Greetings, and welcome to the Energy Transfer Third Quarter Earnings Call. At this time, all participants are in a listen only mode. A brief question and answer session will follow the formal presentation. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Tom Long, Chief Financial Officer.
Thank you, Mr. Long. You may begin.
Thank you, operator. Good afternoon, everyone, and welcome to the Energy Transfer 3rd quarter 2020 earnings call. We really appreciate you joining us today. I'm also joined today by Kelsey Warren, Mackie McCree 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 upon 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 Form 10 Q for the Q3 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 will find a reconciliation of our non GAAP measures on our website. We expect our 10 Q to be filed tomorrow, November 5.
Starting with a few third quarter highlights. We generated adjusted EBITDA of $2,870,000,000 and DCF attributable to the partners of Energy Transfer as adjusted of $1,690,000,000 And our excess cash flow after distributions was approximately $1,280,000,000 On an incurred basis, we had excess DCF of nearly $550,000,000 after distributions of $412,000,000 and growth capital of approximately $730,000,000 We expect significant excess cash flow over the distributions and growth capital going forward. Our 3rd quarter adjusted EBITDA included approximately $250,000,000 of earnings uplift, about half of which was related to one time items. The other half was primarily from optimization activities related to our various marketing and optimization groups. One of our core strengths in providing significant upside to our earnings potential is our commercial team's ability to keep our diversified asset base highly utilized by capturing basis differentials and contango storage opportunities created from market and weather volatility.
Our NGL segment continued to stand out during the Q3 with NGL transportation volumes setting another record, primarily driven by record volumes on our Mariner East and Texas NGL pipeline systems. And our fractionation volumes also reached a new high during the quarter due to an additional ramp up of volumes on frac 7, which went into service earlier this year. And in early September, we were pleased to announce that we completed our Lone Star Express expansion project significantly under budget and ahead of schedule. Now turning to our recent distribution announcement. On October 26, we announced a quarterly cash distribution of $0.155 per ET common unit or $0.61 on an annualized basis.
This distribution will be paid November 19 to unitholders of record as of the close of business on November 6. The reduction of the distribution is a proactive decision to strategically accelerate debt reduction as we continue to focus on achieving our leverage target of 4 to 4.5 times on a rating agency basis and a solid investment grade rating. We expect that the distribution reduction will result in approximately $1,700,000,000 of additional cash flow on an annualized basis that will be directly used to pay down debt balances and maturities. This is a significant step in Energy Transfer's plan to create more financial flexibility and lessen our cost of capital. Once we reach our leverage target, we are looking at returning additional capital to unitholders.
This will come through unit buybacks and or distribution increases with the mix being dependent upon our analysis of market conditions at the time. Turning to the 2020 outlook, we now expect to come in at the high end of our adjusted EBITDA guidance range as a result of better company performance. Looking more closely at our cost reduction measures, which are underway in our corporate offices as well as at our field operations. During the Q3, we identified additional opportunities to leverage our infrastructure to drive operational efficiencies and optimize our assets and have recognized approximately $400,000,000 in G and A and OpEx savings year to date. And for full year 2020, we now expect to achieve cost savings of over $500,000,000 relative to our original budget.
And for our growth capital, we now expect 2020 growth capital expenditures to be less than $3,300,000,000 This represents a further reduction of over $100,000,000 from our guidance provided last quarter as a result of projects coming in under budget. Our spend for the remainder of 2020 consists of several projects that we expect to be completed by year end 2020, including the next phase of Mariner East, Orbit and other NGL export projects. These projects will enhance our existing portfolio and provide near and long term value. We will see a significant reduction in growth capital spend in the years ahead with our forecast of approximately $1,300,000,000 in 2021 and $500,000,000 to $700,000,000 per year in 20222023. Our evaluation process for new projects continues to be very stringent and our threshold for returns is the highest it has ever been.
I'll now walk through the recent developments on our major projects. We'll start with Dakota Access. The appeal process with respect to the Lake Oahe litigation is ongoing. Oral arguments in the case took place earlier today. We still expect a decision from the DC Circuit Court of Appeals by the end of the year.
We continue to believe that our legal positions in the case are strong and we are confident that our pipeline will continue to operate as normal. The pipeline remains in service today and like all of our assets, we will continue to operate it safely and efficiently. We continue to move forward with the Bakken pipeline capacity optimization. And on October 15, we received regulatory approval from the Illinois Commerce Commission, which was the last remaining state regulatory approval required for us to move forward with the optimization project. The initial phase of the optimization will accommodate the volume commitments made by shippers during open seasons.
We now expect this additional capacity to be in service late in Q3 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 Q4 of 2021. Now on to our Mariner East System. During the Q3, we saw the highest average quarterly volumes yet through the Mariner East Pipeline System with year to date 2020 NGL volumes up 40% over year to date 2019.
Utilization of our Mariner pipelines and our Marcus Hook terminal continued to increase, leading to record amounts of propane transported through the pipeline as well as strong butane and ethane utilization. The system continues to demonstrate flexible optionality for shippers, including the ability to handle ethane spot cargoes as well as provide 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 and we are prepared to handle this demand with strategic NGL reserves at Marcus Hook. Additionally, our Mariner system will have the ability to bring natural gasoline to Marcus Hook for gasoline blending and local consumption by early in Q2 of 2021. We are eagerly awaiting the next significant phase of the Mariner East projects, which we expect to be in service by the end of this year, with the final phase expected to be completed in the Q2 of 2021.
Also, our 50,000 barrel per day LPG expansion at the Marcus Hook terminal is now expected to be in service in late 2020 ahead of expectations. 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. And we are very excited to announce Pennsylvania Access, which will utilize part of our Mariner East System to bring refined products from the Midwest supply regions through our Allegheny Excess Pipeline System into Pennsylvania and to markets in the Northeast. This project will require minimal capital, which is already included in our budget and will add significant revenue and synergies with our existing refined products pipeline and terminal assets. We anticipate a Q4 2020 start up for early volumes to be able to flow from Ohio into Pennsylvania and to upstate New York markets.
As I mentioned earlier on the call, we were pleased to announce that our 24 inches 352 Mile Lone Star Express expansion was completed under budget and ahead of schedule. This project adds over 400,000 barrels per day of NGL pipeline capacity from the Permian Basin to the Lone Star Express 30 inches pipeline south of Fort Worth, Texas. LPG demand continues to remain strong and our LPG expansion projects at Nederland will bring our total export capacity to approximately 500,000 barrels per day further integrating our Mont Belvieu assets with our Nederland assets. Construction of our Orbit ethane export joint venture with Satellite Petrochemical is nearing completion. This 180,000 barrels per day project will be ready for commercial service in the Q4 of this year with the 1st ships now arriving by the end of the year for commissioning.
Next, I want to take a moment to provide a renewables update. Last week, we published our 2019 community engagement report, which highlights our pipeline safety management programs and our performance data, risk management and emissions reduction programs. It also covers our stakeholder outreach and community investment activities. As a company, we are committed to identifying and implementing cost effective emission reductions and prevention opportunities, including the reduction of our carbon footprint. As a result, we make significant investments each year in technology to reduce emissions and improve our overall operations, performance and efficiency.
Today, approximately 20% of the electrical energy we purchase originates from renewables and we expect that will continue to grow. We continue to actively look at renewable power deals that will allow us to increase our use of power generated by renewable sources. Additionally, we have approximately 18,000 solar panels located at pipeline metering stations across the country. We also own a gas fired electric generation company that uses renewable natural gas in Pennsylvania to generate electricity, helping to power Pennsylvania homes. Our dual drive compressors, which have a patented technology that allows for switching between electric motors and natural gas engines to drive compressors offers the industry a more efficient compression solution helping to reduce greenhouse gas emissions.
More recently, we entered into our first ever dedicated solar contract for which a 28 Megawatt solar facility is currently under construction. This will deliver low cost clean power to energy transfer under a 15 year power purchase agreement and demonstrates our commitment to reducing our environmental footprint by integrating alternative energy sources when economically beneficial. We are also evaluating opportunities to better utilize our available capacity to transport CO2 in the Northeast and are looking into the potential to bring renewable diesel into West Texas via our J. C. Nolan pipeline.
As the energy industry continues to evolve and customer demand for these services increases, we will look for additional ways to further integrate alternative energy sources into our business when economically beneficial. Now let's take a closer look at our 3rd quarter results. Consolidated adjusted EBITDA was $2,870,000,000 compared to $2,810,000,000 for the Q3 of 2019. This was a result of strong performance from our NGL and refined product segment as well as some uplift from optimization activities. DCF attributable to the partners as adjusted was $1,690,000,000 for the Q3 compared to $1,550,000,000 for the 3rd quarter of 2019.
This is primarily due to the increase in adjusted EBITDA along with a decrease in maintenance capital expenditures. Now turning to results by segment. We'll start with the NGL and refined products. Adjusted EBITDA was $762,000,000 compared to $667,000,000 for the same period last year. This increase was primarily due to record NGL transportation and fractionation volumes as well as higher optimization gains from the sale of NGL components at Mont Belvieu.
NGL transportation volumes on our wholly owned and joint venture pipelines increased to 1,500,000 barrels per day compared to 1,400,000 barrels per day for the same period last year. This increase was primarily due to the 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. On our fractionators, utilization rates remained high during the 3rd quarter with average fractionated volumes increasing to 877,000 barrels per day compared to 713,000 barrels per day for the Q3 of 2019. Looking at our crude oil segment, adjusted EBITDA was $631,000,000 compared to $726,000,000 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 lower production and reduced demand due to COVID-nineteen as well as a decrease in our crude oil acquisition and marketing business related primarily to fewer optimization opportunities.
These items were partially offset by the contributions from the SemGroup assets, which we acquired in 2019, as well as an increase related to trading gains realized from contango storage positions. For Midstream, adjusted EBITDA was $530,000,000 compared to $411,000,000 for the Q3 of 2019. In the Ark La Tex region. In addition, operating expenses decreased $33,000,000 Gathered gas volumes were 12,900,000 MMBtus per day compared to 14,000,000 MMBtus per day for the same period last year. Lower volumes in South Texas and North Texas were partially offset by volume growth in the Permian, as well as the addition of assets acquired in 2019 in the Mid Continent Panhandle region.
For our Interstate segment, adjusted EBITDA was $425,000,000 compared to $442,000,000 for the Q3 of 2019. This was primarily the result of a scheduled contract rate step down in January 2020 at our Lake Charles LNG facility, which we have referenced on previous calls this year, as well as less capacity sold on our Panhandle and Trunkline systems. These were partially offset by increased margin from the Transwestern and Rover systems due to increased demand in firm transportation. And in our intrastate segment, adjusted EBITDA was $203,000,000 compared to $235,000,000 in the Q3 of last year, primarily due to lower revenues from pipeline optimization activities as a result of the drop in spreads, partially offset by reduced operating cost. Beginning in 2021, we expect to have less exposure to spreads as we have locked in additional volumes under long term contracts with 3rd parties.
Now moving on to CapEx update. For the 9 months ended September 30, 2020, Energy Transfer spent slightly under $2,500,000,000 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 less than $3,300,000,000 on organic growth, primarily in our NGL and refined products and midstream segments. We're in the final stages of several significant growth projects, which will help support our future growth and we believe that there are exciting days ahead for the partnership as we're taking meaningful actions to build and improve our industry leading franchise. And we currently expect our 2021 growth CapEx expenditures to be approximately $1,300,000,000 and growth capital in 20222023 to be between $500,000,000 $700,000,000 per year.
Looking briefly at our liquidity position. As of September 30, 2020, total available liquidity under our revolving credit facility was approximately $2,650,000,000 and our leverage ratio was 4.24 times for the credit facility. And as a reminder, we have no additional maturities in 2020. And looking ahead, we have very manageable maturities of $1,400,000,000 in 2021, which will be more than covered with the additional retained cash flow from the reduction in distributions. In conclusion, throughout the 3rd quarter, activity consistently improved around our Permian Midstream assets across the Mariner East Complex and through our NGL fractionation assets.
Looking ahead, the near and long term value that our ongoing growth projects will contribute is very clear, and we will continue to leverage our expansive footprint to drive operational efficiencies. In addition, we continue to emphasize the importance of capital discipline throughout the organization, as demonstrated by our growth capital reductions throughout 2020. We remain committed to our investment grade rating and our recent distribution reduction will allow us to accelerate our deleveraging strategy by immediately using excess cash to pay down debt. In addition, our capital discipline and growth capital reductions announced throughout this year demonstrate our commitment to generating excess cash flow. Combined with Energy Transfer's best in class asset base, we believe these actions will better position the partnership for continued long term success.
Operator, please open the line up for our first question.
Thank you. Our first question comes from Yves Siegel with Siegel Asset Management Partners. Please proceed with your question.
Thank you. Good afternoon, everybody. And also congratulations to Tom, Mackie and Dylan for the nice recognition and the promotions. I have 2 quick questions. One is kind of obvious with Biden looking like he's going to win.
How do you think that may impact the company? And maybe if you could tie that into talking about the export market and China. So that's the first question. And then the second question, if I could, is how do you think upstream consolidation may impact the business going forward? And when do you think we could see consolidation in the midstream space?
What do you think the catalyst would be for that? Thanks very much.
Hey, this is Mackie. Thank you for the compliment to us. We appreciate it. We look forward to it, but Kelsey won't go far. He'll be around.
I'll start out with the first question and Tom will finish up with the second one. So I guess kind of from our standpoint as far as election goes, I'm not sure we're in the same boat that it's already been decided. Certainly, that could happen. We think it's probably still a toss-up for a whole number of reasons, but we certainly won't know over the next 2 or 3 days. But just assuming your question that Biden were to win, and we've said in the past, we there's some uncertainty about his positions over the years.
At one point in time, he was kind of pro pipeline. He was kind of always pro fracking and he backed off on that and now he's kind of supposedly going to ban some type of fracking mainly around federal But the positives are in a Democrat controlled government is that the regulations will no doubt increase. So it will be much more difficult to build pipelines, to construct pipelines, to get pipelines permitted, it will be very time consuming. And so companies like ourselves, we probably kind of stand alone with our footprint throughout the country where we go into every major basin, we feel pretty good about that aspect of them winning. From the standpoint of drilling and how it might impact federal lands, it will have very little to no impact on entry transfer as far as the exposure we have to federal lands and potential reduction or removal of fracking from those lands.
So I'll reiterate, we're not sure we are on board that Biden is going to be a winner, but if he does, we'll kind of listen to his policies and we'll make the best of it. But we feel like we're pretty well positioned.
And what about the export market?
I'm sorry, I was just going to ask about the export market in China. Do you think that might improve the outlook there or maybe not?
Yes, I don't know. We've been actively selling and very excited about bringing on our next LPG project
at the end
of this year, 1st part of next year. We're more than doubling our capacity and a lot of the customers that we've already signed up for a year or 2 out or 5 or 6 at least customers from China. So it really hasn't prohibited LPG side of the business. We also still load crude every month to certain Chinese companies. So we really don't anticipate that would be an impact to us.
But it certainly goes without saying that Trump hasn't been a friend of China in the aspect of he feels like China is taking advantage of the U. S. Over the years and he's trying to kind of equal the playing field. So who knows, a lot of info, a lot of data out there around Biden in China. And so it remains to be seen how that all play out if Biden's president.
Okay. Thank you.
And Eze, as far as the upstream consolidation portion of your question, we actually feel good about that in the long term. We feel like it's going to create stronger upstream companies, stronger balance sheet, more opportunities for drilling. So all in all, we're very supportive of the consolidation that we're seeing occur in the upstream companies.
And did you have any insight into the second half of what may push the midstream to consolidate? Any catalyst that you may see or not?
Well, I think yes, and to answer your question as far as catalyst, and there's probably a couple of things there. One of them is what I just mentioned on the upstream side of it as far as being able to create stronger balance sheets, a little more financial flexibility. But the second part of it is more of the commercial side of it, meaning better utilization of available capacity across several of the products, lines, be it crude, NGLs, gas, etcetera. So we actually see that that is a positive for the midstream space and it's something that we do anticipate will start occurring.
Well, thanks guys and really nice quarter. Well done on the execution.
Thanks, Steve. Thanks.
Thank you. Our next question comes from Shneur Gershuni with UBS. Please proceed with your question.
Hi, good afternoon everyone. I wanted to echo Yves' congratulations. Just maybe to start off a little bit, you talked about in your prepared remarks today Pennsylvania Access project. Just wanted to understand or clarify a little bit here, if I have the understanding correct, are you effectively utilizing the Mariner East 2 system and basically partitioning it to be able to move refined product on it and all that capital is sort of contemplated within your budgets and so forth? Or is this kind of a brand new project?
This is Mackie, Shneur. We ask all of our business development team to look for the best utilization of our pipelines. And of course, we're doing that in Texas on our crude pipelines today, and we've got some great ideas and excited about those. But some of our team came up with the idea a while back that from time to time, especially during the winter months, we see kind of a blowout between Chicago and the New York markets and for refined products and we saw the opportunity. So yes, we're in the process and we will be converting the really the 8 inches the Mariner 1 line, a portion of it into refined product service and we're very excited to bring that on hopefully here by the end of the year and that should provide significant upside revenue for an asset.
That doesn't limit us for what we can do with the remaining portions of the Mariner system to be able to transport all of the LPG and ethane that we have contracted and that we're in the process of contracting additional volumes.
Okay. So facing you just moving the NGLs onto 2 and 2x and you're using the original 8 inches Okay. That makes perfect sense.
That's correct.
Okay. And then as a follow-up question, I'm sure you're probably prepared for this, but I was wondering if we could talk about the inside baseball around the distribution cut. Obviously, you mentioned at a high level, it's about pivoting towards accelerated leverage reduction, which I think you all get. But I was just wondering if you can sort of share with us the Board discussions around what scenarios you were thinking about? Was there a thought to cut it deeper and delever faster?
Did you preview it with the rating agencies before? And is there some is there an expectation that some of the negative outlooks will be removed at some point? Just wondering if you can give us the broad inside baseball discussion around it.
Well, Shneur, that was a mouthful there. You got through it well. Listen, we it really is the deleveraging. We were on a path for deleveraging to that 4% to 4.5 even when we had the original guidance back at the 11 to 11.4. It's important to us to stay on that same trajectory for deleveraging and getting to that.
And as far as the dialogue with the agencies, that's what we continue to show them, our objective of moving forward. We feel like the conversations that we have with them are very constructive. They know that we're focused on the deleveraging and increasing our financial flexibility. And I think that they're obviously very pleased with it. As far as the amount, once again, it keeps us at the same pace that we were already headed to.
We've pulled all the other levers. We're completing some fantastic projects on the CapEx side. And so CapEx was already coming down just naturally. We've looked at cost savings and we think we've been doing a very, very good job on that, like talking about on this in the prepared remarks of hitting $500,000,000 over $500,000,000 for this year. So we're pulling all the levers and those are the type of discussions that we have internally when we sat down to make the decision is to continue on the same schedule we've got on deleveraging the company.
That makes perfect sense. And just one clarification, pretty impressive to hit a $500,000,000 cost reduction exercise in 1 year. Just wanted to clarify that that is fully achieved this year or is that kind of the run rate you're at now? And so as we sort of think about next year, cost should trend a little bit down as you sort of season or round trip those cost cuts?
Well, when you combine it with all the great projects that we have that talked about that we're completing this year, just by naturally you're going to see OpEx
come up.
I'm referring to Mariner East, Orbit and other smaller type projects. I think the normal run rate would probably be closer to probably $350,000,000 But don't think that we're not continually trying to look to achieve a higher number than that. But if I was to guide you for going forward, I would probably say at least the $350,000,000 Remember, you also are going to have inflation, just some of the normal increases that occur when you're a company of our scale and size. But $350,000,000 should be a good number you can use.
But when you're talking about inflation, it's just you're adding new assets, so new costs come with those assets. But on a like for like basis, you're still down about 5?
Yes. I think that's probably a fair statement. Cool.
Perfect. Guys, thank you very much. Really appreciate the color today and have a safe day.
Thank you.
Thank you. Our next question comes from Jeremy Tonet with JPMorgan. Please proceed with your question.
Hi, good afternoon. Hello. Hey there. Hi. Just want to look a little bit forward here.
And based on your guidance and your commentary, it seems like there were some favorable items in 3Q that won't necessarily repeat in 4Q here. And so just wondering is the guidance implied with 4Q EBITDA kind of a fair run rate of what the business can do on a recurring basis? And then when you layer on kind of the slew of new projects that are coming into service, I'm just trying to think through how much could EBITDA really step up here? And how do you feel about the pace of deleveraging to get ET off negative watch at the agencies? Just want to see how comfortable we should be feeling on that.
Well, you're right. We want to make sure when we talked about the quarter that we highlighted some of the optimization activities as well as in the midstream on some of the revenue recognition that we saw around that one contract. If you really look forward, I think it's fair to say that we have I want to emphasize once again, we have a great commercial team that will always be looking for opportunities for optimization. It's not necessarily something we bake in at the high end, but we don't bake it in at the low end either. So in fairness, I would I'd say that our guidance that we've left out there, we said at the upper end of that.
I think you can really run with that. From a standpoint, even as you start looking out into next year, I'd like to at least hold off until we do the Q4 analysis Q4 earnings call to discuss further with you as to 2021.
Got it. And maybe just come back to the last part with the agencies here. I guess, how comfortable are you that ET is on the right trajectory here to be taken off negative watch? Are there really incremental actions that are needed ensure that everything goes smoothly there?
Let me just answer that we're very comfortable. I think the conversations we have with them are very constructive, and I'd like to say that we are very, very comfortable about the outlook coming back up.
Great. Thanks. And just one last one, if I could. Pivoting over to renewables, appreciate all the disclosure there. And just wanted to get a sense, appreciate CapEx is really kind of diving down here.
But as you look further out and you look at opportunities across your footprint, be it compressors converting to electric and adding solar, just what type of opportunity set? How big could that be for you guys? And how does hydrogen fit into that?
This is Mackie. Let me start out with saying, it's interesting, this is such a big topic now and I guess it's kind of our time to share that we've kind of been doing this for a while and I'll elaborate on that. But we made the press release about 25 megawatts and it wasn't a project that made sense for us as far as a rate of return project. It wasn't something we were going to participate in. However, the power purchase agreement that we did to get the project off the ground made a lot of sense for us under very inexpensive long term electricity.
So we will look for those opportunities every day. There's probably at least another 100 megawatts to 200 megawatts, both in the south part of the country and the Northeast that will be looking for similar type power purchases. Once again, unless the economics change dramatically from what we've seen, we won't participate, but we certainly will support it with buying cheap electricity. And we've mentioned the other things on the opening remarks that we're looking at doing around renewable diesel and carbon capture and all that. But one thing you mentioned electric compression, we patented this dual drive compression system where you it's either run by a electric motor or a gas engine.
And gosh, I think it was 2012 or so. We've been running for that long. And just to give you an example, in 2019, we emitted 1,000,000,000 less or reduced our emissions by £1,000,000,000 of CO2 just through our dual drive technology, the compressions that we have throughout many parts of our system in Texas. And we would love a lot of our competitors to buy or to participate in these because they are excellent opportunities to optimize your system where you run electricity, where it's much more efficient, it's much better for emissions, but also if there's any issues with electricity, you switch over and you run on gas, you don't have any downtime. So we'll continue to look to apply that technology as well as straight up electric compressors where it makes sense.
But I'll wrap all that up. The way Interchangeable will look at renewables is that we will look at it, we will chase it. When it makes sense and meets our hurdles, we will participate. If not, we'll be a purchaser it makes sense for us from a purchasing standpoint. Around hydrogen, we've looked at hydrogen and honestly the team, our engineering team that I've talked to, we've kind of dug in over the last several months and I'll just hit a couple of them.
For example, we've looked at green energy. So you look at taking wind and solar through the electrolysis process and producing hydrogen, our estimates are it's about 8x per MMBtu as the value of methane. And then you look at gray hydrogen where you take natural gas and introduce water and you produce hydrogen, that's still about 3x the cost or value of methane. So we kind of scratch our heads around hydrogen. We know Europe is setting up 1,000,000,000 of dollars of subsidies and we know there's a lot of companies here talking about it and doing it.
And of course, Air Products is big time in it with their plants and pipeline. But at this point, we don't see anything close in the horizon around hydrogen. It's very corrosive to pipeline, so it's got to kind of fit corrosive to compression. And so that's something that we'll continue to look at. If customers come to us with ideas or the things change or if the government provides more subsidies where it makes sense, we'll certainly look at that.
But right now, we that's a head scratcher.
Got it. That's a helpful perspective. Thank you for that.
Thank you. Our next question comes from Peter Salmon with Simmons Energy. Please proceed with your question.
Yes, good afternoon. And let me extend my congrats to Tom and Mackie as well. My first question is, are you seeing any improvements in the divestiture market? And would you consider divestitures to help delever the company?
No. As far as the first part of your question, we're not seeing improvements, still less capital out there chasing the projects and the multiples clearly have come down. So our guidance to you is there's really not anything material that we're looking at on the divestiture side as we sit here today.
Okay. Thank you, Tom. And then a follow-up question. Just from a real high level, what is your outlook for U. S.
NGL supply next year? And then as well, what do you see kind of a high level outlook for LPG exports out of the U. S. Next year?
Well, I'll start with the second part. As everybody knows, we've got about 180,000 barrels of LPG export capacity from Nederland today. We've been diligently working to add to that and approach 500,000 barrels a day. We couldn't be more excited. As I mentioned a little bit earlier, we've actually now sold out for at least a year, if not 2 years, every slot that we have the ability to sell out other than spot slots that are available each month, depending on how the customers utilize their capacity.
So we're incredibly excited about that. There is an enormous market that we could sit here and rule off 10 or 12 companies I'm sorry, countries that we're dealing with that we have signed contracts with or negotiating with around the world. So you really don't see the impact like you are on crude and gasoline. There is an enormous market both domestically and around the world for petrochemicals that pretty much run our lives and the thousands of products that we use every day. So we see that as a big plus and that's going to be a huge growth area for us, not just at Nederland, but also at Marcus Hook as we complete years and 1,000,000,000 of dollars of projects to complete our pipelines and build out our infrastructure at Marcus Hook.
So we're could be more excited and anxious to kind of kick off this next phase to become, if not the largest exporter of LPG and ethane in the country, pretty darn close by the end of this year, early part of 2021. As far as NGLs, we that's tied a lot to, of course, drilling in West Texas is kind of a core area for us for our growth in Eagle Ford to a certain degree. We actually are somewhat optimistic. Now that's taken into account WTI has got to hang in there, got to kind of hang around 40 or maybe start to grow to kind of keep this kind of optimism. But talking to our producers, looking at the just a lot of DUCs out in West Texas, we do think there will be drilling around lot of these areas.
We think we'll see 15% to maybe 20% growth by the end of next year kind of conservatively with a lot of our producers. So we are I wouldn't say we are overly bullish, but we are certainly optimistic that we will see volumes grow on our systems, our rich gas, ultimately producing NGLs to transport and frac and to export or sell into the domestic markets.
Thank you, Mackie, for the color.
Sure.
Thank you. Our next question comes from Michael Lapides with Goldman Sachs. Please proceed with your question.
Hey guys, thank you for taking my question. And like the others, congrats on the various promotions, Tom and Mackie, Kudis. Real quickly, can you talk a little bit about where you think you are in the producer kind of bankruptcy cycle? And when you look forward across the different businesses, where do you think the greatest risk may lie to either existing producers that are 35 or producers that may be in high distress right now?
Yes. Let me start and maybe Tom can add if you would like to. But and we say this a lot, we're pretty proud of our credit the credit of most of our customers. We certainly have some that are out there that are a little concerning. And of course, there's been some bankruptcies already that we're kind of dealing with.
But for the most part, we don't really see anything that can happen that's just very material. And even those bankruptcies that do happen, there's things we can do and renegotiating agreements and call it blend and extend with some other deals we may have with them in other areas. So I wouldn't sit here to say and Tom may elaborate on this, but I wouldn't sit here to say there's anybody really out there that gives us a great deal of concern about bankruptcies at this point.
And I just want to echo Mackie's comment. There really isn't anyone. I always like to compliment our credit group. I think they do a very, very good job of monitoring all of our counterparty risk. They do a good job of mitigating the counterparty risk.
And as we sit here today, don't have anyone or any concerns with any.
Got it. And then one question on capital of the Bakken expansion. Can you just remind us, you've gotten the Illinois Commerce Commission approval, how much incremental capacity you're adding? And I know you've got contracts, but does the market given lower production out of the Bakken, does the market actually need that capacity right now or even in the next year or so?
Well, that remains to be seen. Certainly, we need some more rigs to move back in for volume growth. Fortunately, we know that when they do move back in, we will be the pipeline of choice or the outlet of choice. So we're always very pleased to have that situation up there. We'll be expanding from 570,000 barrels a day about 740,000, 750,000 barrels a day.
And as you said, a large portion of that, not the walk up space, but a large portion of that is demand charge. And so we'll receive payments regardless of whether the volumes are there or not. But we're somewhat optimistic that the volumes will be there, that drilling will commence as long as crude kind of hangs in there or increasing early part of 'twenty one. Hopefully, all these economies get back going again sooner than later. And so we are hopeful that production returns.
But from a risk standpoint, from Energy Transfer, those are backed by demand charge agreements.
Got it. Thank you, guys. Much appreciated. Once again, congrats.
Thank you.
Thank you. Our next question comes from Ujjwal Pradhan with Bank of America. Please proceed with your question.
Good afternoon, everyone. Wanted to add my congratulations to Tom and Mackie as well.
Thank you.
Thanks.
I'll first begin on your 2021 CapEx outlook. Obviously, you have significant number of ongoing projects set for in service by year end. And next year, it seems you have remaining spend on Mariners 2 and the Ted Collins pipeline. Outside of those 2, can you talk about what forms the bulk of your $1,200,000,000 budget?
Yes. I'll take off with this and then Mackie can chime in. But I would say that it's still the NGL and refined products. Clearly, carries the majority of it, 70% to 75% of it. Midstream brings up the next piece of it and it's down to 10% to 15% of it.
And we do have and you already highlighted this, but on the crude oil side, like the Ted Collins link and some of the optimization, that brings up the last piece at 5% to 10%.
Got it. Thanks for that, Tom. And second question on the double access pipeline and some of the challenging that we have faced here. Appreciate the update from today's hearing. And we think a contingency plan around what you could do under an adverse outcome from the court cases might help address some of the market concerns here.
So for illustrative purpose, under a potential adverse outcome, do you believe you'll be able to operate sections of the pipe not impacted by the permit issue or monetize sections that are not impacted? Thank you.
Yes, I'll start. Tom, maybe. But this is Mackie again. Yes, we really don't we had a hearing today and we'll continue to go through the process, but we really don't envision or see a scenario where we will take the pipeline out of service. We just don't think that's going to happen.
We are highly confident that DAPL will remain in service like it has safely, efficiently for the last 3 years. And so the real issue is that will full EIS have to be completed or not and that remains to be determined as time goes on. But we're highly confident that the pipeline will continue flowing and not shut in.
Got it. Thank you. And if I can just squeeze a bit in a quick one. So the asset so the CapEx reduction this year, it looks like that came from project cost savings. Can you talk about what sort of items led to that?
I'll start. This is Mackie. Yes, well, one of them was we just completed our Lone Star Express and we came in significantly under budget and we kind of saw that as the year was coming, but we actually realized it as we brought the pipeline online here recently. So that was some of it. We also a little bit has been deferred.
And then some of it is just we put it on hold because some of the producers that we were contracting with had held up drilling and held up the need for some of the services that we were going to provide.
Yes, there's not a whole lot more to add to that. It really is the savings. We lowered it by, we said, a little over $100,000,000 and those are the primary drivers. There's some other, what I would call, smaller immaterial type projects, but that clearly is the driver of what Mackie just went over.
The color here. Have a good day.
Thank you. You too.
Thank you. Our next question comes from Jean Ann Salisbury with Bernstein. Please proceed with your question.
Hi. I had one more about Mariner East 2 and 2X. Is the right way to think about that, that your substitute pipe is already moving the vast majority of the available NGLs? So the upside on EBITDA will mostly be from the natural gasoline when that starts, but that's kind of most of the upside that we should expect and a ton more NGL volume and revenues?
No, this is Mackie. No, it would be both. So as we complete Mariner 2 at the end of this year and 2x later on in 2021, we have volumes that will be coming online, both transport volumes and volumes that will need to be chilled and exported or sold in the local market. So we will increase our NGL volumes and our throughput, both for ethane to a certain degree a little bit and also for LPGs for LPG. But the portion of the 8 inches line that we're converting, that will be moving refined products, that will be brand new revenue that we have never received new business where we'll be able to benefit from the arbitrage or the spread between the Chicago market and the New York market really on a monthly basis, wherever the highest price for gasoline is, we'll be able to buy directly move either direction.
So we see that just almost as just another system.
Okay. And that LPG that you'll pick up is moving by rail now, I guess?
Correct. By rail or some volume growth.
Yes, that's super helpful. And then my second question is just, I think that the early Permian Expresses, like Permian Express 12, I think those are listed as mostly 5 7 year
contracts in 2013 and
2015. Can you comment roll offs from that next year? It seems like both of those would have some from the original contracts coming off.
Yes, we've actually had one of those roll off this year. And yes, over the next couple of years, we will have several more rolling off. However, we are working on a project and moving it forward, going to happen, where we're working with another company to move barrels from Cushing. That will start filling in some of the Permian Express 1 capacity of the contracts they'll roll over. So if we're unable to roll them over at rates that work for us, we do have some volumes that we'll be filling in of at least 60,000 to 65,000 barrels a day with the ability to double that as the market allows.
So we are as I said earlier, that's our some of the biggest focus in our partnership is to look at our crude capacity as the contracts roll over and extend those contracts or chase new barrels and or to utilize some of those pipelines in a different service.
That's very helpful. Thanks. That's all for me.
Thank you. Our next question comes from Keith Stanley with Wolfe Research. Please proceed with your question.
Hi, thanks. First one, just want to confirm. So you're going to have a lot of free cash flow next year after growth CapEx and distributions now. So I think I know the answer, but I just want to clarify, you expect 100% of that free cash flow to go to debt repayment at this point? Or is there any flexibility at all on uses of the free cash flow?
There's always flexibility, but I will say we expect at this time for 100% of that to go toward debt pay down. It's one of those that once we get into our target range of 4 to 4.5, we will evaluate that further. But right now, we're focused on bringing the leverage now.
Thanks. And one other quick one, just any interest still in preferred equity market to further accelerate deleveraging after the distribution cut?
Yes. We will take advantage of that market when it makes economic sense. And we do feel like that's something that does accelerate it. You're exactly right. And we will continue to monitor that market.
Great. Thank you.
Thank you.
Thank you. Ladies and gentlemen, that's all the time we have today for questions. I'd like to turn the floor back over to Tom Long for closing remarks.
All right. Thank you. And once again, we really appreciate all of you for joining us today. And as we've mentioned today, we remain very excited about the performance of our existing asset base as well as all of the projects that we have coming online. Thank all of you for your support, and we look forward to talking to you in the near future.
Ladies and gentlemen, this concludes today's web conference. You may now disconnect your lines at this time. Thank you for your participation and have a great day.