Filed By Energy Transfer Corp LP
pursuant to Rule 425 under the Securities Act of 1933
and deemed filed pursuant to Rule 14a-12
under the Securities Exchange Act of 1934
Subject Company: The Williams Companies, Inc.
Commission File No.: 001-04174
Date: February 25, 2016
TRANSCRIPT
The following is a transcript of the Energy Transfer Partners, L.P. (“ETP”) and Energy Transfer Equity, L.P. (“ETE”) joint fourth quarter 2015 earnings conference call held at 8:00 a.m. Central time on February 25, 2016. While every effort has been made to provide an accurate transcription, there may be typographical mistakes, inaudible statements, errors, omissions or inaccuracies in the transcript. ETE believes that none of these inaccuracies is material.
********
CORPORATE PARTICIPANTS
Tom Long Energy Transfer Partners, L.P. – CFO & Energy Transfer Equity, L.P. – Group CFO
Mackie McCrea Energy Transfer Equity, L.P. – Group Chief Operating Officer and Chief Commercial Officer
Kelcy Warren Energy Transfer Partners, L.P.—Chairman and CEO
CONFERENCE CALL PARTICIPANTS
Brandon Blossman Tudor, Pickering, Holt & Co. Securities—Analyst
Jeremy Tonet JPMorgan—Analyst
Michael Blum Wells Fargo Securities, LLC—Analyst
Darren Horowitz Raymond James & Associates, Inc.—Analyst
Ted Durbin Goldman Sachs—Analyst
Kristina Kazarian Deutsche Bank—Analyst
Robert Balsamo UBS—Analyst
Helen Ryoo Barclays Capital—Analyst
John Edwards Credit Suisse—Analyst
Selman Akyol Stifel Nicolaus—Analyst
Corey Goldman Jefferies LLC—Analyst
Eric McCarthy Citadel Securities LLC—Analyst
John Kiani Teilinger Capital Ltd.—Analyst
Zev Nijensohn The Boston Company Asset Management—Analyst
Norman Hale Stifel Nicolaus—Analyst
PRESENTATION
Operator
Greetings and welcome to the Energy Transfer Partners fourth-quarter 2015 earnings conference call. (Operator Instructions) As a reminder, this conference is being recorded.
I would now like to turn the conference over to Mr. Tom Long, Chief Financial Officer for Energy Transfer Partners. Thank you, Mr. Long. You may now begin.
1
Tom Long - Energy Transfer Partners, L.P. – CFO & Energy Transfer Equity, L.P. – Group CFO
Thank you, operator. Good morning, everyone, and welcome to Energy Transfer Partners’ and Energy Transfer Equity’s fourth-quarter 2015 earnings call. Thank you for joining us today.
I will begin with a discussion of Energy Transfer Partners’ fourth-quarter results, followed by a growth project update, a financing and liquidity update, and an ETP distribution discussion. Then I will provide a brief update on the merger with Williams and lastly, an overview of Energy Transfer Equity’s fourth-quarter earnings and other highlights. I’m also joined today by Kelcy Warren; Mackie McCrea; Matt Ramsey, who is ETP’s new President and Chief Operating Officer; John McReynolds; and other members of our 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 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.
Now for ETP’s fourth-quarter results. Please note as a result of the Regency merger, which was a combination of entities under common control, ETP’s financial results have been retrospectively adjusted to reflect the consolidation of Regency.
Adjusted EBITDA on a consolidated basis totaled $1.36 billion, which is a decrease of $168 million compared to the fourth quarter of 2014. We had continued strong growth in the liquid segment, but saw midstream EBITDA decrease. And in the fourth quarter of 2014, we had unusually strong retail performance.
DCF attributable to the partners of ETP, as adjusted, totaled $959 million, an increase of $165 million from a year ago. We had a current tax benefit from bonus depreciation, partially offset by higher maintenance capital.
Now let’s go over the individual segment results. In the midstream segment, adjusted EBITDA was $264 million, down $96 million compared to the same period a year ago. This decrease was primarily driven by lower commodity prices. These were partially offset by higher throughput volumes, an increase in fee-based revenues, and lower G&A. There were also several plant outages, the majority of which have been resolved, and continued volume shut-ins in the Northeast.
Gathered gas volumes totaled over 10 million MMBtus per day, which is a 5% increase versus the same period last year, primarily due to higher volumes in the Eagle Ford, Permian, and Cotton Valley regions as well as the King Ranch acquisition. NGL production also increased in the fourth quarter by 67,000 barrels per day to 444,000 barrels per day compared to the fourth quarter of 2014. And Equity NGLs decreased in the fourth quarter by 1,000 barrels per day to 29,000 barrels per day.
In the liquids, transportation, and services segment, adjusted EBITDA increased by 40% to $222 million compared to the same period last year. The increase in adjusted EBITDA was due to higher throughput at the Lone Star fractionators and West Texas NGL pipeline as well as increases in storage margin due to the ramp up of Mariner South and related storage fees. We also increased margin in several other areas.
NGL and crude transportation volumes on our wholly owned and joint venture pipelines increased 20% to 474,000 barrels. This was due to increased volumes out of the Eagle Ford and Permian as well as the commissioning of a crude oil transportation pipeline at the end of 2014. There was also an increase in volumes on our NGL pipelines from our plants in Southeast Texas.
Average daily fractionated volumes increased 22% to 250,000 barrels compared to the fourth quarter of last year due to the startup of our second fractionator at Mont Belvieu, which was commissioned in late 2013.
In our intrastate segment, adjusted EBITDA increased slightly year over year to $122 million. This was due to the increased transportation fees and newly initiated long-term demand contracts for Mexico export volumes on our Houston pipeline system. Also, while transported volumes decreased to 7.9 million MMBtus per day from lower production in the Barnett Shale, we expect this trend to reverse due to volume growth in 2016 related to increased demand from Mexico and the Gulf Coast LNG facilities.
In our interstate segment, adjusted EBITDA was $283 million, down $24 million from a year ago, partially due to the expiration of a transportation rate schedule on the Transwestern pipeline and the repurposing of Trunkline’s 30-inch line for the Bakken pipeline project. There were, however, increased deliveries on the Transwestern pipeline due to sustained cooling demand and increased customer demand.
Moving to Sunoco Logistics, who had another great quarter, with EBITDA of $317 million. This was $80 million higher than SXL’s fourth quarter of 2014. Moving to retail, as a reminder, due to ETP’s sale of its 100% membership interest of Sunoco GP LLC and all of the IDRs of Sunoco to ETE, ETP no longer consolidate Sunoco for accounting purposes. ETP’s remaining proportionate investment in SUN is accounted for under the equity method. This change impacts the comparability of the retail segment results versus prior periods.
2
For the fourth quarter of 2015, adjusted EBITDA for the retail segment is reported as ETP’s 100% ownership of the assets in Sunoco, Inc., and includes adjusted EBITDA related to unconsolidated affiliates, which is comprised of our 68.4% interest in Sunoco LLC, the wholesale distribution business, and our investment in Sunoco LP based on ETP’s percentage ownership of outstanding LP unit. For the fourth quarter, the retail segment contributed $119 million of adjusted EBITDA.
Going forward, as a result of our dropdown of our remaining interest in Sunoco LLC to SUN LP, which is expected to close in March, we will not report retail results as its own segment. Instead, our investment in SUN LP will be reported in the all other segment and broken out in our disclosures related to supplemental information on unconsolidated affiliates.
For the current all other segment, adjusted EBITDA decreased to $33 million, down $17 million versus a year ago due to weaker refining crack spreads from our investment in PES. As it relates to the PES IPO, this has been postponed and will restart when market conditions improve. We still view this interest as an attractive near-term monetization option for ETP.
Now let’s move to our growth projects, where I’ll provide a brief update. Starting with the Bakken pipeline project, our joint venture with SXL and P66, we are obtaining the necessary permits and regulatory authorizations for this project. We expect to receive the remaining state agency authorizations in the next few months.
This should provide us with sufficient time to construct the project by the fourth quarter this year. Our project management group has done an outstanding job keeping Bakken on schedule.
Next on Bayou Bridge, another joint venture with SXL and P66, construction is nearly complete on the Nederland to Lake Charles segment of the pipeline, which is expected to be mechanically complete in March. Bayou Bridge successfully concluded its expansion open season in November, adding incremental committed shipper volumes to the project.
Based on these commitments, the segment from Lake Charles to St. James is moving forward and is currently in the permitting and right-of-way acquisition phase. We continue to anticipate the deliveries to St. James will commence in the second half of 2017.
On the Rover gas pipeline, we received the draft EIS from FERC last Friday, with final EIS scheduled for the end of July and the FERC certificate in the beginning of the fourth quarter of this year. We anticipate being in service to the Midwest hub near Defiance, Ohio, by June of 2017. And to markets in Michigan and Union Gas Dawn hub by November of 2017.
Lone Star’s Frac III was placed into service in mid-December on time and under budget. Lone Star’s three 100,000-barrel-per-day fractionators have averaged 339,000 barrels per day to date. Frac IV remains on schedule to be in service by December of 2016.
The Lone Star Express NGL pipeline remains on schedule, with Phase I to start up in the second quarter and final completion expected to be in the third quarter of this year. It is also expected to come in under budget.
The Trans-Pecos and Comanche Trail pipelines, which will expand our intrastate pipeline capacity to carry gas from the Permian Basin to Mexico, remain on track to be in service in the first quarter of 2017. We have completed the project financing and expect to commence construction on both projects in the next several weeks.
On the Edinburgh and Oasis pipelines in South Texas, volumes to Mexico continue to grow as our demand fee contract expands from 530 million cubic feet per day to 930 million cubic feet per day, effective March 1. Both the 24-inch Volunteer pipeline and the 200-million-cubic-foot-per-day East Texas cryo plant, also known as the Alamo plant, came online in January of 2016.
On the 2.1 Bcf per day Utica Ohio River expansion, as a reminder, Phase I was placed in service in mid-October last year and Phases II and III came online at the end of December. The project is now fully in service, delivering volumes into both REX and TETCO and we expect volumes to continue to grow throughout the year.
And on the Revolution project, the pipeline and plant as well as the fractionation facility are expected to be in service in the third quarter of 2017. As a reminder, our project provides shippers with unique end-to-end solution, with significantly improved netback economics compared to their other alternatives.
Our 200 million cubic feet per day Orla cryo processing plant in the Delaware Basin is expected to come online in April and be full within 30 days. We have additional 200 million cubic foot per day cryo processing plant, the Panther plant, which is in the Permian Basin that is expected to come online in the fourth quarter of this year.
Now moving on to CapEx, ETP invested over $1.2 billion during the fourth quarter in organic growth projects, with the majority allocated to our liquids transportation and services, midstream, and interstate segments. For full year 2015, ETP invested approximately $5.6 billion in growth CapEx projects.
3
For 2016, as we mentioned in our distribution press release, we have identified approximately $750 million of CapEx that could be deferred or cut from our original forecast. As a result, we now expect to spend approximately $4.2 billion on organic growth capital for 2016. This is net of an additional $325 million that is expected to be financed at the joint venture level with nonrecourse debt.
A majority of the CapEx reduction is related to the midstream segment, where we have placed new processing plants and other projects on hold. In addition, we have deferred some projects at Lone Star and delayed and reduced cost in the interstate segment. We continue to foresee significant EBITDA growth in 2017 from the completion of our project backlog and a majority of these projects are backed by long-term fee-based contracts.
During the fourth quarter, we spent $142 million on maintenance capital expenditures, and for full year 2015, we spent $394 million. As you can see, fourth-quarter maintenance capital was higher than normal. Accordingly, for 2016, we expect to spend approximately $345 million on maintenance capital expenditures.
Before moving on to discussing our distribution, let’s take a quick look at our liquidity position as well as our funding strategy for 2016. We ended the quarter with a debt to EBITDA ratio of 4.5 times for our credit facility. As of December 31, 2015, there was $1.36 billion in outstanding borrowing under the $3.75 billion facility. And we issued approximately $400 million of equity during the fourth quarter of 2015 under our ATM and DRIP programs.
Taking a look at our current funding strategy for 2016, with the expected closing of the previously announced dropdown of the remaining interest in Sunoco LLC and the legacy Sunoco retail business to Sunoco LP in March, the outstanding balance under ETP’s revolver will be close to zero. As a result of this transaction, along with the $750 million reduction in 2016 growth capital funding and other potential asset sales, and the project financings, we do not expect to need to access the fixed income market in 2016 or to need to issue ETP common units in 2016.
While we do not need the equity markets to fund our growth, we expect to opportunistically utilize the ATM from time to time in order to manage our leverage. In addition, ETE recently agreed to extend the $95 million annual management fee paid to ETP through 2016. Collectively, these actions are fully consistent with our goal of maintaining ETP’s investment-grade rating, which we consider a top priority.
We have also kicked off initial discussions regarding project financing of the Bakken pipeline. This measure would materially reduce the direct spending required to finance this project and would substantially reduce ETP’s and SXL’s 2016 capital funding requirements.
Now I would like to touch on our recent distribution announcement. In January, we announced a distribution of $1.055 per common unit for the fourth quarter or $4.22 per common unit on an annualized basis. This was flat compared to our third-quarter distribution and was paid on February 16 to unitholders of record as of the close of business on February 8.
As it relates to potential distribution increases going forward, this is a time when coverage and liquidity are valued more by the equity markets and rating agencies than distribution growth. We will continue to evaluate our distribution on a quarterly basis and will be prudent as it relates to balancing coverage and liquidity with distribution growth.
Now for a brief update on our merger with Williams. As a result of the FTC’s second request for additional information, we entered into a timing agreement with the FTC on December 14, under which we have agreed not to consummate the proposed acquisition prior to 60 days after substantial compliance with the second request. ETE and Williams continue to work cooperatively with the staff of the FTC as it conducts its review of the proposed acquisition.
In addition, on February 1, we received comments to our S-4 Proxy that we previously filed with the SEC. We are in the process of working through those comments, some of which relate to the information that will be included in the ETE and Williams 10-Ks and expect to file an amendment to the S-4 shortly after filing our respective 10-Ks.
The pending merger also remains subject to the approval of Williams’ stockholders and other customary closing conditions. As a result, we now expect closing to occur sometime in the second quarter.
As it relates to the integration planning, we recently announced that Don Chappel has accepted the role of CEO of WPZ post-closing of the merger. In addition, our integration committee has been diligently working through the integration planning. We intend to actively implement a shared services model and continue to expect substantial synergies as a result of the merger.
As a reminder, we have a commitment for a $6.05 billion bridge loan in place with a syndicate of banks to fund the cash portion of the merger. This is effectively a two-year loan. We have had extensive discussions with the rating agencies and we are evaluating several alternative financing plans internally. We will provide more details on this at the appropriate time.
With that update, we will not be taking questions on the call today related to the merger. We appreciate your cooperation in this regard.
4
Moving on now to ETE, I will begin with ETE’s fourth-quarter results, followed by a liquidity financing update and a Lake Charles LNG update. We will then take your questions.
Turning to the financial results, first of all, we are pleased with the fourth-quarter results of SXL, Sunoco, and ETP. As a reminder, effective July 1, 2015, ETE acquired 100% of the membership interest of Sunoco GP LLC, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP. So Sunoco still appears in the consolidated financial statements for ETE.
ETE’s cash flows came from the general partner and IDRs and LP interests at ETP, 90% of the economics of the GP, and the IDRs from SXL through the Class H units, through the ownership of the Lake Charles LNG, and 100% of the GP and IDRs of Sunoco LP. Our distributable cash flow as adjusted for the fourth quarter totaled $343 million, an increase of $100 million compared to the same period last year.
DCF as adjusted per unit for the fourth quarter was $0.32 per unit or an increase of 45% compared to the fourth quarter of 2014. Distributions from ETP accounted for 68% of ETE’s total cash flows in the latest quarter. SXL contributed 17%, Lake Charles LNG approximately 11%, and Sunoco LP contributed 4%.
ETE announced last month a quarterly distribution of $0.285 per unit. This equates to $1.14 per unit on an annualized basis. Our distributable cash flow coverage was 1.15 times for the fourth quarter. It was paid on February 19 to unitholders of record as of close of business of February 8.
Let’s look now at liquidity and financing. ETE continues to have a healthy liquidity position. We ended the quarter with a debt to EBITDA ratio of 2.96 times for our credit facility. As of December 31, 2015, there were $860 million in outstanding borrowings under the facility. Therefore, at the end of the fourth quarter of 2015, the overall ETE stand-alone debt was $6.33 billion with a blended interest rate of 4.8% and with no pending maturities until almost 2019.
Now turning to Lake Charles, which — to remind everyone — is owned 60% by ETE and 40% by ETP. Progress continued to be made during the fourth quarter. We received our final FERC authorization in December to site, construct, and operate the facility, and we received our final approval from the US Army Corps of Engineers last Friday.
On February 15, Shell completed its acquisition of BG. And last week, we held our kickoff meeting for the project financing, and preliminary responses from lenders have been strong. We remain on target to reach affirmative FID on the project in 2016, with the construction expected to start immediately thereafter and first LNG exports anticipated in early 2021.
Before opening the call up to your questions, I would just like to say that our business continues to demonstrate resiliency in commodity markets that have been challenging as well as the benefits of our diversified business model. Our project backlog is built on long-term, third-party demand fees that give us visibility into future EBITDA growth, particularly in 2017. These projects are tracking on schedule and on budget.
ETP’s financing needs for 2016 are expected to be met without the need to access the equity or debt markets, and our counterparties are strong, high-quality companies, or have security for performance that is well structured to mitigate risk. ETE’s priority is to support its core operating subsidiaries and it will take the steps necessary to ensure they maintain their financial health and investment-grade ratings.
We remain very focused on project execution, cost management, and improving our balance sheet strength by lowering our leverage and increasing coverage. The underlying fundamentals of our business are strong and we believe we will be in a great position for growth when the current market conditions improve.
Before we begin taking your questions, I just want to reiterate that we will not be taking questions on the call today related to the pending merger with Williams or related matters. Thank you once again for your cooperation.
With that, operator, that concludes our prepared remarks. Please open the line up for questions.
QUESTION AND ANSWER
Operator
(Operator Instructions) Brandon Blossman, Tudor, Pickering, Holt.
5
Brandon Blossman - Tudor, Pickering, Holt & Co. Securities - Analyst
Good morning. Let’s start on Lake Charles. Has there been any conversations with Shell post-close? And what does that timeline look like or what’s the process to get to FID over the course of 2016?
Todd Carpenter – Energy Transfer Partners, L.P. - Counsel
There’s been no direct conversations with Shell, but BG met with Shell last week and those conversations continue. This week, the feedback from our counterparts at BG said the meetings were very favorable and we’ve been told to proceed as planned.
Brandon Blossman - Tudor, Pickering, Holt & Co. Securities - Analyst
Great. That sounds very positive. Okay, let’s — as far as we can track through 2016 and into 2017, what conceptually or philosophically — how do you address the kind of intermittent use of the ATM program for equity versus kind of distribution thoughts as you consider kind of rating agency action and your investment-grade credit rating?
Tom Long
You bet. As you know, the ATM has always been really a good tool. We have obviously gone lighter on it as we’ve moved into these lower prices. But clearly we want to leave it as an option out there. And with trying to manage once again our leverage ratio and our — as far as our credit metrics, all of our credit metrics.
So the reason why we want to leave that is — in place is not because of the funding needs that we have, but once again just because we want to just make sure that we are staying down the middle of the fairway.
Brandon Blossman - Tudor, Pickering, Holt & Co. Securities - Analyst
Okay. Fair enough. And then just a detailed accounting question. On the bonus depreciation add to DCF in the fourth quarter, what period was that for?
Tom Long
The bonus depreciation was for 2015.
Brandon Blossman - Tudor, Pickering, Holt & Co. Securities - Analyst
Full year 2015?
Tom Long
Yes. But there was some carryback into 2014 and 2013.
Brandon Blossman - Tudor, Pickering, Holt & Co. Securities - Analyst
Thank you very much. That’s all for me for right now.
Operator
Jeremy Tonet, JPMorgan.
6
Jeremy Tonet - JPMorgan - Analyst
Just wanted to turn to the midstream segment, if we could. And was wondering if you could provide any more thoughts as far as how things are trending into 2016. And we saw a decline in the quarter. Do you think things have baselined and growth CapEx coming into service can kind of stem that? Or, how do you think about that these days? And appreciate there’s a lot of uncertainty with producer budgets at this point.
Mackie McCrea
Thanks, Jeremy. This is Mackie. As we look at the challenging times we’re in and you look at our volumes, they are actually up if you compare the fourth quarter of 2014 to 2015. Certainly some of that is related to King Ranch, but even without King Ranch, as a whole — some down, some up — as a whole, our volumes are up across the board. In fact if you take out North Texas, the Barnett Shale, our volumes are up significantly, not only on midstream, but also on our intrastate.
In addition to that, as we kind of take a forward look into 2016, once again in very challenging times, the thing we concentrate on the most is volumes. As Kelcy has always said, we can’t control basis. We can’t control commodity prices, but we can be aggressive and more competitive on volumes. And we actually are seeing volume growth in 2016 compared to the fourth quarter of 2015, ranging anywhere from 4% to as high as 17% depending on the basin.
So the things that we can control, we are pleased with, especially in the environment we are in. And we can’t worry about the things we don’t control.
Jeremy Tonet - JPMorgan - Analyst
Got you. Fair enough. And as far as the midstream reductions there, would you be able to share more color on which plants were being deferred? And was Revolution part of that CapEx reduction?
Mackie McCrea
I’m not sure on CapEx reduction, but we’ve — we still are on track to have Revolution in by the third quarter of 2017. It has been pushed back a little bit to be in line with the downstream pipelines.
The other plant that Tom talked about earlier was Orla. It’s coming on soon. We are very pleased with that plant. It’s very rare you bring a plant on and it’s full within 30 days. Panther will be very similar at the end of this year. It will ramp up fairly quickly. Any other plants that we have contemplated, we have put on hold until we have accretive contracts to support them.
Jeremy Tonet - JPMorgan - Analyst
Sounds great. Thanks for that. And just as far as the JV potential as far as managing the balance sheet and as far as project financing at Dakota Access, do you need agreement from all of the JV partners there to do that? And are you looking for any other JVs on growth projects that you have to further strengthen your balance sheet?
Tom Long
We are — first off, first part — I think the last part of your question there — yes, we do need the consent of the JV partners, which, as you know, that’s P66 is our 25% partner on that one. What we’re looking at there is, we’re not looking at necessarily pushing the leverage up really high on that. We are really just kind of looking at kind of a 50-50 financing on that project. I’m sorry. The second part of your question was around the JV?
Jeremy Tonet - JPMorgan - Analyst
Well, for — as far as this type of a financing, bringing in JV partners for any other projects — is that a possibility at this time?
Tom Long
Yes, I would say that that is a possibility. We’re clearly focused on the project financing side of it is what we are focused on right now. But yes, that is a possibility.
7
Jeremy Tonet - JPMorgan - Analyst
Got you. Thank you. And then just one last one from me. In the liquids segment, it looks like there was an inventory liquidation. Could you just provide a little bit more color on what was happening there?
Tom Long
Are you talking about kind of the goodwill and the impairment? Is that what you are referring to?
Jeremy Tonet - JPMorgan - Analyst
In other margin? In other margin, I think there was a little bit of an increase this quarter, so I was just wondering about that.
Tom Long
Listen, I’ll have to get back to you on that other marketing. I apologize. I thought you were asking a question. Let me get back to you on that one.
Jeremy Tonet - JPMorgan - Analyst
Great, appreciate it. Thank you.
Operator
Michael Blum, Wells Fargo.
Michael Blum - Wells Fargo Securities, LLC - Analyst
Can you go back to, I guess Mackie, some of your comments you were just making about your outlook for volume? I know at your investor day, you said that you weren’t really seeing volume declines and you actually expected some increases.
So you just threw out a range: 4% to 17% growth. Can you just kind of walk us through by basin kind of what you’re seeing there and what’s driving volume growth?
Mackie McCrea
Sure, you bet. One thing we are very pleased with is a lot of our dollars, a lot of our capital has been focused in two of the better basins in the country, that being Eagle Ford and probably the best basin in the world with Permian Delaware. So we certainly are — see significant growth there. As I mentioned a minute ago, we’ll have 200,000 a day flowing through our Orla facility by May or so. So that’s an increase alone just at that one facility.
Also, we’ve seen significant growth up in the Northeast on our Ohio River system. It came on last year, started ramping up toward the end of the year, and its exceeding our expectations in the first quarter. And we project that that will continue throughout 2016. Once again, even in these very difficult environments.
As I mentioned earlier, Barnett Shale — Barnett Shale, it is on a slow decline. The reserves are there. Our pipes there are waiting whenever the prices make sense, but every other area for the most part — Rebel is growing the volumes there. South Texas, we’ve had some downtime on some plants that, as Tom alluded to, we have those up and running. So we’ll see volumes at least hold, if not gain a little bit in the Eagle Ford.
So all in all, as I mentioned earlier, other than a few exceptions, we are pretty excited or pleased with where we see volume growth this year compared to our competitors and in this very difficult environment.
Michael Blum - Wells Fargo Securities, LLC - Analyst
Okay, great. And then as I’m sure you know, Chesapeake made some comments on their call about some recontracting on Tiger, it looks like. But it seems like there is some sort of quid pro quo and you’ll be seeing a benefit somewhere in your gathering system. I was wondering if you could just provide a little more details and maybe if you could quantify for us how that trade occurred.
8
Mackie McCrea
You bet. You know, it’s funny. When all this started happening, Kelcy and I talked. There is always some lemonade with the lemons, and that’s what we try to do. We’ve built our relationship with creating or working with producers on their needs. And clearly, there’s a lot of pain on the E&P side — on all the sides.
And we have in that situation been able to help out Chesapeake in the short term by shifting demand charges, where some of their business is more commodity now with us in the short term, and by extending contracts that were ending over the next three to five years for many years out. And then also adding significant business in the future.
So we are very pleased with Chesapeake. We enjoy — have enjoyed working with them. We do believe they will make it through these tough times and we look forward to being kind of their partner of choice is what we hope as they continue to drill out some of the better rock that they have control of or have leases on throughout the country.
Michael Blum - Wells Fargo Securities, LLC - Analyst
Okay. So we should see that benefit show up in later years in the midstream segment? Just trying to figure out where the offset is.
Mackie McCrea
Yes. You’ll see more of it — I can’t get into a lot of details here, but certainly you’ll see more of it more in the midstream and even in some different basins.
Michael Blum - Wells Fargo Securities, LLC - Analyst
Okay. And then just on Rover, can you just remind us kind of what percent of that pipe is currently contracted? And also how much capital has been spent to date?
Mackie McCrea
I’ll let Tom speak to the capital on the math. It’s like 97%, I believe. 97%, 98%. We have 150,000 left or 3.25%, whatever the math is there. I think it’s about 97% or 98% on demand charge. And on the CapEx that’s been spent?
Tom Long
On the CapEx, Michael, I’ll get back with you. I believe we are probably at about $2 billion or so. But I tell you what — I’ll get back with you on that, see what’s the absolute latest on that.
Michael Blum - Wells Fargo Securities, LLC - Analyst
Okay, great. And my last question is really — I don’t know if you can or will comment, but obviously there’s been a lot of speculation with the departure of Jamie. And I just wanted to know if there’s anything you could share in terms of the circumstances with that whole situation? Thanks.
Kelcy Warren
Michael, this is Kelcy. I think to be respectful to Jamie, I’ll keep this to a minimum. And we’ve talked to many, many that are on this call. Jamie is a very talented guy, but the decision was made by me that we needed to make a move and we did. And Tom Long is now our CFO.
Michael Blum - Wells Fargo Securities, LLC - Analyst
Great. Thank you.
9
Operator
Darren Horowitz, Raymond James.
Darren Horowitz - Raymond James & Associates, Inc. - Analyst
Morning, guys. Tom, if I could, I just have one question. I want to go back to your discussion around the balance sheet. And obviously what the market is telling us is they want more transparency, not just into the timing, but the magnitude of enhancing liquidity and reducing leverage.
You’ve talked about your options, like monetizing part of the Bakken pipe, maybe deferring more CapEx. Obviously, that $2.2 billion in proceeds from the sale of Sunoco interest helps. But there are other options and I’m wondering how you guys rank those in terms of priority or in terms of what could have the biggest benefit to the balance sheet.
If you think about SUN, it’s obviously countercyclical. Historically, you’ve said not a core business. And it helps both ETE and ETP with regard to the GP and the LP interest. And I’m thinking about if you could just provide some color how you view those monetization options, what’s changed in the marketplace, and if you could provide any transparency on the timing and your forecast for where you want leverage to be exiting this year, especially if this fundamental or cost of capital challenge continues into 2017.
Tom Long
Okay. No, you bet. Let me kind of start with the last part. Our target is still to maintain a 4.5 times leverage ratio, so obviously at year end. And this is per the credit facility. That’s how we continue to manage that as we look out. And we still think that’s a very good target, and of course, as you know, we are right in the middle of a lot of pre-funding.
So we knew that that was going to put some pressure on the leverage, but it was also going to put some pressure on the coverage. You know, the real comforting thing to us is these projects are all coming on late this year, early next year. So that’s what we’ve been working toward in getting kind of the last portions of this funded.
Back to the prioritization, I guess I would say we do have those options. It’s really kind of difficult to prioritize them in the sense that the market is so dynamic. You know, as you look at various options, different days, different things move around on you. And it’s — we’re going to probably stay consistent with what we’ve always done in the past, and that is to — as we get and make a certain decision as to what’s the best for the Company, from once again all of the various metrics — coverage, credit metrics, etc. — we will make those decisions at the time and we will announce them at the time.
But if we try to get out and preannounce on these, you can appreciate what that really does. So just kind of staying consistent with the way we’ve always funded our projects in the past, where we announce them at the time that we get whatever negotiated, is what we are going to continue to go — a plan that we are going to stick with.
Kelcy Warren
Darren, I would add that — as you and I have spoken recently, it is ETE’s job to support the partnerships that operate underneath it. And so there will be continued support to the extent IDR holidays for growth are appropriate that they will be given. And other means that ETE can support ETP’s growth and get ETP into late 2017, where ETP has pretty remarkable growth at that time. So just note, just rest assured that ETE will do what it needs to do.
Darren Horowitz - Raymond James & Associates, Inc. - Analyst
Thank you.
Operator
Ted Durbin, Goldman Sachs.
Ted Durbin - Goldman Sachs - Analyst
Thanks. Maybe just taking that one more level. Is a distribution cut on the table at all for either ETP or ETE, relative to the leverage metrics you are looking at? It’s a choice that some other partnerships have made. Maybe you can put that in the context of if and when the Williams deal goes through, how you think about that. And then also balancing between ETE and ETP and where you might make that decision.
10
Kelcy Warren
I’ll take the first part. There is no contemplated distribution cuts at ETP whatsoever. We’ve not looked at any scenario where that would be appropriate or necessary. It’s just not — we just don’t see that. You know, like we said before, we’re not going to talk about the Williams transaction.
But you know, ETE is a very healthy. Our — distribution cuts are not required at ETE. And we take our obligation to our unitholders very, very seriously. We have a duty to maintain our distributions. But everybody knows obviously that that’s an option. To the extent that we need access to distributions to maintain our financial health at ETE, would we reach into that bucket? It would be the last one that we would reach to, but it’s certainly possible.
Ted Durbin - Goldman Sachs - Analyst
Okay, I appreciate that, Kelcy. Can we just talk about the Bakken pipeline? And it sounds like you are still confident in hitting that late 2016 in-service date. It feels like it’s a stretch from my seat, at least given that you haven’t started construction as far as I can tell. What’s left that needs to get done on the permitting side to hit that in-service time?
Mackie McCrea
Ted, this is Mackie again. You know, I’ve got to say, like we do for most of our teams, we have one of the best teams in the country building that pipeline, with Joey Mahmoud on the engineering side and Lee on the commercial side.
And that project has gone exceptionally well in a very, very difficult environment throughout the country. We still are holding to the schedule. We have every permit other than a permit in Iowa — material permits — and we are optimistic and hope to have that permit in March. And as soon as we have that permit, we will begin construction. But right now, we do expect to be flowing oil by January 1st of 2017 and it’s very realistic that that’s going to happen at this point.
Ted Durbin - Goldman Sachs - Analyst
That’s great. I appreciate it, Mackie. And then last one for me, just on the Lone Star Express. I think you had spoken about that as being kind of a 6X multiple on invested capital. Are you still comfortable with that, given the environment?
Mackie McCrea
Yes, we are.
Ted Durbin - Goldman Sachs - Analyst
I’ll leave it at that. Thank you.
Operator
Kristina Kazarian, Deutsche Bank.
Kristina Kazarian - Deutsche Bank - Analyst
Not to beat a dead horse here, but just a clarification question on ETP’s IG rating. So the — Kelcy, the thought process is that if ETP had the risk of being downgraded from another sibling entity or a parent entity and readthrough, that the parent would actually backstop the rating and help it out to protect that balance sheet. Is that fair?
Kelcy Warren
That is fair.
11
Kristina Kazarian - Deutsche Bank - Analyst
Okay, perfect. And then I know you talked about this in an answer to a different question, but over the whole complex, maybe can you touch about counterparty risk and the potential or magnitude for contract resetting, kind of like the Tiger line, which we heard about yesterday?
Tom Long
I’ll take the first part of that. You know, with the slide that we used in Analyst Day, where we showed that 86% was basically BB or higher on our credit ratings, that has really remained very consistent in where we are from that standpoint.
So we continue to stay obviously very focused on that and we like the positions that we have with our counterparty credit exposures. But I wouldn’t — we’ve really not seen much movement in that and we know there’s been a lot of changes with the agencies. But it’s not really impacted as far as our top credit exposures at this point.
Kristina Kazarian - Deutsche Bank - Analyst
And on the second part, maybe about potential contract resetting, like throughout all of 2016 across your fleet?
Tom Long
I tell you what, Mackie — go ahead. I’m sorry — second part, one more time.
Kristina Kazarian - Deutsche Bank - Analyst
The second part is how do I think about contract resetting potentials across the whole complex for calendar year 2016?
Mackie McCrea
Midstream, intrastate, interstate, the whole complex?
Tom Long
Yes.
Mackie McCrea
Well, on our midstream, most of the contracts in our midstream are long term now. Any plant that we’ve built recently is under at least 10 or 15 year contracts. On all of our NGL business, there are long-term contracts. Most of our frac contracts are at least 10 years and probably a majority of them are 15 years.
On the interstates, it varies depending on the interstate. The older interstates, the interesting phenomena there is that as the contracts roll off, we actually are increasing rates. Certainly not charging tariff on some of our pipelines, but certainly at higher rates than where they have been. You know, for example, we’ve taken out our Trunkline pipeline, and on the existing space that we still have on Trunkline has provided for higher rates because of demand in the Northeast this winter.
So all in all, we don’t have a whole lot of exposure. And as I mentioned earlier in our discussions with Chesapeake, we are having similar discussions with other companies that have similar type pain. And in those, we are looking at extending contracts that are ending in the next year or two out for at least 10 or 12 more years. So we are pretty pleased with where we sit across the complex of all of our segments on the timing of our contracts.
And our goal, through this tough period, is extending everything out because we provide that opportunity by helping them — some of these companies with the difficulties they are going through today.
12
Kristina Kazarian - Deutsche Bank - Analyst
Perfect. Thanks, guys. Appreciate the clarification.
Operator
Robert Balsamo, UBS.
Robert Balsamo - UBS - Analyst
Most of my questions have been answered. Just a quick one. On the unconsolidated affiliates, it looks like PES was down for the quarter due to crack spreads, which make sense. But the distributions seem to be strong in the segment, unconsolidated affiliates.
And I just wonder if you could talk a little bit about that, if the distribution is kind of being maintained. Looks like they are still growing. Kind of how to think about cash flows and distributions coming from that segment — PES and then unconsolidated affiliates overall.
Tom Long
Yes, you bet. You are right. We did have some pressure because of the crack spreads there in that refinery. From a distribution standpoint, we’ve always been very much aligned with our partner there — both of us wanting to maximize distributions. And you know, kind of like I said in my prepared remarks, we are going to obviously maintain it and be ready to go with an IPO at any time.
But I think direct answer to your question, we will always try to maximize distributions going forward. But that is going to be kind of up and down with where the market — with where crack spreads are.
Robert Balsamo - UBS - Analyst
Okay, thank you. That’s all.
Operator
Helen Ryoo, Barclays.
Helen Ryoo - Barclays Capital - Analyst
Good morning. Just couple of quick items. When you say — when you plan to do the DAPL project financing, do you need FERC approval to launch it? And also, if you were to get, let’s say, 50% project financed, would that reduce your 2016 CapEx by, let’s say, about $1 billion?
Tom Long
Yes, to the last part of your question. You are right on that. That’s 2016 is right at $1 billion is what it would reduce it by. As far as the FERC approval, no, we do not need FERC approval to get project financing on that pipe.
Helen Ryoo - Barclays Capital - Analyst
Okay. So this is something you could launch anytime, basically?
Tom Long
Yes, yes. We’ve actually already started the dialogue on it.
13
Helen Ryoo - Barclays Capital - Analyst
Okay, got it. And then how much of your DAPL spending was already in your 2015 CapEx? I see $2 billion of liquid CapEx and, are you able to quantify how much of DAPL has already been spent?
Tom Long
As far as DAPL, I think we are right at about $1.7 billion, $1.8 billion on how much has been spent to date.
Helen Ryoo - Barclays Capital - Analyst
Is that net to ETP?
Tom Long
No. That would be the 8/8ths. The full amount.
Helen Ryoo - Barclays Capital -Analyst
Got it, got it, great. And then apologies if I missed this, but what drove the increase in midstream OpEx in the quarter? It was up quite steeply and —.
Tom Long
Yes, what you saw during the fourth quarter, of course, was several plants starting up where you started seeing some additional expenses. You probably saw nearly additional $25 million, $26 million worth that occurred during the quarter.
I would say, Helen, though, it is fairly normal to kind of see in the fourth quarter. A lot of times as you get into year end, you will see the expenses come up some. I guess what I’d like to say is as you go into 2016 and really look at the, let’s say, the early quarters, I would say that that number probably popped up by about a $25 million number that we would expect not to necessarily see as we roll into 2016.
Helen Ryoo - Barclays Capital - Analyst
Got it. And then your comments on PES, you mentioned that the IPO is delayed, but that this is a near-term monetization option. So when you think about a couple of, I guess assets you could sell, and I assume that includes Lake Charles, do you see this as something more — higher in the rank in terms of probability? Or maybe you could more broadly talk about certain assets that you could sell to help the balance sheet.
Tom Long
Helen, you can probably, like I say, appreciate you know talking too much specifics before you actually have a — you have a plan or have a deal in place is always difficult. In other words, usually you would announce those at the time that you would actually go out.
But I think when you really look, clearly this is one you could look at — our 33% ownership in that. But I think we still feel like that until you really get it to kind of to an IPO, that’s probably where you are going to get the highest value. So it’s not one that’s — let’s just call it ripe for doing that.
And LNG was the other one you brought up. Clearly that’s one that — that is an option out there, but you heard the update today. We are very excited at where that is and moving forward. But likewise don’t necessarily see that as being something you would do today.
And then, you know, I think there was other — even a comment made earlier about options around if any of the JVs you wanted, to bring in any other partners, etc. You could obviously do that. But I will just reiterate once more that I think from a funding standpoint on the projects with the $4.2 billion, what we’ve accomplished on that front, we feel like we’ve got a lot of leeway here as we look out through 2016.
14
Helen Ryoo - Barclays Capital - Analyst
Okay. And then my last one is just on SUN, I guess, deal closing date seems like it’s got pushed out a month. What’s causing that? And any other — any risk of further delays there?
Tom Long
No. And listen — Helen, really that one is really pretty much on schedule with where we — it kind of anticipated. Remember that we file our 10-Ks — we’ll probably get them filed by at least Monday. And you really could not finish up the carve-out financials to close this transaction until after those 10-Ks were filed.
So just keep in mind, that’s probably a — when we say March, I would like to tell you that’s probably a very early March, meaning possibly as early as next week, even — by the end of the week or so. But we are working through those financials and that is really the component.
Nothing is going to change as far as the effective date of the transaction. It’s still going to be January 1st of 2016. So whether we do it the first week or the second week of March, but the only — absolutely the only holdup was getting the 10-Ks filed and then getting the carve-out financials.
Helen Ryoo - Barclays Capital - Analyst
Understood. Thank you very much.
Operator
John Edwards, Credit Suisse.
John Edwards - Credit Suisse - Analyst
Just a couple follow-ups on the counterparty risk side. Just out of the — you indicated I think it was 14% — 86% is BB or higher. So out of the remaining 14%, if those BB or lower went to bankruptcy, I am just curious how many of those rates were perhaps above market. Or how you would quantify, say, the revenue hit if those contracts had to be renegotiated, like in a bankruptcy situation, you know, some sort of revenue quantification we could look at.
Mackie McCrea
This is Mackie. And I won’t go through specific risks or producers in areas, but one thing that’s very helpful is where a lot of this risk is, it’s on parts of our gathering systems where it’s really hard to compete. Certainly, in a bankruptcy, there may be some renegotiation, but we don’t see in a lot of these situations a lot of risk because our ability to either work it out with them or because there may not be a lot of options out there. And the price that we are moving it for is the market price.
So not talking about any specific producer. We can reduce that exposure significantly just because of how they are situated in our system.
Tom Long
And John, what I’d like to go ahead and just add to that from the absolute kind of percentage, if you will — when you get down to that group, I mean, the exposure — and I know we talked some about the Chesapeake — but as far as the counterparties and where those percentages lie, they are really small. It’s spread out over a lot of counterparties and it’s — the number is well less than 1% on any one customer.
John Edwards - Credit Suisse - Analyst
Okay, that’s helpful. And then just following up, Tom, on the balance sheet, you indicated you are targeting 4.5 times exiting this year. I’m just curious kind of your longer-term leverage target, what you’re thinking about.
Tom Long
Yes. And once again, at ETP, we do feel like that the 4.5 times is a good place to be. Remember that the credit facility calculation, the way we do that, does allow for the inclusion of the material project adjustments, if you will. I know we’ve talked about before.
15
And so that’s how we get to the number. In other words, these are the calculations that we will be sending out to the banks at this 4.5 times. But the real beauty of that: it does show these projects as they come on, where the economics are. And it does give you a line of sight of where both GAAP and NPA are headed to be basically the same number at the 4.5.
So once again, as we go through 2016 and complete a lot of this funding, you know, you are going to see that that 4.5, both on a GAAP basis as well as a — with the material project adjustments, that gap narrows significantly.
John Edwards - Credit Suisse - Analyst
Okay, that’s helpful. And then I guess — I know we all have to jump to the next call, but just maybe you could give a little bit of color on the impairment losses. I mean, I think there was the $339 million item there.
Tom Long
Yes, you bet. It really is all around the commodity prices, if you will. So let’s start with the Transwestern piece first. The number was $99 million. It really was about kind of looking out at where the commodity prices were on that. So that was the goodwill impairment.
The rest was really all in the refinery services. In other words, in the liquids segment. And same thing: it related to actually the spread that you see in those contracts we had between the off-gas projects we have. And we actually took one of those plants completely out of service. So that was it. It was the refinery services and then the Transwestern. So that’s what makes up the $339 million.
John Edwards - Credit Suisse - Analyst
Okay, thanks. I’ll follow-up with the rest of my questions. But thank you for that.
Operator
Selman Akyol, Stifel.
Selman Akyol - Stifel Nicolaus - Analyst
Just a couple quick ones. Mackie, going back to your earlier comments, you mentioned there was some downtime on plants in the midstream segment. I was wondering is there any way to quantify the impact on that?
Mackie McCrea
I wouldn’t — it would take a while to go through kind of every specific because we have issues on several plants. But for example, in South Texas, we’ve had issues on a plant that moves about 130,000 a day. That’s been down off and on and we’re hopefully to the end of that, where that runs reliably.
And then some of our plants out in West Texas, we continue to kind of work through issues, but we are working through those. That has a lot to do with why we are seeing our volumes increase on our projections in 2016 as we kind of line all those issues out.
Selman Akyol - Stifel Nicolaus - Analyst
I got you. And then just one more. I guess at the time of — when you guys acquired Regency, you had forecasted some pretty good synergies. And I’m wondering: are you seeing any of those? Are they yet to come? Is it just being chewed up in the commodity environment? Any commentary around that?
Mackie McCrea
No, we are seeing them across the country. If you look at West Texas, we’ve talked about Orla. You know, Energy Transfer is building Orla, putting in place, tying it to the Regency system. The Delaware basin, as I mentioned earlier, if you talked with some of the larger producers in the country, they believe that’s some of the best rock in the world.
16
So as we kind of expand out our business, the Regency assets and the broad expansion of all those gathering systems and all their plants, gives us the ability to provide services while we are building new plants. So the synergies out in the Permian Basin in West Texas have been extensive.
Up in the Northeast, of course with Ohio River, we are seeing a lot of volume growth there. Once Rover is up and transporting gas, that will be one of the main feeders to that pipeline or a very significant supply source. And then we also have some synergy in East Texas that we are benefiting from. So yes, it’s been very — areas of the country we’ve had significant synergies that have helped out a lot.
Selman Akyol - Stifel Nicolaus - Analyst
All right. Thank you.
Operator
Chris Sighinolfi, Jefferies.
Corey Goldman - Jefferies LLC - Analyst
This is Corey filling in for Chris. Just real quick, Tom, just to follow-up on the last question. I think again, you had mentioned some plant outages and some Northeast volume shut-ins. Can you quantify the EBITDA impact there that you saw in 4Q?
Tom Long
Yes, that impact was probably $6 million to $7 million.
Corey Goldman - Jefferies LLC - Analyst
Got it, thanks. And then last question. I think you had mentioned Revolution was pushed one quarter into 3Q. But effectively, what was the remaining cause for the $500 million in decrease. You mentioned CapEx. Which projects specifically are being deferred or shifted there?
Tom Long
Let me give you more of a high level versus maybe talking about the specific projects. Just to give you a split on that $750 million, I would say about 25% of that was actual cuts. The other 75% of it is really more deferral, and you’ll see that spend kind of over that kind of occur in — over 2017, maybe a little bit more of it in the first half of 2017.
You know, I think — and Mackie touched on this. But I think you have, of course, the gathering system down in South Texas. But you also had a West Texas plant likewise that — and that’s — like I say, the rest of it is really more around just some of the deferral on the projects that are already there.
Corey Goldman - Jefferies LLC - Analyst
But no other timing has changed besides Revolution?
Mackie McCrea
No other timing has changed. Well, Rover at one time — gosh, I think at the analyst meeting we were optimistic that we would be in by April or May. Where we stand with FERC, we thought we would have the ability to kind of push the July 29th date up a little bit. It’s clear that that’s very unlikely, so we are planning accordingly and so we have moved that date out to June. We are confident that we will be flowing most of the pipeline in June and then complete it by November.
17
Corey Goldman - Jefferies LLC - Analyst
Okay, great. And same thing on intrastate. What was the reason for the $135 million shift in CapEx there?
Tom Long
I’m sorry, you said on the intrastate.
Corey Goldman - Jefferies LLC - Analyst
Yes, I think you reiterated Trans-Pecos is still in 1Q. So just wondering now what the mix shift was there.
Tom Long
Yes. And that was on the — that was on the Mexico projects. And it really does relate to the project financing. Because what you have is the last time we gave the number, we really didn’t have that project financing in place. So we since have locked that up at very good rates and very long term. But that’s what really drove that one down from the intrastate.
Corey Goldman - Jefferies LLC - Analyst
Got it. Thanks guys.
Operator
Eric McCarthy, Citadel.
Eric McCarthy - Citadel Securities LLC - Analyst
I was hoping you could elaborate a little bit further on the Chesapeake contracts. Chesapeake disclosed $50 million in savings in exchange for some GMP contracts. What basin does that apply to and what’s the — does it make up for the $50 million in full? And what’s the ramp down around that?
Mackie McCrea
This is Mackie again. As I mentioned earlier, we can’t really get into the details of that. I think if you look at their comments more closely, they also consummated some similar type amendments with other companies. So that $50 million isn’t attributed to just us, but it’s throughout several of the basins that they have significant positions in. Some of which we don’t have a lot of business with them today and some of which we do have a lot of business with them. So — but getting into any more details than that with our confidentiality agreement with them, we can’t do that.
Eric McCarthy - Citadel Securities LLC - Analyst
Okay. That’s about it. Thank you.
Operator
John Kiani, Teilinger Capital.
John Kiani - Teilinger Capital Ltd. - Analyst
Good morning, Tom. Just a few questions, please. First, the $230 million tax benefit that contributed to DCF this quarter, trying to understand — the coverage looked like it was in the 0.8 times range without that. Should we expect tax benefits like this going forward? How should we think about coverage with and without that, please?
18
Tom Long
Very good question, John. And I guess what I would tell you is that if you really take that $230 million, since we didn’t really bake anything on the other component of that, that other $50 million. You take that $230 million, really about $120 million came about from the bonus depreciation. So I wouldn’t count on that again.
As far as the $80 million, another $80 million component came about through just lower overall taxable income was the other component. And then you have the last $24 million piece that related really to a state income tax that we had a favorable outcome on.
So I think the way I would look at it, John, is that if you look out through 2016, I wouldn’t necessarily bake in any type of benefit. In other words, kind of — or expense either. In other words, I would really kind of leave that one fairly flat.
John, I think the other thing I’d like to — since you are on this topic, I’d like to go ahead and add to it is that what we’ve really kind of looked at is really probably — you’ve also had maintenance capital that came up to the $142 million. Our normal kind of run rate that we are looking at next year is probably closer to $85 million a quarter.
And then the other thing you had is some of the other stuff that we talked about today from some of the operational, etc. All in all, I guess I can say is that if you took the $230 million and then you backed approximately $80 million or so of what I call items that went the other way, you are probably at about $150 million is where I would take you. And based upon that math, you are probably at about 0.9 — a little bit more. So anyway. Does that help?
John Kiani - Teilinger Capital Ltd. - Analyst
Yes, that makes sense. Another question, please, is when you think about the portfolio, and you talked about the potential at some point for some asset sales, what do you think about some of the businesses you inherited through all the acquisitions that aren’t necessarily as pipeline-like? Could you sell those? What about like the coal business that came with PVR. Things like that that are just not as visible as some of the legacy assets. What about those businesses, please?
Kelcy Warren
Yes, this is Kelcy, and you are correct. We do have employees there, so I need to be a little bit careful. But those type of businesses are being analyzed. And we are looking at monetizing things that do not have the promise for great cash flow going forward or deferred cash flow in the future. So yes, we are.
John Kiani - Teilinger Capital Ltd. - Analyst
Okay, thanks. And then last question, please. Kelcy, you mentioned the potential for support and IDR holidays and things like that for your subsidiary companies. One thing I’m trying to just get a better handle on is with the pro forma debt balance for ETE being $17 billion to $18 billion.
And how does that work? I guess I’m getting a little confused because it’s somewhat of a zero sum game. If ETE takes less cash in the form of IDR holidays or some type of support for its subsidiaries, how does it sustain and service that type of debt load in its own distribution? Am I missing something or should I think about it in a different way?
Kelcy Warren
Think about it another way. There’s going to be the need for all of the partnerships to issue new equity going forward to fund their growth. And to the extent that ETE should waive IDRs on those new units that are going out, then it will. So if you follow that, that’s not taking money out of the coffers of ETE. It’s future dollars that would have been earned that have been forgiven or deferred.
John Kiani - Teilinger Capital Ltd. - Analyst
Right, right, okay. Thank you; that’s helpful.
Operator
Zev Nijensohn, The Boston Company.
19
Zev Nijensohn - The Boston Company Asset Management - Analyst
Hey guys. Thanks for taking my question. I was hoping you could help me back check my numbers. And I’d like to focus specifically on adjusted EBITDA. But hypothetically, if you didn’t spend another dime of CapEx as of December 31, 2015, can you quantify how much EBITDA on a run rate basis is on the come from projects that were I guess either approaching completion or were completed, but not fully reflected during the fourth quarter?
Tom Long
Yes. Well, you know, I’m not going to probably give you an absolute dollar amount just because we just don’t give guidance like that. But you know, these projects that are all coming on are in the $10 billion to $11 billion range. I think we’ve always kind of given guidance that we kind of got kind of mid-teen type returns. I’m just giving you a balance across all of them.
And as you also know, some of these things start ramping up over time. So I think that’s — that hopefully helps and that’s what you can kind of use as your guidance for each one of these various projects and how they start up. And then the timing of when we’re telling you they are starting up.
Zev Nijensohn - The Boston Company Asset Management - Analyst
Okay. Then if I switch gears for a second, and I guess this is a question more for Kelcy, but if you think about things from a real long-term, long-ball type perspective, why not consider cutting the dividend entirely at ETE in order to give yourself a lot of coverage in terms of funding interest and doing something similar to what KMI did, since you’re not necessarily getting credit for it in the market right now?
Kelcy Warren
Yes, well — and I hear you. And it’s our job here to protect the distribution. Our unitholders expect us to do that. We take that responsibility very seriously. But as I said earlier, if there is a chance that one of the partnerships would be in peril for a downgrade in ratings, ETE will do what is required to help that operating partnership.
Of course, the 800 pound gorilla is ETP and we will be — we’re going to be taking moves to help ETP get to middle of 2017, which is all it needs. And then it’s cooking in grease after that. So I hear you. We would like to reach into every bucket we’ve got before we would reach into that one, as I mentioned before, but it is a possibility.
Zev Nijensohn - The Boston Company Asset Management - Analyst
Thank you.
Operator
Norman Hale, Stifel.
Norman Hale - Stifel Nicolaus - Analyst
You know, the primary source of the pain for the energy industry, which has filtered into the midstream industry, is product prices. What do you guys see as being a normalization in terms of both the crude oil price and the natural gas price?
Kelcy Warren
Wow. All of us are just like you. We read everything we can read. We listen to other people’s opinions on the subject. And so I’ll just start and Mackie, maybe you can help me.
I’ll talk about crude for a second. We are — there’s something very healthy going on in our industry and it’s unfortunately is painful. Every time we’ve had one of these downturns, these cycles, they end up being a very healthy thing. But my goodness, they are painful.
And what I mean by that is until we see meaningful reduction in drilling, which translates into Mackie and Matt Ramsey making their job harder and harder. Because when there’s just less volume coming on, your volumes inevitably are going to be stressed.
20
But until we see that, I don’t believe we are going to see meaningful improvement in crude oil prices. I just don’t see it. There’s too much success. These guys are drilling 8,000-foot laterals, for God’s sake. I mean, their science has improved so much. But we are beginning to see that.
It’s sad. We are beginning to see very few people that are going full out anymore. And then that ultimately will correct. I personally believe and this is — boy, you can — with this and a dollar, you can maybe buy half a cup of coffee somewhere. But the — I personally believe that we are going to see this recover more rapid than people think.
Unfortunately, we’ve got to find that balance. We’ve got to get crude oil production with the crude oil market in balance, and then I believe there will be inevitable cuts coming out of our not-so-good friends over in the Middle East. And then we’ll be back up on a ride.
Now, I don’t think $100 crude is healthy for anybody. I don’t believe it is. I believe $60 to $80 crude is a very, very good. So anyway, that’s my view on that. Mackie, what —?
Mackie McCrea
Also you look at the market side of it. It’s just — it’s going to take time. If you look at the growth into Mexico, just our projects alone are going to grow and increase the volumes into Mexico significantly beginning in 2017. And even as we mentioned earlier, some volume increases this year.
With the Chinese — the China market and all the Eastern markets, the demand has just slowed down. If demand ever picks back up, that will help tremendously. But just from my perspective, I think that without some major occurrence in the Middle East, this is just going to take time.
It isn’t going to be immediate, but to Kelcy’s point, once it does return, we are very optimistic that it will be very difficult for producers, for service companies to react quick enough. And so we could see a pretty quick movement certainly on the oil side and probably be sustained for some period of time. It’s just — when is that going to take place is the big question. How soon?
Kelcy Warren
Yes, I’ll add. Hey, by the way, this is our last question, so we are a little bit more relaxed on this one. So this is great; we are finishing up here. But you know, Mackie, the amount of volume we are going to be moving to Mexico within — by 2018 is huge. It’s huge and those things are chipping away. And the point is, we are seeing demand for natural gas improving.
Mackie McCrea
Today. Today. I believe it happened today. Cheniere loaded their first LNG ship for the first time ever we’re exporting LNG. That’s going to increase. Freeport of course hope to get to FID. All that takes time, but with the market growth that we already know of and any kind of improvement overseas, it’s going to be — there’s plenty of supply right now. The market needs to grow to really help our situation.
Norman Hale - Stifel Nicolaus - Analyst
Yes, I hear you. Thanks, guys. I think you guys are doing a great job in a really tough environment. Keep up the good work.
Mackie McCrea
Thank you. We appreciate that.
Kelcy Warren
Okay. Thanks, everybody, for the call. Good questions. And we’ll be talking to you soon. Thank you.
Operator
21
Thank you. Ladies and gentlemen, this does conclude today’s teleconference. You may disconnect your lines at this time and thank you for your participation.
***********
Forward-looking Statements
This communication may contain forward-looking statements. These forward-looking statements include, but are not limited to, statements regarding the merger of ETE and Williams, the expected future performance of the combined company (including expected results of operations and financial guidance), and the combined company’s future financial condition, operating results, strategy and plans. Forward-looking statements may be identified by the use of the words “anticipates,” “expects,” “intends,” “plans,” “should,” “could,” “would,” “may,” “will,” “believes,” “estimates,” “potential,” “target,” “opportunity,” “designed,” “create,” “predict,” “project,” “seek,” “ongoing,” “increases” or “continue” and variations or similar expressions. These statements are based upon the current expectations and beliefs of management and are subject to numerous assumptions, risks and uncertainties that change over time and could cause actual results to differ materially from those described in the forward-looking statements. These assumptions, risks and uncertainties include, but are not limited to, assumptions, risks and uncertainties discussed in the most recent Annual Report on Form 10-K and Quarterly Report on Form 10-Q for each of ETE, Energy Transfer Partners, L.P. (“ETP”), Sunoco Logistics Partners L.P. (“SXL”), Sunoco LP (“SUN”), The Williams Companies, Inc. (“WMB” or “Williams”) and Williams Partners L.P. (“WPZ”) filed with the U.S. Securities and Exchange Commission (the “SEC”) and assumptions, risks and uncertainties relating to the proposed transaction, as detailed from time to time in ETE’s, ETP’s, SXL’s, SUN’s, WMB’s and WPZ’s filings with the SEC, which factors are incorporated herein by reference. Important factors that could cause actual results to differ materially from the forward-looking statements we make in this communication are set forth in other reports or documents that ETE, ETP, SXL, SUN, WMB and WPZ file from time to time with the SEC include, but are not limited to: (1) the ultimate outcome of any business combination transaction between ETE and Energy Transfer Corp LP (ETC) and Williams; (2) the ultimate outcome and results of integrating the operations of ETE and Williams, the ultimate outcome of ETE’s operating strategy applied to Williams and the ultimate ability to realize cost savings and synergies; (3) the effects of the business combination transaction of ETE, ETC and Williams, including the combined company’s future financial condition, operating results, strategy and plans; (4) the ability to obtain required regulatory approvals and meet other closing conditions to the transaction, including approval under HSR and Williams stockholder approval, on a timely basis or at all; (5) the reaction of the companies’ stockholders, customers, employees and counterparties to the proposed transaction; (6) diversion of management time on transaction-related issues; (7) unpredictable economic conditions in the United States and other markets, including fluctuations in the market price of ETE common units and ETC common shares; (8) the ability to obtain the intended tax treatment in connection with the issuance of ETC common shares to Williams stockholders; and (9) the ability to maintain Williams’, WPZ’s, ETP’s, SXL’s and SUN’s current credit ratings. All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by this cautionary statement. Readers are cautioned not to place undue reliance on any of these forward-looking statements. These forward-looking statements speak only as of the date hereof. Neither ETE nor WMB undertakes no obligation to update any of these forward-looking statements to reflect events or circumstances after the date of this communication or to reflect actual outcomes.
Additional Information
This communication does not constitute an offer to buy or solicitation of an offer to sell any securities, nor shall there be any sale of securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction. No offering of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the U.S. Securities Act of 1933, as amended. This communication relates to the entry by ETE and Williams into definitive agreements for a combination of the two companies. In furtherance of this proposal and subject to future developments, ETE, ETC and Williams may file one or more registration statements, proxy statements or other documents with the SEC. This communication is not a substitute for any proxy statement, registration statement, prospectus or other document ETE, ETC or Williams may file with the SEC in connection with the proposed transaction. INVESTORS AND SECURITY HOLDERS OF ETE AND WILLIAMS ARE URGED TO READ THE PROXY STATEMENT(S), REGISTRATION STATEMENT, PROSPECTUS AND OTHER DOCUMENTS FILED WITH THE SEC CAREFULLY IN THEIR ENTIRETY IF AND WHEN THEY BECOME AVAILABLE AS THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED BUSINESS COMBINATION TRANSACTION. Any definitive proxy statement(s) (if and when available) will be mailed to stockholders of Williams. Investors and security holders will be able to obtain free copies of these documents (if and when available) and other documents filed with the SEC by ETE, ETC and Williams through the web site maintained by the SEC at http://www.sec.gov. Copies of the documents filed by ETE and ETC with the SEC will be available free of charge on ETE’s website at www.energytransfer.com or by contacting Investor Relations at 214-981-0700 and copies of the documents filed by Williams with the SEC will be available on Williams’ website at investor.williams.com.
ETE and its directors, executive officers and other members of management and employees may be deemed to be participants in the solicitation of proxies in respect of the proposed transaction. Information regarding the directors and officers of ETE’s general partner is contained in ETE’s Annual Report on Form 10-K filed with the SEC on March 2, 2015 (as it may be amended from time to time). Additional information regarding the interests of such potential participants will be included in the proxy statement/prospectus and other relevant documents filed with the SEC if and when they become available. Investors should read the proxy statement/prospectus carefully when it becomes available before making any voting or investment decisions. You may obtain free copies of these documents from ETE using the sources indicated above.
Williams and its directors, executive officers and other members of management and employees may be deemed to be participants in the solicitation of proxies in respect of the proposed transaction. Information regarding the directors and officers of Williams is contained in Williams’ Annual Report on Form 10-K filed with the SEC on February 25, 2015 (as it may be amended from time to time). Additional information regarding the interests of such potential participants will be included in the
22
proxy statement/prospectus and other relevant documents filed with the SEC if and when they become available. Investors should read the proxy statement/prospectus carefully when it becomes available before making any voting or investment decisions. You may obtain free copies of these documents from Williams using the sources indicated above.
Energy Transfer Equity, L.P.
Investor Relations:
Brent Ratliff, 214-981-0795
or
Lyndsay Hannah, 214-840-5477
or
Media Relations:
Granado Communications Group
Vicki Granado, 214-599-8785
mobile: 214-498-9272
or
Brunswick Group
Steve Lipin, 212-333-3810
or
Mark Palmer, 214-254-3790
or
The Williams Companies, Inc.
Investor Relations:
John Porter, 918-573-0797
or
Brett Krieg, 918-573-4614
or
Media Relations:
Lance Latham, 918-573-9675
or
Joele Frank, Wilkinson Brimmer Katcher
Dan Katcher, Andrew Siegel or Dan Moore, 212-355-4449
23