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Energy Transfer LP
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Greetings, and welcome to the Energy Transfer Fourth 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. [Operator Instructions] As a reminder, this conference is being recorded.
It is now my pleasure to introduce your host Mr. Tom Long, Chief Financial Officer. Thank you, Mr. Long, you may begin.
Thank you, operator. And Good morning, everyone, and welcome to the Energy Transfer fourth quarter 2018 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.
As a reminder, we will be making forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These are based on our beliefs as well as certain assumptions and information currently available to us. 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.
I just want to start by saying that Energy Transfer saw significant growth and change in 2018. In addition to delivering strong financial performance with record adjusted EBITDA of $9.5 billion for the year, which is up nearly 30% over 2017, we successfully executed on several key initiatives, including a simplification of ETE and ETP, the completion of multiple major growth projects, and we took meaningful steps towards deleveraging the company and improving the financial flexibility of our balance sheet.
As for our fourth quarter performance, consolidated adjusted EBITDA was up almost 30% over the fourth quarter of last year, and pro forma for the merger of ETE and ETP, DCF attributable to the partners of ET, as adjusted, also increased almost 30%. We continue to see strong performance in all of our major businesses and reported record operating results in the NGL, intrastate and interstate segments.
Distribution coverage for the quarter was 1.9 times, which resulted in excess cash flow after distributions of approximately $715 million for the quarter. These results demonstrate our ability to internally generate a large amount of equity capital, which can fund our excellent backlog of growth projects in a credit-friendly manner and also allow us to further organically strengthen our balance sheet. Looking ahead to 2019, we continue to expect to generate between $10.6 billion and $10.8 billion in adjusted EBITDA, and we also still expect to expand approximately $5 billion organic-growth projects.
Before going into a more detailed discussion around fourth quarter earnings, growth CapEx, guidance and the liquidity update, I’ll start with the latest developments on our growth projects. Starting with ME2 and 2X, I am pleased to say that we placed the initial capacity of ME2 into service on December 29 of 2018. Volumes are ramping up on the pipe, and we expect to be running at capacity in the near future. And on ME2X, 99% of the mainline construction is complete, and at this time, we continue to target having the pipeline in service by late 2019.
Now turning to Frac VI, we are pleased to announce that this 150,000 barrel per day fractionator went into service earlier this week and is expected to be running at full capacity early in the second quarter. And in November 2018, we announced plans to construct our seventh Lone Star fractionator. Frac VII will also have a capacity of 150,000 barrels per day and is fully subscribed under long-term demand-based agreements. It is expected to be in service in the first quarter of 2020.
To accommodate this growth, we previously announced the 24-inch 352-mile Lone Star Express expansion, which will add approximately 400,000 barrels per day of NGL pipeline capacity from Lone Star’s pipeline system near Wink, Texas to the Lone Star Express 30-inch pipeline south of Fort Worth, Texas and is expected to be in service in the fourth quarter of 2020, and we continue to evaluate further expansions of our frac capacity due to the strong demand from customers.
In January of 2019, we completed a successful open season on the Bakken pipeline to bring the current system capacity to 570,000 barrels per day. This capacity is available today with new shipper commitments from the recent open season becoming effective on or before March 1. Continued basin production growth and fourth quarter differentials drove nominations in excess of our available capacity during the fourth quarter. This demand as well as incredible demand from capacity during our recent open season further highlights the need for additional takeaway capacity out of the basin.
As a result, we are looking at increasing system capacity to serve this growing demand, and we’ll make that decision at appropriate time. And on the 30-inch Permian Gulf Coast pipeline joint venture project with Magellan MPLX and Delek, we are continuing to pursue shipper commitments. This 600-mile pipeline will provide unprecedented flexibility from the Permian Basin for deliveries to both Energy Transfer’s Nederland terminal as well as Magellan’s East Houston terminal and ultimate delivery through our respective distribution systems. Additionally, it will provide shipper capacity to our storage facility and pipeline header systems at Nederland.
ETC is also in discussions with Exxon and Plains to potentially join their project. We will continue to go down parallel paths in order to evaluate and achieve the most efficient and accretive project for our partnership. Now looking at Bayou Bridge, we are nearing completion of construction on the 24-inch segment from Lake Charles to St. James, and expect commercial operations to begin in March.
On Permian Express 3, as mentioned on the last call, the final 50,000 barrels per day of capacity went into service in September of 2018, bringing our total capacity of PE3 to 140,000 barrels per day and PE1, PE2 and PE3 all continue to operate at full capacity. The expansion of the 36-inch North Texas pipeline, which we jointly own with Enterprise, was placed into service in early January.
The North Texas pipeline expansion provided approximately 160,000 MMBtus per day of additional capacity from West Texas for delivery into Old Ocean natural gas pipeline, which we also jointly own with Enterprise and is capable of transporting 160,000 MMBtus per day from Maypearl, Texas, South 240 miles to Sweeny, Texas. Both the North Texas and Old Ocean pipelines are already running full due to strong demand driven by the wide basis differentials.
On the Rover pipeline, we have been collecting demand charges on 100% of the long-haul contractual commitments on Rover since September 1, and in early November, commence service on the final two laterals. In the fourth quarter, volumes on Rover averaged just over $3 million MMBtus per day.
Turning to Orbit, which is our joint venture with Satellite Petrochemical USA Corp., for which we are constructing a new ethane export terminal on the U.S. Gulf Coast to provide ethane to satellite. Construction has begun on the project in both the U.S. and China. The export terminal is still expected to be ready for commercial service in the fourth quarter of 2020. And we are excited to be opening a new office in Beijing next month to continue expanding our export capabilities to Asia.
Now looking at our processing plants in West Texas, the 200 million cubic foot per day Rebel II processing plant in the Midland Basin went into service at the end of April and is running at capacity. And the 200 million cubic foot per day Arrowhead II cryo plant went into service at the end of October and is nearly full. During the fourth quarter, we approved Arrowhead III, another 200 a day processing plant in the Delaware basin. We are thoughtfully adding plants to meet growing producer demand, and Arrowhead III is expected to be in service in the third quarter of 2019.
We are seeing continued demand and expect to announce another processing plant in the Permian Basin shortly. This plant will be in service in 2020 and is already fully subscribed. The Red Bluff Express Pipeline went into service in May 2018, and the second phase of the pipe is expected online in the second half of the year. Volumes during the fourth quarter averaged approximately 315,000 MMBtus per day, and we expect volumes to more than double toward the end of the year. The majority of these volumes are also flowing through the Waha Oasis Header thereby generating additional revenues downstream. As we have previously mentioned, our anchor shipper is Anadarko and their affiliate Western Gas exercised their option to buy 30% interest in the Red Bluff Express Pipeline effective January of 2019.
Lastly, just a quick update on Revolution. We are working together with the Pennsylvania DEP and have communicated to them that we are committed to bringing this project into full compliance with all environmental permits and applicable regulations. The operations of our in-service pipelines are not impacted by PA DEP’s recent permit hold nor any areas of construction where permits have already been issued.
Now let’s go ahead and turn to our fourth quarter results. Today, I will discuss Energy Transfer’s results pro forma before the merger. Then I’ll also walk you through ETO segment results for the quarter. As a result of the merger, we have reevaluated our segment reporting and now report our investment in Sun and USAC as their own respective segments. In addition, Lake Charles is now reported in the intrastate segment. Additional disclosure regarding quarterly results can be found in the ET press release issued yesterday or in the ETE or ETO 10-Ks, which are expected to be filed tomorrow.
ETE’s Consolidated adjusted EBITDA was up almost 30% to $2.67 billion compared to $2.08 billion for the fourth of 2017. This increase is due to increases in all of our core operating segments with record operating performance in our NGL, interstate and intrastate businesses. On a pro forma basis for the merger, ETF attributable to partners, as adjusted, was $1.52 billion for the fourth quarter, up $338 million or nearly 30% compared to the same period last year, primarily due to the increases in adjusted EBITDA.
Pro forma for the merger coverage for the fourth quarter was 1.9 times. And on the distribution, in January, Energy Transfer announced a distribution of $0.305 per common unit for the fourth quarter or $1.22 per common unit on an annualized basis. This distribution is flat compared to the third quarter of 2018, and was paid on February 19 the unitholders of record as of the close of business on February 8.
Turning to our results by segment and starting with the NGL and Refined Products segment. Adjusted EBITDA increased to $569 million compared to $433 million for the same period last year.
The increase was due to record transport in FRAC volumes as well as increased refined products terminal volumes, and stronger results from our butane blending business. NGL transportation volumes on our wholly-owned and joint venture pipelines were 1.1 million barrels per day compared to 963,000 barrels per the for the same period last year. The increase was primarily due to higher volumes on our pipelines out of the Permian Basin and on the Mariner West and Mariner South pipelines.
Fourth quarter average daily fractionated volumes increased to 594,000 barrels per day compared to 455,000 barrels per day last year, primarily due to the increased volumes from the Permian region as well as an increase in fractionation capacity as our fifth fractionator at Mont Belvieu came online in July of 2018.
Moving onto our crude oil segment. Adjusted EBITDA increased to $636 million compared to $544 million for the same period last year. The increase between the fourth quarter of 2017 and the fourth quarter of 2018 was primarily due to growth on our Bakken pipeline, increased throughput in the Permian on existing pipelines, partially offset by decrease of $107 million in margin, excluding unrealized gains and losses from the crude oil acquisition and marketing business. We have approximately 9 million barrels of operational inventory that is accounted for is available for sale of product.
These barrels combined with the movement in crude oil prices that occurred during the fourth quarter, had a negative impact of approximately $150 [ph] million on a weighted average cost of sales. Crude oil transportation volumes increased to 4.3 million barrels per day, an all-time high compared to approximately 3.9 million barrels per day for the same period last year, primarily due to volume growth in the Bakken and increased production from the Permian Basin.
During the fourth quarter, volumes on our Bakken Pipeline continued to average above 500,000 barrels per day and demand for space on both our Bakken pipeline and Permian Express pipes remains strong.
Now for the midstream, adjusted EBITDA was $402 million compared to $393 million for the fourth quarter 2017, primarily due to higher throughput volumes, partially offset by lower NGL prices, which negatively impacted results by $25 million. Gathered gas volumes also reached a record 12.8 million MMBtus per day compared to 11.5 million MMBtus per day for the same period last year. This was primarily due to increased volumes in the Permian from higher producer demand, growth on Ohio River System in the North East, as well as growth in north Texas.
Looking at our interstate segment, adjusted EBITDA was $479 million compared to $342 million for the fourth quarter of 2017. This increase was primarily due to additional EBITDA from the commissioning of Rover and capacity saw that higher rates on Transwestern, Panhandle and Trunkline. Interstate transportation volumes were 11.1 million MMBtus per day compared to 7.2 million MMBtus per day for the same period last year, due an increase of 2.2 million MMBtus per day from the Rover pipeline, as well as higher utilization on Panhandle and Trunkline increases on Tiger due to production growth in the Haynesville Shale, and increases on Transwestern as a result of favorable market opportunities due to the Permian production growth.
As for our intrastate segment, adjusted EBITDA increased to $306 million compared to $146 million in the fourth quarter of last year. This was primarily due to a $154 million increase from commercial optimization activities due to wider basis differentials from West Texas to the Houston Ship Channel, as well as the acquisition of the remaining interest in the RIGS pipeline in April. I reported intrastate transportation volumes increased primarily to more favorable market pricing in the Texas markets as well as RIGS now being treated as a consolidated subsidiary.
Now moving on to Sunoco in USA compression, which are now both reported as their own segments. For investment in Sun, adjusted EBITDA was $180 million compared to $158 million a year ago, primarily due to increases in fuel margins and fuel volumes, partially offset by decrease related to Sun’s retail divestment in January of 2018.
And for investment in USA compression, we had a very strong quarter. Adjusted EBITDA was $104 million driven by strong market backdrop, which led to increased utilization and pricing.
Now moving onto CapEx and 2019 adjusted EBITDA update. For the year ended December 31, 2018, Energy Transfer spent $4.9 billion in organic growth projects, primarily in the NGL and Refined Products and Midstream segments, excluding Sun and USAC CapEx.
As I mentioned earlier, we still expect to spend approximately $5 billion on organic-growth projects for full year 2019, primarily in the NGL and Refined Products segments. For 2019, as we mentioned earlier, we continue to expect adjusted EBITDA of $10.6 billion to $10.8 billion as we have a number of fee-based projects coming on and ramping up in 2019.
These projects include the most recent Bakken expansion, Permian Express 3, FRAC VI, ME2, Arrowhead II and III, Bayou Bridge, Phase II, Red Bluff Express plus full year contributions from Rover and FRAC V. This increase in fee-based earnings is expected to more than offset our assumptions around lower contributions from our optimization and marketing businesses.
Looking briefly at our liquidity position, as of December 31 of 2018, total liquidity under our revolving credit facility was approximately $2.24 billion and our leverage ratio was 3.38 times for the ETO credit facility, which excludes the debt sitting at ET. In January 2019, ETO issued an aggregate $4 billion principal amount of senior notes and used the net proceeds to repay in full ET’s outstanding senior secured term loan, redeem certain outstanding high coupon senior notes at maturity, repay a portion of the borrowings outstanding under ET’s revolving credit facility and for general partnership purposes.
We expect in the near-term to launch a lifetime exchange, whereby we will offer the legacy ETE note holders with the ability to exchange their notes for an equivalent ETO note. This exchange will allow the ET holders to become very pursue with the ETO note holders and will remove their structural subordination.
Before we open the call up to your questions, I just want to say that once again we are very pleased to have reported another very strong quarter. Contributions from the Bakken crude oil pipeline, Rover and other growth projects were big components of this growth in earnings. Our diverse portfolio of assets generate quality earnings with 85% to 90% of 2019 margins expected to come from fee-based contracts and our assets continue to internally generate a significant amount of excess cash flow.
Looking ahead to 2019, we are excited for the continued DCF growth as our backlog of accretive growth projects are completed and ramp up, which will contribute additional fee-based earnings. We have leading footprints across the midstream value chain in nearly all the major producing basins in the U.S. and we continue to find a significant number of accretive growth capital opportunities.
Any new project announcements will be carefully evaluated with an emphasis on prudently targeting projects with very favorable returns that were ramp up quickly like our fractionators and Lone Star Express expansion. For 2019, we remain very focused on project execution and safety, as well as exercising discipline when it comes to grow. In addition, we are committed to retaining at a level of cash flow that allows for flexibility to find our growth projects.
Operator, that concludes our prepared remarks. Please open the line up for questions.
Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] Our first question comes from the line of Michael Lapides with Goldman Sachs. Please proceed with your question.
Hey guys, congrats on a good quarter and good year. Easy question for you. How are you thinking about the options around the Bakken pipeline? Meaning, you’ve obviously got incremental demand above the 570. How are you thinking about both the timeline for figuring out what expansion is possible? And then, the actual implementation of that?
This is Mackie, Michael. We couldn’t be more excited about how that whole project has turned out. We went out for an open season, for 35,000 barrels a day, way over – requested way above what we have. We closed that open season. As part of that, we also had commitments from shippers in our next open season. So we are certainly going through all the processes to hopefully, begin that open season at the right time in the future.
And can you do that expansion just using pumps or DRA or is there something more physical to the system you’d have to do to be able to add significantly more barrels?
We’ll be able to provide, we believe, significant barrels just by adding horsepower.
Got it. Thank you, guys. Much appreciated.
Thank you. Our next question comes from the line of Shneur Gershuni with UBS. Please proceed with your question.
Hi, good morning, guys. Just to start off, you reaffirmed your guidance for 2019. I was wondering if you could give us a little bit of color around the sensitivities, guidance inputs around spread and commodities assumptions. How you could potentially achieve the upside of your guidance certain – are their macro factors or timing issues that could play within the range and so forth?
Yes, and good morning. This is Tom Long. Let’s start with – I think let’s start with the sensitivities. If you really kind of look at it just on the commodity side, we’ll go to the spread side here in just a minute, but if you go at the commodity side and you look at a $1 move in crude oil, $1 per barrel, that’s probably on an annual basis, an impact of about $8 million to DCF. If you look at it from a gas side, a $0.10 move would be about $7 million on an annual basis. And going back to the crude just for a minute, that does assume certain correlations with the NGL. So that’s the NGLs baked in with that.
As far as the basis, we’ve not given out guidance on that at this point. We continue to evaluate that. But I will tell you, Shneur, in those assumptions, we have used – let’s just call it mid-single digits. I know that we’ve talked before, and I’d refer to the fact that we stayed pretty conservative on that. But we didn’t stretch that on that side of it. And that includes both the gas and the crude. I mean the crude is where we state kind of mid-single digits. The conservative part is we’ve likewise stayed conservative on the gas side of it also on the intrastate side.
As far as the projects go, I think we’ve stayed down in the middle of the road on these projects ramping up. So I think overall, we’ve kind of stayed down in the middle of the fairway with these, and primary reason why we’re still comfortable with staying with the $10.6 billion to $10.8 billion for 2019.
All right, that makes total sense. Just switching to the CapEx side, you had multiple years where you’ve spent in the $5 billion plus range for CapEx. There have been delays along the way, some of it regulatory, some of it not. You have a $5 billion capital program this year. You’re needling some projects for the out years as well too. Has there been any changes in practices that Energy Transfer learnings from the past to execute better? How are things being planned on a go forward basis? Just wondering if there’s – we just that have been taken in place where CapEx could potentially come in more on time and more under budget. Just any color around that would be greatly appreciated.
Yes, we’re all staring at each other, figuring out who is going to answer this, and I’ll start. And it’s probably several people, but yes, we’ve learned all kinds of lessons. And we’ve made mistakes and we are correcting those mistakes and we’ll not make those mistakes again. So yes, we’ve learned a lot. Every place is not Texas.
And so we’re making adjustments as far as our CapEx goes, and Mackie, I’d like you to chime in on this if you would, as far as our CapEx goes, that is driven by the commercial engine of this company and I think everybody knows Energy Transfer, and my opinion is somewhat unique. There’s a few like us that commercial drives who we are and then the other sized organizations support that. The commercial engine drives the growth and so, I don’t really see that coming down much, Mackie. Do you agree?
No, I don’t. We said this in the past is that we don’t win everything. In fact, we don’t win a lot of the bids on gathering and processing and even the big intrastate gas pipelines that have been announced. But what we are winning is very accretive, high rates of return projects that in most cases are very synergistic and add revenues either upstream or downstream.
So the capital could certainly change up or down. To give you an example, on PGC or Exxon, we’re trying to decide what’s the best way to go. One would require more capital with not as good a rate of return. The others less capital with a lot better rate of return. So at the end of the day, we’re going to do what’s best for our partners, but that certainly could even lower some capital expectations in 2019. But we’ll continue to chase every deal that’s out there, but we don’t expect to win a whole lot of them unless we have really good rates of return.
But to follow back up on kind of the genesis of your question on those two discussions there, we’ve grown so much. We made some mistakes, and specifically now we’d like to talk about Pennsylvania and we’re going to take our medicine and fix those mistakes and complete good projects from this point forward. Not insinuated that everything we’ve done has been bad. It’s just we’ve made some mistakes we’re not proud of. So you’ll see that improve and when we don’t make those mistakes again, that our costs are going to improve and the predictability of those cost are likewise going to improve.
Kelcy, have you expanded the management team at all in terms of project execution.
We have – we’ve done a reorganization, the Engineering and Construction now reports directly to me. Operations, which is we’re so big and just got to be overwhelming here. We had so much growth, but Engineering and Operations under Matt Ramsey who reports to me. Kevin Smith runs Engineering and Operations. And Kevin has assembled pretty much a new team, pretty much and some new faces and some just moved over. But it’s – I’m really pleased with organization and I’m really pleased with the approach that I’m seeing at this stage and it will continue to show improvement.
Great. And just one final question, I was wondering if you can talk about your USA compression position. If you sell back the GP, would you be able to deconsolidate the debt from your balance sheet? And secondly, would you be looking to monetize the position to improve leverage going forward?
Yes. So your first part of your question, if you were to sell the GP, that’s exactly right. It would not be consolidated. As far as the second part of the question, I think we’ve been pretty consistent in saying that we plan on the divesting probably the two to four-year timeframe, as far as our position goes there. So we’ll see how that goes. I think the most important point is for us to emphasize, once again we’ll be very, very careful in how we do that, in order not to put pressure on the unit price, so.
All right. That makes perfect sense. Thank you very much for the color guys.
Thank you. Our next question comes from the line of Michael Blum with Wells Fargo Securities. Please proceed with your question.
Thank you. Good morning, everyone.
Good morning.
Just wanted to talk about Mariner East II for a minute. Do you have any update on additional contracting of the pipeline now that it’s up into, at least interim service? And then related to that, what’s your latest thoughts in terms of how open are you to sell a stake in that – in ME2 either as a way to attract incremental volume commitments or to accelerate that the deleveraging process?
Hey Mike, this is Mackie. In regards to contracting, what we’ve sold already, it will be fully utilized on ME2 in this space. When we bring on 2X, we sold a significant portion of that. We continue to look and talk to other potential shippers. We also work with more downstream markets to develop more chilling and storage capacity at Marcus Hook. So we’re fully subscribed on what we’re able to move today. When we bring 2X on, it will give us more capacity and we expect to continue to sign up additional customers.
As we said all along, once it’s finally built, then we believe a lot of volumes will find a way it’s the best option price wise, net back price wise producer have the Marcellus and Utica. And so we expect to see continued commitments from shippers. As far as selling a stake in Mariner, I think – I mean, what Kelcy’s always said is that we’d be open to selling a stake in something like that if somebody was willing to pay a promote and brought a significant amount of volume to that – to the asset. Other than that, I don’t think we’d be interest in divesting.
Got It. Thank you very much.
Thank you. Our next question comes from the line of Keith Stanley with Wolfe Research. Please proceed with your question.
Hi, good morning. Couple more questions on Pennsylvania. First is for the Pennsylvania DEP is restoration at the revolution site the only thing they’re asking of you guys right now to get the permits again. And just any sense at all on when you’d have permit authorization again?
Sure. This is Kevin Smith. We have four documents that are due to pay debt on Monday 25, which is the date mutually agreed. We expect that they’ll review and approve those documents within 30 days, which would allow us to commence the restoration effort. And yes, that is the only thing that’s prohibiting us.
Okay. And on ME2X, I think I heard correctly Tom, that you said 99% of the mainline construction is now done. Can you just give a little more color on what’s left to be built on ME2X, if this includes some of the tougher geological areas and what permits you need from the DEP still for ME2X?
Sure. That is correct. 99% of the pipeline itself is installed. It’s a matter now of completing the HDDs and some open cut. There are roughly 20 permit modifications required to convert from HDDs to open cut. We’re processing those – submitting in processing those with pay debt. And I think that we have adequate time in our schedule for the return of those to be able to execute this. And as I say, we’re still committed to completing 2X by the end of 2019.
Great, great. One follow-up on the results please on Q4, so the crude marketing decline, did I hear correctly that it’s a – there was $150 million negative impact to EBITDA due to the inventory accounting on crude prices dropping?
That’s correct. It is approximately $150 million just for the quarter.
Okay. So marketing really would have been up a little bit if you didn’t have that, that impact. And then any – did anything change the one thing that was a little surprising was the big increase from Texas pipelines and Permian production was up $125 million year-over-year. I’m assuming some of that’s PE3, but just any other color on that strong of an increase on Permian pipes in the quarter.
Permian pipes around crude, we brought on Permian Express 3, fully loaded. We also transacted a transportation deal with Plains. We’re moving more barrels really off of their system up into Wichita Falls down all the way to Nederland, so as we’ve said before, we’re doing everything we can to fully utilize all the capacity in our pipeline. And we’ve done a good job of that. We’ll continue to look for further expansions and adding additional horsepower to increase our throughput.
Great. Thank you very much.
Thank you. Our next question comes from the line of Jeremy Tonet with JPMorgan. Please proceed with your question.
Good morning. Just want to take a high level question here, and it seems like there’s a big tug of war in the market now as far as wanting to grow, having – deploying capital and good growth projects but also looking to delever and getting improving financial strength. So I was just wondering if you could refresh us on your thoughts as far as kind of hurdle rates and how you think about that at this point in time.
This is Mackie again. As I mentioned earlier is that we have raised our hurdle rates. As I’ve said, we’re not successful in competing for some of the intrastate business, because a 11% or 12% rate of return doesn’t make sense to us when we have the availability to chase so many projects throughout the country at much better rates of return, and as I’ve said that are synergistic. So we’ll continue to be very prudent about how we spend our dollars, and we will chase the most accretive projects that are out there.
That’s helpful. Thanks. And then just kind of annualizing these results put to you, it’s seems like well in line with your leverage target, and your DCF targets will fund over half of your state-to-capital plan. Assuming that DCF will grow and that Capex backlog will shrink in future periods, how do you guys think about excess DCF? What you will do with it in the future when all this materials.
Yes, and listen, this is Tom Long. I will tell you that we do, as we look out at our projections, we – I mean, obviously very excited to be in this position to have this much free cash flow. So we balance it between the various projects, but let’s just say the overarching driver is clearly our balance sheet, our leverage metrics.
So once we see that and once we kind of look out and see the kind of 4.5, we’re balancing all this between capital allocation, between growth projects, between unit buy back, or even debt pay down. But remember debt pay down is really probably not as big as the fact that our deleveraging is occurring from all the growth of our EBITDA coming on with these projects. So that’s the way we’ll evaluate it. We’ll run the numbers based upon multiple variables and we’ll do whatever is a most accretive for unitholders.
That’s helpful. That’s it for me, thanks.
Thank you. Our next question comes from the line of Jean Ann Salisbury with Bernstein. Please proceed with your question.
Hey, good morning. To meet your mid-2020 startup target for PGC, when is kind of the point of the return for deciding on the size and the rate?
This is Mackie, again. Probably the best way to look that is that once we get to FID, we believe it’ll be built in a little less than two years. So right now, we’re really out of 2020 best case in 2021, if we can get to FID in the next 30 days or so.
Got it. That’s helpful. I believe that you’ve said in meetings that you’ve been firming up some of your Waha to Katie capacity on Oasis, into long-term contracts. Is there any more color that you can provide on how much you firmed up?
Yes, there really isn’t specifically, but we have a number of contracts that roll off two years from now, three years from now and four years from now, and what we’re trying to do is do 7 and 10-year deals starting about a year from now. We’ve done a fair amount so far. We’re also in negotiations to not only move across Texas, but also to move Delaware volumes down to Oasis and then move across Texas. So we’ll continue to sell a fair amount of that. We’re trying to capture as much of that spread today for the next year or so. But we certainly expect, as the industry always does, to be overbuilt in two or three years. And by that time, we’ll be much more sold out at much higher spread than we’ve experienced in the last 10 years for the next seven or eight years. So we’re being prudent, not so at all upfront. But we are as we do in our crude business and everything else, is trying to have a mix of sales in short-term and long-term deals.
Makes sense. Thank you, that’s all for me.
Thank you. Our next question comes from the line of Elvira Scotto with RBC Capital Markets. Please proceed with your question.
Hey, good morning, everyone. Just a quick follow-up on PCG. So do you currently have enough shipper interest to FID this pipeline and it’s just a matter of size and scope or whether you combined with the Exxon deal?
Yes, we do have enough commitments to move forward on accretive project. The question becomes, is that the best move and the best decision for our partnership when looking, as I mentioned earlier, to apply our capital at the best rates of return. So we’re in serious discussions with Exxon Plains, if it makes more sense to join their project and have fewer projects built that are full day one, that is certainly a possible direction we’ll go.
Thank you. And then, can you provide little more detail on the orbit Ethane Export JV, specifically around the permitting process in China and what’s going on there.
The only update I can give you on that is that we have the provincial approvals for the area. Our understanding was the government entities that approved that were in Washington this week, and a lot of that we believe still hinges on the trade issue that we have between our country. So that could still hold up the final approval, however, we’re actually going to visit here about in three weeks. But they are moving as quickly building their crackers as we are building our tanks and chillers in Nederland.
Great, thanks. And then just the last one from me, in the past few months it looks like the LNG market has been heating up with new contracts signed. Can you give us an update on Lake Charles and where you are in the process of potentially FID in that?
Yes, this is Tom Mason. We’ve – I think as Kelsey expressed on our last call, we are somewhat frustrated with the progress, pace of progress with Shell as a joint developing partner on the project. But we really turn the quarter on that front, and we’ve made a lot of progress with Shell. One of the main things is driving a very competitive price for the LNG offtake. And so we spent a lot of time with Shell on value engineering to get, when you go out to get bids on EPC side that we’ll get the best bid we can possibly get that will therefore allow us to sell LNG at the most competitive price in the market.
So we’ve made a lot of progress on that. We’ve been out marketing LNG particularly in Asia and in Europe. And as Mackie alluded to it, the Chinese trade wars have had some impact on marketing and I think there’s also been a little bit of – a lack of clarity with our relationship with Shell, but I think that’s during the quarter, I think the Chinese trade wars will get resolved, we think in the near future and that’s a big market.
And so I think that will help us move the project forward as well. But long and short, I think we’re progressing – it’s a big project and there’s lots of moving parts to it. But we’re pleased with the progress and we think, we’ll have some developments to announce in the near future. But I think we’re looking at hopefully an FID in the first half of 2020 and we think that’s very achievable.
Thank you. That’s all I had.
Thank you. Our next question comes from the line of Dennis Coleman with Bank of America Merrill Lynch. Please proceed with your question.
Thank you. Hi, everyone. One question I guess on the gas pipeline side, you’ve talked about some higher tariffs on Transwestern, Panhandle and Trunkline, I think as a result of Rover coming on. I wonder, are those in the form of long-term contracts? Is it sort of a temporary situation? And I guess in addition on the pipelines, any update on the 501-G process and potential rate cases there?
Okay. This is Mackie again. I’ll start with Transwestern and we said this probably in the last call is that, we kind of labored for years on Transwestern because there was very little spread other than our long-term business we had secured and things have changed. Fortunately we use to be disappointed when the markets would only do one to three year deal. Thankfully that’s what’s now rolling off and we’re able to increase our margins some cases by 50% to 75% of what we’d done in the past and doing two or three year deal.
So we see Transwestern continued to improve in revenue and we’re excited about that. On the Panhandle and Trunkline both of those to a certain degree benefit from Rover, no doubt on the backhaul from the gas moving from north to south. But as far as long-term contracts, we’ll continue to roll over and do business with a lot of the utilities along Panhandle and Trunkline because of our storage capabilities and our ability to provide kind of a no-notice service, especially in the wintertime. Those pipelines will continue to offer excellent value and in some cases the best options for market.
So, similar to Transwestern, we see a lot of – we’re excited about Pebble and Trunkline continue to grow revenues. Around the 501-G, we don’t really see that. I guess I describe it as almost zero impact. We believe all of our rates are fair and reasonable, and any Intersection 5s that are issued to us by FIRK, we’ll do what’s necessary to contest those. And we believe at the end of the day it will have no material or zero impact to our revenues.
Okay. Thanks for that. I guess one more for me, if I can. Tom, there was a $431 million impairment charge in the quarter. Can you give just a little bit of color on what that was?
Yes. Well, as you know, every year end, we go through a extensive kind of valuation on all of the goodwill that we have recorded across the company. Some of that was really probably as much as any was related to some of the midstream up in the Northeast, and then you also had a little bit around some – and some of this was coming around some of the delays that we’ve seen, like on some of the other assets that we’ve seen up there. So pretty much most of it that’s really where it came from.
Okay. Thanks. That’s it for me.
Thank you. Our next question comes from the line of Ross Payne with Wells Fargo Securities. Please proceed with your question.
Hey, Tom. Thanks for all your disclosure here. I was hoping that we could get a total debt number for the quarter, and second of all with leverage approaching your target do you have any updated thoughts on where you want your credit ratings to end up? Thanks.
Okay. Well, listen, I’ll start with the latter. We’ve been saying out there the mid-4s. If it was 4% to 4.5%, I think that would be great, but I think the mid-4s. One thing that’s always, I think, very important when anyone’s talking about leverage out there is that you need to look at kind of the basis of the earning stream all the way through to your contracts, et cetera. And with our 85% to 90% mostly being fee-based type earnings, you look at our sheer scale and size, you even look at our coverage ratio and the flexibility that gives us at 1.9%, so you roll through a lot of that, we really feel like that a company with all these metrics and et cetera that 4.5% is a good number. But I will say that you’re going to see us target probably 4% to 4.5% or so as we look out from that standpoint.
I think the total debt, and this is the GAAP debt, you’re looking kind of at the mid-40s, $46 billion or so, including the complete consolidated with the Sun, USAC, et cetera.
Okay. And, Tom, more specifically, are you targeting – you’re obviously low triple by the agencies. Is it your hope at some point to get to mid, or do you feel like you just don’t want – you don’t need that? Or what are your thoughts on that?
No, we would like to be at mid. We think based upon our size and all the great projects we’re working on and everything else, I think – we do think it’s important to be kind of at that mid and we’re going to work toward that. And we feel like if you get to that 4.5% and you’ve got coverage still sitting well above 1.5%, which we’re hitting that target very well right now at 1.9%, as we march toward those the mid-triple D’s is very much a target.
Okay, and one final one for me. As we get towards the end of the year, you’re obviously going to be on top of your leverage metrics here in very short order. Should we be budgeting any kind of decrease in the distribution coverage as you potentially move that up?
No, I don’t think so. We’re going to navigate toward that number, and it’s kind of like I think I was mentioning earlier. We’ve got all the various allocations of capital, and we’re going to look at that. You’re going to run it through your models and based upon the variables, and one of those variables is being where you’re trading on a DCF yield. You’ll make those decisions at various times, but I think you’re going to see us keep a good strong coverage as we continue to fund these very, very good projects.
All right. Thanks, Tom. Appreciate that.
Thank you. Our final question comes from the line of Ethan Bellamy with Baird. Please proceed with your question.
Hey, guys. Thanks for taking it. Following up on Elvira’s question, Kelcy, in the past you’ve said that industry always overbuilds. Do you see any change in behavior this cycle should be encouraged by these EDC discussions or is it still a question of when, not if long-haul Permian oil and gas capacity specifically gets overbuilt?
Yes, well, really great question, and it will occur again for sure. And this will go on until the end of time. That’s just what pipe routers do. However, I’ve noticed, and Mackie kind of commented about this, I’ve noticed a great discipline by our group’s part. I mean, it’s a – You know, think about. Energy Transfer didn’t show up as one of the big 42-inch optic pipelines coming out of the Permian, and there’s arguments that maybe we should’ve. But we couldn’t reason our way through it. The returns did not justify it, and so here we look at it today and as Mackie commented on our crude oil exercise that we’re going through, we’re being extremely disciplined here.
And I’m not saying we haven’t been in the past, but I’m seeing at least in the Energy Transfer house, we are conducting ourselves in a very, very conservative way as it relates to overbuilding.
I worry about fractionation overbuild, but what the heck do you do there? You’ve got contractual obligations with producers that expect that they signed up for something they expect you to perform. So that one is a little different, we have no choice. We have a contractual obligation to frack product, and we must honor those contracts. So there’s everyplace we’re looking at, overbuilding a little bit, and we’re worried about it and we’re being very careful. Now there’s still many place in the country that’s severely under-built, as you know, and we’re also focusing heavily on those areas, too.
Thank you. Separate topic. You’re racketeering suit against Greenpeace got tossed out about a week ago. Is that the end of the dapple legal battle? And if not what’s the next move there?
No, sir. I’ll let Tom Mason answer that, so I’m guiding him. No, sir.
So this is Tom Mason. Yes, that was a little bit of a disappointment. It’s not over, though. We’re looking at other alternatives. There’s a potential state court action that we’re looking at, and, we’re just not going to stand by and accept this kind of behavior from bad actors. And so it’s not been our history to or tendency to be pushovers and so I think you’ll see something coming out of it in the near future.
Thank you, Tom. And then final question. Kelcy, are you happy with Sonoco’s progress?
I’m very happy, very happy. An incredible management team, absolutely doing everything they’re being asked to do and are expected to do by their unit holders. Very pleased, very pleased with Son and look forward to a fantastic future for that entity.
Thank you very much.
Thank you. We have reached the end of our question and answer session. I would like to turn the call back over to Mr. Long for any closing remarks.
Yes, once again, thanks – thanks all of you for joining us today. As always, we really appreciate all your support. We appreciate you all joining in. I think you can see how excited we are about the performance of our existing asset base as well as all the projects that we have coming online.
So once again, thanks, and we look forward to talking to you in the near future here.
Thank you. This concludes today’s teleconference. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.