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Good day, ladies and gentlemen, and welcome to the PAA and PAGP First Quarter 2020 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, Communications and Government Relations. Please go ahead, sir.
Thank you, Keith. Good afternoon, and welcome to Plains All American's first quarter earnings conference call. Today's slide presentation is posted on the Investor Relations News & Events section of our website at plainsallamerican.com where audio replay will also be available following our call today. As a reminder, later this evening, we plan to post our standard earnings package to the Investor kit section of our IR website, which will include today's transcript and other reference materials. Important disclosures regarding forward-looking statements and non-GAAP financial measures are provided on Slide 2 of today's presentation. A condensed consolidating balance sheet for PAGP and other reference materials are located in the appendix. Today's call will be hosted by Willie Chiang, Chairman and Chief Executive Officer; and Al Swanson, Executive Vice President and Chief Financial Officer. Additionally, Harry Pefanis, President and Chief Commercial Officer; Chris Chandler, Executive Vice President and Chief Operating Officer; and Jeremy Goebel, Executive Vice President of Commercial; 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. Hello, everyone. Thank you for joining us, and we hope that you and your families are safe and well through these very challenging times. This afternoon, we reported solid first quarter adjusted EBITDA of $795 million, which exceeded our expectations. These results include the benefit of additional margin-based opportunities in our S&L segment and a $20 million benefit from a contract deficiency payment previously expected to be recognized in the second quarter. On a GAAP basis, we reported a net loss due to approximately $3.2 billion in aggregate noncash impairments, reflecting the impact of the global market downturn that emerged following our February earnings call. As we all know, the world has changed significantly as a result of the coronavirus, and it remains a very uncertain and dynamic time. Let me first acknowledge the commitment of our PAA team and our colleagues who have responded quickly to the challenges of operating in a socially distant world, including minimizing large group exposure and executing on amended procedures for our field staff and control rooms and more than 95% of our office staff working remotely. Our team has adapted and maintained our operations while responding to evolving market dynamics and working closely with our producer and refining customers during this unprecedented disruption. Acknowledging the dynamic and uncertain market conditions, this afternoon, we furnished updated 2020 financial and operating guidance. Our 2020 adjusted EBITDA guidance of plus or minus $2.425 billion is approximately 6% below previous guidance and reflects fee-based earnings of $2.2 billion, a 12% reduction from our pre-coronavirus February guidance and stronger S&L earnings of $225 million, offsetting a portion of the lower fee-based estimate. This guidance highlights the benefits of our integrated business model where we can generate additional S&L earnings in certain volatile market conditions. That said, the combination of the current impact on our transportation segment, limited visibility regarding the pace of demand recovery and our desire to be proactive really drove our actions that we announced in early April to further strengthen our balance sheet, our liquidity and our long-term financial flexibility. As shown on Slide 3, collectively, we expect these changes to result in approximately $1 billion of benefit to our cash positioning in 2020. As outlined on Slide 4, our specific actions included making significant reductions to both our capital program as well as our common equity distributions. We also continue to pursue and capture capital and cost reductions throughout the organization and our supply chain as well as additional noncore asset sales. Regarding asset sales, transactions representing approximately $440 million of our $600 million target have either closed or are pending closing under definitive agreement. We continue to target a total of $600 million in noncore asset sales in 2020, but we do acknowledge that this number could be more difficult to achieve in the current environment and could slip into 2021. Now let me share a few observations that underpin our outlook. Shortly after our February 4, 2020 earnings call, the world changed significantly. We've included a few charts on Slide 5 that illustrate the fundamental changes experienced today. As the coronavirus escalated into a global pandemic, the associated societal mitigation actions, including shelter-in-place orders and the resulting energy demand destruction accelerated at an unprecedented pace and magnitude. This demand decrease is a significant near-term challenge facing our industry, specifically, this uncertainty around not only the scale and duration of the impact but also the timing and the extent of recovery. For context, the majority of reputable estimates of year-over-year global demand destruction for the second quarter range from 20% to 25% and plus or minus 10% for the full year. The OPEC++ efforts to curtail production has since followed. And although these cuts alone are not enough to offset near-term demand destruction, they certainly will help the longer-term process of rebalancing the market, which will depend heavily on the ultimate level of demand recovery as well as the duration and extent of the near-term global surplus. In North American markets, the widespread shelter-in-place requirements for most metropolitan areas resulted in an immediate response by the U.S. refining sector to quickly reduce runs. Demand destruction is impacting the entire value chain, the supply chain, causing crude oil and gasoline inventories to approach their peaks, driving wellhead prices to historic lows and reducing producer drilling and completion activity, causing significant levels of voluntary shut-ins, which we expect will cause production levels to decline in the very near future in most, if not all, key basins. The overhang of inventory for both crude oil and refined products, coupled with the potential for a more gradual recovery, suggests that a price recovery may be extended into 2021. However, that will be dependent on the duration of the impact of demand, the willingness of producers to continue to curtail production. With this backdrop, we're now forecasting a year-over-year, exit-to-exit basis that the Permian crude oil production in 2020 could be down 15% to 20%, reaching trough levels in June and flattening out the second half of this year. It remains too early to call Permian growth trajectory for 2021, but we expect it to be lower than what we internally forecasted at the beginning of the year pre-coronavirus. As a result of these dynamics and as previously announced and as reflected on Slide 6, we have reduced our 2020/2021 capital program by $750 million or approximately $1.35 billion or 50% when factoring in previously anticipated JV project financing to a total of approximately $1.55 billion over the 2-year period. Our first quarter investment was approximately $350 million, and we currently expect an estimate $1.1 billion of total investments in 2020 and $450 million in 2021 with the potential for some timing shifts between the 2 years. We expect the vast majority of this investment to proceed considering the highly contracted nature of these projects. That said, we continue to challenge all investments in the current environment and are working to capture additional cost savings. Beyond 2021, we expect annual expansion CapEx to be below the $500 million level. With that, let me turn the call over to Al.
Thanks, Willie. During my portion of the call, I'll recap our first quarter results, discuss our 2020 guidance, review our current capitalization, liquidity and leverage metrics. I will also review the noncash impairments we reported in the quarter. In the first quarter, we generated solid results in each of our segments, reporting fee-based adjusted EBITDA of $652 million and adjusted EBITDA of $141 million in our Supply and Logistics segment. As shown on Slide 7, Transportation segment results slightly exceeded expectations, coming in 11% ahead of the first quarter of 2019 and slightly below the fourth quarter of 2019. First quarter Facility segment results also exceeded expectations, including the $20 million benefit of an early deficiency payment that Willie referenced. S&L results exceeded expectations due to favorable crude oil differentials, partially offset by less favorable NGL margins.
Now let me shift gears to our 2020 guidance, which is reflected on Slide 8. As Willie discussed previously, clearly, this is a very challenging market to assess right now. The largest headwind for our business is the shift to near-term declines in production, both from reduced drilling and completion activities as well as from producer shut-ins. Our revised 2020 adjusted EBITDA guidance of plus or minus $2.425 billion is $150 million or 6% below our original guidance provided in February.
As is normal practice, we are providing a plus or minus number versus a range but we would caution that with the dynamic market conditions and lack of visibility associated with the COVID-19 demand destruction, there is a range of outcomes depending on market developments, either to the plus or minus side of these guidance amounts. Additionally, there may be some interplay for the balance of the year between our Transportation and Supply and Logistics segments depending on shifting market signals associated with storage availability and regional pricing differentials.
Our revised guidance reflects a $300 million downward revision for the Transportation segment, a $150 million upward revision to our S&L segment and no change to our Facilities segment. For the Transportation segment, our February guidance had assumed 10% volume growth from 2019, with 2020 tariff volumes averaging 7.6 million barrels per day driven by continued Permian production growth and, in the aggregate, flat to slightly lower production in the remaining U.S. shale basins. We now expect 2020 shale production to decline in all basins, both in terms of the year-to-year average and exit rates, including the Permian, and now forecast 2020 Transportation segment volumes of 6.6 million barrels per day. For perspective, forecasting Transportation volumes for the second quarter alone has proven challenging due to the extreme volatility in recent commodity prices and assessing the corresponding response from producers, which is why we provided the reminder about the range of outcomes to the plus or minus of our guidance amount. With respect to the S&L segment, in the near term, we expect to capture additional margin opportunities resulting primarily from contango market structure as well as overall dynamic market conditions. Additionally, in 2020, we expect a portion of the benefits from near-term contango opportunities to be offset by lower margins in our Canadian NGL business. In addition to our expansion capital reduction that Willie outlined, our updated guidance reflects a $35 million reduction in our expected maintenance capital for 2020, which is the result of our emphasis on reducing capital expenditures while continuing our focus on safe, reliable and responsible operations. Moving on to our capitalization and liquidity, a summary of key metrics is provided on Slide 9, and all metrics are strong and remain in line with or favorable to our targets. Following the actions we announced in early April, our investment-grade credit ratings were reaffirmed by S&P and Fitch, both with stable outlooks. Our committed liquidity as of quarter end was $2.5 billion. Additionally, we have no senior notes maturing in 2020 and one $600 million senior note maturing in February of 2021. Accordingly, we do not expect a need to access the capital markets, certainly, through the end of this year, and we have adequate flexibility to refinance the February 2021 senior note maturity on our revolver if capital markets do not present attractive opportunities over the next year or so. Before turning the call back over to Willie, let me share a few additional comments related to the $3.2 billion of noncash impairments we took in the quarter. The recent events and related uncertainty impacting global economies and the energy industry represented a trigger event requiring an interim assessment of our goodwill balances. Accordingly, we performed a quantitative impairment test as of March 31 and recorded a full impairment of the $2.5 billion goodwill balance. We also recorded additional noncash impairments, totaling approximately $655 million. These include $150 million loss on the classification of our LA terminal asset to held for sale that we communicated last quarter as well as various noncash asset impairments totaling $505 million.
With that, I'll turn the call back over to Willie.
Thank you, Al. So as discussed throughout the call, and as we've all experienced, 2020 clearly remains a very dynamic and challenging environment. We've taken a number of proactive actions to further strengthen our liquidity, our balance sheet, financial positioning, and we continue to actively manage our costs and capital expenditures. We remain constructive long-term as we believe that demand will return and meet the needs of a growing global population, although full recovery may occur beyond the next 12 months. Additionally, it's worth pointing out that we have a very integrated crude oil infrastructure system throughout much of the U.S. and Canada with a significant pipeline and storage network in the Permian Basin, underpinned by significant volume commitments in over 2 million dedicated acres. And we believe the Permian will lead North America in the eventual recovery. The significant retrenchment of industry investment should provide opportunities over time, and we expect that the actions we've taken position PAA well for the future.
Finally, we remain very focused on what we can control, which is prioritizing the health and safety of our employees, operating in a reliable and responsible manner and continuing to manage our business for the long term. I'd like to publicly acknowledge and thank our employees for their hard work and dedication as we continue to navigate through these unprecedented times.
A summary of the takeaways from today's call is outlined on Slide 10. We look forward to sharing additional updates on our second quarter earnings call in August.
With that, I'll turn the call back over to Roy.
Thanks, Willie. [Operator Instructions] Additionally, Brett Magill and I plan to be available this evening and through the balance of the week to address additional questions. Keith, we're now ready to open the call for questions.
[Operator Instructions] We'll take our first question from Shneur Gershuni with UBS.
Just wanted to start off on the guidance, with all the talk of shut-ins, I guess the Transportation guidance makes sense. And it sounds like you're not expecting a reversal of shut-ins before the end of 2020. So I was wondering if we can talk about the S&L side for a minute. If I subtract out the 1Q performance from your guidance, it sort of looks like you're saying the back half -- or the next 3 quarters is going to equal less than half of what you did in the first quarter. So kind of wondering if you don't think you'll be able to capture some of the surge in storage rates and spreads that are currently occurring right now. Or is it more that you're being conservative similar to how you've guided S&L throughout 2019?
Yes. Shneur, this is Willie. I'll start, and then I'll let either Jeremy or Harry jump in. One thing I wanted to remind you of is our typical S&L earnings profile is a saddle, right? Normally, the first and fourth quarters are the stronger quarters, with the second and third, less strong. Jeremy or Harry?
Yes. I think our assets are well positioned to take advantage of disruptions and volatility. I think our -- the current opportunities in front of us, we're capturing contango going forward at market differentials. So any volatility and choppiness in between, we'll be able to capture. I think this reflects something we're -- a number we're very comfortable in.
Yes. I think Al pointed out in his prepared comments that the guidance reflects positive benefit from contango margin opportunities, a little bit offset by some weakness in the NGL as expected at the balance of the year.
Okay. I appreciate that color. And maybe as a follow-up, I was wondering if we can talk about G&A and OpEx expenses. Just wondering if you've put any targets out or have any expectations about being able to take down your G&A and OpEx expense. A lot of your peers are taking that down as well, too. And also if you can confirm the $500 million CapEx number post-'21 that you mentioned in the prepared remarks.
Sure, Shneur. This is Willie again. I'll start, and I'll ask Chris Chandler to comment on this. Let me start with the easy one first. And the CapEx expectations for '21 plus is under $500 million. So I confirm that. On G&A and operating expense, we are absolutely pursuing cost reductions. We have in 2019, we're building on that. We've got a lot of initiatives in this year to try to capture some, and we've already captured a number of savings. The one nuance I want to give you is when we are doing this -- I've been in many different situations where you chase cost savings. And rather than put a dollar target out, we have focused heavily on how do we streamline our organization. We've got different segments within the company that we're trying to make sure we are consistent. We get the best practices between it. So we're really setting a goal to streamline and be as efficient as we possibly can. And that's kind of the overarching thing. But what I will tell you is the numbers are substantial, and we baked a lot of that into our current outlook. Chris, you want to talk a little bit more?
Yes, thanks. This is Chris Chandler. I'll just build on what Willie said. We're really continuing what we started in 2019, and the focus there was identifying best practices and really driving organizational consistency across North America. We're also looking closely at our business processes and our business systems for cost and efficiency improvements. So here we are in 2020, and we're really accelerating all those initiatives we started in 2019. We are seeing some cost deflation across the industry, and our supply chain organization is working tirelessly to rebid services, materials and chemicals and capture that savings. We have reduced hiring. We're absorbing vacancies. We're reducing energy and utility costs across our system as we optimize our operations with flows moving in different directions and at different volumes. We're doing things like optimizing drag reducing agent injection rates, even optimizing the number of pumps we're operating in pump stations that we operate. Travel expenses are down, as you might expect. We're operating maintenance spend while not impacting safety or integrity. We have not implemented $1 or a percentage target for our cost savings. But we do expect them to be significant. And they could be in the order of -- the range of $50 million to $100 million for 2020. And that is, as Willie said, incorporated into our guidance. So I hope that's helpful.
Yes, that's super helpful, guys. Really appreciate the color. Though I have a lot more questions, I'll step back into the queue for now. Stay safe.
Thanks, Shneur.
We'll take our next question from Keith Stanley with Wolfe Research.
First, just wanted to confirm, Willie, you said -- I guess the volume and EBITDA guidance for the year, you're assuming volumes trough in June and then kind of flatten out over the second half of the year. I guess, one, is that true? And wouldn't that also mean based, obviously, the solid moving target, but based on what you know today, you're thinking 2021 volumes could be kind of consistent with an exit rate for this year?
Yes. Keith, I'm going to ask Jeremy to address those.
Keith, this is Jeremy Goebel. Just as Willie said, what we're looking at is lower activity, shut-ins. In May, we estimate, for instance, in the Permian Basin, close to 1 million barrels a day of shut-ins. June and forward, we're ultimately dictated by pricing signals. So contango spreads, regional basis differentials, flat prices, all of those will come in and help producers' decisions. So what we've assumed is that the most severe is May, June and into July a bit, then you have some level of activity coming back in, in the August time period. And so the pace of demand destruction and coming back into the market will dictate what that signal is and how much activity comes back. So the inflection point at the end of the year will be heavily dependent upon prices. It could be an upward trajectory, it could be flat, is largely what we've assumed in this forward guidance that we've given.
Okay. But for 2020, you're assuming -- it sounds like you're assuming a little bit of a recovery in Q3, Q4 relative to May and June levels.
It's just more of a flattening. So the pace of the underlying decline will naturally mitigate itself as well as the decline happens. But there's some activity that will come in just to offset additional declines. So it's a very low level of activity, but that's consistent with our forecast.
Okay. Got it. Second question, just curious if you have any more to add on the thought process around the dividend, just factors you weighed, how you ended up at a 50% cut, I guess, how you're thinking about your leverage targets as part of that decision as well.
Al, do you want to take that?
Sure. As far as the determination, there was a number of things that we considered as we reflected on it, one, industry conditions, visibility for those conditions, but also leverage our liquidity being a couple of them are investment programs. There was no one single kind of driver to reach it. And so management did a lot of work, ran multiple scenarios that it worked with our Board of Directors, and we came up with the size of it. But there was no one single kind of driver with regard to it. Clearly, as we've been talking for a period of time, we have wanted and continued to focus on ensuring that our leverage continues to migrate down over time. And our focus on retaining and improving our investment-grade credit ratings over time factored into our decision as well.
Yes, Keith, I'll just reinforce, balance sheet and financial flexibility are really the keys.
We'll take our next question from Jeremy Tonet with JPMorgan.
Just want to start off with the Permian volume trajectory, as you outlined it there, just wondering how you think this plays itself. Do you see your volumes being better or worse or kind of in step with the rest of the basin there? And then how does this impact your system across kind of like the gathering, the intra-basin pipe, the takeaway? If you could just help us dive into your thoughts there, that would be helpful.
Jeremy?
Jeremy, this is Jeremy Goebel. We've assumed largely just for planning purposes that we would be impacted by the system. Our system gathering and intra-basin system would be impacted similar to the general market. As for outbound pipes, we balance flows on pipes where we believe that the barrels will want to go over periods. So we have a -- it's a mix. For specific gathering systems, we've taken what producers' guidance has specifically given us for intra-basin. It largely looks like the rest of the basin. And for the outbound pipes, we actually balance the entire system based on where we think commitments and how the systems are connected. So it's a little bit of a Rubik's cube.
Got it. And as far as the impacts, I mean, do you see more impact on the gathering or the takeaway? Or just trying to get order of magnitude feeling for how you see uplifting your system?
So the takeaway, a lot of it's contracted under T&D. So physical flows and revenue will be different. On the intra-basin system, it's a mix of T&Ds and acreage dedications. So the physical flows and the revenue impact will be different. But where we have the T&Ds on a lot of our long-haul pipelines, that's going to have a more muted impact. On the gathering side, it's going to be based on forecasted productions, and overall basin inflows will impact the intra-basin movements.
That's helpful. And just want to see -- supply and logistics moving up, transportation moving down the guidance. Is there any interplay there between one bucket moving to the other bucket? Or is S&L really just kind of contango or other drivers to that opportunity set?
Go ahead, Harry.
The S&L is largely driven by contango. But as the year develops, we very well could see some fluctuations between transportation and supply. I think Al touched on that a little bit in his prepared comments. Al?
Yes, that's right. There very well likely could be interplay, Jeremy.
We'll take our next question from Michael Lapides with Goldman Sachs.
Can you talk a little bit about what your customers are seeking in terms of storage these days? Meaning, are your customers concerned about storage filling up? If so, where do you think -- or are there other mechanisms you can do to alleviate storage concerns faced by the producers? Meaning, are there opportunities to use other facilities, whether it's unutilized pipeline capacity, whether it's other assets you own to help increase the short-term amount of storage available to customers?
Michael, this is Willie. I'll start and then let Jeremy add on to it. Clearly, there's been a lot of work to try to find additional storage within our system. We've been successful for getting some of those barrels, but it is a very dynamic situation. And I'll let Jeremy explain a little bit more.
Yes. Thank you for the question. So if you think about our facilities, they're largely leased out for operational purposes for long term. So the facility storage is largely spoken for. Within the basins and within our system, really, a lot of our customers are looking -- since Plains Marketing is a big purchaser, they're looking for flow assurance, and we have the ability with our system to provide that. Where there's opportunities for additional storage, we're fully taking advantage of that with our -- for ourselves and for our customers. So right now, I think April, we had a build, but pricing signals may change things going forward. So there was a build into April. But currently, prices are rallying, which could suggest things could change. So going forward -- that was an issue in April, finding flow assurance and takeaway. Now shut-ins are looking to balance the market, and so we'll see how things go from here.
Got it. And one follow-on real quickly. Can you just give us a high-level view, how much of your Permian long-haul and intra-basin pipeline capacity is contracted under a take-or-pay basis versus kind of more volumetrically exposed?
This is Al. A large majority of our Permian takeaway is under MVCs, whether it's on our pro rata piece of BridgeTex, Cactus I, Cactus II. The basin pipeline system probably has the lower percentage. That's more the line that runs up to Cushing. Intra-basin, as Jeremy mentioned, is a mix.
And just to add on to Al's answer, a lot of our Mid-Continent pipelines and pipelines long-haul from the DJ, those are all fully contracted. We announced transactions on Saddlehorn and Red River to fully contract those pipelines. So it's not just Permian takeaway. We have T&Ds throughout our pipeline system.
It's clearly been one of our strategies is how do we lock in longer-term value as we work with different producers. And sometimes we end up doing a strategic joint venture on a supply push or a demand pull project where, in exchange for additional volume, there's ownership in the pipe.
We'll take our next question from Michael Blum with Wells Fargo.
I'm wondering on storage, can you talk to us about the tenor of the contracts you have there on the crude storage side? And as contracts roll off, how much uplift do you think you'll see in terms of pricing?
We've priced most of our storage on a long-term basis. We don't really think about it in the context of, a, it's a short-term opportunity here that's a few months of contango. Like Jeremy pointed out earlier, most of our customers are operational customers, and they use those tanks for their daily requirement. So minimal contract roll-offs this year. So I think that's probably the best way to think of it.
Okay. Great. And then I have a question on the Canadian business. So you sold, I guess, some U.S. NGL storage assets here. I just want to understand, is there a shift in the business model in Canada related to that? And the second part of that is the asset sale is being reported as about a 4x EBITDA multiple. So I wonder if you could provide your perspective on that multiple.
Sure, Michael. This is Jeremy Goebel. First, on the business model, ultimately, what we're moving to is larger bulk transactions and focusing on our lowest cost supply NGLs. We're greatly simplifying the business. We're maintaining profitability and margin, but much fewer transactions. So we view it as a much more sustainable business model going forward. With that, the assets that we've sold became less core to our business. With regard to the specific Crestwood comments, I'd say, look, this is an asset where Crestwood was a very logical buyer, and it's worth more to them than it is to us based on their business model. We spoke to multiple buyers, and I can just tell you, we're very happy with the outcome.
We'll take our next question from Tristan Richardson with SunTrust.
Appreciate all the comments and for quantifying what you can, particularly in this environment. Just a quick follow-up on the transportation side. Your outlook there, seeing a sort of a 4% impact on the volume side versus prior expectations but a higher percentage impact on the EBITDA side. Can you talk about the extent to that this is -- to which this is higher-tariff barrels being more disproportionately impacted? Or is this just basic operating leverage? Just kind of curious there.
Jeremy?
This is Jeremy. I think the way to think about it is some of the spot capacity could have come off of pipelines, and that's obviously higher tariff. But some of it's pull-through. If it's a gathering barrel that doesn't go through, the intra-basin that doesn't go through the long haul, it's those that have somewhat of a multiplier impact. So I'd say it's a combination of spot and pull-through from the lease all the way through the pipeline system.
Tristan, you made a comment about a 4% reduction. Was that the question?
Just on the volume outlook.
Okay. Because the -- okay, got it. Is that the right number, 4%?
I think you compare right here. Got you. Okay. Yes.
Appreciate it. And then just a quick follow-up on the facility side. Could you talk a little bit about maybe some of the tailwinds and the headwinds there? I mean, it seems like better prospects for higher utilization in storage or possibly priced, but to the extent there's lower throughput activity, just kind of maybe generally, the dynamics going on in the facilities outlook remaining unchanged.
Facilities is largely contracted under long term arrangements. So if you look at our store capacity to all the major hubs or fractionators, they're all under term arrangements.
Yes. And keep in mind, part of the -- where we had a little stronger 1Q on that segment was for this contract resolution that we had modeled later in the year. So that's just a shift between 1Q and later in the year.
Hey, Tristan. This is Willie. I just want to make one clarification. The -- if you're looking on the page, the updated 2020 guidance, remember, our guidance was a 10% increase, and now it's a 4% -- it's 10% and 4% together. That's the total impact on volumes.
So we'll take our next question from Gabe Moreen with Mizuho.
Just a question on Capex. And the scrutiny on growth CapEx and the reduction, is the ability to lower CapEx further, would that be a function more of projects dropping out of the queue or the ability to maybe slow walk some projects with your contractors? I'm just curious how that's going, what you're focused on and also the discussions with your partners on those projects.
Yes. Gabe, this is Willie. Thanks for the question. I'm going to ask Chris to give you kind of an overview of that.
So our CapEx reductions come from a number of sources. Certainly, our discussions with producers and our customers have guided some of that. It's really a combination of project deferrals, spending delays to match the required project completion dates. Obviously, there's not an incentive to finish anything early and then capturing cost deflation that we're seeing across the industry. So could that continue to change? We do continue to talk to our JV partners and our customers. And to the extent that their plans change, we'll adjust our plans as well, but I would not expect it to be significant.
Okay. So in other words, some of these big projects that you've got, just they're going ahead. They've got contractual backing. Understood. And look, I've got a question. I know it's not a big business for you. But on the natural gas storage side, not a business you break out anymore. I don't think it's that sizable. But are you seeing any interest in additional contracting there given that that's also a futures curve, which at this point seems to be in contango?
In general, that business has done well, and it's fully contracted. We continue to see rates creep up. So it's been positive.
We'll take our next question from Colton Bean with Tudor, Pickering, Holt & Co.
So just to follow-up on the commentary around shut-ins and particularly the expectation that production may trough in June, I guess how do you reconcile that with producer commentary over the last few days, signaling a willingness to bring production back online in the $20 to $25 barrel range or effectively where we sit today.
Colin, this is Jeremy Goebel. I think pricing signals dictated what happened in May, shut-ins, like Willie mentioned, it's somewhere between 3.5 million and 4.5 million barrels a day, U.S. and Canada. Pricing signals in June will help inform what nominations we receive in the coming weeks and what flows on the pipelines. Just to carry on with what Willie said, it's May, June, potentially July trough. We assumed June, July time period for trough and then some activity resumption in the August time period. So if it happens sooner, that's a positive to our business. And this is some of the interplay that Al mentioned with S&L. If the market flattens and there's more pipeline transportation, that's one of the other ways there could be interplay in this. But we're planning for a dearth of activity in April, May, June, and then we expect some resumption starting maybe in the August time period. That's our plan in case.
Got it. And then maybe to ask the question around alternative storage a little bit more explicitly. It was in soft down Capline service not expected until the middle of next year, is there any potential to utilize that capacity for continual opportunities here in the interim?
This is Chris Chandler. I'll take that. That is a discussion we've had, but the answer is no. The activities required to reverse the pipeline make it unsuitable for storage.
But one thing to remember is there's terminals on both ends, and we're actively using those for contango purposes, so at Patoka and St. James. So we're utilizing all available storage in a safe manner and that we can get barrels in and out of. But unfortunately, while the conduit doesn't work, we've worked with our partners to commercialize both ends.
It's a great question. We've looked at it.
We'll take our next question from Ujjwal Pradhan with Bank of America.
This is Ujjwal. First question following on your comments on drivers earlier to Keith's question. So given the EBITDA headwinds here and further uncertainty, can you update us on your conversation with the rating agencies? And how much headroom you have on leverage?
Yes. This is Al. What I would point to is just the actions that they came out with here in the last 30 days, Standard & Poor's and Fitch. Clearly, our leverage today is in good position relative to our ratings at all 3 agencies. Clearly, the environment is challenging as we've talked. So part of the actions we've taken is to make sure we stay ahead of that. But I'd normally try not to put words in their mouth, but I would point you to the S&P and the Fitch press releases that they provided in the last 30 days.
And a quick follow-up. Can you provide more details on the impairment charges, particularly around what assets and regions were under a question here?
Al, impairment charges.
Yes. I would put them into 3 kind of high-level buckets. One, the $2.5 billion from goodwill. That's basically -- we accelerated the test. Our normal annual cycle is June 30 for doing that test. Based on all the events in the industry, we view that we had a trigger event. Did the test and basically took the $2.5 billion impairment as you probably note, there's been a significant number of goodwill impairments in the industry over the last week or 2. And so that's how that one triggered. The LA terminal that we put under contract for sale and we expect to close later in the year as we transferred that asset to held for sale, we took a $150 million impairment on that. If you recall, we actually "flagged" that on our February earnings call. We put it under contract in this year, we knew it was coming. It just hadn't flowed through our year-end results yet. And the balance of them are basically where we go in and do analysis on individual assets and based on conditions and cash flow forecast, you do impairment tests, and that was on multiple assets, several of them, and it aggregated to be about $500 million.
We'll take our next question from Jean Ann Salisbury with Bernstein.
The exit-to-exit decline of 15% to 20% for the Permian is a helpful estimate. Can you share how this compares to your view of U.S. or North America decline overall in 2020? It's about the same or floor?
Jean Ann, I think you'd look at activity across, and it's going to differ by basin. I think there's been some quality challenges in the Eagle Ford, which has pulled a lot of activity out there. So you could see steeper declines in the Eagle Ford. I think the Williston shut-ins have probably been the most aggressive of anywhere. It's farther from market. Canadian productions, we would expect that to normalize once -- that's going to be largely driven by shut-ins. So it's going to differ by basin. The DJ, you can see the activity decline. So I think the Permian is going to be lower -- shallower than some of the other basins is the way I look at it.
And then on the -- you reduced volume guidance by 1 million barrels a day. Can you break out how much of that reduction was gathering versus intra-basin versus long-haul barrels?
We don't have that detail now, but we can look to -- or follow-up with Roy or Brett.
We'll take our next question from Ganesh Jois with Goldman Sachs.
Just a couple of questions. Firstly, on your CapEx outlook for 2021 and beyond. In a flat to decline in U.S. production environment, I'm wondering what it is exactly that you might be thinking of spending on? And the second question I have is, we've now seen 3 distribution cuts from you all. At what point a unitholder is going to be prioritized when it comes to capital allocation as opposed to bondholders and generally asset build-out, I guess?
Ganesh, this is Willie. I'll take -- I'll answer, and then Al can add. On the CapEx of 500 or below, we're not trying to telegraph anything specific for the out years other than it's below $500 million. And clearly, as you look at our expectations on projects is there's a lot of cap that's been built. And our strategy is really moving towards efficiency mode to be able to utilize existing assets, which is why I wanted to telegraph the lower CapEx spend in the out years. On distribution, our focus has been to get our debt metrics down. We -- the actions, I think we've taken on CapEx and additional cost savings is in motion. And once those are -- those 2 are well on track, it allows us really to focus on increasing shareholder return.
Ganesh, this is Jeremy. Just one thing to add on to that. A lot of the projects we're working on now are largely driven by demand. It's refiners committing to long-haul transportation on the Red River pipeline, Wink to Webster is largely driven by the buyers of crude that we're buying in Houston are now buying in the Permian Basin. So a lot of the projects we're working on are underpinned by 7- to 10-year long-term commitments from high-quality credit quality counterparties, and there'll be core assets to the U.S. crude oil transportation going forward. So we've really narrowed down, including Diamond, Capline, largely driven by St. James refining demand. So I think demand pull pipes is where a lot of our focus and incremental capital is.
We'll take our next question from Becca Followill with U.S. Capital Advisors.
Realizing that this is an incredibly unusual time with lots of uncertainty, perhaps this is an unfair question. But can you tell us the degree of confidence you have in this guidance that you put out?
Well, Becca, I'll give you my answer. We're balancing everything we currently see. We're very confident. The challenge, as you can imagine, is what might be there out of the ordinary that is very difficult for us to see. Is the demand recovery trajectory, does it change dramatically because of additional outbreaks or hotspots? That's a big variable. And certainly, the other big variable is what really happens on the production side. We've got -- the producers have been very proactive in production cuts. But if we get to a scenario where that's not the case, which is not what we expect, but that could certainly change the trajectory. So I don't know if that's helpful, but it gives you my view anyway.
It is. I just wanted to see where the places maybe that would change it. And then the second question is every curve that you look at it, there's not another pipe that's needed for the Permian. So can you give us assurance that when Wink to Webster is built that you're not sitting there on a time frame where it's built. You don't have the volumes flowing that you're not getting full EBITDA that you expected. Is that absolutely -- there's a guarantee that you're going to get those -- that EBITDA from the pipe once it gets filled and not sitting there waiting on it, on volumes to come?
Well, this is Jeremy. So you're talking specifically about Wink to Webster pipeline? If that's the case, yes, it's very high credit quality. The -- some are integrated producers. Others have the large -- I mean, we're tying into the largest refining -- largest 2 -- 2 of the largest refiners in the Gulf Coast that will be buying the barrels off that system.
Highly contracted.
It's very long contract.
Contracted in terms of MVCs or volumetric?
MVCs.
MVCs. Becca, you're aware of this, but I'll repeat it anyway. On Wink to Webster, that was a very, very -- it was a large pipeline that started off with 2 to partners that ultimately, back to capital efficiency, we were able to work win-win with ultimately 7 total parties, which really filled the lineup. So I think that's actually a good example of capital efficiency on the pipe, all anchored by MVC. So we would expect that to be probably the most resilient pipe out there.
We'll take our next question from Pearce Hammond with Simmons Energy.
I just want to follow up on Michael's question earlier. Given your unique vantage point and your extensive oil storage assets, do you think it is a certainty the U.S. onshore oil storage will fill? And if so, when do you think that occurs? Or have the production curtailments really changed that calculus?
So Pearce, April filled, as everyone expected, but the pricing signals have changed. And so I think pricing for May is largely set by a lot of the impacts in April with regards to time spreads, with regard to location differentials and quality differentials. So that absolutely caused the really large 3 million to 4 million barrels a day of shut-ins that we're seeing now across North America. What happens in June is being set by pricing as it goes now. So I think storage is a function of an imbalance in supply and demand. So you're just going to have to watch supply and demand through the figures going forward. We don't want to forecast what the future is in that, but we watch the same things there. And honestly, it's going to -- what happens in June is going to impact whether things full. And the closer you get to full, the more incentive it is for producers to take production off-line. So I think it's just a dynamic situation, and we'll all continue to watch.
Keith, I think we have time for one more, one more participant question, and then we'll call for today.
Okay. For our final phone question, we'll take that question from Vikram Bagri with Jefferies.
I have 2 questions focused on long-term cash flow sustainability. In third and fourth quarter, you had provided an estimate of competition on your 2020 EBITDA of about $85 million. Now you've dramatically changed U.S. production outlook. Has there been any change in that $85 million number? I'm trying to understand how much of the decrease in Transportation segment EBITDA per barrel is going to reduce tariffs versus incentives versus change in transportation mix?
This is Jeremy Goebel, Vikram. It's largely driven by volumes, not incentive tariffs. The vast majority of volume that flows on our system is contracted either through MVCs or acreage dedication. So this is largely volume reductions under acreage dedications. Our system is completely different. It's contracted in a completely different manner than it was in 2013. These are not -- we're not largely built on month-to-month contracts. It's largely either take-or-pay or acreage dedications to our system now.
You might share where our next threshold is as far as contracts coming inspiring. It's --
Yes. It's years away. I think we provided detail on the last call that it's minor impacts in '24 and some impacts in '25 plus. And so we've largely worked to -- anything we build is to support incremental production from additional contracting. It's not speculative building.
Okay. Great. And as a follow-up, the Facilities segment continues to do pretty well. I was wondering how much of the benefit from by WCS differential is flowing into that segment with rail volumes? You don't report that number anymore. But are you seeing increased rail volumes to your St. James facility, which can handle that heavy upgrade? And how much of -- if you can quantify what that benefit is in Facilities segment.
So through our facilities, it's largely fee-based tariff revenue. Throughputs to our facilities are impacted by WCS and other blends. But at this point, it's largely refiners moving barrels in and out of the system. So there is some throughput revenue, but it's largely for Shell barrel storage. In St. James, we're seeing more throughput because we've aligned ourselves with several of the growth projects coming through the system. And so we would expect continued activity there. Several of the large downstream guys in that market have taken out storage for long periods of time, and they're bringing additional pipeline connections in and out. So we would see throughput increasing Capline, some of the other projects that are coming through the St. James area will bring more volume in and necessitate feeding downstream refineries.
Thank you, everybody, for joining us today. We appreciate your time and look forward to updating you on our next call in August. Keith, I think that will end our call for today.
Thanks, everyone. Be safe.
Thank you. Ladies and gentlemen, this does conclude today's conference. We appreciate your participation. You may now disconnect.