Plains All American Pipeline LP (PAA) 2019 Q3 法說會逐字稿

Good day, and welcome to the PAA and PAGP Third Quarter 2019 Earnings Call. Today's conference is being recorded.

And at this time, I'd like to turn the conference over to Roy Lamoreaux, Vice President of Investor Relations and Communications. Please go ahead, sir.

Thank you, Eduardo. Good afternoon and welcome to Plains All American's Third Quarter 2019 Earnings Conference Call. Today's slide presentation is posted on the Investor Relations News and Events section of our website at plainsallamerican.com.

Slide 2 contains important disclosures regarding forward-looking statements and non-GAAP financial measures. The appendix includes condensed consolidating balance sheet information for PAGP.

Today's call will be hosted by Willie Chiang, Chief Executive Officer; and Al Swanson, Executive Vice President and Chief Financial Officer. Additionally, Harry Pefanis, President and Chief Commercial Officer; Jeremy Goebel, Executive Vice President, Commercial; and Chris Chandler, Executive Vice President and Chief Operating Officer, along with other members of our senior management team are available for the Q&A portion of today's call.

With that, I will now turn the call over to Willie.

Thanks, Roy. Good afternoon, everyone, and thank you for joining our call.

Let me begin by hitting the high points of the information that we released this afternoon. We're pleased to report solid third quarter earnings results. As outlined on Slide 3, these results exceeded expectations in our fee-based segments and reflect the continuation of strong performance in our Supply and Logistics or S&L segment. As Al will discuss more in detail, we have increased our 2019 full year adjusted EBITDA guidance by $100 million to plus or minus $3.075 billion. And we have decreased our 2019 growth capital program by $150 million to $1.35 billion.

Additionally, our preliminary guidance for 2020 adjusted EBITDA is approximately $2.55 billion to $2.6 billion. This is composed of $2.5 billion for our fee-based businesses, reflecting fee-based growth of approximately $100 million which includes offsetting an estimated $85 million of expected impacts from the competitive environment. Our preliminary adjusted EBITDA guidance for our S&L segment is $50 million to $100 million. Our preliminary 2020 growth capital guidance is $1.35 billion, and we expect meaningful reduction on our capital investment programs in 2021 and beyond as we complete our current capital program.

Let me put our preliminary 2020 guidance into context with respect to the Permian production growth. During 2018, Permian production grew by approximately 1 million barrels a day, and we expect 2019 growth of approximately 800,000 barrels a day. For the full year 2020, we expect Permian production to grow, on average, approximately 500,000 barrels a day which is about 100,000 barrels a day on average less than our prior estimate as we have further calibrated the anticipated impact of producer capital discipline on drilling and completion activity. I would note that we expect 2020 Permian production to end the year 300,000 to 400,000 barrels a day higher than year-end 2019.

Accordingly, our 2020 preliminary guidance reflects a moderated rate of year-over-year fee-based growth, it includes the impact of the more competitive environment as well as a lower level of S&L earnings as new Permian takeaway capacity is placed into service. The new takeaway capacity relieves infrastructure constraints, which have supported strong spot volume throughput and high utilization on our Permian long-haul systems.

Beyond 2020, our next wave of fee-based growth is underpinned by multiple strategic, capital-efficient and highly contracted projects that phase into service from late 2020 through 2021. These are outlined on slides 4 through 7 and highlight our focus on optimizing our existing systems and aligning with strategic partners throughout the crude oil value chain. These projects are supported by long-term third-party commitments and provide solid visibility for fee-based growth as we enter 2021. Additionally, these projects meet or exceed our targeted return thresholds, and we plan to fund them with non-dilutive sources, providing strong growth in DCF per common unit in 2021 and beyond.

Now let me share some brief comments on several of the projects. With respect to Permian long-haul projects, as shown on Slide 5, we placed the Cactus II pipeline into initial service in mid-August and have established connectivity to Taft, Ingleside and Corpus Christi. The pipeline is mechanically complete and has demonstrated its design capacity of 600,000 barrels a day and is currently meeting customer nominations for deliveries to these markets.

On Wink to Webster, we're advancing the project consistent with our expectations and expect the pipeline construction to begin before year-end. We have ordered the majority of the long-lead equipment. We continue to acquire right of way and we're targeting in-service in early 2021.

The Wink to Webster JV has completed an undivided joint ownership arrangement with an undisclosed third party who has acquired 29% of the pipeline's capacity in the Midland to Webster segment of the project. The JV now owns 71% of this segment but the respective interests of the JV owners at the Wink to Webster JV level have not changed. I would note that our estimated net project cost remains directionally in line with the cost described on our previous earnings conference call, which already accounted for this undivided joint interest arrangement.

Beyond the Permian, we continue to advance a number of projects that leverage our existing pipeline systems and hub terminals. As shown on Slide 6, upstream of Cushing, we are advancing potential expansion and optimization opportunities on our Rangeland and Western Corridor systems that have the potential to provide pull-through benefits to our systems downstream. Additionally, as previously announced, White Cliffs is completing a line conversion to NGL service and Saddlehorn is advancing a fully committed 100,000 barrel a day capacity expansion. As announced previously, we provided an option to a third party through the first quarter of 2020 to acquire a 10% interest from us in the Saddlehorn JV.

Moving to Slide 7. Downstream of Cushing, we are advancing the Red Oak JV pipeline project. We continue to target bringing Red Oak into initial service in the first half of 2021. Additionally, the Diamond expansion and Capline reversal is progressing. We are preparing to order long-lead equipment required for the project and continue to advance efforts to secure additional committed volumes. I will note that we have extended the in-service timing for the light crude service to the first half of 2021 to better reflect our current estimates for establishing full connectivity of Diamond into the Capline system.

Before turning the call over to Al, I would also mention that our Red River JV expansion is progressing on schedule and we're progressing the Cushing Connect JV with Holly Energy Partners that we announced on October. Both of these demand pull systems are underpinned by long-term third-party commitments.

With that, I'll turn it over to Al.

Thanks, Willie.

During my portion of the call, I'll share a brief recap of our third quarter results, provide additional information on our guidance for 2019 and our 2020 preliminary guidance and review our current capitalization, liquidity and leverage metrics.

Our third quarter adjusted EBITDA of $731 million represents a year-over-year increase of 15% driven by solid fee-based performance and strong S&L performance.

Moving to Slide 8. Our third quarter fee-based results of $635 million exceeded expectations and on a sequential basis were driven by higher than anticipated Permian gathering volumes and the early start-up of Cactus II. These fee-based results represent a year-over-year increase of 13% and an increase of 9% over the second quarter 2019. Our S&L performance reflects favorable crude oil differentials in the Permian Basin.

Slide 9 provides an overview of our updated fee-based guidance for 2019, our preliminary fee-based guidance for 2020 and our estimated growth CapEx for both years. We expect to generate more than $1 billion of cash flow in excess of distributions for 2019, resulting in full year common unit distribution coverage of more than 200% and per unit results that exceed our prior expectations. Additionally, we have reduced our 2019 capital program by $150 million to plus or minus $1.35 billion, reflecting some shift of capital investment to 2020 as well as some optimization of project scope and lower costs.

With respect to our 2020 preliminary adjusted EBITDA guidance, let me build on a few of Willie's comments. From 1Q '17 through 3Q '19, we nearly doubled our Permian tariff volumes, averaging quarterly growth of approximately 230,000 barrels per day. This includes more than 95% growth on our long-haul systems which for the first 3 quarters of 2019 have operated at effectively 100% utilization. Our 2019 results also benefited from accelerating the Cactus II pipeline into initial service in mid-August. We expect Cactus II and our total Permian tariff volumes to continue to grow in 2020.

In total, our 2020 preliminary adjusted EBITDA guidance reflects year-over-year fee-based growth of plus or minus $100 million and S&L margins consistent with our long-held and public expectation for increased crude oil lease gathering competition and narrowing regional differentials, particularly in the Permian. As we indicated at our Investor Day presentation in June, our 2020 fee-based growth is expected to be partially offset by lower utilization of spot capacity on several long-haul lines primarily in the Permian Basin. Accordingly, our 2020 fee-based adjusted EBITDA guidance absorbs an estimated $85 million impact primarily from these factors.

Looking forward, we believe this amount captures the large majority of the expected impact of competition, including narrowing differentials and changing flows for the next several years. Furthermore, we have meaningful contractual support across our systems and we do not have material contract renewals for several years. Our 2020 preliminary guidance also includes the impact of approximately $100 million of asset sales we expect to complete in early 2020, which includes an assumption that the purchase option is exercised on Saddlehorn.

With respect to our capital program, our 2020 preliminary CapEx guidance of plus or minus $1.35 billion assumes approximately $300 million of our net CapEx is funded via project debt within the Red Oak JV entity and therefore is not included in the $1.35 billion amount. Consistent with our targeted financing structure, our 2020 capital program is expected to be funded with excess distributable cash flow and asset sales and the balance with long-term debt. We do not expect to issue common equity to fund our 2020 capital program. We may consider additional preferred equity depending on funding requirements and market conditions.

Before moving from Slide 9, I would point out that over the last several years, we have funded over $4 billion of the capital investments with asset sales and S&L overperformance. As mentioned previously, we have incorporated $100 million of asset sales into our 2020 guidance and we continue to evaluate additional divestiture opportunities. If successful, proceeds would be used consistent with our capital allocation levers to fund capital investment, pay down debt or return capital to our investors.

Moving on to our capitalization and liquidity as illustrated on Slide 10. At quarter end, we had a long-term debt to adjusted EBITDA ratio of 2.8x, which has benefited from S&L overperformance over the last 12 months. As described on our last earnings call, we expect our leverage to tick a bit higher in 2020 as we complete our capital program, but we remain focused on continuing to migrate leverage with a moderated S&L contribution down within our targeted long-term debt to adjusted EBITDA range of 3.0 to 3.5x.

As a reminder, the rating agencies make certain adjustments for their leverage calculations, including for our preferred equity securities. The current adjustments add roughly 3/4 of a turn. So the 3.25x midpoint of our target range would currently equate to roughly 4.0x on a rating agency basis. Reducing our leverage to these levels is consistent with our objective of achieving mid-BBB credit ratings over time.

In September, we completed a public offering of $1 billion of 3.55% senior unsecured notes due December 2029. We intend to use the proceeds in the fourth quarter to retire our $500 million notes due in December and $500 million notes due January 2020, which together had an average interest rate of 4.2%. I would also note that in mid-October one of the rating agencies changed their outlook on our credit rating from stable to positive, reflecting progress we have made.

We expect to end 2019 with significant committed liquidity and well positioned to continue to finance our growth investments in 2020. We look forward to providing an update on our progress and provide full 2020 guidance during our year-end conference call in February.

With that, I'll turn the call back over to Willie.

Thanks, Al.

Thus far in 2019, we've delivered solid fee-based results, enhanced by strong S&L execution in a period of favorable market conditions. In addition, we've continued to advance our ongoing efforts to improve the safety and reliability of our operations with strong performance in those areas year-to-date.

Looking forward, we've aligned ourselves with long-term industry partners across the value chain, which allows us to build and optimize capital-efficient projects, help solve industry needs and secure returns that meet or exceed our hurdle rate above our weighted average cost of capital. We remain focused on continuing to grow our fee-based business through the completion of our current capital program and ongoing optimization efforts while maintaining a strong balance sheet and credit profile.

As Al mentioned, we will also continue to look at portfolio optimization and additional potential asset sales. Acknowledging the headwinds described throughout our call, we believe we're well positioned for 2020 and beyond. Initiatives described throughout the call drive cash flow as we complete our current capital program, which will allow us to further balance our capital allocation levers, including leverage reduction and returning capital to unitholders in the next few years.

A summary of our performance versus our 2019 goals is included as well as key takeaways from today's call shown on Slide 11 and 12. We look forward to updating you in February with our full 2020 guidance.

And before I turn it over to Roy, I do want to make a clarification. When I talked about our Cactus II pipeline, it is mechanically complete. I may have referred to it as 600,000 barrels a day of demonstrated design capacity. The correct number is 670,000 barrels a day of design capacity.

With that, I'll turn it back to you, Roy.

Thanks, Willie. (Operator Instructions) Additionally, Brett Magill and I plan to be available this evening and tomorrow to address additional questions. Eduardo, we're now ready to open the call for questions.

(Operator Instructions) We'll now take our first question from Jeremy Tonet at JPMorgan.

I want to start off with capital allocation philosophy. And you touched on it a lot of different ways during the call, but just wanted to bring it back in light of kind of where the share price sits right now and how it's kind of declined and how you think about stacking capital for the projects that you have, if they could be scaled, if they could be JV-ed, portfolio optimization and thoughts on whether buybacks at any point in the future could make sense just kind of given the levels where it's trading at right now, how that all kind of plays together.

Jeremy, this is Willie. Let me make a couple of comments then I'll ask Al to add to it. I mean, clearly, we've got a capital program that's going on for this year and next year. We need to continue to allocate capital to complete that. Priority one is to get that done. We always look at ways that we can improve the returns of projects. As you've seen, we've brought additional partners into that. We'll continue to look at that. But we really hit a point of inflection in 2021 where the cash flow starts kicking in from the completed capital projects and our capital load starts dropping. So at that point, it gives us more flexibility to do things.

And then the other thing we're looking, as Al talked about, we continue to look at potential asset sales and even some other ways to -- additional cash to give ourselves some more financial flexibility. So that's kind of the base case. Depending on if we get some excess earnings from S&L and/or asset sales, there's a possibility for shareholder return. We would only buy shares back if they were value compelling. We have had discussions with our Board on it, and we would be able to move quickly on it. But at this point, our focus is really to get our capital projects done and get ourselves moving where we can get some of the cash in the door. Al?

Willie, I think you hit it. Clearly, it's one of the prongs of our capital allocation strategy. As Willie mentioned, we've had discussions with our Board. We think we could implement a program very quickly. It's just right now we're prioritizing leverage and funding what we think are very highly strategic and accretive projects. But there will be a time when we'll prioritize it if it makes sense at the time when we get there.

That makes sense. That's helpful. And there's been a lot of talk in the marketplace as we've seen over time with the Permian takeaway competition kind of ramping up and seems like we're at the precipice of it right now with some competitor pipes entering service. And so just want to see if you could provide any more color on 4Q Transportation. Looks like the guide embeds a little bit of a step-down there. And so just want to see given that we're partway into the quarter right now what level of comfort do you have as far as kind of hitting that number. Just any color you can provide there would be helpful.

Jeremy, let me ask Jeremy Goebel to address that.

Jeremy, first of all, to answer the second part of your question, the near term. What we were doing is reflecting a surge in production. We saw spot capacity and regional differentials across multiple pipes and multiple regions that supported spot capacity. We forecasted in Q4 additional takeaway capacity from regions coming on. Cactus II came on which is different than some -- that rolled in but some of the spot capacity we value differently in the fourth quarter. As we go through the quarter, we feel comfortable where the projection is.

Going into next year and beyond, I think Al touched on it during the call and Willie did as well that our forecast for next year reflects our view of what regional differentials are and what we view spot capacity and allocation will be. It steps up year-over-year as the surge in production we're seeing now that's come into our system maintains. One thing to take away from the call is, we've been preparing for this environment for several years. We've been firming up our lease supply. We've been ensuring we have the right upstream and downstream connectivity to provide our customers the utmost connectivity and most efficient way to get from the wellhead to the market.

In addition, that termed up lease supply gives us opportunities to make sure that where we have slack, we can optimize utilization of our pipeline systems. On top of that, we have substantial long-term commitments that I think both Willie and Al talked about. That's why we get excited about the projects we do. We have long-term industry partners, long-term contracts. That, combined with our marketing position, gives us an ability to make sure our pipes stays full and optimize their capacity.

(Operator Instructions) We'll now take the next question from Shneur Gershuni at UBS.

Just wanted to actually talk about Permian takeaway capacity for a little bit here. Some of your peers have mentioned the high cost of using DRA and how much capacity it's added to the overall Permian takeaway system. So with spreads seriously compressing and probably expensive to use DRA, do you have a sense of how much capacity could be taken out of Permian takeaway capacity as a result of sort of taking out this peak capacity of sorts?

Yes. Shneur, this is Chris Chandler. The short answer is, we don't have an estimate of how much capacity could be taken out if DRA usage was stopped, but it is something that we optimize on a daily basis. We take into account things like power cost, pipeline flow rate and crude quality. And it's a continuous optimization. And really, in some cases, some of our more recent pipelines have been designed to utilize a baseload of DRA. So it's unrealistic that DRA would be removed completely from use in our pipelines.

Shneur, this is Willie. A good rule of thumb is plus or minus 20% on capacity for DRA, just a general comment.

Perfect. Okay. And as a follow-up question. I know that you've sort of given us an initial outlook on '20 and my question is about, to be about '21. But as you sort of look at the projects that you currently have complete visibility on right now that you're building out and so forth. When I look at Slide 9, you sort of have plus '21 with CapEx being meaningfully lower in '21 versus the current year and it sort of seems to be suggesting that there could be some incremental EBITDA growth in '21. Are we looking at something that can be pretty meaningful in '21 in terms of just the continued ramp? When you sort of think about the capital you're putting in place for '20, how much would still be ramping at the end of '20 and into '21? Do you have some sort of sense on that?

Yes. Shneur, I would look at it as these capital projects kicking in and getting the benefit of it. So it is a meaningful amount that would start ramping up in 2021.

We'll now take the next question from Tristan Richardson at SunTrust.

Just had a question, the new development on Wink to Webster. Can you talk a little bit about how the UJI came about? And typically, it seems like we've seen your equity partnerships focused on large customers that can bring volumes to bear. Kind of curious how this one came about.

Good afternoon. This is Jeremy. Look, we are always looking to optimize. If you remember, at this time, there were several competing projects for similar routes. Saddlehorn is an example when merged with Grand Mesa. This is optimizing long-term takeaway to ensure that there's sufficient takeaway to meet producers' needs, but at the same time making sure the industry is capital efficient.

Wink to Webster and its partners had a fully committed pipeline, but for the long-term benefit of the downstream refiners, the producers and the owners of the pipeline system, felt it made sense to merge the projects together and come up with a capital-efficient solution. You'll see us continue to do that in all the projects. Look at the White Cliffs project that we're reversing and turning into NGL service. I mentioned Saddlehorn, Grand Mesa, the Red River project, Diamond, Capline. All of these projects are taking existing capacity or bringing partners together that have potentially competing projects and trying to be capital efficient. So I think Wink to Webster was just another one where rational minds come together in the industry and take 2 projects and put together as one.

Tristan, I would characterize this as really a great example of what we mean by driving capital efficiency across both ourselves and the industry.

Appreciate it. And then, Al, you mentioned preferred equity as a potential tool in the toolbox. Could you talk about sort of maybe bookends sort of what kind of conditions you think that would make sense as a funding mechanism? Is it a balance sheet consideration? Just trying to think of what would set the stage that, that might be the best option.

Yes. Clearly, we view that our leverage will tick up in 2020 as we fund this capital program. So we view that as a funding tool. It'll be kind of done in concert if we were to do it in relation to how much assets we may identify to monetize, any changes in our CapEx program, if any, and kind of the way we look at the preferred security with the 50-50 kind of equity-debt weighting that the rating agencies ascribe to it versus our cost of capital. And I think ballpark, we have $800 million to $1 billion kind of in our basket that we could utilize so. But the security also is subject to market conditions in that. So we do view that as one of the things we'll be monitoring. And if we need to, to manage leverage or fund our program, we'll look to access that market.

We'll now take the next question from Gabe Moreen.

Two questions for me. One is in terms of the year-on-year Permian growth forecast of 300,000 to 400,000 barrels a day, whether that is conservative or aggressive, I guess, time will tell, but it seems a little bit more of a conservative number as compared to some, I think some other stuff that's out there. Can you talk about to what extent that's been developed in conjunction with talking to your producer customers versus whether that may be a PAA internal viewpoint?

Sure. This is Jeremy. We continually look at our forecast. It's continuous based on dialogue with customers, our own internal views. It's dialogue that our customers are having with the market. It may prove conservative. We basically look at, in this case, it's almost a run rate, say, in the 375 current rigs that are running, continue to run through 2020 is the perspective.

To be honest with you, 2018 ended with more production than we thought and so it began this year. So while activity continued to decline this year, our 2019 exit rate is higher than we had forecasted at the beginning of the year simply because of the momentum from 2018. It's quite possible that, that happens again. We expect 2019 to exit around 4.65 million barrels a day. In this forecast that Willie was working from, which is really a constant activity forecast and no efficiencies built in, gets you to roughly 5 million barrels a day exit next year.

That growth will be different by different operators. I mean you'll see some of the integrateds will far exceed historical growth rates and you'll see the levered E&Ps that have substantially lower. So it doesn't necessarily mean anything specific for specific operators. It just means that, look, that's our respective view of this activity level, the core assets and we view well performance will continue to slightly increase as lateral lengths get longer. On a normalized basis, it seems like it's fairly flat. So the impacts of parent-child relationships, we think our customers are working through it, that and well spacing, et cetera. So we continue to see the incremental well be better than the last well, a lot of it because of getting smarter. And so as we said, none of that's built in. What we've got is a continuation of current activity, and that's what yields that number.

And based on current, the kind of current price environment as well.

Correct.

And Gabe, this is Willie. To make sure I was clear when I described it. I gave 2 numbers. One was 2020 average versus 2019 average, which is the 500,000 number, which is a little lower than we expected before. And then the 300,000 to 400,000 number was year-end '19 to year-end '20, which reflects the back end of 2020 starting to taper off.

Got it. And then my follow-up question really is around some handholding around S&L, the $50 million to $100 million. To what extent you're protected on the downside if relationships get really out of whack in terms of Permian barrels selling at a premium because of MVC commitments and the like relative to Gulf Coast prices, how you feel that $50 million to $100 million might be your downside in a scenario like that?

This is Jeremy. I would look at it as that's our current reflection of all the impacts of S&L, S&Ls in Canada, S&Ls in the Rockies, S&Ls in the Permian. So we feel like we've got a good handle on those attributes.

With respect to the Permian, we can be the beneficiary being a pipeline operator and owner of capacity to multiple markets, plus the ability to sell into Midland. So to the extent that, that happens, there's ways for us to benefit as well. So I think our length in this situation will help us take advantage if that turns out to be. And we'll continue to look for opportunities to optimize around our asset base, our S&L footprint and through our marketing affiliate.

So that number, Jeremy touched on this. But really, it's a reflection of, when we look at our contractual commitments and our contractual position in 2020 and our volume forecast and like he said, rolling in the NGL as well, we think that's a pretty fair reflection of the opportunity set in 2020.

We'll now take the next question from Michael Blum at Wells Fargo.

My question really is about the asset sale approach for next year. I guess would that be discrete assets or would you also consider JV-ing the existing assets? And I guess within that context, specifically with Red Oak, are you sort of set at the current JV structure or is that something that you'd also be willing to sell down into as well?

Let me go ahead and take this one, Michael. I don't want to get too specific on asset sales. We've talked about the option on one of the pipelines. That's specific. We've been working a number of potential opportunities. And I would answer, it's really all of the above. As you've seen us implement over time, we do have some additional things we are looking at, but it's probably premature for us to give you specifics on that or give you a number on that. Jeremy, you want to add something?

Yes. I think Willie captured it. We're opportunistic. And we like our assets and won't sell them unless that there's valuation that we're comfortable with. But in addition, your question specifically on Red Oak, P 66 and Plains are always looking to optimize the ownership, the strategic alliances. It may be that we keep it this way. It may be that we bring someone in. It all will be based on the opportunity set.

We'll now take the next question from Keith Stanley at Wolfe Research.

The Q3 EBITDA was very strong in the Transportation segment and your updated guidance, it implies kind of a tick down in the fourth quarter in Transportation and in Facilities and volume's pretty flat. Just anything unusual going on there, is it just conservative in Q4 looking forward?

I believe this question was asked earlier, but I think very simply, there were -- Cactus II came online, and we have a surge of production from it. In addition, because we were the first project online, all of our Permian outlets all maintained full while Cactus II was at elevated rates. So we wouldn't expect that spot capacity on those volumes. In addition, there were some opportunities in the Rockies and others that had spot differentials. Red River pipeline was running at elevated levels. But our reflection next year is to step up $100 million from this year in spite of that as projects come online, as Cactus II fully ramps and towards the end of the year as Red River and Saddlehorn MVC step up. So we feel like next year reflects it, but Q3 was an instance where we had Cactus II full and every one of our Permian pipelines is full in addition to some Rockies opportunities and Red River.

On the Facility side also, there's a lot of spot activity that's hard to forecast. Natural gas assets, for instance, significantly overperformed relative to the guidance we had out there. So those are the types of things a little harder to anticipate quarter-to-quarter.

Got it. And just one quick follow-up on the sell-down of Wink to Webster, the 29% interest. Can you just confirm the party who acquired that interest has not disclosed that publicly to the market yet?

To our knowledge, they have not disclosed that.

We'll take the next question from Colton Bean at Tudor, Pickering, Holt & Co.

Just to follow up on the $50 million to $100 million of S&L next year. Could you give kind of the high-level breakdown of contribution between the Canadian NGL business and crude marketing?

We don't go into that type of detail on the guidance to tell you the truth.

And then I guess, as you look at that number, the assumption is that would be consistent with pretty tight spread environment on crude?

Yes. Correct. Next year is going to be competitive.

Got it. Well, I guess, do you see any impacts on the NGL side of the business? I mean the Edmonton spread has come in. So is that, that's all kind of dialed in here in that $50 million to $100 million?

Yes. It is.

Perfect. And then just on the $85 million, I think you referenced...

The Edmonton spread is on a short-term basis, the Canadian diffs have gotten weaker because of Keystone. Not sure that, that's something that persists on a long-term basis.

Got it. Okay. Is that on the crude side or...

That was on the crude side, actually, I was speaking to. On the NGL side, the differentials have compressed as well.

See, Colton, the reason we don't try to give too much more transparency is there's so many variables in the market that it really gets into a reconciliation nightmare on what might happen. So I think we'll just stick with our answer on the $50 million to $100 million and you know the components of what we do.

Understood. And just on the -- I think it was $85 million that you referenced in terms of Permian headwinds next year for Transportation. Can you just characterize where in the system that's hitting? Is that primarily long haul or are you seeing any impact closer to the wellhead?

Yes. I'll let Jeremy touch on this. The $85 million was really across our system. And it includes Permian long haul as well as some lower tariffs on some Rockies pipelines.

Yes. I think Willie covered it. It's primarily long haul but are a reflection of what we think the rates through Transportation, intra-basin transport, any changes to contracts we have within the basin, our view of what spreads are across the region was all impacted into that number.

As we've talked before, we've got this complex system that can get to different markets. When everything is constrained, everything's full going up to Cushing primarily. And with a lot of new pipelines that have been built, the volumes now are actually going to the Gulf Coast market. So a good portion of that reduction on long haul is on our basin system going up to Cushing.

Yes. And I would also add to this that when you think about our system and the movements within given basins, a lot of that is on long-term contracts just as the takeaway pipe. So when you think about it, our guidance next year reflects the combination of our views of intra-basin, long-haul, regional differentials, et cetera.

We'll now take the next question from Pearce Hammond at Simmons Energy.

Just one question for me. I'm curious if you have any update on the Eagle Ford terminals, Corpus Christi, the JV with Enterprise. Any changes there? I know there was some talk about maybe Enterprise selling their portion.

Thanks, Pearce. This is Jeremy. Business as usual in the Eagle Ford JV with Enterprise as a partner. We're excited. We're shipping 2 to 3 cargoes a month. And the terminal started up in September and our customers are very happy. So I think that's the only update I have for you.

So we have not been in the loop on what Enterprise is doing with their ownership.

We'll take the next question from Ujjwal Pradhan at Bank of America.

First one from me. Would you be able to talk about what led to the reduction in your 2019 CapEx and then 2020 coming in line with 2020 -- sorry, 2019, as you previously stated. Is that because of delays in project construction timing or is that just the lower contribution from JV?

Ujjwal, this is Chris Chandler. As we shared earlier, we have reduced our 2019 CapEx to $1.35 billion. To answer your question, it's a mix of timing adjustments, project scope reductions and cost optimization. So some of those have flowed through to 2020 as well, but a cause might be something like improved results from competitive sourcing versus our initial estimates. We're also looking at optimizing line size, number of tanks, number of booster stations, exact routing of the pipeline, things like that. So capital efficiency is something we're always pursuing so our ability to bring that number down for both 2019 and 2020 is a good thing obviously.

Got you. And maybe wanted to touch briefly on recent market concerns related to potential future federal legislation or any kind of presidential directive against fracking on federal lands. Have you considered what could be the scope of a potential throughput impact based on where your assets are?

Yes. This is Willie. It's hard to comment on that. It's something that's further out there and there's a lot of uncertainty on what might happen. What I can tell you is, I can give you one statistic that if we look at the acreage dedications that we have, we've got less than 20% that are on federal lands. So from what I've been hearing from the producer community, there's some flexibility for people being able to move things around, but I think it'd be premature for us to quantify direct impacts before we know what might happen.

We'll now take the next question from Jean Ann Salisbury at Bernstein.

Just one more on the $85 million impact in your guidance next year mostly, I think, due to lower utilization of spot capacity. Can you just comment on if this is still anticipating material spot barrels to flow or is this actually pretty close to the take or pay, I guess what I'd call floor level?

A lot of the volumes on legacy pipes don't have MVCs. So it's sort of a combination of what moves on MVCs, what's dedicated to our gathering systems and where we think those volumes naturally flow because of demand pull where there's not an MVC.

Okay. I guess I meant more outside of the flows to Cushing.

No. That's across our system, right? We have legacy assets that aren't new construction. And whether it be in the Rockies or the -- and so a lot of our assets are demand pull. There's historical shipper industries controlled by refiners. They ship on those pipelines to feed their refineries. A lot of the newer construction has MVCs and this reflects that component. So what Harry is talking about is our plan, this $85 million reflects the net impact across the pipelines based on our flows and based on our view of what our MVCs are, the net impact to the business unit. That's the fee-based pipeline business unit.

Okay. That's helpful. And then as the only midstream operator who will have exit capacity from the Permian to Cushing, Houston and Corpus, can you share your thoughts on what you think is the relative attractiveness of the 3 destinations to shippers once there's plenty of capacity to each one?

Sure. Cushing has a substantial refining complex and they like neat barrels. And to the extent you see lower activity in the Rockies and the Mid-Con and there's a shortage of barrels, that's what would pull the quality of the neat Permian barrels and pull barrels that way. From a Corpus standpoint, the ease of access and the competition for water, I think there's substantial new capacity, and that market is working as an export market. Houston, there's -- in addition to Corpus having some refining capacity, Houston has a bigger refining base but it also has substantial exports. Nederland is in a similar function. So we have customers. And Jean Ann, if you looked at a map of our system when we're done with all the projects in 2021, if you look at slides 5 or 6, you can see we could take a barrel from the Permian Basin and get it to St. James, Nederland, Corpus, Cushing, Wichita Falls or Houston. So our intent is not to tell to our customers where the barrels go but to ensure that they have access to all of them. And pricing in our terminals can reflect those options. Makes our assets stickier for the long term and that's the ultimate plan and what we're developing for.

Jean Ann, the only thing I would add on that is, I would just highlight that Cushing's demand, there is a demand for WTI quality, right, the medium quality is there. That is the hub for a lot of the Mid-Continent refineries. And as we go forward. We've always kind of predicted that crude segregation is going to get more important as the aggregate barrels get lighter. And I think we're going to continue to see more of that, but there's going to be a continued pull on 45 and lower gravity at Cushing.

We'll take the next question from Sunil Sibal at Seaport Global Securities.

Most of my questions have been hit but I did have a couple of clarifications from points discussed. First, on the federal land drilling, I think you mentioned 20%. Was that referring to your current production coming from those kind of lands or is it more related to your acreage dedications with regard to the federal lands?

My comment was on the total acreage of what we have in the Permian.

So it wouldn't impact existing production.

Right.

Okay. Got it. And then on the CapEx side, so seems like from your last update between '19 and '20, a $300 million reduction in capital. And then I think you talked about another $100 million or so of asset sales. So net-net, when we think about leverage exiting 2020, you're talking about a $400 million difference versus where you were when you provided guidance last time. Is that correct?

Chris, you want to take that?

You're correct on the capital number and you're correct on the asset sales number that you referenced. So consistent with our capital allocation strategy, we look to self-fund our capital investments and also reduce leverage as we have the opportunity to.

But Sunil, of the 2019 and 2020 numbers, right, there's a timing component, a cost savings and an optimization component. We haven't given you the breakdown on that, but some of that will be CapEx that will shift from 2020 to 2021 as well.

We'll take the next question from David Amoss at Heikkinen Energy.

Thinking about the question that Shneur asked earlier on 2021, can you just talk about how you expect your return on invested capital to change as we get further beyond your guidance now through 2020. Should there be some meaningful improvement in capital efficiency in 2021 and beyond?

Yes. Al?

Well, it's hard beyond 2021, it's hard to say what our return on capital will be for projects that we don't have vetted and all that. I think I can speak to the projects that were on the slides Willie walked through, and there's a number of them. And I think in total they aggregate to over $2 billion of invested capital. We feel very good about the returns we're going to get from those projects, highly contracted with third parties, with natural shippers, long-term MVCs and returns that meet or exceed our hurdles which is 300 to 500 basis points over. So we feel very good about the returns we're going to get on what we're investing in today. Beyond that, it's a little bit harder to opine. Our view is, is that we need to earn those return hurdles or we shouldn't make the investments. So bottom line is, we're trying to be as disciplined as we can with our capital dollars. They're precious. And ultimately, we -- again, we feel very strong about the returns we're going to see and the growth we're going to see in 2021 as we complete these projects.

And then, David, if I would add also, as you think about some of the asset sales that we've done, asset sales sold at good values that should be accretive to the projects we're doing. So I think directionally, there's a lot of positive desire on taking return on capital employed up.

And then one follow-up. Just if you wouldn't mind expanding on moving Capline back a little bit in terms of timing, what's the cause of that?

That project is progressing largely as expected. We're in the process of purging Capline itself and removing linefill. That's going well. That's to prepare for both inspection and reversal activities. And then the new section of pipe is an extension of Diamond, of course, from Memphis, Tennessee to Byhalia, Mississippi. That's approximately 40 miles. We are taking a little extra time to make sure we've chosen the best route that has the least impact on the community. And we're in the process right now of optimizing that route and obtaining the right of way for that extension.

Just one last one, if you don't mind, that process on the 40 miles, when do you feel like you'll be secure in knowing that, that's done and you could proceed with your project?

That should come fairly soon. We're preparing to order long-lead equipment. We're in the middle of detailed engineering. So there'll always be route optimization until we buy our last piece of right of way, but we have on the schedule to start construction in early 2020. So that, of course, requires that the route be locked down for those sections.

We'll take the next question from Christine Cho at Barclays.

I just have one question on your CapEx. So your CapEx for next year that you assume $300 million pro rata debt at Red Oak. And I think you said that's project-level debt. Are you guys evaluating project-level debt for Wink to Webster? And if so, could your CapEx come down next year even further?

Christine, this is Al. No, we are not with regard to Wink to Webster. On these equity investment JVs, we've historically treated as investment and reported our capital investment as to contributions in. Clearly, the reason we're doing the disclosure around the Red Oak is to make sure that whether it's debt inside of the JV entity or contributions from us that we're full disclosure on what the true investment is net pro rata to us, but we are not looking at Wink to Webster project financing.

This concludes today's question-and-answer session. At this time, I'd like to turn the conference back to the speakers for any additional or closing remarks.

And thank you all. We appreciate you joining us today and we look forward to providing you an update in February.

This now concludes today's call. Thank you for your participation. You may now disconnect.