Energy Transfer LP

NYSE:ET

Earnings Call Transcript 2020-Q2

[Operator]

Greetings and welcome to Energy Transfer's Second Quarter Earnings Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded.

I would now like to turn the conference over to today -- to Mr. Tom Long, CFO. Thanks sir. You may begin.

[Tom Long, Chief Financial Officer]

Thank you operator and good afternoon everyone and welcome to the Energy Transfer second quarter 2020 earnings call and thank you for joining us today. I'm also joined today by Kelcy Warren, Mackie McCrea, and other members of the senior management team who are here to help answer your questions after our prepared remarks.

Hopefully, you saw our press release we issued earlier this afternoon as well as the slides posted to our website. As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These statements are based on our current beliefs as well as certain assumptions and information currently available to us and are discussed in more detail in our quarterly report on our Form 10-Q for the second quarter of 2020.

I'll also refer to adjusted EBITDA, distributable cash flow, or DCF, and distribution coverage ratio all of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP measures on our website. And we expect our 10-Q to be filed tomorrow, August 6.

Let me start today with a short update regarding our operations. The COVID-19 pandemic continues to impact how we go about our daily lives and how business is conducted. However, I am pleased to say that to date our field operations have continued uninterrupted. This is a testament to the hard work of our employees who remain focused on the safe and efficient operations of our assets during these stressful times.

Now, turning to the second quarter 2020 highlights. We generated adjusted EBITDA of $2.44 billion and DCF attributable to the partners of ET as adjusted of $1.27 billion. And our coverage ratio for the quarter was 1.54 times, which resulted in excess cash flow after distributions of $448 million.

During the second quarter, the COVID-19 pandemic and the associated drop in crude oil prices led to significant volume shut-ins throughout many of the producing regions in the country. We have also seen a reduction in spreads on our crude and natural gas pipelines from the Permian to the Gulf Coast as well as crude spreads from the Bakken to the Gulf Coast.

Offsetting these headwinds our NGL segment continued to set records during the second quarter with our transportation volumes reaching new highs, primarily driven by record volumes on our Mariner East system as well as strong volumes across our Texas NGL pipelines.

And our fractionation volumes reached another record during the quarter due to the addition of Frac VII earlier this year. In addition gathering and processing volumes on our Midland Basin system also reached new highs near the end of the second quarter.

Now, turning to our 2020 outlook. As the energy industry continues to face demand destruction and other challenges associated with the COVID-19 pandemic due to the uncertainty of the pace of recovery, we are revising our 2020 adjusted EBITDA guidance range to $10.2 billion to $10.5 billion. This reflects our latest expectations during these unprecedented times including a slower recovery than initially forecasted.

Although we believe that we reached the bottom during the second quarter, our revised guidance reflects a more conservative ramp-up than our previous expectations.

We are encouraged by the signs of recovery that we are experiencing as current production volumes in the Midland Basin through our processing plants, volumes across the Mariner East complex, and volumes through our Texas NGL fractionation assets are all currently above pre-COVID levels.

As we look ahead, we continue to expect our fully integrated diversified asset base along with contributions related to the addition of the SemGroup assets, the ramp-up of Mariner East, Frac VII, and Panther II, as well as the projects that went into service in 2019 to help offset some of the impacts from lower volumes in certain basins, narrower spreads, and lower commodity prices.

Operationally, we continue to seek out opportunities to leverage our extensive infrastructure to drive operational efficiencies and optimize our assets where possible.

As we mentioned on our last call, we have undertaken cost reduction measures both in our corporate offices as well as our field operations. Year-to-date, we have already recognized approximately $200 million in G&A and OpEx savings. And we now expect to achieve cost savings of approximately $400 million for full year 2020 relative to our budget.

We also continue to carefully evaluate our growth capital expenditures. Given the current state of our industry and the number of assets that are not fully utilized across the midstream space today our evaluation process for new projects is very stringent and our threshold for returns is the highest it has ever been.

That being said upon further review of projects spend to date completion dates and the economic impact of delaying particular projects, we now expect our 2020 growth capital expenditures to be approximately $3.4 billion. This represents a reduction of $200 million from our previous guidance or a total reduction of $600 million from our original guidance of $4.0 billion and is primarily related to delaying some growth capital spend. Approximately 80% of the growth capital spend in 2020 will be spent on projects that are expected to be in service in 2020 or early 2021. This includes Mariner East the Lone Star Express expansion and the Orbit and other NGL export projects at Nederland.

As we think about our future capital spend, we currently expect our 2021 growth capital expenditures to be approximately $1.3 billion and we now expect growth capital for 2022 and 2023 to be in the range of $500 million to $700 million per year. We remain committed to generating free cash flow and still expect to be free cash flow positive in 2021 after growth capital and equity distributions.

Looking more closely at our growth projects, I'll now walk you through recent developments. We continue to move forward with the Bakken pipeline capacity optimization. The initial phase of the optimization above the pipe's current capacity of 570,000 barrels per day will accommodate the volume commitments made by shippers during recent open seasons. We now expect this additional capacity to be in service in the third quarter of 2021.

Next, the Ted Collins link is an efficient way to increase the utilization of existing assets while providing market connectivity between our Nederland and Houston terminals. It will ultimately allow us to transport up to 275,000 barrels per day of crude oil from West Texas and Nederland to our Houston terminal and is expected to be in service in the fourth quarter of 2021.

Moving to Mariner East system, I am pleased to say that we saw the highest average quarterly volumes yet through the Mariner East pipeline with volumes for the first half of 2020 up nearly 50% over the first half of 2019. Utilization of our Mariner pipelines and our Marcus Hook terminal continues to increase, with record amounts of propane and butane transported through the pipelines.

We are also seeing strong ethane utilization which is expected to grow in the fourth quarter of this year. The system continues to demonstrate flexible optionality for shippers with multiple local market connections for ethane, propane and butane. Customers at Marcus Hook are currently taking advantage of this flexibility by placing barrels for the upcoming winter season into local markets.

Additionally, our Mariner system will have the ability to bring natural gasoline to Marcus Hook for gasoline blending and local consumption by early 2021. Both domestic and international demand for all natural gas liquids has remained strong even while motor fuel demand has waned because of COVID-19.

We are eagerly awaiting the next significant phase of the Mariner East project which we now expect to be in service by the end of this year with the final phase completed in the second quarter of 2021. Also, our 50,000 barrels per day expansion at the Marcus Hook terminal will provide additional chilling and storage capacity and is expected to be in service in the first quarter of 2021.

The Mariner East system in conjunction with the Marcus Hook terminal will provide additional chilling and storage capacity and is expected to be in service in the first quarter of 2021.

The Mariner East system in conjunction with the Marcus Hook terminal continues to provide the most efficient transportation route for liquids in the Northeast and provides customers, the optimal way to reach the best markets for their product.

Now looking at – moving to Lone Star and looking at Frac VII. It was placed into service in the first quarter of this year and began ramping up. All seven of our fracs are running full today. We're in the final stages of construction on our 24-inch, 352-mile Lone Star Express expansion, which will add over 400,000 barrels per day of NGL pipeline capacity from the Permian Basin to the Lone Star Express 30-inch pipeline south of Fort Worth Texas. We continue to expect the expansion to be in service in the fourth quarter of 2020.

Also, we have converted some of our underground storage facilities at Mont Belvieu to allow the storage of significant amounts of natural gasoline and diesel to take advantage of the profitable contango opportunities. LPG demand has remained strong and our LPG expansion projects in Nederland will bring our total export capacity to approximately 500,000 barrels per day by the end of 2020, further integrating our Mont Belvieu assets with our Nederland assets.

Construction of our Orbit ethane export joint venture with Satellite Petrochemical, who is a great partner is nearing completion. This 180,000 barrel per day project will be ready for commercial service in the fourth quarter of this year with the first ships arriving in November for commissioning.

Now let's take a closer look at our second quarter results. Consolidated adjusted EBITDA was $2.44 billion compared to $2.83 billion for the second quarter of 2019. The change from the prior period was primarily due to the impact of lower volumes and prices among several of our core operating segments. DCF attributable to the partners as adjusted was $1.27 billion for the second quarter compared to $1.6 billion for the second quarter of 2019. This is primarily due to the decrease in adjusted EBITDA. Distribution coverage ratio for the second quarter was 1.54 times.

In July Energy Transfer announced a distribution of $0.305 per common unit for the second quarter or $1.22 per common unit on an annualized basis. This distribution is consistent with the first quarter of 2020 and will be paid August 19 to unitholders of record as of the close of business on August 7.

Looking at our results by segment. For NGL and refined products, adjusted EBITDA was $674 million compared to $644 million for the same period last year. This increase was primarily due to record NGL transportation and fractionation volumes, which were partially offset by a decrease in terminal services margin. NGL transportation volumes on our wholly owned and joint venture pipelines increased to 1.4 million barrels per day compared to 1.3 million barrels per day for the same period last year. This increase was primarily due to record volumes on our Mariner East pipeline system as well as increased throughput on our pipelines out of the Permian Basin and North Texas regions as a result of higher liquids production from both wholly owned and third-party gas plants. Second quarter average fractionated volumes increased to 836,000 barrels per day compared to 701,000 barrels per day for the second quarter of 2019.

Now for our crude oil segment. Adjusted EBITDA was $519 million compared to $752 million for the same period last year. This was primarily due to lower volumes on the Bakken pipeline and our Texas crude pipelines as a result of unprecedented shut-ins as well as a decrease in our crude oil acquisition and marketing business related primarily to well shut-ins leading to unfulfilled producer supply commitments and unfavorable pricing conditions. These items were partially offset by contributions from the SemGroup assets, as well as a positive inventory valuation adjustment of $14 million compared to the second quarter of 2019.

For midstream, adjusted EBITDA was $367 million compared to $412 million for the second quarter of 2019. This was primarily due to lower NGL and gas prices, which impacted results by $39 million, as well as a decrease related to volume shut-ins in South and North Texas, which were partially offset by a $23 million reduction in operating expenses.

Gathered gas volumes were 13 million MMBtus per day compared to 13.1 million MMBtus per day for the same period last year. Lower volumes in South and West Texas were nearly offset by volume growth in the Northeast and the addition of SemGroup assets in the Mid-Continent Panhandle region.

In our interstate segment, adjusted EBITDA was $403 million compared to $460 million for the second quarter of 2019. This was primarily, the result of additional revenue recognized in the second quarter of 2019, as well as lower rates on LNG that we mentioned on our last call and less capacity sold on our Panhandle and Trunkline systems. These were partially offset by increased margin from the Transwestern system due to increased demand in firm transportation.

As for our intrastate segment, adjusted EBITDA was $187 million compared to $290 million in the second quarter of last year, primarily due to lower revenue from the pipeline optimization activities as a result of the significant drop in spreads. Beginning in 2021, we expect to have less exposure to spreads as we have locked in additional volumes under long-term contracts with third parties.

Moving on to a CapEx update. For the six months ended June 30, 2020 Energy Transfer spent approximately $1.8 billion on organic growth projects, primarily in the NGL and refined products and midstream segments, excluding SUN and USAC CapEx.

And as I mentioned earlier for full year 2020, we now expect to spend approximately $3.4 billion on organic growth, primarily in the NGL and refined products and midstream segments, of which approximately 80% will be on projects expected to be in service in 2020 or early 2021. And we currently expect our 2021 growth CapEx expenditures to be approximately $1.3 billion and growth capital in 2022 and 2023 to be between $500 million and $700 million per year.

Looking briefly at our liquidity position. As of June 30, 2020 total available liquidity under our revolving credit facilities was approximately $2.9 billion and our leverage ratio was 4.29 for the credit facility. As a reminder, we have no additional maturities in 2020. And looking ahead, we have a very manageable maturities of $1.4 billion in 2021. We continue to target a rating agency leverage ratio of four to four and half times.

In conclusion in the second quarter, we saw challenges. But with some volumes picking up across a number of our assets and our Mariner East pipeline recently reaching new highs, we expect this positive momentum to continue as we enter the second half of the year. Throughout the remainder of 2020, we will continue to look for efficiencies and optimization opportunities across our footprint and our fully integrated multiproduct assets are well positioned as our industry works to a recovery.

In addition, we anticipate further ramp-up of our recent projects to contribute additional near and long-term value. However, we know that it is imperative to remain disciplined when it comes to spending. And as our growth capital reductions demonstrate, our capital expenditure approval process is increasingly stringent.

We remain committed to our investment-grade rating and improving our leverage metrics as we navigate through the current market disruption. And above all, we continue to emphasize safety and project execution and we are continually impressed by our employees' dedication and resilience during these challenging times.

[Tom Mason, General Counsel of Energy Transfer]

This is Tom Mason, the General Counsel of Energy Transfer. And I wanted to inform you that, we just received the decision related to our motions to stay from the Court of Appeals. We are still reviewing this decision, but the good news is that the Court of Appeals granted our stay of the portion of the district court order that required Dakota Access to shut the pipeline down and empty it of oil.

The Court of Appeals also denied a stay of the other part of the district court order which vacated the easement for the pipeline at Lake Oahe.

As a result, no court order stops Dakota Access from continuing to operate the pipeline. The Court of Appeals contemplates further proceedings at the district court following determinations by the Army Corps, under its regulations regarding the continued operation of the pipeline, in light of the easement being vacated.

The Court of Appeals also ordered an expedited schedule for determining the merits of the appeal by the Army Corps and Dakota Access as to whether an Environmental Impact Statement will be required. This really is expected by the end of the year. We will continue to review the substance of today's court decision and we will need to run the course with this litigation. We believe our legal positions are strong and we are confident that the pipeline will continue to operate.

With this I turn it over to the operator to open our first question.

[Operator]

Thank you. [Operator Instructions] Our first question is from Shneur Gershuni with UBS. Please proceed with your question.

[Shneur Gershuni, UBS]

Hi, good afternoon everyone. I realize the DAPL news is very fresh and it sounded like your update was pretty straightforward there. So I won't be belabor it. Maybe to pivot a little bit here, the guidance update that you provided today, Tom I was wondering if you can give us a little bit more color on what's moving the guidance down? What are the puts and takes? And was there anything related to DAPL as part of this? I realize the DAPL decision just came in, as you were basically hitting the send button on the press release.

[Tom Long, Chief Financial Officer]

You bet. Let's start with the last part of your question Shneur. First off nothing related to DAPL was pertaining to the guidance -- updated guidance that we had. I will say that, when you really look out at what we were -- what caused or probably what drove the reduction was really the - basically the volumes and the spreads. We were looking at the assumptions and the forward curve when you really look out. So I'd say that probably drove it as much as any. You can see really from crude oil, as well as the intrastate were the two primary segments.

[Shneur Gershuni, UBS]

Okay. Fair enough. And maybe as a follow-up question, the -- heading into this year there was a path for deleveraging, the goal was 4.5x. Obviously COVID and OPEC have kind of derailed that. Can you talk about your path to how you think you'll get there on a go-forward basis? How you're thinking about the distribution versus the investment-grade credit rating if we were to hit that crossroad, just kind of interested in your overall thoughts with respect to both?

[Tom Long, Chief Financial Officer]

You bet. Clearly the investment-grade rating is very important. But I think it's also important to highlight the various levers we have to pull and the CapEx reductions that we announced today were obviously a big part of that. We're going to continue to work with the rating agencies. We're going to continue to work toward bringing our leverage down. And clearly the distributions are a topic when we discuss how to get the leverage down.

[Shneur Gershuni, UBS]

Fair enough. And then maybe one last question just since you brought up the CapEx. I mean, the commentary you put out today was for a very material step down in CapEx for of '21 and into '22 and '23. You've already cut $600 million so far this year. And it sounds like in your prepared remarks Mariner East II is actually moving ahead faster than expected.

Is -- I realize that's a lot that you've accomplished, but are there any opportunities to cut CapEx further? And I was sort of thinking along the lines of are contracting and labor costs coming down? Or is there equipment costs -- could there still be a little bit more to go in terms of lower costs and lower CapEx?

[Tom Long, Chief Financial Officer]

We're going to continue to evaluate it, but I would not guide you to lower amounts at this time. But clearly as we continue through the rest of the year, we'll update as we go. But right now I wouldn't guide you to any lower numbers.

[Shneur Gershuni, UBS]

Perfect. We’ll have obviously a lot more questions, but I’ll step back into the queue. Really appreciate your thoughts today and have a safe day.

[Operator]

Our next question comes from Jeremy Tonet with JPMorgan. Please proceed with your question.

[Jeremy Tonet, JPMorgan]

Hi. Good afternoon here. Just wanted to follow-up with the credit side. And just kind of curious what you calculate your leverage is on a rating agency basis. And want to get better color on kind of the path of how long it takes you to get into that.

[Tom Long, Chief Financial Officer]

Well, as you know, each agency has their own metrics they use for how they calculate that. We -- depending on which agency you look at as you know we're in and around that five number. We're going to continue to look out not just for this year, but for next year. And we're going to highlight the fact that we're running into a free cash flow period for 2021 with the CapEx I announced.

So I think when you look at it, you can see that any dollars that are left over will be allocated toward debt paydown, and that's what we're looking at, which will then bring that leverage down. But I would calibrate you to the five-ish range depending on which -- 5 to 5.5 depending on which agency you're looking at.

[Jeremy Tonet, JPMorgan]

Got it. That's helpful. Thanks. And then just want to make sure as we're thinking about it for modeling purposes. When you think about kind of contango or other opportunistic gains you might have recognized in the quarter, did they all show up in 2Q? Or could they show up over the balance of the year as well? Just trying to think of how that might be booked.

[Mackie McCrea, President & Chief Commercial Officer]

Yes, Jeremy. This is Mackie. No. We did recognize some of the contango in the second quarter. However, there's substantially more contango that we will recognize the second half of this year. And there's also some contango as Tom mentioned in his remarks around some new storage facilities that we're taking advantage of at Mont Belvieu around -- May take advantage of those later this year if the opportunity arises. Otherwise, those will -- we'll take advantage of those in the first quarter of next year.

[Jeremy Tonet, JPMorgan]

Great. That's very helpful. Thank you very much.

[Operator]

Our next question comes from Ujjwal Pradhan with Bank of America. Please proceed with your question.

[Ujjwal Pradhan, Bank of America]

Good afternoon guys. This is Ujjwal, Bank of America. Thanks for taking my question. First one wanted to touch on cost savings. You noted approximately $400 million in savings that you expect to realize in 2020. Just wanted to get a sense of how much of that is a function of just lower volume-driven expenses. Really trying to get at how much of that would be ratable going forward?

[Tom Long, Chief Financial Officer]

You bet. When you really look at it, it's a combination of both G&A as well as operational expenses. As far as being able to continue with that, clearly, that's what our plans are is to be able to look at this. But as the assets continue to ramp up as we look into next year, et cetera, the operational expenses will go along with that. But I would say that I want to commend all the Energy Transfer team and what they've done to be able to bring down these costs. But it is a blend of both like, I said, G&A as well as operation expense.

[Ujjwal Pradhan, Bank of America]

Got it. And second question trying to get your thoughts on asset monetizations at this point as one of the levers for delevering. Assets like Rover, which have been under consideration in the past does keep the profile of nat gas pipelines that have recently treated. Would you be able to comment on what your thoughts are and how you see the market today and your level of interest in using this tool?

[Tom Long, Chief Financial Officer]

We will not comment on specific assets like that. But I will say, we've been pretty open about our compression -- investment in USA Compression. We're not going to do anything that would ever harm the value of the units, but that is something that we continue to evaluate as far as that position goes the units that we hold as well as the general partner. But overall, we don't have really a long other list of assets that we're working on that we're evaluating from that standpoint.

[Ujjwal Pradhan, Bank of America]

Understood. Thanks and very helpful.

[Operator]

Our next question comes from Pearce Hammond with Simmons Energy. Please proceed with your question.

[Pearce Hammond, Simmons Energy]

Good afternoon and thanks for taking my question. I just want to follow-up on the prior question. But more specifically in light of the Berkshire Hathaway, Dominion transaction, do you see an attractive environment to divest assets? Is there more interest, or is kind of COVID throwing a wet blanket on that?

[Tom Long, Chief Financial Officer]

It's interesting because prior to the downturn that we've experienced, the COVID impact we've had there was clearly a lot of calls that came in with various levels of interest around assets. But I will tell you that that has slowed. I think multiples have come down as far as assets and what they trade for at least from what we're seeing.

[Pearce Hammond, Simmons Energy]

Okay. Thank you. And then as a follow-up, are you hearing from your customers? Are they actively looking to blend and extend contracts? And so what's the environment like for that?

[Mackie McCrea, President & Chief Commercial Officer]

This is Mackie. There are some of those out there and we've made it public that we've been pretty aggressive over the last year or two of doing that. That hit us a little bit in this year, because we took away a little bit of the revenue this year for extended contracts that were ending in the next year or two and extended those out seven or eight years.

But I would say that we're not as focused on that right now. Our primary focus right now from a commercial standpoint is getting all these assets online in the Northeast and in Nederland and filling them up as quickly as possible. So we're really not looking at a lot of the blend and extend at this point in time.

[Pearce Hammond, Simmons Energy]

Thank you, Mackie.

[Operator]

Our next question comes from Jean Salisbury with Bernstein. Please proceed with your question.

[Jean Salisbury, Bernstein]

Hi. The release referenced a reduction of $117 million in the crude segment in the quarter due to the Bakken pipeline. But I was under the impression that DAPL was almost fully contracted. Is that impression wrong? Or were the well shut-ins I guess a valid reason to not pay on take or pay?

[Mackie McCrea, President & Chief Commercial Officer]

This is Mackie again. No, your impression is correct. We -- the 570,000 barrels a day we have sold that out. However, it has different components to it. It does have an MVC component. And it also has a flex component for a lot of our foundation shippers. And then, of course, it has the walk-up capacity. And then the way our -- it impacts our revenues is depending on how the customers use that flex capacity, it does have some impact from quarter-to-quarter depending on the amount of volume that they actually flow.

[Jean Salisbury, Bernstein]

Okay. Are they on the hook to pay you for the flex component eventually? Or is that more of a spot sale I guess?

[Mackie McCrea, President & Chief Commercial Officer]

Yes, they have an MVC amount that they're required to pay us whether they flow it or not. But they have the ability to flex it and they can flow it in a month -- or a quarter past the quarter that we're in. But yeah there is a set volume that they're guaranteed to pay on an annual basis regardless of what they flow.

[Jean Salisbury, Bernstein]

I see. Okay. So some of that flex should hopefully come back in the next couple of quarters.

[Mackie McCrea, President & Chief Commercial Officer]

That's correct.

[Jean Salisbury, Bernstein]

Okay. That's helpful. Thank you. And then I know you -- it sounded like from your commentary that the Satellite project was still on track from the customer side, but I just wanted to confirm that. And also just see how you expect the ethane volumes to ramp over time on their side. My understanding is that they're building one of the crackers this year and then one next year. So it'd be, kind of, a slow ramp on the ethane side, but wanted to confirm that.

[Tom Long, Chief Financial Officer]

Yeah. We're so excited about our ethane projects. You probably saw here three or four days ago, we loaded our first VLEC up at our Marcus Hook facility almost 800,000 barrels of ethane. As far as Satellite goes in Nederland everything is on track. They've done a tremendous job, getting their facilities built, getting their ships ordered and ready to go. So we're very excited about that project. They will have a cracker on by the end of this year.

As you heard earlier, we will be commissioning our facility with a ship of theirs in November is our expectations. And then, yeah, latter part of the first quarter or first part of the second quarter, I believe their second cracker's coming on.

So as we say every time, what great partners. They've been a pleasure to deal with. They've done everything they said they would do. And now for the first time at Nederland we'll be bringing on 180,000 barrels per day of ethane capacity primarily for them.

However, we are chasing other markets. We do anticipate selling ethane to other third parties as early as the first quarter of next year. And we'll do everything we can to fully utilize that facility on a daily basis depending on what Satellite actually pulls on a daily basis.

[Jean Salisbury, Bernstein]

Perfect. Thanks a lot.

[Operator]

Our next question comes from Spiro Dounis with Crédit Suisse. Please proceed with your question.

[Spiro Dounis, Credit Suisse]

Good afternoon, guys. First question just want to go back to the 2022-plus capital spending. Wondering how you describe the nature of that spending? Is that part of larger scale multiyear projects that are flowing through those years? Or is it really more blocking-and-tackling-type CapEx? Just trying to get a system – if there's something that can keep the system full of EBITDA or at least flat? Or is it something that can actually grow your EBITDA base?

[Mackie McCrea, President & Chief Commercial Officer]

Yes. This is Mackie again. As you see there's a range there. So there are projects that are in the works and we will be building those. We have contracts that back them. But we also have a cushion there that gives us the ability to grow with some opportunities that we already see out there, some very synergistic opportunities with assets that we already have built. So hence the range of $500 million to $700 million. It's a combination of deals that are already done that are backed by contracts and expectations of new deals.

[Spiro Dounis, Credit Suisse]

Got it. And then strong NGL volumes pretty impressive, especially under the circumstances. Are you guys able to quantify how much of that was ethane recovery versus pulling down some inventory? And I guess how ratable would you say that is going forward?

[Mackie McCrea, President & Chief Commercial Officer]

This is Mackie again. Yes. We are so excited about our NGL segment both in the Northeast with Mariner and Marcus Hook franchise up there as well as what's going on at Nederland. As far as the ethane goes, certainly as ethane prices have increased and we've recovered more ethane, it benefits our NGL system. So that no doubt has been a shot in the arm.

We have the capability depending on where ethane prices go where we can also reject ethane and that's a benefit to our residue pipelines. But where it makes the most sense is what we'll do and it's made a lot of sense over much of this year to go into full recovery so that we can receive the benefits from both transportation and fractionation of those products and also of the marketing of those products and to tailgate our fracs.

[Spiro Dounis, Credit Suisse]

Thanks, Mackie. That’s it for me.

[Operator]

Our next question comes from Keith Stanley with Wolfe Research. Please proceed with your question.

[Keith Stanley, Wolfe Research]

Hi, thank you. First I just wanted to clarify the remarks at the end of the prepared remarks on DAPL. So assuming the Army Corps allows the pipeline to continue operating without an easement, I think I heard you say, could that decision now be challenged by the environmentalists at the district court?

Second, on the time line, I just want to confirm, you said you would expect a decision on the need for an Environmental Impact Statement by the end of the year. And then third just does the Army Corps still work on the EIS in the meantime with the goal of getting it done by the middle of next year? Or are they kind of on pause pending the appeals process?

[Tom Mason, General Counsel of Energy Transfer]

As far as the EIS preparation – this is Tom Mason, again. It's the Army Corps' kind of bailiwick to do that work. And at this point, as Dakota Access, we're not certain as to whether they have started that process or not. There's a certain amount of prep work that could have been done but that's – I think we've kind of been waiting for these decisions before really pressing on that.

So I think we're still confident that we'll win in the appeal process and then an EIS won't be required. So it really hadn't been on the top of the burner in terms of pushing on that from our perspective.

As far as the appeal, itself being heard by the end of the year, I think that's – the briefing schedule that was in the order I think contemplates the decision pretty quickly. And it may well be before the end of the year. So I think that's probably pretty certain.

As far as the challenge of the Army Corps' decisions, I think as with all litigation almost everything gets challenged, whoever wins on a motion or a decision. So I think everything is kind of in flux in terms of what's going to happen next. But appeals are just part of the normal process. So does that answer your questions?

[Keith Stanley, Wolfe Research]

That does. That's very helpful. Thank you. Second question. I guess the company and Kelcy in particular have emphasized the importance of growth as an MLP. And today you're coming out and giving multiple years of pretty low CapEx numbers. So it's going to be a lot tougher to grow organically with that type of capital budget.

So I guess, how do you think about that? And then what are the key criteria you would look for in a potential acquisition candidate? And I guess most importantly, I'm interested if acquisitions are one of the levers you would look at for your balance sheet strategy to reduce leverage. If you were to buy a business or a company that's less levered and can generate synergies from that?

[Kelcy Warren, Chairman & Chief Executive Officer]

Yes. This is Kelcy. You're right. I mean, the -- as large as we are those growth CapEx numbers are low. And that's frustrating to me, but that's what we need to do. It's the right thing to do at this time due to our credit metrics. However, I want to remind everyone and it's been brought up in these discussions, but the backlog of growth that's going to be coming on in the fourth quarter and into the early part of 2021 is huge. And the dollars that are going to follow that are likewise huge. Mackie addressed some of that with the NGLs, but there's others as well. So we went through a very aggressive growth spurt and it's been painful, because it's lasted longer than we expected and cost more than we expected. But now, it's about over and we're relieved that it is.

As far as M&A, I think most people in this sector believe that consolidation is necessary. It is very difficult for us to even contemplate anything really because our units are trading so poorly, it's just hard to do. However, as I said in the last quarter ,it would certainly -- any M&A that we contemplated or ultimately did I guess would need to be deleveraging. We would not undertake anything that was not.

[Keith Stanley, Wolfe Research]

Thank you.

[Kelcy Warren, Chairman & Chief Executive Officer]

Thank you.

[Operator]

Our next question comes from Michael Lapides with Goldman Sachs. Please proceed with your question.

[Michael Lapides, Goldman Sachs]

Hi, guys. Just a cash flow question. With the dramatic reduction in CapEx, I mean, $2 billion next year in terms of lower growth CapEx and another big chunk down or a big step down in '22 '23 assuming that's what plays out, how do you think about, how you actually use -- if EBITDA were to remain somewhere in the trajectory of where 2020 EBITDA is, how do you actually use the cash? Like where on the debt side of the balance sheet do you deploy it? What's the most optimal way to deploy it on the debt side of the balance sheet? And is that the right way to think about it?

[Tom Long, Chief Financial Officer]

You bet. That's actually a very, very good question. We're excited to be in a free cash flow status for next year. And I will tell you that that free cash flow is earmarked toward reduction in debt. Michael, did that answer your question? I'm just trying to tell you that the various buckets that you have and it's earmarked for that when you referred to the free cash flow.

[Michael Lapides, Goldman Sachs]

But same in 2022 and 2023, meaning not just the free cash flow next year. But are you thinking about it that you're in a multiyear deleveraging process assuming EBITDA is -- I know you're not going to give multiyear EBITDA guidance, but let's say we're within the realm of where we are right now. If you had a scenario of flattish EBITDA, are you in two or three years of continuous debt paydown with your free cash? Or do you think of it as a 2021 event and then after that it's let's wait and see?

[Tom Long, Chief Financial Officer]

I see this as more of the multiyear like what you started the question with, meaning that it's 2021 as maturities come up next year. Remind you once again, very manageable maturities for next year of $1.4 billion. But we do have some drawn on the credit facility, so we will likewise bring that balance down. But when you look out at 2022, 2023 I would see that as continuing. A lot of that goes back to the target that we've got on leverage ratio of that 4 to 4.5x.

[Michael Lapides, Goldman Sachs]

Got it. Thank you, Tom. Much appreciate it.

[Tom Long, Chief Financial Officer]

You bet.

[Operator]

Our next question comes from Becca Followill with U.S. Capital Advisors. Please proceed with your question.

[Becca Followill, U.S. Capital Advisors]

Good afternoon. Back on DAPL, assuming that the court maintains the decision that an EIS is required, how do you guys kind of handicap or view the development of an EIS underrate potential by the administration?

[Tom Mason, General Counsel of Energy Transfer]

This is Tom Mason again. It's really hard to speculate on that. It's -- everybody probably has different opinions on what might happen. So it's just hard to speculate.

[Becca Followill, U.S. Capital Advisors]

Okay. Thank you.

[Operator]

At this time, I would like to turn the call back over to Mr. Tom Long for closing comments.

[Tom Long, Chief Financial Officer]

Once again, we thank all of you for joining us today and we really look forward to answering your questions -- follow-up questions after this call. Thanks so much.

[Operator]

Thank you. This does conclude today's teleconference. You may disconnect your lines at this time. And thank you for your participation and have a great day.