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Energy Transfer LP
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Greetings, and welcome to the Energy Transfer's Fourth Quarter Earnings Call. At this time, all participants are in listen-only mode and a question-and-answer session will follow the formal presentation. And as a reminder, this conference is being recorded.
It is now my pleasure to turn the conference over to your host, Mr. Tom Long, Chief Financial Officer. Thank you, Tom. You now have the floor.
Thank you, operator. Good morning, everyone, and welcome to the Energy Transfer fourth quarter 2017 earnings call, and thank you for joining us today. I'm also joined today by Kelcy Warren, Mackie McCrea, Matt Ramsey, John McReynolds and other members of the senior management team, who are here to help answer your questions after our prepared remarks. I'll begin today with an overview of our most recent announcements followed by a discussion of the latest developments on our Rover, Mariner East 2, Permian Express 3, Bakken and other growth projects. Then, I'll turn our focus to a discussion of Energy Transfer Partners' fourth quarter results followed by a CapEx discussion, liquidity and funding update and lastly a distribution discussion.
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 and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You'll find a reconciliation of our non-GAAP measures on our website. Before turning to recent developments and a growth project update, I just want to start by saying that we are pleased by Energy Transfer's very strong fourth quarter. ETP's adjusted EBITDA increased more than 30% and DCF attributable to the partners of ETP, as adjusted, increased approximately 25% over the fourth quarter of last year pro forma for the merger between ETP and SXL. I will provide more details later on in the call. But this increase is due to significantly higher results from the midstream and crude oil transportation and services segments.
I'm also pleased to say that we have recently received authorization from FERC to resume HDD operations at Tuscarawas River for Rover, and on ME2, the Pennsylvania Department of Environmental Protection or PADEP has lifted the Administrative Order in Pennsylvania and we have resumed construction activities on ME2. I will provide more detailed updates on these projects a bit later in the call. Now, turning to our most recent announcements; on January 16, ETP entered into an agreement to sell our Contract Compression business to USA Compression Partners for approximately $1.7 billion, consisting of $1.225 billion in cash, 19.2 million USAC common units, and $6.4 million Class B units. The Class B units will not receive distributions paid on the USAC common units prior to the one year anniversary of the closing date at which point each Class B unit will convert to USAC common units.
This transaction is expected to strengthen ETP's balance sheet by allowing ETP to use the approximately $1.225 billion in cash proceeds to reduce leverage. At the same time, ETE announced plans to acquire all the equity interest in USAC's general partner, and approximately 12.5 million USAC common units in exchange for $250 million in cash. As part of the transaction, pursuant to an equity restructuring agreement, the IDRs in USAC will be cancelled and the general partner interest in USAC will be converted into a non-economic interest in exchange for the issuance of 8 million new USAC common units to ETE. We received early termination of HSR on February 9 and continue to expect the transaction to close in the first half of 2018 subject to customary closing conditions. And on February 7 SUN redeemed all the outstanding Series A preferred units held by ETE for an aggregate redemption amount of $300 million and a 1% call premium plus accrued and unpaid quarterly distributions.
ETE used the proceeds to repay amounts outstanding under its credit facility. Also on February 7, SUN repurchased approximately 17.3 million SUN common units owned by ETP for approximately $540 million. ETP used the proceeds to repay amounts outstanding under its revolving credit facility. Now, moving on to our growth projects where several of our projects continue to ramp up in the fourth quarter, while others are in the construction phase and moving towards completion. First for an update on Rover, Phase 1A was placed in service on August 31, 2017 and Phase 1B was placed into service on December 15, 2017. We are pleased to say that Phase 1 of Rover is now capable of transporting more than 1.7 Bcf per day of natural gas from Cadiz, Ohio to Defiance, Ohio, the majority of which we are receiving full negotiated rates on.
As I mentioned earlier on the call, on February 6, we received FERC approval to resume our HDD operations at the Tuscarawas River and we remain committed to continue to comply with the approved HDD plans and the additional measures requested and approved by FERC. Work also continues at several other HDD locations along Phase 2. Today, we are more than 99% complete with construction for the full project and more than 82% complete with the HDDs. We will be requesting permission from FERC to put pipeline laterals and associated compression on Phase 2 into service in stages as they are completed throughout the next few months. This would allow Rover to ramp up capacity prior to achieving full completion of the 3.25 Bcf per day project in the second quarter of this year.
Now, moving on to Mariner East 2 and 2X, we continue to make progress on the construction of this project with 94% of mainline construction complete and 83% of HDDs completed are underway. At this time, we continue to target placing ME2 into service by the end of the second quarter of 2018. Construction on ME2X also continues and we now expect the pipe for ME2X to be online in mid-2019. On our Revolution Project, the construction is mechanically complete and we will go into full service once Rover and Mariner East 2 are in service. We're evaluating other options to move residue and natural gas liquids on Revolution before Rover and ME2 are ready for service.
Now, moving to West Texas; the 200 million cubic foot per day Arrowhead processing plant in Reeves County in the Delaware Basin came online in early the third quarter. This plant meets a critical need for additional processing capacity and is currently running near capacity. The 200 million a day Rebel II processing plant in the Midland Basin is still expected to go into service in the second quarter of 2018. Including the Panther Plant, which came online in December of 2016, Rebel II is our third plant in the Midland Basin. We're nearing capacity in the Midland Basin and we'll need Rebel II as soon as possible to meet growing producer demand in the region. The residue gas and NGL barrels for the Arrowhead, Panther, and Rebel II plants will be delivered into ETP systems.
Also, in West Texas, our Red Bluff Express pipeline will run through the heart of the Delaware Basin and will connect to our Red Bluff and Orla plants as well as multiple third-party plants to our Waha Oasis Header providing residue gas takeaway. Red Bluff Express will consist of 80 miles of 30- and 42-inch pipe and will have a capacity of at least 1.4 Bcf per day with guaranteed fee-based long-term commitments supporting the project. Our anchor shipper is Anadarko and Western Gas has an option to buy into this project. The project is currently expected to cost less than $300 million and is expected to be online in the second quarter of 2018.
On Permian Express 3, we successfully brought Phase 1 online in the fourth quarter with additional volumes expected to be brought online later this year. As we have mentioned before, we have the ability to expand PE3 by an additional 200,000 barrels per day and are evaluating this expansion. However, we are also aggressively pursuing a larger project to move barrels from the Permian Basin to Nederland, providing shipper capacity to our storage facilities and pipeline header systems. We'd be looking to bring strategic partners in on this project as well.
Next, on Bayou Bridge, on the 30-inch segment from Nederland to Lake Charles, we transported an average of 145,000 barrels per day in the fourth quarter. On the 24-inch segment of Bayou Bridge from Lake Charles to St. James, construction is now underway and we expect commercial operations to begin in the second half of 2018. Our Bakken Pipeline project went into commercial service under the Committed Transportation Service Agreements on June 1. We are very pleased to have this pipeline online delivering domestic crude production to refineries in the Midwest, and along the Gulf Coast for the benefit of U.S. consumers. Our earnings are already seeing a significant increase as a result of the demand fees we're collecting. Q4 volumes which averaged over 400,000 barrels per day were up nearly 20% compared to Q3 volumes.
Lone Star's 120,000 barrels per day Frac V is still expected to be in service in the third quarter of 2018. It is fully subscribed by multiple long-term fixed-fee contracts, and also includes NGL product infrastructure and a new 3 million barrel Y-grade cavern. And Frac VI is expected to be in service in the second quarter of 2019. The majority of this frac is fully contracted under demand based contracts. Next, the 400 million cubic foot per day agreement with Enable, which will allow us to begin fully utilizing idled pipeline capacity and processing capacity in North Texas, is expected to begin in the second quarter of 2018. This contract will fill all unused capacity at our 700 million cubic foot per day Godley plant with the majority under a 10-year demand agreement.
Now, let's turn to our fourth quarter results. As I mentioned, ETP had a very strong quarter. Adjusted EBITDA on a consolidated basis totaled $1.94 billion, which was up $453 million compared to the fourth quarter of 2016. This increase is due to significantly higher results from the midstream and Crude Oil Transportation and Services segment. DCF attributable to partners as adjusted totaled $1.2 billion, an increase of $240 million compared to the fourth quarter of 2016, primarily due to the increase in adjusted EBITDA. ETP's coverage for the fourth quarter was 1.3 times and for the full year was 1.2 times. During the fourth quarter, we changed our accounting policy related to certain crude oil, refined product and NGL inventories associated with the legacy SXL business from the LIFO method to the weighted average cost method in order to be consistent with legacy ETP's treatment of inventories. These changes have been retrospectively applied to all periods presented and the prior period amounts have been adjusted for those amounts previously reported.
Turning to our results by segment and starting with midstream; adjusted EBITDA was $393 million compared to $258 million for the fourth quarter of 2016. This increase was primarily due to higher throughput volumes and higher NGL and crude prices as well as a decrease in SG&A expenses primarily due to certain reserves that were recorded in the fourth quarter of 2016. The other gas volumes totaled approximately 11.5 million MMBtus per day compared to 9.7 million MMBtus per day for the same period last year. This was primarily due to increased volumes in the Permian from the ramp ups of the Orla and Panther processing plants, growth on the Ohio River System in the Northeast, as well as the acquisition of PennTex in North Louisiana, and volume growth in South Texas.
NGL production totaled 502,000 barrels per day compared to 431,000 barrels per day in the fourth quarter of 2016. Equity NGLs were 27,000 barrels per day for the fourth quarter of this year compared to 29,000 barrels per day in the same period last year. Growth on our Ohio River System in the Northeast once again continue to exceed our expectations, driven by greater than anticipated results from our anchor shippers on this pipeline in the dry Utica. We continue to see volumes fill up on our processing plants in the Permian Basin and expected to announce future processing expansions to support volume growth from our committed shippers.
In the NGL and Refined Products segment, adjusted EBITDA increased to $433 million compared to $424 million for the same period last year. The increase was due to higher volumes on our Texas NGL pipelines and our Mariner East System and higher throughput at the Lone Star fractionators partially offset by a decrease in our optimization and marketing group, due primarily to the timing of recognition of inventory gains and lower spreads in the Butane Blending business. NGL transportation volumes on our wholly-owned and joint venture pipelines were 963,000 barrels per day compared to 791,000 barrels per day for the same period last year due to the increased volumes out of the Permian Basin in Louisiana.
Refined products transportation volumes on our wholly-owned and joint venture pipelines were 618,000 barrels per day compared to 627,000 barrels per day for the same period last year primarily due to lower volumes from the Midwest refineries. Year-over-year, average daily fractionated volumes increased to 455,000 barrels per day compared to 394,000 barrels per day last year due to the start-up of our fourth fractionator at Mont Belvieu, which was commissioned in October of 2016 as well as increased producer volumes. Now, looking at the Crude Oil segment, adjusted EBITDA increased to $544 million compared to $237 million for the same period last year. The increase was primarily due to placing our Bakken pipeline in service in the second quarter of 2017, as well as the acquisition of a crude gathering system in West Texas, increased volumes on existing assets and an increase from the crude oil acquisition and marketing business related to the wider basis differentials between Midland and the Gulf Coast that we experienced in the fourth quarter.
Crude transportation volumes increased to 3.8 million barrels per day, compared to approximately 2.8 million barrels per day for the same period last year, primarily due to the placing of the Bakken pipeline, Delaware Basin extension, Phase 1 of Bayou Bridge, and the Permian Longview and Louisiana Access projects in service, as well as the Vitol acquisition, and the growth on existing assets. Crude terminal volumes increased to 2.1 million barrels per day compared to 1.6 million barrels, primarily due to growth at Nederland. In our Intrastate segment, adjusted EBITDA decreased to $146 million compared to $152 million in the fourth quarter of last year. This was primarily due to a decrease in transportation fees due to renegotiated contracts and a customer bankruptcy, partially offset by higher EBITDA from the unconsolidated affiliates due to placing Trans-Pecos and Comanche Trail into service and higher natural gas sales from pipeline optimization activities.
Transported intrastate volumes increased due to higher demand for exports to Mexico, as well as the addition of new pipes to our intrastate system. Although we continue to expect volumes to Mexico to grow particularly as a result of our Trans-Pecos and Comanche Trail pipelines, we are dependent upon infrastructure build-out in Mexico, which has been running behind U.S. infrastructure. While we currently believe volume growth will be slower than originally anticipated, all capacity is contracted under firm transportation agreements. In our Interstate segment, adjusted EBITDA was $298 million compared to $269 million for the fourth quarter 2016. This increase was primarily due to additional revenues of $44 million from the placement of Phase 1 of Rover in service, partially offset by an impact from the contract restructuring on Tiger, as well as lower rates on some of our pipelines due to weaker basis spreads and mild weather.
We continue to expect earnings in this segment to pick up, once the remaining sections of Rover in service and we are able to efficiently provide end user customers with Marcellus and Utica gas. Moving on to the All Other segment, which includes our equity method investment in limited partnership units of SUN LP that previously consisted of 43.5 million units representing 43.6% of SUN's total outstanding common units along with other assets. As I mentioned earlier on the call, subsequent to SUN's repurchase of a portion of its units from ETP on February 7, our investment in SUN now consists of 26.2 million units representing 31.8% of SUN's total outstanding common units.
Adjusted EBITDA was $124 million compared to $145 million a year ago primarily due to the decrease related to the termination of the management fees paid by ETE that ended in 2016. A decrease related to our investment in SUN and a decrease related to the earnings from our Gas Marketing business. Now moving onto CapEx update, for the full year 2017 ETP funded approximately $5 billion in organic growth projects. On a net basis, it was $4 billion after factoring in $1 billion of asset level debt. For 2018, we expect to spend approximately $4.5 billion on organic growth projects. The increase from our previous guidance is due to higher costs resulting from delays on our Rover and Mariner East projects, newly approved projects and carryover from 2017.
Taking a look at our liquidity position and funding strategy. In September, we issued $2.25 billion of 10-year and 30-year senior notes with a weighted average cost of debt of 4.9%. In September and October, we redeemed $1.2 billion of senior notes due in 2021 and 2023, which had a weighted average cost of debt of 5.9%. In November, ETP issued $950 million of 6.25% non-call 5-year Series A preferred units and $550 million of 6.625% non-call 10-year Series B preferred units. The securities provide an extremely cost effective means of raising equity capital and ETP used the proceeds to repay amounts outstanding under its revolving credit facility and for general partnership purposes. These securities received 50% equity treatment from all three agencies. These non-convertible securities which have a weighted average cost of capital of 6.4% provide equity credit at a lower yield than common equity.
On December 1, 2017, ETP entered into a 5-year, $4 billion unsecured revolving credit facility, and $1 billion, 364-day revolving credit facility, which replaced the legacy ETP and SXL credit facilities. Upon closing of these new facilities, we completed a process by which all legacy ETP and SXL senior debt was made pari passu with our credit facility. Total liquidity under these facilities at the end of the quarter was approximately $2.5 billion. As of December 31, 2017, ETP's leverage was 3.96 times. As I mentioned earlier on the call, since the end of the year, SUN has completed its repurchase of approximately 17.3 million SUN common units owned by ETP for approximately $540 million and ETP entered into an agreement to sell our Contract Compression business for a combination of equity and approximately $1.225 billion in cash. Pro forma for the $1.765 billion cash received from these two transactions, ETP would have had $4.275 billion available under its credit facility as of December 31, 2017.
We expect our recent financings, proceeds from the sale of CDM, and the SUN unit sale, and anticipated excess coverage in 2018 provide us liquidity to fund our 2018 growth projects. While we continue to expect that we will not need to issue equity at least through the middle of this year, we are targeting not having any equity needs in 2018, and we will continue to access the appropriate debt equity in hybrid security markets to term out our revolving borrowings and refinance 2018 debt maturities. Next, I'd like to touch on our recent distribution announcement. In January, ETP announced a distribution of $0.565 per common unit for the fourth quarter or $2.26 per common unit on an annualized basis, which was paid on February 14 to unitholders of record as of the close of business on February 8.
This distribution is flat compared to the third quarter of 2018. Even with ETP's great fourth quarter and the contribution from major projects coming online, we felt with ETP's current cost of equity, it was prudent to temporarily suspend the distribution growth in order to retain excess cash flow to fund the equity component of our growth projects and continue to reduce our leverage. Now, moving on to ETE; I'll begin with ETE's fourth quarter results, followed by liquidity and financing update. For the fourth quarter, ETE's distributable cash flow as adjusted totaled $263 million. ETE's coverage for the fourth quarter was 0.99 times. And just briefly touching on ETE's distribution, in January, ETE announced a quarterly distribution of $0.305 per unit. This equates to a $1.22 per unit on an annualized basis and was paid on February 20 to unitholders of record as of the close of business on February 8. This was the second consecutive quarter of $0.01 distribution growth and equates to just over a 7% increase over the fourth quarter of last year.
Let's turn now to liquidity and financing update. ETE continues to have a healthy liquidity position and ended the quarter with a debt-to-EBITDA ratio of 3.68 for our credit facility. In October, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The net proceeds from the offering were used to repay a portion of the outstanding indebtedness under its term loan facility and for general partnership purposes. In conjunction with the senior notes offering, ETE lowered the borrowing rate on its term loan facility by 75 basis points. As of December 31, 2017 there was $1.19 billion in outstanding borrowing under the credit facility. Before opening the call up to your questions, I would like to say that throughout 2017 our base business continue to perform well. The contributions from the Bakken crude oil pipeline and Phase 1 of Rover contributed to our strong fourth quarter results and we made great progress toward improving ETP's liquidity position.
Our performance for 2017 is attributable to the hard work of our employees and the resiliency of our business model. Looking ahead to 2018, our asset base remains well positioned for growth. We're excited about the year ahead and for the growth expected as we complete Rover, ME2 and other growth projects. Our construction and engineering groups remain committed to working closely with FERC, PADEP and other regulatory agencies and are focused on safely and responsibly bringing Phase 2 of Rover, ME2, Bayou Bridge and all of our other projects into service. At ETP, we remain firmly committed to our investment grade rating and we continue to place emphasis on maintaining a strong balance sheet by lowering our leverage, while also increasing coverage and liquidity. And at ETE, the priority remains supporting its core operating subsidiaries.
With that operator, that concludes our prepared remarks. Please open the line up for questions.
Sure thing. Ladies and gentlemen, we'll not conduct the question-and-answer session. And our first question comes from the line of Kristina Kazarian with Credit Suisse. Please proceed with your question.
Good morning, guys. Tom in your opening comments, you mentioned you're considering a new pipe from Permian to Nederland. Can you give me a bit more color on – how large this pipe could be? Would it be in addition to or instead of the PE3 expansion you also talked about? And kind of lastly, how you're thinking about the potential for this pipe in the context of lot of other companies also announcing potential projects?
Yeah, Kristina. This is Mackie. Good morning. Yeah – kind of all the above. First of all, with our partnership with Exxon, we need to work closely with them. We're very excited about our ramp on PE3 that we've already accomplished. We do have the ability to ramp up to 200,000 barrels per day more and we are talking to customers about doing that. But because of the just tremendous forecast on barrels out of the West Texas area about Delaware and Permian, it really makes sense for us and our customers have asked us to do this to look at a much bigger project. So, to specifically answer your question, we really can't do that. It certainly wouldn't be bigger than a 24-inch going across the state, quite likely a 30-inch or possibly even bigger. We have a lot of momentum with a handful of producers, and that is probably the cheapest type of transportation that we can provide, but we're looking at all the above. We're listening to our customers, and we're going to build whatever capacity is warranted after those discussions and what we consummate.
Perfect. And since you mentioned Exxon, they've been talking about spending $2 billion in the Permian and Gulf Coast on midstream. Can you maybe talk about other opportunities associated with the JV that you guys have with them for potential growth or new project areas?
You bet. If you – as everybody probably knows if you lay our pipeline network out and then compare it to kind of what Exxon's needs are, nobody fits better. We're looking at ways to get in a bigger way to Baytown at Beaumont. We're one of the largest suppliers there and the ability to supply much more. We have the ability to put a lot on our docks and terminals, a lot of potential growth there. We can put barrels into a Bayou Bridge to go to Exxon's facilities west. And Exxon wants to take their equity volumes to their facilities. That's just what they do and so we – we have a very nice fit with theirs. Yes, they've announced it. We'll see how things go and – but either way, we feel like we'll be in the mix with Exxon in some manner.
And then last one for me, this was a very strong quarter. Can you guys maybe give me a bit of color of how much of the EBITDA was coming from new projects, coming online in that versus operating leverage on the base business and how we should be thinking about that on a run rate basis? Thank you.
Yeah, I'll start and I'm sure Tom can finish. But if you look at the way we contract, for example Orla and Red Bluff and Rebel and Arrowhead, those are not full day one typically, they ramp up over nine or 12-month period. So we continue to see revenue growth throughout 2017 in plants that were built in early 2016 in the third quarter at Arrowhead in 2017. So as those plants ramp up, it gives us time to bring in additional volumes and add additional facilities. So, just the way – our strategy and the way we do businesses, yes, there is inherent growth from the day we bring a project on and until that's completely full, while we're in the process of bringing another say process and plant on or fractionator on.
Okay. And, Kristina, probably don't have it broke out by all these projects just because they are kind of ramping up and so many of them are coming on. That might be one we can follow-up with you later and just kind of walk through everything from each of the segments. But as you know, Rover like talked about in here you saw what – that segment was up $44 million. A lot of that was dribbled to Rover, of course, the Bakken crude oil pipe continues to ramp up also. But you also have in the midstream, of course, the processing plants that we've seen. So we can share work with you later kind of piece-by-piece on that as far as those components.
Perfect. Really nice job today guys. Thank you.
Thank you.
Thank you.
And our next question comes from the line of Shneur Gershuni with UBS. Please go ahead.
Hi. Good morning, guys. Just a follow-up on the sort of your backlog type of question, you've talked about Permian Express 3 potentially, or the expansion being potentially bigger. But we're seeing lot of CapEx announcement by midstream companies, seems things are getting tighter in the energy patch. I was wondering if you can comment about pricing for capacity. Is that going to move higher? Are you evaluating other new projects? Could we see Lake Charles finally come to fruition? Just wondering if you can sort of talk about the outlook as you sort of think about the landscape right now?
Yeah. This is Mackie again. You bet. One thing we'll say is, is that what we're not going to do is just to add volume or to do deals or to announce deals, is do something that doesn't make sense for our cost of capital and for our ability to grow our partnership, we need to be prudent and sensible and with Kelcy's guidance we stay very focused on that. But it doesn't mean we're not doing deals. Every plant that we've announced is committed to at least do time over nine to 12 month period and we see that growth. We have, for example, every processing deal that we do. We don't put any revenue in for the downstream business, the TNF and the residue, which typically we get the majority of.
So even though the margins have tightened on some of our processing deals, we still are doing accretive deals. Certainly, we're losing a lot of deals either to things that just don't make sense to us or to companies that we don't know for sure they know what they're doing because they haven't built plants or pipe in some period of time. So, we're getting our fair share and we're announcing and bringing on projects that are accretive and then we have synergistic revenues that just continue to add with no additional cost to a project.
And with Lake Charles, is that something that could finally come to the table?
This is Kelcy. Yes, it's been – we've begun to actively, that being Energy Transfer, actively market that capacity to customers. We are making progress and as you know forever, we were just more of a landlord and BG was the renter, let's call it, and so that changed with the Shell merger and so we have been not forced, I should say, but we have chosen to get very active in the success for that project. We remain very optimistic, but we don't have anything to announce at this time.
Great. And as a follow-up question, more financial or balance sheet related, I believe you've taken equity off the table for 2018. You've had this on unit sale, the compression sale, a very strong earnings uptick at ETP. Is there a possibility that we can see ETP's credit rating increased, if you sort of net all the requirements that have been laid out by the rating agencies or does the notching from ETE sort of limit the potential there? I was just wondering if you had any thoughts?
Well, We sure hope so. Listen, it's clearly on this equity piece of it, like I started off talking about here is that, we're saying that we don't see any equity needs through mid this year and that we're targeting to go out through end of 2018. We've started off talking about lot of these projects here we're working on, et cetera. So we'll update that as we kind of move into the first part of the year. But kind of moving on to the second part of your question, as you know, a lot of the dialogue has been around the project execution. And we would sure hope from a – just even from a rating but from a notching and even on an outlook standpoint that absolutely that we would go up as these projects go, fantastic quarter, great leverage metrics. So as you can appreciate, that makes the discussions with the agencies very positive when we have that dialogue. So, can't really guide you anything further though as far as what the agencies may do, so.
Okay. And one final question. I'm not sure if you mentioned this in the prepared remarks or not, but how many HDDs are left specifically with Rover? Are we close to almost being done with them?
This is Matt Ramsey. Let me check one thing right here. Hold on just a sec. Yeah, I think we're 82% done on the HDDs and I think it's 14%; I have my notes here. Apologize, let me – it might take me a second here to look through here.
Was it approximately 14% Matt?
I think that's about of 14% left, yeah.
Okay.
Okay. And at this point right now the Ohio EPA objections have been lifted and so you're able to move forward quickly with them, I can presume at this point?
We are – we entered into a consent agreement. We were under Administrative Order. We got it lifted in very short period of time. Remarkable effort on the part of the engineering and construction team to provide the data that Ohio EPA requested. We paid a civil penalty there in conjunction with the consent order and that put us back into the business of moving forward on our HDDs up there. We're still under the original court order up there, where PADEP is approving the HDDs. I mean, so we still have some HDDs that come out of Ohio EPA, but they're in process right now, but we're moving forward.
Great.
I presume you – you said – you were talking about Mariner East, weren't you, with Ohio – I mean with the PADEP? Or are you talking about Rover?
Rover in particular.
Oh, I'm sorry. (38:49). So on Rover, apologize to you, under FERC, we're released on all our HDDs up there. So, we're making great progress on our pilot hole, with the – under the Tuscarawas River, which is the one that they stopped us on. We have not been stopped on any other HDDs at Rover. They're progressing well, and Rover has released us on all of those to move forward.
Great. Thank you very much. Appreciate the...
Yeah.
...the details and color.
Sorry, didn't mean to mix up the projects for you.
No problem.
Okay.
And our next question comes from the line of Jeremy Tonet with JPMorgan. Please proceed.
Good morning.
Good morning.
Don't want to beat a dead horse here, but just come back to equity need, seems like you've done a lot of funding as you said. And I was just wondering if you could expand a bit more as far as on SUN USAC unit as a source of funds for ETP in 2018 plus. And if you're at the point where hybrid securities could really fill the gap, seems like you have more capacity to do that. And even equity needs in 2019 might be pretty minimal or you hit kind of – the closer the inflection point where common equity is really no longer needed. Could you provide any thoughts there?
Yeah, and listen, you stated a lot of the very positive things and that's the reason why we're using the target word. Once again, you can see we've got a lot of good projects and et cetera, we're looking at. But likewise, a lot of it is as these other projects come on, specifically Rover and ME2, it's going to be a lot more clarity as we get through the year, as these start up and the EBITDA starts ramping up on these projects as we look at it. But you're exactly right. We have taken a lot of steps to do everything we can to stay with the target that we put out there of staying out of 2018 and if that rolled into 2019, that would be great. But at this point, I think it's safe to kind of stay with where we are and then we will obviously stay updating everyone as we get into each one of the quarters in these calls.
Great. Thanks for that. And you noted an accounting change a bit earlier with the legacy SXL. I was just wondering if you might be able to provide some color as far how material that was to – you reported adjusted EBITDA. Was there a big influence there or things would have been largely the same with the accounting change?
Yeah. No, you bet, very good question. For the – let's just talk about the fourth quarter. For the fourth quarter, as you know, legacy SXL both the crude oil as well as the NGL liquid side of the business had always used a LIFO type accounting within ETP, which is primarily, as you know, the natural gas liquid side of it. It didn't have the crude oil side of it, had always used kind of an average cost. And so we got both of them on the same methodology. And so, the way you really should look at this is for the fourth quarter, and you're going to see when we get the 10-K filed tomorrow, you're going to see some of the changes that we made in some of the previous quarters. But if this would have been the – a call using the LIFO, what we would have been saying is, is that we saw probably about – on the crude oil side of it probably about a $75 million negative impact that we would see coming back on the future quarters and the number would be probably about $15 million on the natural gas liquids side of it. So as you – you can see in total about $90 million there would have been a kind of a negative hit that we would have been then saying, we would expect to come back to us over the future quarters. Based upon this new methodology though, this is the way we're reporting it and this is the way you'll see it going forward without using any that it will be coming back to us in the future quarters. So, but the number you should use is probably about $90 million.
That's very helpful. Thanks. And one last one if I could, I think you touched on a few points here but just as far as the increase in the CapEx budget for 2018 versus 2019. Could you just lay out a bit of the chunkier items driving the change there?
Well, the chunkier items, I think probably the best way to bucket this, as you can see we said – associated with some of the delays of the Rover and the ME2 that we saw. So you see higher costs. I'd probably tell you that about half of that increase and remember this is just spend, spend for the year. But about half of that increase is associated with those. The other half is really associated with what we call the new projects as well as some of the carryover from 2017.
Great, that's all helpful. That's it from me. Thanks.
Okay. Thank you.
Our next question comes from the line of Darren Horowitz with Raymond James. Please proceed.
Hey Mackie. Quick question for you on Revolution, as you guys are assessing it, how do you see the most cost-effective options to move liquids and residue gas until Rover and ME2 are complete? And then as a follow-up, Matt, I think you were talking about under that original court order was PADEP. Do you expect the approvals for those remaining HDD locations to arrive at the same timing pace from what you've seen recently? Have you built a buffer into that assumption should anything change? More importantly, I'm just trying to think about how any sort of shift in timing could further affect the 2018 volume ramp on Revolution?
Yeah. I'll start with it. Yeah, Revolution as you know – that is built to feed Rover and it's built to feed Mariner and because of the delays, it just makes sense to look at other options. But there is not a lot of great options. There is high priced options going into ATEX. There is trucking options, but – so I'm not sure what we're going to find. Our bottom line is we're keeping our head down and we're very hopeful that we'll have Rover complete. We're very close on that soon and that sometime in the second quarter, we'll have Mariner on and ready to take barrels from Revolution.
Okay. And then, if I could just switch real quick to what's going on around the Waha Hub and the Oasis Header in particular. I think that scaled to about 6 Bcf and I'm wondering with some change in basis spreads and obviously some change I think in the timing of magnitude, as to when volumes are going to show up at Waha. How do you think about or is there a change in how you think about capitalizing on that volume growth? Because it seems to me the amount of hydrocarbons hitting Waha and Oasis is going to be a little bit misbatched if you will, relative to the downstream takeaway option, so obviously you've got the opportunities for Comanche Trail and Trans-Pecos. But is there a bigger opportunity for you to move some of those volumes possibly to the south or southeast?
You bet. As I sit here and think about answering that question, I think about if we're handed – if we're given a hand of cards and we've got to handle, all of our competitors do nothing gets close to Energy Transfer. If you look at placing a header anywhere in the United States, where would you want it right now? There's more volume growth predicted that can go in multiple directions through our intrastate, interstate pipelines. You'd want to stick it right where our Waha Compressor station ends. So not only will we continue to see growth through that header through our pipelines, when Red Bluff brings on at least 1.4 Bcf that will be coming into Oasis Header. Ironically, some of our competitors were building big inch pipe, 42 inches in South Texas, it's going to tie into our Oasis and CFE headers. So, we are extremely excited and pleased about the future.
And we also see some other benefit. The timing of the growth in the Permian Delaware basin is so immediate that there is really not a lot of outlets. Because of the lack of timing for infrastructure in Mexico, those pipes really can't ramp up as quickly as everybody had hoped. And there's not a lot of ways out of there for the next year-and-a-half to two years. Oasis is kind of the primary outlet. We still have capacity on Oasis for a minimum amount of capital we're spending now by adding compression, we're going to add over a 100,000 Mcf a day here in the second quarter. So, we're well-positioned, really well-positioned short-term to maximize on the growth out there through that header and through our pipes and we're excited about what that's going to allow and provide us to do long-term out of that area. So, we like our hand in West Texas.
And I'm going to – this is Matt on your Mariner East question. We've got 94% of the pipeline is welded back tails. We got about 6% of the pipe its non-HDD related on Mariner East 2, 62% of the HDDs that are required for in-service or done. We've got 24 that are approved to proceed right now. We've got 16 that are still in PADEP for approval. I think we have a good working relationship with PADEP. We have a weekly meeting with them where we look at the gating items. We are still under court order deadlines that, that we have to adhere to and they have to adhere to. But I think our progress is good. And so I don't see a change in the timeline from what we've given you before.
Thanks, Matt.
You bet.
And our next question comes from the line of Jean Salisbury with AllianceBernstein (sic) [Sanford C. Bernstein & Co. LLC] (48:41). Please go ahead.
Hi. Good morning. Just a quick question on ME2/ME2X. Can you confirm whether it can only move ethane, propane and butane or also T5 endocrine (48:52) products? I think I'm (48:55).
Yeah. Let me answer that question a little more broadly. We have Mariner 1 that's in service. We'll have Mariner 2 in service hopefully here in the next quarter and we can do a number of things. Right now, we're moving propane and ethane and butane through Mariner 1. We can actually put that into refined product service when we bring Mariner 2 and Mariner 2X on. So, as time goes on and when we finally, ultimately bring Mariner 2X on, we have a multitude of options. But what we've built is an incredible enterprise with the ability to move hundreds of thousands of barrels to whatever the commodity is and will of course designate and place it in the pipes that are most optimal for our customers, but more importantly, most optimal for our revenues. So it gives us a tremendous amount of flexibility to move ethane in one of the pipes and then C3 plus and others and potentially refined products in another pipeline.
Thank you. That's very helpful. And then just one more on Waha. The Waha differential has widened considerably this year. But I don't see a big uptick in Texas interstate, which is where I think that would be captured. Do you still have leverage to this? I think in the past you had said, it was something like $40 million for every $0.10 or something like that?
Yeah, and let me answer that question in several ways. One is a little bit of a misnomer on how we performed in intrastate. If you look at kind of called the onetime items where the bankruptcy that hit us about $5 million on our intrastate. We have about $20 million to $21 million of losses that we had to show in the fourth quarter that we will see in the first quarter. Those alone, I think put us above anybody's consensus. And so, we will see a significant improvement in our intrastate. The spread has really started spreading out kind of toward the end of 2017 and what we're seeing happen as we get close to the prompt month that spread has kind of come in during the winter. The outer – the next year or two spread, I believe is much as a $1 right now, close to a $1. We are looking at hedging some of that. So, for example, the volume – the capacity that we're adding in the second quarter is a little over 100,000 a day.
You can do – everybody can do the math themselves, we'll be hedging a large portion of that. And the kind of the beauty about our question and some of the analysts wrote about this is, are we concerned about re-contracting around some pipe? Sure we are and we have teams that look at that, especially on some of our interstates. How do we go about looking out three, four, five years and we're very aggressively doing that. And we've done in the past as you know. Well, we're on the opposite side in the intrastates. We're looking forward to some of these contracts ending because we have contracts that are $0.10, $0.15, $0.18 that are rolling off over the next year or two that we will be re-contracting at much wider spread. So we're being prudent about it, we're going to be hedging these at much larger basis levels than we've seen in the past. And as I mentioned earlier, we're really excited about how we fit in the intrastate market.
Cool. Thank you very much.
And our next question comes from the line of Ross Payne with Wells Fargo Securities. Please go ahead.
How are you doing guys? Kelcy, you have to be very pleased with your team putting some of these projects together and we're going to see a nice ramp looks like in 2018 from that. My first question for Tom is, is what is the total debt number at 12/31 for ETP? And then the second question I've got is, obviously, putting the ETE and ETP together has been a discussed matter here. You talked about doing it in 2019. Could this be potentially accelerated? And second of all we saw EQT spin off their midstream into a C-Corp with the MLPs remaining below at least for now. Is that a structure that perhaps Kelcy you might examine in the future? Thanks.
Okay. Listen, I'll start off with the first one. Okay, well, listen, I'll start off with the first part of that, as far as the total debt, I think you'll see it's about 30 – first long-term debt. This is less the current maturities, you're looking at about $32.5 billion is that number. I'll hand it off to Kelcy to kind of respond to the last part about the collapse so?
Yeah. Ross, absolutely. If we're allowed to accelerate a consolidation of ETE and ETP, we will do that. It's just fundamentally simple as in – Ross you know the numbers about as well as anybody in the industry. We just can't risk any kind of negative view by rating agencies and until we get our financial health improved and the family, we will not be doing any kind of consolidation. But as soon as we can, we will.
And on the structure that EQT put out yesterday, is that something of interest to yours? And second of all Tom, if you can give us current maturities as well on the quarter so we can get a total debt number. Thanks.
Yeah, Ross, on the structure – I'll comment generally, because I'm not as up to speed on the EQT structure as I need to be, but I will be this afternoon. We are interested in a C-Corp structure. As you know we almost did one with the Williams transaction. We have many quality assets that are already in a corporate structure and they're quality assets. So we're exploring having a publicly traded C-Corp in the family of Energy Transfer that will allow us to better access the capital markets and hopefully there'll be more to follow on that.
Okay. And as far as those current maturities, you're looking at probably about $1.6 billion.
All right. Go ahead, Tom. Sorry about that, but thank you very much. That's all I've got.
Okay.
And our next question comes from the line of Michael Blum with Wells Fargo Securities. Please go ahead.
Thanks. Good morning. So I think Ross just asked most of my questions, so thanks, Ross. But two follow-ups; one on the CapEx, just going back to the $4.5 billion; I'm still a little unclear on what the newly approved projects are. So can you give a little more detail on what that entails?
Well, the newly approved, you got things that we're working on like Enable. We've got – we actually have some projects approved by our board that are not public yet and there's reasons for that around some tax abatements and things like that. But we've got a handful that we're in the process of completing. In that mix, just in the second quarter as everybody knows we're moving quickly on Red Bluff. We're finalizing Rebel II, bringing on next quarter. We're bringing on the Enable project out of Fort Worth Basin in the second quarter also. We're ramping up volumes and a little bit of cost around PE3. And then in the third quarter, we've got Frac V coming online. So there's just a lot of new projects that are in the works that are going to hit as we keep saying, they're all coming on kind of at the same time. We have – we're set up for a tremendous second quarter with those projects along with Rover fully on and along with Mariner fully on. We couldn't be more excited about getting to the end of the second quarter and bringing all these projects on.
Okay. And then my second question is with the change in the tax rate. Can you just talk about any impacts to your cost of service pipelines and how that may impact revenues going forward? Thanks.
Yeah. Listen, Michael, we – we're finding that's going to be very, very immaterial to us. As you know, most of ours are negotiated rates and therefore you just – you don't see any impact to those whatsoever. I think if you roll into the one that's got the match rates, once again, we don't see much impact on – and that's the Florida Gas one. So that's one that doesn't really impact us of – with any materiality is the best way I'd guide you on that one. So...
All right. Thank you very much.
And our next question comes from the line of Eric Genco with Citi. Please go ahead.
Hi, good morning. I just wanted to ask, on ME2, how many E&C (58:18) spreads are running right now? I think it was seven and I just wanted to get a sense for how that would theoretically drop as we move towards sort of 2Q completion and just trying to get a sense if there were any more delays as to how that could potentially impact CapEx estimates going forward? How do we handicap that?
I think we got six spreads going right now in ME2, if that answers your question.
Yes. Is there like a schedule where they would come off in theory as you get closer to completion and that would decrease over time that you could share?
Well, I think we've – going back on ME2 on initial service date is in the second quarter of 2018. So I don't think that's moved.
Okay. And I just want to make sure, you, because it was a little bit muffled, did you update your CapEx guidance for the year from $3 billion on the gross side? Is there a new number?
Yeah, we updated it from the $3 billion we had, what our guidance is now, is $4.5 billion.
Okay, on the growth side and that's growth?
Yes. Yes.
Okay, cool. And then I just wanted to ask also just so I – maybe this is a little bit of a modeling question, but as we look at the ramping crude and sort of, I think it was listed in the press release, you get $247 million from DAPL, et cetera, this quarter. Last quarter it was $194 million. So there's a $50 million uplift there but then we also have to sort of over the last two quarters, the minority interest give back on DCF is moving up. Just want to get a better sense for like, how much of DAPL drove the increase to $247 million from $194 million versus some of the other gathering systems, and any help you can give us in sort of thinking about that minority interest line in the DCF would be helpful.
Yeah, as you know, we do have to consolidate a lot of these. This is probably one of those that maybe we should walk through after the call if you'd like, just to kind of...
Sure
...walk through from a modeling type question, if that's okay with you.
That works
Because as you know, we got a lot of various joint ventures; some we consolidate, some we don't. And so, that minority back out is a pretty lengthy table so.
Okay, great. All right, thank you.
Ladies and gentlemen, this concludes the question-and-answer session. I'll now turn the call back over to Mackie McCrea for any closing remarks.
Yeah, before Tom closes out, this is Mackie. I'm going to say one more thing. First of all, I want to appreciate what Keith Stanley said. He said something to the effect of back, back, back, back gone and that was really nice to read because our teams have worked hard. And as you can see the last several quarters, we're improving, our volumes are improving. Now we're seeing margins improving, and you guys will do your homework and you'll see it, but just quarter-to-quarter, if you walk through real quickly our NGL transport is up 25%, our frac is up 15%, our crude is up almost 40% of – moving through our pipelines. Our interstate just walking down the list, Tiger up 40%, Panhandle up 20%, Trunk Line up 30%, FPL up 5%, FPP 20%, EP 10%.
You look at our intrastate, yeah, there is some onetime items that kind of impacted us. We're going to see that reverse in the first quarter and our volumes are up tremendously, especially up in the north east. And so, we know and we understand, we've got to get Mariner on, we've got to get Rover to the finish line. We're very close to both of those but we do appreciate comments like that when you recognize that we do feel like we're kind of hitting some home runs each quarter and our equity price doesn't seem to show that but we're getting close and we appreciate what you guys all do to follow us and support us.
And the only thing I guess I would like to add is probably the same thing, Mackie has just said, how excited we are about all these projects, I think you can tell and we can't thank all of you enough for your support. And obviously we look forward to talking to all of you in the future. Thanks.
Ladies and gentlemen, this does conclude the call. We thank you for your time and participation. Have a great rest of the day.