Good day and thank you for standing by. Welcome to the PAA and PAGP first quarter 2021 earnings call. At this time, all participants are in listen-only mode. After the speaker's presentation, there will be a question and answer session. And for the participants to ask a question, you will need to press star one on you telephone keypad. If you require further assistance, you may press star zero. I would now like to hand the conference over to your speaker today, Roy Lamoreaux. Please go ahead.
Thank you, Joseph. Good afternoon and welcome to Plains All American's First Quarter 2021 earnings call. Today's slide presentation is posted on the Investor Relations website under the news and events section at plainsallamerican.com, where audio replay will also be available following today's call. Later this evening, we plan to post our earnings package to the Investor Kit section of our 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 two 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 CEO, and Al Swanson, Executive Vice President and CFO.
Additionally, other members of our executive team are available for the Q&A portion of today's call, including Harry Pefanis, our President, Chris Chandler, Executive Vice President and Chief Operating Officer, and Jeremy Goebel, Executive Vice President and Chief Commercial Officer, as well as Chris Herbold, Senior Vice President and Chief Accounting Officer. With that, I will now turn the call over to Willie.
Thanks, Roy, and thanks to each of you for joining us this evening. We plan to keep our prepared comments brief. We continue to make solid progress on our plans, reporting first quarter results that exceeded our implied expectations by roughly $50 million, generating strong free cash flow, maintaining full-year 2021 adjusted EBITDA guidance at ±$2.15 billion, and advancing a number of key objectives. I'll note that our full-year guidance incorporates an estimated $25 million net benefit from Winter Storm Uri. Al will provide more detail on our results and outlook in his section of the call. I'll plan to focus my comments today on our longer-term positioning. We are increasingly constructive in our outlook for global energy demand recovery. COVID vaccinations are progressing, key world economies are reopening, and global inventory levels have drawn down meaningfully.
On the supply side, the combination of OPEX discipline, recent increases in Permian activity levels, and our ongoing dialogue with producers reinforces our confidence in the Permian to resume growth in the back half of 2021 and, importantly, building momentum into 2022 and beyond as global supply and demand balance improves. We expect the Permian to exit 2021 at 4.4 million to 4.5 million barrels a day, which is an increase of 200,000 To 300,000 barrels a day from year-end 2020 to year-end 2021. Notwithstanding our constructive bias, we chose to maintain our 2021 adjusted EBITDA guidance of $2.15 billion at this time due to the combination of the timing matters that Al will cover and the fact that our constructive view of the fundamentals is weighted towards the end of the year. For PAA, we believe 2021 represents meaningful cash flow injection point.
As illustrated on slide four, we've increased our free cash flow estimate by $100 million and now expect to generate ±$400 million after distributions and excluding asset sales. We remain confident in our ability to achieve our 2021 asset sales target of $750 million, having continued to progress formal sales processes with strong levels of interest and engagement. Including targeted asset sales, our projected free cash flow after distributions grow to $1.15 billion. Beyond 2021, maximizing free cash flow will continue to be our focus. We expect to generate sizable levels of free cash flow after distributions over a multi-year period, and any further asset sale proceeds would be additive.
We plan to continue allocating free cash flow after distributions in a balanced manner with a near-term focus on debt reduction and a larger percentage shifting over time to equity holders through a combination of share repurchases and/or distribution increases. We believe this balanced approach of strengthening our balance sheet while also increasing cash return to our equity holders offer meaningful value for our current and prospective investors. Our long-term cash flow visibility is bolstered by the substantial completion of our multi-year system buildout, resulting in a significantly lower CapEx profile going forward, which is illustrated on slide five. We continue to exercise discipline, limiting our investment capital to must-do, no-regrets opportunities.
Relative to our prior estimates, we have further reduced our 2021 investment and maintenance capital expectations by $65 million or roughly 10%. A high-level overview and status update for our two key remaining projects, Wink to Webster and the Diamond Expansion Capline Reversal, are located within the appendix of today's presentation. With that, I'll turn the call over to Al.
Thanks, Willie. As shown on slide six, our first quarter fee-based adjusted EBITDA of $559 million exceeded expectations and was in line with fourth quarter 2020. First quarter results benefited from lower power costs, including gains on power hedges and stronger results in our natural gas storage business, as well as some lower operating expenses that are timing-related and we expect to incur later in the year. These benefits more than offset the revenue impacts of the storm-related downtime across our Texas and MidCon pipeline systems, as well as lower realized revenue at certain non-hub crude terminals and Canadian NGL facilities.
Before I get into the performance relative to our guidance and to level set, everyone, our first quarter supply and logistics was expected to be weaker than normal because NGL margins for the quarter were locked in during the second half of 2020 and did not reflect the rising prices during the first quarter. Looking forward, our NGL margins for the balance of the year are a little lower than the current market but are in line with historical margins. Focusing on the first quarter, adjusted EBITDA of -$13 million was below our guidance for the quarter. The primary drivers for the underperformance were a combination of the negative impacts of Winter Storm Uri and less favorable crude oil differentials in both the U.S. and Canada. The impacts of Winter Storm Uri extend into the second quarter as inventory builds in the Gulf Coast compress crude differentials in the U.S.
Additionally, despite proration levels in Canada being in line with our expectations, we continue to see differentials that are less favorable than we originally anticipated. As Willie Chiang noted earlier, we generated strong free cash flow after distributions, which totaled $511 million for the first quarter. Free cash flow fluctuates based on changes in and the timing of short-term working capital requirements. While the first quarter benefited from these items, even after adjusting for them, we were able to increase our forecast for the year by $100 million. Our capitalization and liquidity metrics are provided on slide seven. As of March 31st, our long-term debt-to-adjusted EBITDA ratio was 4.0x , which is above our target range of three to three and a half times and reinforces our focus on further debt reduction. Additionally, we exited the quarter with $2.8 billion of committed liquidity.
As outlined on slide eight, we increased our fee-based 2021 adjusted EBITDA guidance by a net $25 million and decreased our S&L segment guidance by a similar amount, resulting in our overall 2021 adjusted EBITDA guidance remaining unchanged at ±$2.15 billion. The slide summarizes some of the drivers of the changes for each segment. I would note that the change in inter-segment NGL fees was approximately $40 million for the full year, which reduces our facility segment adjusted EBITDA with a corresponding increase to S&L.
Before returning the call to Willie, slide nine summarizes the equity repurchase program that we initiated in November. Although we did not make equity repurchases in the first quarter, our capital allocation plans remain consistent with allocating up to 25% of our 2021 free cash flow after distributions to equity repurchases. The ultimate total allocation, pace, and timing will continue to be balanced as described on slide nine. With that, I will turn the call back over to Willie.
Thank you, Al. We've turned a meaningful corner with respect to free cash flow generation, and we expect to enhance unit holder value by generating significant levels of free cash flow over a multi-year period, and we will continue to allocate free cash flow to the benefit of our unit holders. We are increasingly constructive on the long-term outlook of North American Energy, including our business, as global demand continues to recover. Meanwhile, our focus continues to be maximizing our free cash flow through optimizing and rationalizing our systems, working with customers, partners, and peers to align interests and streamline and rationalize excess capacity, lowering our cost of operations, advancing our sustainability program, and above all, delivering safe, reliable, and responsible operations.
A recap of our 2021 goals is outlined on slide 10, followed by a summary of key takeaways from today's call provided on slide 11. We appreciate your investment in and support of Plains, and we look forward to providing you with additional updates on our continued progress. With that, I'll turn the call over to Roy to lead us into Q&A.
Thanks, Willie. As we enter the Q&A session, please limit yourself to one question and one follow-up question, and return to the queue if you have additional follow-ups. This will allow us to address the top questions for as many participants as practical in our available time this afternoon. Additionally, our investor relations team plans to be available throughout the week to address additional questions. Joseph, we're now ready to open the call for questions.
Thank you, presenters. Once again, for the participants, you may press star one on your telephone keypad. Then we have our first question from Shneur Gershuni. Your line is open.
Hi. Good afternoon, everyone. Maybe to start off, I was wondering if you can sort of reconcile the guidance for me a little bit here. Overall, you had a strong quarter, certainly better than you had guided from a fee-based perspective. Your commentary on the call today, definitely more constructive than it was last time. You talked about building momentum. Sounds like your production forecast for the Permian back-half weighted but is certainly better. Kind of on the math, you kind of beat expectations by $60 million since your fee-based guidance is only up about $25 million. Is that an election of conservatism? I think you had mentioned the word election before. Or is there a degradation in the base business? Is something happening in the back half of the year? I was wondering if you can just sort of expand on that for us, if you can.
Thanks, Shneur. I'll start off, and then I'll let Jeremy Goebel and Harry Pefanis kind of fill in the blanks. When you think if your question is around the full year or just first quarter, was it focused on just first quarter?
It's around the full year. I mean, at the end of the day, you beat expectations, you maintained guide, which it seems to even on the fee-based basis, seems to imply that you're expecting a worse back half of the year. You talked about momentum and positive commentary. I was just trying to figure out if you can square that, if that's conservatism or if there's something that we need to be thinking about.
Yeah, Shneur, let me start, and then the others who can jump in here. I made a comment in my prepared comments. If you think about the benefits that we got based on the storm, it's really $25 million across the whole year. It's $25 million for the year. That's related to some of the shifting in the impacts of the storm shifting into S&L. I think that'll be a good starting point maybe for Jeremy to comment a bit more.
Good afternoon, Shneur. It's a bit of an acceleration. We saw some benefit in the first quarter. That $50 million that you mentioned is driven by the transportation segment seeing additional or lower operating costs somewhat offset by lower volumes and our facility segment benefiting from some opportunistic around our NGL facilities. Part of that involved some operating expenses close to $5 million-$10 million that was deferred to later in the year just because of timing and interruptions in Q1. That is part of the net $50 going down to $25. The other component is driven by S&L. There were some impacts of Uri that were pushed into the second quarter and even further based on market spreads and timing. You'd see some of that erosion is just all lumpiness associated with Uri.
If you say the net impact's 25 versus 50, the other part is just wait and see on the rest of the opportunity. We see completions. We see efficiencies. We really haven't seen the rigs accelerate faster. We're looking to see for production growth back in weighted. We're also seeing I'll mention this as well is we're not seeing Canadian differentials widen to historical levels based on the level of proration. Part of that's built into our plan, and we're looking to see. As far as core Permian assets and other assets that are performing in line with expectations, there's no degradation to that core business.
Okay. That makes sense. Really do appreciate the wait and see aspect of it. Maybe as a follow-up question, I was wondering if we can talk about the asset sale process. If you can remind us in terms of the timing and EBITDA that you've baked into the guidance for this year, and does this process block you out from doing any share repurchases?
Sure. Hi. This is Jeremy Goebel again. As Al and Willie both stated, we are very confident in our ability to execute. The processes all began in the first quarter of this year. We don't want to speculate on timing or impact of the transactions just for sake of confidentiality. I feel very strongly in our ability to execute with regard to our targets.
Richard, why don't you comment on the blackout period?
I don't think the asset sales, the timing of that will have any impact on repurchases. We've included that as a part of our guidance. No impact on the ability to affect repurchases.
Perfect. Thank you very much. Really appreciate the color and the clarification today.
Thanks, Shneur.
We have our next question from Christine Cho from Barclays. Your line is open.
Thank you. Jeremy, you usually provide sort of expectations for what exit rate for the year is on Permian volumes. Curious if we could kind of get that and maybe sort of what that means for 2022 for you guys. In that context, how should we think about earnings growth tied to the volumes with the headwind that we're going to be one year closer to some contract expirations? Just at what point do you guys think about blends and extends to keep the volumes on your system for longer?
Jeremy.
Christine, good questions. We'll start. If I get them right, I heard there's an exit rate. What does that mean for momentum in 2022? What does that mean for our ability to contract longer term on our pipes? With the first question, I would say that we're seeing a positive bias on drilling and completion efficiency manifesting themselves in shorter cycle times and higher EURs. That's driven by spacing. February was a bit of a speed bump. Texas production, New Mexico production were down just because of timing. March and April came back stronger. What we're seeing is an acceleration of some completions into this commodity environment. The rigs aren't there. They're pacing our original projection. We're seeing some acceleration of production, but nothing that materially changed our outlook.
If we entered the year at 4.2 million barrels a day, our view is 4.4 million-4.5 million barrels a day exit. Rigs really need to step in for acceleration. This goes to your 2022 expectations. We're increasingly optimistic about North American production, but it ultimately comes down to supply and demand. We're not going to see that material rig ramp until you see OPEC production come out from behind pipe and you see demand fill that. I think there's a wait and see approach there. That's why we're cautiously optimistic. We need to see demand respond, and we need to see the OPEC barrels hit the market before you'll really see an expectation. It's really too early to call 2022 because you need to see that backfill of additional rigs to enter material production growth.
I know I didn't directly answer your question, but that's how we're thinking about it this time. With regard to blend and extends, we're constantly in dialogue with our customers. Right now, with $0.50 to $0.66 Midland MEH differentials, that doesn't bode well for recontracting at levels that we'd accept. What we're doing is we're staying close to our customers. We continue to add dedications of the lease, and we're now well over 2.5 million acres with term that continues to extend. Our customers are very happy with us. When those customers come back to recontract, part of the big problem with the long-haul pipes right now is people securing supply. We first purchased over 900,000 barrels a day and are in a very strong position when it comes to either filling the pipes ourselves or recontracting.
Volume's not going to be a concern in filling our pipes. We want to do it at the right time. I think we have levers that most don't. We'll be patient, but we're in constant dialogue there, and we'll constantly look for opportunities to rationalize across the space to where while you say we don't have time, 2025 is a long time from now before we have any material reductions on our commitments. We do have time to let some of this evolve because the industry understands the overcapacity, and they're constantly looking for options to rationalize. We'll be right in the center of those discussions.
Christine, I'm sorry. Go ahead.
No, go ahead, please.
I was just going to add - this is Willie - the key point on this is the momentum that builds with our expectations in the end of 2021. It happens at the end of 2021, but clearly, if you don't build the momentum, there's a longer lag time before you see the benefits. That's what we're optimistic about. We see the recovery kind of driving a quicker growth trajectory into this year if everything continues the way we expect it to.
Okay. Just because you did sort of end the comments on pipeline or rationalization, as we think about that, it would seem that a conversion to gas would maybe make the most sense since we have sufficient takeaway on the NGL side. From what I understand, it doesn't sound like it's that simple to convert a liquids pipe to gas. It sounds like it requires meaningful CapEx to change out pump stations. I've also heard that the diameter needs to be at least 30 inches. Is that right? Or are there other things that these pipes could transport that would require less spending? Just trying to get a sense of what the options are here.
Well, Jeremy and Chris have been working this. Jeremy, why don't you start off?
Christine, thanks again. On the rationalization piece, gas is a natural home for takeaway as you look for more gas getting to markets. It's a question of valuation and capital and scope. Those get reviewed from time to time. Then it's a question of how do you deal with existing contracts and existing structures on pipes. I think it's one of many options. I mean, we're looking at any and all options across the system, and so are our peers. I'd say just be patient. We don't have details for you right now. Some of the comments you make around gas are true just because of the compressible nature of the gas and fuel consumption increasing with smaller diameter pipes. That does make sense. All of that gets looked at. I just need you to be patient as the industry works through the best options. We're all working on it.
Chris, do you have anything you want to add?
Yeah. This is Chris Chandler. I guess I would just confirm kind of the points you made in your initial question. Natural gas pipes are typically larger, and they, of course, require compression instead of pumps like you'd have on liquids pipes. It can be done, and it's certainly specific to the asset in question. It's been done a number of times, sometimes liquid to gas and back to liquid in the history of our industry. There's certainly opportunities to do it out there. In general, you have to replace the pumps with compressors, and you do take an efficiency or a capacity impact by having a relatively smaller pipe than you might install if you were building it from scratch.
Hey, Christine. This is Willie. One of the other benefits I think that's important is it seems as if it's getting harder and harder to build assets now. One of the things that we've got is a lot of operating leverage in our system, which gives us the capability to be able to evaluate some of these things perhaps more than others. The challenge really is if you think about capital efficiency across the industry, while it may not be perfect and if you were designing it from scratch, you'd go with a new line of a certain size, in many cases, when you factor all these other things in, it does make a lot of sense. That's what the industry really needs to start working through.
Really helpful. Maybe if I could just tack on a follow-on, are all your major long-haul pipes out of the Permian over 30 inches or more?
This is Chris Chandler. They vary in size from 20 inches up to 36 inches.
Great. Thank you.
Specific to the Permian.
Thanks, Christine.
We have our next question from Jeremy Tonet from JP Morgan. Your line is open.
Hi. Good afternoon.
Hi, Jeremy.
Hi. Just want to kind of dive in a little bit more on your producer conversations and what's given you, I guess, the sense of confidence, I guess, into 2022. It seems like the privates are a bit more active than the publics. Just wondering what that means for Plains, if you agree with that, and you kind of see different activity trends there and what that means for you guys.
Jeremy?
Hi, Jeremy. Jeremy, thanks again for the question. It is consistent. The public company operators are largely holding the line and maximizing free cash flow and waiting for supply and demand to balance. Their investors are demanding it, free cash flow going back to equity holders and paying down leverage. The large private producers with little to no leverage, they just see the returns, and they're investing in that. They're investing heavily in it. I wouldn't generally say it's private versus public. I'd say a very select group of very large privates that are very well capitalized, that's the group that's hitting the accelerator.
They'll have some impact, but that's not all that's driving this. I think $65 oil with slight backwardation versus steep backwardation allows producers to hedge. I'd say that's more free cash flow for them to allocate. I think market structure, aggregate flat price, but there's cautious optimism on that side. There's a few select operators that are stepping out in front of it. The generalization's made with all the privates versus all the publics. I'd say that there's a gray area, and there's a select fewer that are really hitting the accelerator.
Got it. That's helpful. Thank you for that. Just want to pivot towards energy transition. Obviously, very topical and getting more topical. Wondering if you had any new thoughts on that subject these days. Specifically, thinking about carbon capture and wondering if you see the 45Q credits as they're written right now as kind of sufficient to move forward with projects. If you have existing assets that could be kind of redeployed in that direction, just any thoughts in general would be helpful.
Jeremy, this is Willie. On CO2 sequestration, I would tell you, in transport, we have not been as active as far as looking at that. Others can make a comment on it. The point I would make on energy transition is, as you know, our company doesn't produce a resource, and we don't manufacture a product. We have commercial agreements to move products from point A to B and find solutions. While we may have not been advancing some of the advancing discussions on specific sequestration projects, we do stay very in tune with our upstream and downstream peers.
As well as our peers, we see a lot of activity. Really, it's our role to figure out how can we generate solutions to moving things around. At this point in time, again, back on CO2, there's nothing that we have really moved forward on. There's really no news I can share with you other than we stay tuned on different things we can do on energy transition.
Got it. I'll leave it there. Thank you.
Thank you.
We have our next question from Tristan Richardson from Truist Securities. Your line is open.
Hi. Good afternoon, guys.
Hi.
Just a clarification question with respect to the upper bound of potential repurchases. Should we think of that as inclusive of asset sales to the extent they materialize throughout the year, or is that purely just of the free cash flow after distributions guidance?
Al, why don't you take that?
Yeah. No. I would think of the up to 25% being the maximum. What we've articulated specifically around asset sales are that we would have to take into account and consider the EBITDA that we're selling as well. As you're selling an asset, part of those proceeds need to go to reduce debt just to keep leverage flat. You got to think of it after that. Again, we provided the up to 25% to give a mathematical maximum. Practically, with asset sales, it would be less than that.
Helpful .
I will point you to the other points on our slide nine. There's other considerations that we'll factor it in. We view this as a tool that will be part of our capital allocation going forward. There'll be a number of considerations that will come into play.
That's helpful. Appreciate the earlier comments on the cadence of the year. Curious, is there any delta around the timing of asset sales that's factored in? Just to follow up on a previous question, sort of has the timing changed within the year in terms of general assumptions for asset sales that is contributing to sort of that fourth-quarter weighted outlook?
Hey, Tristan. It's Jeremy. I'd say, one, we don't want to speak to timing the asset sales as we talked about earlier. We have assumptions in there. They haven't materially changed since the beginning of the year. If something does change, we'll update once we make the announcement of the divestiture.
I appreciate it. Thank you guys very much.
Thanks, Tristan.
We have our next question from Keith Stanley from Wolfe Research. Your line is open.
Thanks. Good evening. Just two quick follow-ups. First, sorry if I missed this. Did you comment on the amount of asset sales completed now year-to-date?
Keith, this is Jeremy Goebel. We've completed $20 million of asset sales to date. That's consistent with what we had. I guess we did that in January of this year. That's the total amount completed to date. The rest is in progress.
Okay. Great. The other ones I just want to understand. The lower NGL intersegment fees item, I assume that's just you're lowering rates on some of the facilities assets that the S&L business uses. I just want to clarify. I think you said facilities EBITDA is hurt $40 million by this, and it helps S&L by $40 million for the year?
Keith, that's correct. This is Jeremy. Effectively, thinking about it, is we just charge our marketing affiliate market rates. We look at that. We make assumptions for beginning of the year to impact by market structure and competitive rates around the area. We made that adjustment. It's a net neutral. It's just an allocation from facilities to S&L.
Great. Thank you.
We have our next question from Gabe Moreen from Mizuho. Your line is open.
Good afternoon, everyone. Most of my questions have been asked or answered. Maybe I was just going to talk about how, I guess, low you think you can sort of whittle down your ongoing maintenance CapEx and just CapEx outside of where you're kind of finding those savings so far and how you might be able to take those numbers on an annual basis.
Sure, Gabe. I'll let Chris Chandler address that.
Hi, Gabe. It's Chris Chandler. I'll start with maintenance capital. We've said previously that we think a long-term run rate for maintenance capital is less than or equal to $200 million. We still believe that to be the case. We did update our guidance for 2021 to $180 million, a $15 million reduction. There's a number of factors driving that, including asset sales that have been completed and ones that are forecasted later in the year. We're also completing a number of multi-year improvement programs related to integrity and reliability that we won't have to spend on going forward. Regulatory requirements continue to evolve, as do best practices around inspection methodology, tools, and analysis. It's a number of factors. It's, by all means, not a lack of investment or a lack of commitment to maintenance or integrity.
When best practices are found internally or within the industry, we certainly look to apply those. As to your question on investment capital, we've lowered our guidance there by $50 million from $425 million- $375 million. Likewise, there's a number of factors involved. We're always looking to optimize our maintenance capital spend. So some of that's cost improvements, scope reductions, timing optimization. We'll talk with our customers. And if we can delay a part of the scope of a particular project without a financial impact or with support of the customer, we will do that. We've also pushed back the start of construction for the Vidalia project.
That's the piece of the Diamond Expansion at the very end, the 40 miles that goes from the Memphis refinery to the Capline facility outside Vidalia, Louisiana. We've done that to take some time to evaluate some alternatives in response to our stakeholder engagement activities that we've been doing for almost two years now. We're still planning on a startup by year-end. If the alternatives cause that to change, we'll certainly provide an update when appropriate.
Hey, Gabe. This is Willie. One thing I want you to take away from what Chris talked about is back to the maximizing free cash flow, the goal that we all do. I mean, it's part of our dialogue every day as we think about investment CapEx, maintenance CapEx, operating costs on how do we maximize free cash flow, right? It is a much broader discussion. That's why we think we will continue to have success in that area.
Thanks, Chris. Thanks, Willie. Maybe I could just ask a quick follow-up on, I guess, that Vidalia extension. If your timeline slips there for whatever reason because you have to look at alternatives, do the Capline contracts still kick in as expected, or are those tied together somehow?
This is Chris. I'll answer that. On the Capline Reversal, the main line that originates in Patoka and ends at St. James, that project is moving ahead as scheduled. It's an independent project. It's independent of anything on the Diamond Expansion and the Diamond extension. Things are unchanged there. That's still on schedule for a startup by year-end.
Thanks, Chris.
We have our next question from Michael Lapides from Goldman Sachs. Your line is open.
Hey, guys. Thanks for taking my question. Real quick, just a follow-up on Diamond and Capline. Can you remind us when do you expect Capline to be fully in service, kind of so both legs? Do you expect it to be at full run rate EBITDA in that first year, or will it take a couple of years to kind of ramp into that?
Jeremy, thanks for the question. As Chris mentioned, we're evaluating some alternatives associated with the Diamond piece. To reiterate what Chris stated is you'd be at full run rate on committed capacity for Capline from north to south. There is some uncommitted space. We look to continue to fill that. Based on current commitments, that will go to full run rate in first quarter of 2022 from the north to south piece. We'll look to add additional commitments over time. On the Diamond piece, we're evaluating alternatives. We'll update you guys as soon as possible.
Got it. Then on Diamond, it's gotten messy, obviously, at the city council and with the litigation underway as well, both state and federal. Just curious, is there an opportunity to use your partner's pipeline? There's a second pipeline that kind of runs not too far from Vidalia. Do you have that opportunity to utilize that as a workaround, or is that a full pipe right now?
Michael, this is Willie. I would tell you we're evaluating all options and leave it at that.
Got it. Okay. Thanks, guys. Much appreciated.
Thank you.
We have our next question from Jean Ann Salisbury from Bernstein. Your line is open.
The committed tariff that was posted for Wink to Webster recently for $0.72 and then $0.45 per barrel, which I think has caused some investor confusion and, if we're being honest, some confusion for me as well, is the right way to think about it, that that's just an interim rate for large customers? The true committed long-term rate hasn't been posted or disclosed yet?
Jean Ann, this is Jeremy. You're absolutely correct. This is just interim service with limited pump capacity. It's limited origination capacity. It's effectively matching the ARB from Midland to Houston during a period prior to the fourth quarter when the MVCs kick in. That has no reflection on the long-term committed tariff and limited destination alternatives.
Eventually, when the pipeline is up and running, that long-term tariff rate will be posted?
Correct.
Okay. Thank you. As a follow-up, any update on the Rangeland expansion? It seems like with Keystone getting axed, that might be garnering more interest.
Jean Ann, this is Jeremy. We're in constant dialogue with our customers. We have interest in that expansion. At this point, we're shipping in our capacity's full going south from Canada to the U.S. and multiple destinations.
Okay. Thanks. That's all for me.
Thanks, Jean Ann.
We have our last question from Harry Mateer from Barclays. Your line is open.
Hi. Good afternoon, guys. Al, you highlighted the large drop in short-term debt in the first quarter. I think, historically, you've tended to guide for that number to sort of fluctuate in the $400 million-$800 million range. Is that still a good guide to use? How should we think about the short-term debt line trending for the rest of 2021?
Yeah. What we would say is it's obviously a number of variables that will impact kind of the long-term trend. That's probably still a reasonable long-term number. What I would say is we do expect some of the benefit we saw in Q1 to be temporal. We do expect, again, on our free cash flow after distributions to be in that $400 million number. Clearly, Q1 was $500 million. That kind of tells you we expect some of that benefit we've seen in Q1 to be temporal.
Okay. Thanks. Related to that, just when it comes to debt reduction, you think about getting these asset sale proceeds in the door. How are you planning to prioritize that debt reduction? Is there something prepayable you have? Is it going to be about lengthening runway? Might you target some high coupon debt to sort of better boost metrics like free cash flow and coverage?
Most of our high "coupon debt" has a lot of maturity left to it. It's obviously harder to get out and take out. There's an upfront cost associated with that. We do have, I think, $1.15 billion maturing within the next couple of years and a few other issues shortly after. We will likely target some of the nearer-term senior note maturities to look to retire some on the front end. With that said, we will take a look at if there is an economic benefit to some of the longer-dated stuff. It's out there always. We think we'd be better suited to try to maintain and manage near-term exposure.
Okay. Got it. Thanks very much.
Thanks, Harry. Hey, I wanted to thank everybody again for joining our call. We look forward to having follow-up conversations with many of you in the coming days. Thanks again. We look forward to updating you again in August.
Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.