our Refining utilization rate was 98% for the quarter. We operated well across our Refining system. Utilization for Atlantic Basin and West Coast regions exceeded 100%. Our Gulf Coast region ran at 93%, reflecting hurricane impacts at Sweeny. Our Chemicals businesses, on the other hand, were challenged due to extended downtime related to the storm. In advance of the hurricane, operations were shut down at several of our Gulf Coast facilities where we have Refining, Chemical and Midstream assets. In early September, we started up many of these assets, including facilities at Sweeny, which were back to full operations by mid-September. Our Lake Charles and Alliance refineries ran through the storm with minimal operational issues. Our employees worked through the logistical challenges to get crude in our refineries and ensured products were getting out to market. Additionally, in Midstream we took operations down at the Pasadena, Beaumont and Freeport terminals. These facilities all resumed operations in early September. Our most significant impact was in Chemicals at the CPChem Cedar Bayou facility in Baytown, Texas. Cedar Bayou received 60 inches of rain and poured 8 feet of water in various locations within the facility. A phased start-up of operations is underway with most units expected to be online by the end of November. We remain focused on executing our strategy. We're committed to operating safely, reliably and in an environmentally responsible manner. We demonstrated this commitment during the storm and the aftermath. We have also made progress this quarter advancing key growth and return projects. In Midstream, we continue to invest in the Beaumont Terminal to increase our storage and export capabilities. We're building additional 3.5 million barrels of crude storage, which is expected to be in service by the end of 2018. We're also expanding the terminal's export facilities from 400,000 barrels a day to 600,000 barrels a day. This is scheduled to be completed in the first quarter of 2018. Earlier this month, we contributed in Merey Sweeny and our 25% interest in the Bakken pipeline to Phillips 66 partners in a $2.4 billion transaction. This is the largest acquisition to date for PSXP. PSXP is well positioned to achieve its goal of $1.1 billion run rate adjusted EBITDA by the end of 2018. DCP Midstream is increasing the Sand Hills NGL pipeline capacity from 280,000 barrels a day to 365,000 barrels a day and is expected to be in service by the end of the year. DCP plans to further expand the capacity to 450,000 barrels a day in the second half of 2018. Sand Hills is owned two-thirds by DCP and one-third by Phillips 66 partners. Also, DCP continues to focus on expansions in high-growth basins. The Mewbourn 3 gas processing plant being constructed in the DJ basin is expected to start up in the fourth quarter 2018. Also in the DJ, the O'Connor 2 gas processing plant is scheduled to be complete in 2019. In the Permian Basin, DCP plans to jointly develop the Gulf Coast Express Pipeline to link natural gas production to markets along the Texas Gulf Coast. In Chemicals, CPChem started up two new 1.1 billion pound per year polyethylene units. Through the impacts of Hurricane Harvey, we now expect commissioning of the new Cedar Bayou ethane cracker to begin in the first quarter of 2018. Together these assets will increase CPChem's global ethylene and polyethylene capacity by approximately one-third. In Refining, we're progressing return projects to include improved clean product yields. A diesel recovery project in the Ponca City Refinery is on track to start up in the fourth quarter. We're modernizing FCC units at both the Bayway and Wood River Refineries. We expect these projects to be completed in the first half of 2018. Financial discipline, with an emphasis on returns, and prudent capital allocation is fundamental to our strategy. We're further lowering our 2017 capital expenditures guidance to about $2 billion. During the quarter, we returned over $800 million to shareholders through dividends and share repurchases. Earlier in October, our board approved a new $3 billion share repurchase program. The new program increases the company's total share repurchase authorizations to $12 billion since 2012. So with that, I'll turn the call over to Kevin to review the financials.

Thank you, Greg. Let's start with an overview on slide four. Third quarter earnings were $823 million. We had special items that netted to a loss of $35 million. The largest of which was $44 million of after tax hurricane-related costs. After excluding these items, adjusted earnings were $858 million or $1.66 per share. Excluding a negative working capital impact of $195 million, cash from operations was $596 million. This also reflected the impact of a $390 million discretionary contribution to the pension plan in the quarter. Capital spending for the quarter was $367 million with $209 million spent on growth projects. Distributions to shareholders in the third quarter consisted of $356 million in dividends and $461 million in share repurchases. We finished the quarter with a net debt-to-capital ratio of 27%. Our adjusted effective income tax rate was 33%. Annualized adjusted year-to-date return on capital employed was 8%. Slide five compares third quarter and second quarter adjusted earnings by segment. Quarter-over-quarter, adjusted earnings increased by $289 million, driven by improvements in Refining, partially offset by lower Chemicals results. Slide six shows our Midstream results. Transportation-adjusted net income for the quarter was $98 million, up $24 million from the prior quarter. The increase was due to a full quarter of commercial operations on the Bakken pipeline. In addition, we had higher crude oil throughput volumes due to high utilization at refineries integrated with our Midstream assets. In NGL, the $14 million decrease from the prior quarter was largely due to hurricane impacts on fractionation and export volumes. DCP Midstream had adjusted net income of $1 million in the third quarter. The $12 million decrease from the second quarter was due to the impact of rising NGL prices on forward hedges, as well as $6 million of asset impairments. After removing non-controlling interests of $32 million, Midstream's third quarter adjusted earnings were $67 million, $3 million higher than the second quarter. Turning to Chemicals on slide seven, third quarter adjusted earnings for the segment were $153 million, $43 million lower than the second quarter. In Olefins and Polyolefins, adjusted earnings decreased by $42 million, primarily due to lower margins and volumes from hurricane-related downtime, which resulted in 83% utilization. The earnings impact from low utilization was somewhat mitigated by inventory drawdown during the quarter. Adjusted earnings for SA&S increased by $1 million, as higher equity earnings resulting from less unplanned downtime, was mostly offset by lower margins. In Refining, crude utilization was 98% for the quarter, consistent with the second quarter. Pre-tax turnaround costs were $43 million, $111 million lower than the second quarter. Clean product yield was 85%, consistent with the prior quarter. Realized margin was $10.49 per barrel, up from $8.44 per barrel last quarter. The chart on slide eight provides a regional view of the change in adjusted earnings. In total, the Refining segment had adjusted earnings of $548 million, a $315 million improvement from last quarter. This increase was driven by improved margins in all regions and lower turnaround costs. Adjusted earnings in the Atlantic Basin were $172 million, up $63 million from the second quarter. The increase was primarily driven by a 25% improvement in the market crack during the third quarter. The Gulf Coast adjusted earnings improved $21 million during the quarter, due to the higher market crack. Partially offset by lower clean product utilizations and lower volumes. The lower utilizations resulted from the rise in prices relative to the timing of pipeline shipments and Sweeny refinery downtime during the highest margin period of the quarter. Adjusted earnings in the central corridor were $198 million, up $169 million from the previous quarter. The increase was driven by a 42% improvement in the market crack as well as lower turnaround costs and higher volumes as the Billings refinery completed a turnaround in the second quarter. In the West Coast, adjusted earnings improved $62 million over the previous quarter. The increase was primarily due to the higher distillate crack. Slide nine covers market capture. The 321 market crack for the quarter was $18.19 per barrel compared to $14.06 per barrel in the first quarter. Our realized margin for the third quarter was $10.49 per barrel resulting in an overall market capture of 58%, down slightly from 60% in the prior quarter. Market capture is impacted in part by the configuration of our refineries. During the third quarter, we made less gasoline and slightly more distillate than premised in the 3:2:1 market crack. Losses from secondary products of $2.10 per barrel were lower than the previous quarter due to improved NGL and fuel oil prices relative to crude. Feedstock advantage improved realized margins by $0.62 per barrel, which was consistent with the prior quarter. The other category mainly includes costs associated with RINs, outgoing freight, product differentials and inventory impacts. This category reduced realized margins by $3.20 per barrel compared with $1.30 per barrel in the prior quarter, mainly due to Gulf Coast clean product realizations and higher RINs costs. Let's move to Marketing and Specialties on slide 10. Adjusted third quarter earnings were $211 million, $7 million lower than the second quarter. In Marketing and Other, the $22 million decrease in adjusted earnings was largely due to lower realized margins. We continue to see volume uplift from our reimaging program with a 3% year-over-year improvement in gasoline sales at our reimage sites. Specialties' adjusted earnings were $48 million, an increase of $15 million over the prior quarter, mainly due to higher equity earnings from the Excel Paralubes joint venture, driven by higher utilization. On slide 11, the Corporate and Other segment had adjusted tax net costs of $121 million this quarter compared to $142 million in the prior quarter. The $21 million decrease in net costs was primarily due to tax adjustments. Slide 12 shows the changing cash during the year. We entered the year with $2.7 billion in cash on our balance sheet. Excluding working capital impacts, cash from operations for the first three quarters was about $2.6 billion. Working capital changes decreased cash flow by about $900 million, primarily due to inventory bills. Year-to-date, we funded approximately $1.3 billion of capital expenditures and investments and distributed $2.2 billion to shareholders in dividends and share repurchases. We ended the quarter with 507 million shares outstanding and our cash balance was $1.5 billion. This concludes my review of the financial and operational results. Next I'll cover a few outlook items. In the fourth quarter in Chemicals, we expect the global O&P utilization rate to be in the high 70%s due to continued downtime at CPChem Cedar Bayou facility. We expect most of the units to be online by the end of November. In Refining, we expect the worldwide crude utilization rate to be in the mid-90s and pre-tax turnaround expenses to be between $100 million and $130 million. We expect Corporate and Other costs to come in between $125 million and $145 million after tax. In December, we will provide further details on our 2018 capital program. With that, we will now open the line for questions.

Thank you. Good morning, team.

Good morning.

Good morning.

Greg or Kevin. I want to start on the $2 billion to $3 billion capital spending range for 2018. Very wide range kind of in line with our expectations. But given the fact that you've lowered 2017 capital spend, is it fair to assume that we should think that you're going to be erring on the lower end of that range? And recognizing that you're going to provide more color here in a couple weeks?

Yes, I mean, Neil, thanks for the question. I know someone said that's wide enough you could drive a truck through it. But it's been very consistent with the last couple of years we’ve been saying $1 billion sustaining capital and $1 billion to $2 billion of growth capital, and $1 billion to $2 billion of share repurchase. So we go to the board in early December on our capital budget, and I certainly don't want to front run that. But what I would tell you in terms of capital, we still expect we're going to be on the high end of that range. In terms of share repurchase, we don't expect we're going to be on the low end of that range.

Understood. Understood. On Chemicals, can you talk about Cedar Bayou, just in terms of project and service? I think you said by the end of November and what's left to be done mechanically there, and then again can you reiterate the targets for the end of the first quarter for the new chemical capacity to come online for next year?

Hi, Neil. It's Tim Taylor. In terms of the operating units at Cedar Bayou, we've gotten our first unit back up in operation in mid-October. It's the 1-hexene unit, which is a very critical component for polyethylene manufacturing globally. And we've done that. We're getting utilities back up as we speak. And we would anticipate that the cracker should be up by mid-November. And then there's a couple of polyethylene units that will come up maybe in early December. So essentially by mid-November, we expect to have most of that complex back up. And it's really around making sure the instrumentation that was wet is functional, replacing that, motors, and those kinds of things. So it tends to be a lot more electrical work in terms of the repair on the facility. And as you might guess, bringing back electrical power substations and switchgear for that. A similar story around the cracker. There's two things going on with the new cracker at Cedar Bayou. One, there was a need to repair some of the instruments and the motors that are associated with the new cracker. That's ongoing as well. But in conjunction with that, we've continued to work on completing the mechanical part of that. And that's gone well as well. So we've been able to pull the progress forward like we had hoped on both of those, and so the mechanical completion in the first quarter on the start-up looks in terms of feed in, we're still confident that we can hit that date and that really puts us, I think, in full commercial operation on new cracker in the second quarter. So, more to come as we go through that, but we have been pleased with the progress that everyone on the team out there has made in terms of their commitment, the organization and getting it done, and getting that unit back in operation.

Thanks, Tim.

Hi, Greg. More positive dynamics in many ways in Refining. Are you cheering up about it at all? I know you've been pretty resolutely determined not to increase any spending. Firstly, I was wondering is there any potential maybe on the strength for you to think harder about leaving California, which you might have talked about in the past. And then secondly, can you see a structurally better argument for the industry right now? Thanks.

Yes, so Paul, I would tell you, we're more constructive on refining for 2018. Certainly if you think back to 2016, coming into 2017, we were pretty negative. But we've seen the inventory clear out with the hurricanes; fundamentally, demand is pretty good. We're in the turnaround season now and in the first quarter. So I think we're starting to see mid-cycle or better in terms of cracks in 2018, and so we're pretty positive around that environment. The other thing I would just say is across the portfolio, we're pretty happy with the portfolio. You get frustrated from time to time with California and what goes on there, but still reasonably good assets, well positioned, generating good cash for us. And so I don't think you'll see us doing things with the California assets in the near term. And then fundamentally, I think about 2018 for us, we're coming off of kind of peak capital spending; we've got the new assets coming on, so we really are hitting the pivot point in terms of free cash flow generation for us with new cash coming from the assets coming on and reduced capital expenditures. So I think I'm pretty constructive about 2018.

And I guess, are you guys still relatively long distillate? I think that's always been the historic case. I wondered if others have kind of caught up with you.

So I think that's true. I think that when you look at our portfolio, how we're configured, we do like distillate because we make a lot of it.

Yes, and then could I just follow up did you just – forgive me if I missed this – did you just address – actually, I'll tell you what. I'll ask it a different way. One of the things that's happening with CapEx is that it's coming down on costs and we've heard actually ConocoPhillips say that one of the issues was that people have kind of tapped the brakes in the U.S. E&P and I can understand how that would temper costs. But it's not clear to me with relatively tight labor markets and ongoing expansions in chemicals, how the costs have come down so successfully given the scale of labor. Labor is part of the overall budgets there. Could you just talk a little bit about where the benefits and the cost benefits have come for you guys? Thanks.

Well, I think in terms of costs and construction costs, I'm not sure we've seen a big decrease yet. I think as the E&P tap the brakes that will free up some capacity. But there's still a ton of petrochemical going on, on the U.S. Gulf Coast. And so that obviously plays into that. But I don't think we've seen it.

My understanding was that your CapEx could come down again. And I guess it's got a very wide range because of that cost uncertainty. Is that fair because of the lower cost certainty.

Yes, Paul. So I would say the CapEx coming down is a function of a couple things. One is we're kind of through that big push in terms of the big projects we've been doing. And then led by you and others, I think there's an important conversation going on, on growth and returns in the upstream business. And as we look at what's going on out there, we see a lot of return challenged projects. And part of our reduction in capital this year has been around the delay of the frac decision. But it's also around some projects that we've just chosen not to proceed with that we had laid in the plan because they didn't meet our return hurdle requirements. So I think you had that dynamic going on too. And then everyone's looking at the Permian. And in a $40, $60 world it seems to make sense. But everyone sees the opportunity, and so there's a lot of people chasing the volumes coming out of the Permian. And you just look at those returns, and those are tough returns, particularly in the Midstream space.

Got it. Thanks, Greg. Have a good weekend.

You too. Thanks, Paul.

Thank you. Good morning, everybody.

Hey, Doug.

Greg, I wonder if you can give us an update on the thoughts on CPChem going to cracker 2. Obviously we're seeing some swings in the dividend distribution, it looks like. And I'm just curious if the appetite on both partners is the same to move forward and when you might expect to hear about it.

So I would tell you that, I mean we are advancing the next project. We're doing engineering work on it. We haven't agreed on a date for the FID for that project. But I'm guessing it's sometime late 2019, 2020 would be the appropriate time on that, Doug.

So just to be clear. That would be funded at the CPChem level. In other words, that would obviously impact distributions.

Correct.

Doug, it depends a bit on the capital structure. They have the ability, clearly, with a great credit rating. And they have the ability to help finance those projects. And so I think that's the other variable to distribution policy. But I think both owners want to see distributions continue, yet we have to do that in the most capital-efficient way. The only other comment I'd add on that too is that CPChem continues to look outside the U.S. for opportunities as well. And so I think there's a number of things that they're looking at beyond just a U.S. Gulf Coast cracker for the second project.

Okay. I appreciate that, Tim. Thank you. My follow up, Greg, is kind of a bit of a convoluted question, I guess. Before we had the export ban lifted on crude oil, the whole industry seemed to pivot to take advantage of what seemed to be something of a structural crude spread. I realize it's there now, but I don't think, I guess there was a debate over how wide that remains. But my point is, or my question is rather, that as you see pricing exports really ramp up in the U.S. from the Gulf Coast, pricing in Gulf Coast crude, light sweet crude seems to be linking more to Brent than to WTI, let's say. So I'm just curious. Does that change the dynamics of your crude slate? Do you see more challenged pricing coming from that shift towards lighter sweet crude? Or do you think it just kind of washes out? I'm just curious on your perception. I'll leave it there. Thanks.

I'll let Tim take it.

Doug, as we think about it, you're right. The Gulf Coast is much more linked to Brent because you've got the opportunity for imports as well as exports. What's interesting right now is the pull on WTI and more the inland crudes to make it there to the export market. And so we've actually seen some infrastructure bottlenecks that probably get alleviated, but probably speak to a wider WTI-Brent, a little wider than we would have expected probably over the last year. In terms of crude slate, I think from our perspective it certainly gives the mid-con WTI's advantage versus Brent, that's a positive for that. I think on the coastal regions it just increases your optionality if you're looking at light crudes to import or to use U.S. crude. So I think the world is just kind of rebalancing about what the optimum crude on the light side is. We haven't seen much of an economic incentive to really change between light and heavy. And so it will take a lot more differential to drive that. So I think it's really been more about crude choices and I think the world is sorting out where is the best destination for the different crude types that become available. But the coastal regions are just much more competitive on that basis.

Tim, can you offer a perspective on what's keeping TI Brent so wide as it stands today?

I think to us, A, the hurricane costs and disruptions in terms of export capability, we've seen really strong exports out of the U.S. And with that disconnect, there's a need to try and move that WTI, particularly from Cushing and other areas down into the export market. And that space has just really become more valuable. So I think the response has been that the transportation cost to get it there has gone up, and that's led to a wider differential, that probably comes in over time as that gets debottlenecked, but it looks structurally – as we think about the demand export pull, we think that leads to a bit wider WTI-Brent, but probably not in the range that we're seeing today. It should be tighter.

So TI has been weaker, but Brent's been stronger. I think that's part of the formula, too. And I think when we think about the fourth quarter turnarounds, et cetera, we're probably $4 to $6 on that spread. But I don't think that's sustainable long-term. I think as you get into 2018 and some of the infrastructure, you get normalization in the markets. We're still thinking long-term that that spread is something under $4.

Yeah.

Thanks, fellows. I look forward to seeing you in December. Thanks.

Okay. Take care.

Thank you, Julie, and thank all of you for your interest in Phillips 66. If you have additional questions, please call Rosy, C.W. or me. Thank you.