Good day. Welcome to the PAA and PAGP third quarter 2019 earnings call. Today's conference is being recorded. 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 two 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 of 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, thank you for joining our call. Let me begin by hitting the high points of the information that we've released this afternoon. We're pleased to report solid third quarter earnings results. As outlined on slide three, these results exceeded expectations in our fee-based segments and reflect a continuation of strong performance in our supply and logistics, or S&L segment. As Al will discuss more in detail, we've increased our 2019 full year adjusted EBITDA guidance by $100 million to ±$3.075 billion. 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-$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-$100 million. Our preliminary 2020 growth capital guidance is $1.35 billion. 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. 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 estimates 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 barrels a day-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 to 2021. These are outlined on slides four through seven 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 in slide five, 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 six, 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. As previously announced, White Cliffs is completing a line conversion to NGL service, and Saddlehorn is advancing a fully committed 100,000 barrel a 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 seven. 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. 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 in 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 eight, 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 nine 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 ±$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 1Q17 through 3Q19, 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 three 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. 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 ±$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 nine, 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 over-performance. 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 investments, 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 2.8 times, which has benefited from S&L over-performance 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 3.0-3.5 times. As a reminder, the rating agencies make certain adjustments for their leverage calculations, including for our preferred equity securities. The current adjustments add roughly three-quarters of a turn, so the 3.25 times midpoint of our target range would currently equate to roughly 4.0 times on a rating agency basis. Reducing our leverage to these levels is consistent with our objective of achieving mid-triple B 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 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 unit holders 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 11. We look forward to updating you in February with our full 2020 guidance. Hey, 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. As we enter the Q&A session, please limit yourself to one question, one follow-up question, then return to the queue if you have additional follow-ups. This will allow us to address the top questions from as many participants as practical in our available time this afternoon. 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.
All right. If you'd like to ask a question, please signal by pressing star one on your telephone keypad. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, press star one to pose a question. We'll pause for just a moment to allow everyone an opportunity to signal for questions. We'll now take our first question from Jeremy Tonet at JP Morgan. Please go ahead, sir.
Good afternoon.
Hi, Jeremy.
I wanted 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, 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 trending at right now, how that all kind of plays together?
Jeremy, this is Willie. Let me make a couple comments, then I'll ask Al to add to it. 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. That is priority 1, is to get that done. We always look at ways that we can improve the returns of projects. If you've seen, we've brought additional partners into that. We'll continue to look at that. 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. At that point, it gives us more flexibility to do things.
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. That's kind of the base case. Depending on if we get some excess earnings from NGL 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. 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. 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. Thanks. There's been a lot of talk in the marketplace as we've seen over time with Permian takeaway competition kind of ramping up, and it seems like we're at the precipice of it right now with some competitor pipes entering service. Just wanted 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. Just wanted to see, given that we're partway into the quarter right now, what level of comfort 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.
Hey, 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 in 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 That rolled in, but some of the spot capacity we valued 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, as 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 this surge in production we're seeing now that's come into our system continues. 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. That termed-up lease supply gives us opportunities to make sure that where we have slack, we can optimize utilization of our pipeline systems. We have substantial long-term commitments, which I think both Willie and Al talked about. 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 stay full and optimize their capacity.
That's great. That's all for me. Thanks for taking my question.
Thanks.
If you find that your question has been answered, you may remove yourself from the queue by pressing star two. We'll now take the next question from Shneur Gershuni at UBS. Please go ahead, sir.
Hi, good afternoon, everyone. 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. 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?
Yeah, 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. 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. Really, in some cases, some of our more recent pipelines have been designed to utilize a base load 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 any plus or minus 20% on capacity for DRA. Just a general comment.
Perfect. Okay. Thank you. As a follow-up question, I know that you've sort of given us an initial outlook on 2020, and my question's about to be about 2021, 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 nine, you sort of have plus 21.
with CapEx being meaningfully lower in 2021 versus the current year. It sort of seems to be suggesting that there could be some incremental EBITDA growth in 2021. Are we looking at something that can be pretty meaningful in 2021 in terms of just the continued ramp? When you think about the capital you're putting in place for 2020, how much would still be ramping at the end of 2020 and into 2021? Do you have some sort of sense on that?
Yeah, Chandler, I would look at it as these capital projects kicking in and getting the benefit of it. It is a meaningful amount that would start ramping up in 2021.
All right, perfect. Well, those are my two questions. Thank you very much, guys.
Thanks.
We'll now take the next question from Tristan Richardson at SunTrust. Please go ahead.
Hey, good evening, guys. Just had a question, the new development on Wink to Webster. Can you talk a little bit about how the MVC came about? Just typically, it seems like we've seen your equity partnerships focus on large customers that can bring volumes to bear. I am kind of curious how this one came about.
Thank you.
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. 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. I think Wink to Webster was just another one where rational minds come together in the industry and take two projects and put together as one.
Hopeful, thank you.
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. Al, you mentioned preferred equity as a potential tool in the toolbox. Could you talk about sort of maybe bookend 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.
Yeah. Clearly, we view that our leverage will tick up in 2020 as we fund this capital program. 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. Kind of the rate we look at the preferred security with the 50/50 kind of equity debt weighting that the rating agencies subscribe to it versus our cost of capital. I think ballpark, we have $800 million-$1 billion kind of in our basket that we could utilize. The security also is subject to market conditions and that. We do view that as one of the things we'll be monitoring, and if we need to manage leverage or fund our program, we'll look to access that market.
Appreciate it. Thank you guys very much.
We'll now take the next question from Abe Mori. Please go ahead.
Hi, good afternoon. Two questions for me. One is in terms of the year-on-year Permian growth forecast of 300,000-400,000 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 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 producer customers versus what 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 in the market. It may prove conservative. We basically look at, in this case, it's almost a run rate, saying 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, so it began this year. While activity continued to climb this year, our 2019 exit rate's 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 efficiency is built in, gets you to roughly 5 million barrels a day exit next year. That growth will be different by different operators. You'll see some of the integrators will far exceed historical growth rates, and you'll see the levered E&Ps that have substantially lower. It doesn't necessarily mean anything specific for specific operators. It just means that, look, that's our respective view of this activity level. 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. The impacts of Parent-child relationships, we think our customers are working through it, that and well spacing, et cetera.
We continue to see the incremental well be better than the last well, a lot of it because of getting smarter. 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.
Based on current price environment as well.
Correct.
Abe, this is Willie. To make sure I was clear when I described it, I gave two numbers. One was 2020 average versus 2019 average, which is the 500 number, which is a little lower than we expected before. Then the 300 to 400 number was year-end 2019 to year-end 2020, which reflects the back end of 2020 starting to taper off.
Got it. Thanks, Willie. My follow-up question really is around some handholding around NGL, the $50 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 to $100 million might is 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 NGL. NGLs in Canada, NGLs in the Rockies, NGLs in the Permian. 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. To the extent that that happens, there's ways for us to benefit as well. 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 NGL footprint, and through our marketing affiliates.
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 I said, rolling in the NGL as well. We think there's a pretty fair reflection of the opportunity set in 2020.
Great. Thanks, everyone.
Thank you, Gabe.
All right. We'll now take the next question from Michael Blum at Wells Fargo. Please go ahead.
Thanks. My question is really about the asset sale approach for next year. I guess, would that be discrete assets or would you also consider JV-ing existing assets? I guess within that context, specifically with Red Oak, are you sort of set at the current JV structure, or was that something that you'd also be willing to sell down into as well? Thanks.
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 specific. We've been working a number of potential opportunities, 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, 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?
Yeah, I think Willie captured it. We're opportunistic, and we like our assets, and we won't sell them unless there's a valuation that we're comfortable with. In addition, your question specifically on Red Oak, P66 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'll all be based on the opportunity set.
All right. Thank you. That's all I had.
Thanks, Michael.
All right, we'll now take our next question from Keith Stanley at Wolfe Research. Please go ahead.
Hi. The Q3 EBITDA is 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. Anything unusual going on there? Is it just conservative in Q4, looking forward?
I believe this question was asked earlier, I think very simply, Cactus II came online, and we had 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. 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. Our reflection next year is a step up of $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 NBP step up.
We feel like next year reflected, but Q3 was an instance where we had Cactus II full and every one of our Permian pipelines was 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. Those are the types of things that are a little harder to anticipate quarter-to-quarter.
Got it. 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.
Okay. Thank you.
Thanks, Keith.
I'll take the next question from Colton Bean at Tudor, Pickering, Holt & Co. Please go ahead.
Just to follow up on the $50 million-$100 million of NGL 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 in the guidance, to tell you the truth.
Got it. I guess just as you look at that number, the assumption is that would be consistent with a pretty tight spread environment on crude?
Yes. Correct.
Yeah. Next year it will be competitive.
Got it. Well, I guess you've seen the impacts on the NGL side of the business. The Edmonton spread has come in, that's all kind of dialed in here in that $50-$100?
Yes, it is.
Perfect. 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, what I was speaking to. On the NGL side, the differentials have compressed as well.
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. I think we'll just stick with our answer on the $50-$100 and the components of what we do.
Understood. 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?
Yeah, I'll let Jeremy touch on this. The $85 was really across our system, and it includes Permian long-haul as well as some lower tariffs on some Rockies pipelines.
Yeah, I think Willie covered it. It is primarily long-haul, but our reflection of what we think the rates through transportation, intrabasin transport, any changes to contracts we have within the basin, our view of what spreads are across the region, 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. With a lot of the new pipelines that have been built, the volumes now are actually going to the Gulf Coast market. A good portion of that reduction on long-haul is on our basin system going up to Cushing.
Yeah, 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 pipes. When you think about it, our guidance next year reflects the combination of opportunities of intrabasin, long-haul, regional differentials, et cetera.
Got it. That's helpful.
I'll take the next question from Pearce Hammond at Simmons Energy. Please go ahead.
Thanks for taking my question. 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 Eagle Ford JV with Enterprise as a partner. We're excited. We are shipping two to three cargoes a month, and the terminal started up in September, and our customers are very happy. I think that's the only update I have for you.
We have not been in the loop on what Enterprise is doing with their ownership.
Thank you.
I'll take the next question from Ujjwal Pradhan at Bank of America. Please go ahead.
Good evening. Thanks for taking my question. First one for me. Would you be able to talk about what led to the reduction in your 2019 CapEx and then 2020 coming in line with 2019, as you previously stated? Is that because of delays in project construction timing, or is that just a lower contribution from JVs?
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. Some of those have flowed through to 2020 as well. A cost 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 pipelines, things like that. Capital efficiency is something we're always pursuing. Our ability to bring that number down for both 2019 and 2020 is a good thing on both.
Gotcha. Maybe why don't you 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 potential throughput impact based on where your assets are?
Yeah, 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.
From what I've been hearing from the producer community, there's some flexibility for people being able to move things around. I think it'd be premature for us to quantify direct impacts before we know what might happen.
That helps. Thank you.
Yep.
I'll take our next question from Jean Ann Salisbury at Bernstein. Please go ahead.
Hi. 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, is this actually pretty close to the take or pay, I guess what I’d call floor level?
A lot of the volumes in legacy pipes don't have MVCs. 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.
Oh, no.
Yeah
across our system. We have legacy assets that aren't new construction. Whether it be in the Rockies or it be in, a lot of our assets are demand pull. There's historical shipper history controlled by refiners. They ship on those pipelines to feed their refineries. A lot of the newer construction has MVCs. This reflects that component. What Harry's 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, the fee-based pipeline business unit.
Okay. That's helpful. 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 three destinations to shippers once there's plenty of capacity to each one?
Sure. Cushing has a substantial refining complex, they like neat barrels. To the extent you see lower activity in the Rockies and the MidCon, there's a shortage of barrels, that's what would pull there, the quality of the neat Permian barrels can pull barrels that way. From a Corpus standpoint, the ease of access and the competition for water, I think there's substantial new capacity, that market's working as an export market. Houston, in addition to Corpus having some refining capacity, Houston has a bigger refining base. It also has substantial exports. Nederland is in a similar function.
We have customers, 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 five or six, 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. Our intent is not to tell 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.
That's really helpful.
Jean Ann?
That's all for me. Yeah.
The only thing I would add on that is I would just highlight that Cushing's demand, there is a demand for WTI qualities, the medium qualities there. That is the hub for a lot of the MidCont refineries. 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. 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 gravities at Cushing.
Thank you. I appreciate that.
I'll take the next question from Sunil Sibal at Seaport Global Securities. Please go ahead.
Hi. Good afternoon, guys, and thanks for all the clarity. Most of my questions have been hit, but I did have a couple of clarifications from points discussed. First, on the federal lands 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.
It wouldn't impact existing production.
Right.
Oh, okay. Got it. On the CapEx side, seems like from your last update, between 2019 and 2020, a $300 million reduction in capital, and then I think you talked about another $100 million or so of asset sales. 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. Consistent with our capital allocation strategy, we look to self-fund our capital investments and also reduce leverage as we have the opportunity to.
Okay, got it. Yeah.
Sunil, of the 2019 and 2020 numbers, there's a timing component, a cost savings, and an optimization component. We haven't given you the breakdown on that. Some of that will be CapEx that will shift from 2020 to 2021 as well.
Okay. Got it. Thanks.
I'll take another-
Thank you
question from David Amoss at Heikkinen Energy . Please go ahead.
Hey guys. 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?
Yeah, Al?
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. 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 that we need to turn those return hurdles or we shouldn't make the investment.
Bottom line is we're trying to be as disciplined as we can with our capital dollars. They're precious and ultimately, 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.
David, 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. I think directionally, there's a lot of positive desire on taking return on capital employed up.
Okay. Thank you. One follow-up, just if you wouldn't mind expanding on the 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 line fill. That's going well. That's to prepare for both inspection and reversal activities. 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.
Thank you for the clarification. 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 can 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. There'll always be route optimization until we buy our last piece of right of way. We have on the schedule to start construction in early 2020. That, of course, requires that the route be locked down for those sections.
Got it. Appreciate it. Thank you.
I'll take the next question from Christine Cho at Barclays. Please go ahead.
Hi, everyone. I just had one question on your CapEx. Your CapEx for next year says that you assume $300 million for via project 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? If so, could your CapEx come down next year even further?
Christine, this is Al. 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. We are not looking at Wink to Webster project financing.
Great. Thank you.
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 closing remarks.
Hey, thank you all. 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.