Energy Transfer LP (ET) 2015 Q2 法說會逐字稿

Greetings, and welcome to the Energy Transfer second-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. Thank you, Mr. Long, you may now begin.

Thank you, operator. Good morning, everyone, and welcome to Energy Transfer Partners and Energy Transfer Equity second-quarter 2015 earnings call. And thank you for joining us today. I will be providing comments for Energy Transfer Partners, and then hand the meeting over to Jamie Welch, who will discuss Energy Transfer Equity's second-quarter earnings and other highlights at ETE.

I'm also joined today by Kelcy Warren, Mackie McCrea, John McReynolds, and other members of our senior management team who are here to help answer your questions after our prepared remarks.

Not surprisingly, we had an extremely active second quarter. I will begin with discussing our second-quarter results, followed by recent developments, new growth initiatives, a financing and liquidity update, and concluding with a distribution discussion and a brief Regency integration update.

As 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 will also refer to adjusted EBITDA and distributable cash flow, or DCF, both of which are non-GAAP financial measures. You will find a reconciliation of our non-GAAP measures on our website.

Now for our Q2 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. ETP had a very good quarter overall. Adjusted EBITDA on a consolidated ETP basis totaled $1.49 billion, which is up $95 million compared to the second quarter of 2014. DCF attributable to ETP Partners, as adjusted, totaled $894 million, an increase of $149 million from a year ago.

Now let's go over the individual segment results. In the Midstream segment, significantly higher volumes drove adjusted EBITDA higher by $20 million, to $376 million, compared to the same period a year ago. This increase was primarily driven by an increase in fee-based revenues related to higher throughput from assets recently placed in service in the Eagle Ford, Permian, and Cotton Valley, as well as the acquisition of Eagle Rock's midstream business, partially offset by higher operating expenses from these new assets.

Gathered gas volumes on the ETP system totaled over 10 million MMBtus per day, which is up 25% versus the same period last year. NGLs produced and Equity NGLs continued to increase in the second quarter. ETP production was up 107,000 barrels per day, to almost 400,000 barrels per day, compared to the second quarter of 2014.

In the Liquids Transportation and Services segment, adjusted EBITDA increased by $10 million, to $151 million, compared to the same period last year. The increase in adjusted EBITDA was due to margin increases on Lone Star fractionators and pipelines, which were partially offset by lower realized marketing gains related to the accounting treatment of our physical storage position, which revenue benefit is expected to be realized by the end of this year.

NGL transportation volumes on our wholly owned and joint venture pipelines increased from a year ago by nearly 115,000 barrels a day. This was in large part due to increased volumes out of West Texas, as producers ramped up volumes. The remainder of the increase was related to volumes on our NGL pipelines from our plants in Southeast Texas and in the Eagle Ford region. Transportation volumes totaled 482,000 barrels a day in the second quarter. Average daily fractionated volumes increased approximately 63,000 barrels a day from a year ago, to 254,000, due to the ramp-up of our second 100,000-barrel-a-day fractionator at Mont Belvieu, which was commissioned in late 2013.

In our Intrastate segment, adjusted EBITDA declined slightly year over year to $117 million, primarily due to lower retained fuel revenues. However, newly contracted transportation margins remained strong. We expect higher margins to continue, as we see the level of natural gas demand continue to draw supply to the Gulf Coast with the commissioning of new LNG plants, [almost to bonus], and as Mexico increases its natural gas demand from the US. The lower Intrastate production volumes from shippers in the Barnett Shale was partially offset by a ramp-up in volumes related to new long-term Intrastate transportation contracts. These new fee-based volumes will ramp up into 2016.

In our Interstate segment, adjusted EBITDA decreased about $6 million, to $285 million, from a year ago, primarily due to the expiration of a transportation rate schedule on Transwestern Pipeline. Transported volumes were up approximately 128,000 MMBtus per day due to increased throughput on Tiger and Transwestern Pipelines.

Moving to Sunoco Logistics, SXL had its best financial quarter ever, generating $326 million of adjusted EBITDA, which is a $46-million increase compared with last year's second quarter. This mainly reflects higher results from terminal facilities, as well as increased products, pipeline, and throughput volume, and higher average pipeline revenue, partially offset by lower crude oil pipeline results.

The Retail Marketing segment contributed $140 million of adjusted EBITDA for the second quarter, which includes approximately $56 million from Sunoco LP and $84 million from the remaining retail marketing and fuel distribution assets we plan to dropdown to Sunoco LP by the end of 2016.

Merchandise sales more than tripled. And fuel volumes sold grew more than 30% as compared with last year's second quarter. This is in large part due to the Susser acquisition at the end of August 2014, along with the Aloha and Tiger Mart acquisitions.

Fuel margins were lower versus a year ago, due to the rising crude costs throughout most of the quarter. However, the Retail Marketing business delivered strong same-store sales growth in all of our markets, with Stripes up over 3%, and all other regions well above 5%.

For the All Other, adjusted EBITDA increased $28 million, to $93 million, versus a year ago, which was primarily due to higher earnings driven by stronger refining crack spreads from our investment in PES.

We had a couple of significant transactions with our affiliated Partnerships over the last three weeks. First of all, on July 31, we closed on our previously announced dropdown of 100% of Susser Holdings Corporation to Sunoco LP in a transaction valued at $1.93 billion. Sun paid ETP approximately $997 million in cash, including certain working capital adjustments, and issued to ETP 22 million Sun units valued at $967 million.

In addition, there was an exchange of 11 million Sun units owned by Susser Holdings for another 11 million new Sun units to a subsidiary of ETP. Just a quick reminder that Susser Holdings' assets consist primarily of approximately 680 Stripes-branded convenient stores that sell motor fuel and merchandise in Texas, Oklahoma, and New Mexico.

We see several strong positives to ETP in this dropdown, including the transaction being immediately accretive to us in 2015 and beyond. The almost $1 billion of upfront cash will help fund our robust CapEx program, which allows us to avoid a like amount of equity issuances. We acquired Sun units with tremendous confidence in their ability to create additional value through future growth. We intend to drop all of the remaining wholesale distribution and retail marking assets of Sunoco Inc. to Sunoco LP by the end of 2016.

In another transaction announced in July, ETP and Energy Transfer Equity announced the exchange of 21 million ETP common units currently owned by ETE for 100% of the General Partner interest and incentive distribution rights of Sun. In addition, as part of the transaction, ETE has agreed to provide ETP a $35-million annual IDR subsidy for two years.

Just like the dropdown just discussed, we see strong positives to ETP. The transaction reduces ETP's common unit count by almost 5%, and has a commensurate reduction in the amount of distributions to be paid with respect to the IDRs. The bottom line is that ETP benefits from significant cash flow accretion, which will continue to support ETP's attractive distribution growth going forward.

Following the close of this exchange, Sun will no longer be consolidated for accounting purposes by ETP, but, instead, will appear in the consolidated financial statements for ETE. Jamie will discuss the benefits of the exchange to ETE later in the call.

Now let's move to project updates, starting with Delaware Basin Crude Gathering Pipeline we announced yesterday and the Revolution and Bayou Bridge Projects that we touched on in the last earnings call, but since have provided more detail.

The Delaware Basin Crude Gathering Pipeline, when completed, will consist of three separate gathering systems with an aggregate of approximately 130 miles of pipe. The gathering systems, which will have approximately 120,000 barrels per day of crude oil capacity, will deliver crude oil into SXL Delaware Basin Extension. The pipeline is projected to be in service in the first half of 2016.

ETP, through its affiliate ETP Crude, has commenced an open season for the pipeline. This is yet another example of the Energy Transfer family leveraging synergies between our various strategic entities.

For the Revolution project, we will be constructing approximately 100 miles of 20-inch to 30-inch pipeline, providing total gathering system capacity in excess of 440 million cubic feet per day. The Revolution Pipeline will originate in Butler County, Pennsylvania, and will extend to our new cryogenic gas processing plant in Western Pennsylvania. In addition, this project includes a fractionation facility that will be constructed at SXL's Marcus Hook Industrial Complex.

We are continuing to finalize additional contracts with a number of producers in the area. In light of the lower commodity prices, producers are not only interested in a competitive fee to gather and process their volumes, but are also very much focused on the highest price that they can achieve for their residue gas volumes and for their liquids. Our project provides them with a unique end-to-end solution, with significantly improved netback economics compared to their other alternatives.

This is an exciting project for us, as it increases our presence in the Marcellus and Upper Devonian production areas of Western Pennsylvania, and is another example of asset optimization within the Energy Transfer family of Partnerships. The residue gas from the Revolution plant will be delivered into our Rover Interstate Pipeline for deliveries to downstream markets. And the natural gas liquids will be delivered to SXL's Mariner East Pipeline system for delivery to domestic and export markets.

The Revolution pipeline and plant, as well as the fractionation facility, are expected to be in service in the second quarter of 2017 and will no doubt serve as a gathering and processing growth vehicle for us in the Northeast, where we fully intend to expand our operations, bringing strong BCF growth to ETP for years to come.

Now moving to Bayou Bridge, we have expressed our optimism over the past several months that Bayou Bridge would move from a potential project to a project that is off and running. As you hopefully saw last week in the press release issued by ETP, SXL, and P 66, the three companies have formed a joint venture to construct the Bayou Bridge Pipeline, which will deliver crude oil from the SXL and P 66 terminals in Nederland, Texas, to Lake Charles, Louisiana. The joint venture will also launch an expansion open season this quarter for service to the market hub in St. James, Louisiana.

Construction is underway on the Nederland-to-Lake-Charles segment of the pipeline, which will be 30 inches in diameter, and is expected to begin commercial operations in the first quarter of 2016. The results of the expansion open season will determine the size of the pipeline segment to St. James, which has a forecasted in-service date of the second half of 2017. Bayou Bridge is undoubtedly a natural fit with the Bakken Pipeline project, which will provide shippers from the Bakken area multiple delivery options, including moving barrels to Nederland, Texas.

On last quarter's call we provided a bit more detailed updates on other projects. In the interest of time, and noting each project is moving forward as planned, we will simply touch on them briefly today.

Starting first with the Bakken Pipeline. As previously mentioned, our project scope provides for aggregate takeaway capacity out of North Dakota of approximately 470,000 barrels per day. We remain in active discussions with multiple parties about additional commitments, which would move us toward our ultimate target of 570,000 barrels per day.

We are currently in the process of obtaining the necessary permits and regulatory authorizations for the project. The current regulatory timetables for the applicable state agencies have the authorizations coming in late 2015 or early 2016, providing us with sufficient time to construct the project in accordance with our anticipated completion schedule. We continue to plan for an in-service date by the end of 2016.

For the Rover gas pipeline, pending regulatory approvals, the 3.25-BCF-a-day Rover interstate gas pipeline is expected to be in service from the Marcellus and Utica production areas to the Midwest Hub near Defiance, Ohio, by the end of 2016. And from the Midwest Hub to markets in Michigan and the Union Gas Dawn Hub by mid-2017. We expect to receive the draft environmental impact statement from the FERC by the end of the month, and expect our FERC authorization in 1Q of 2016.

As to Lone Star's Frac III, a 100,000-barrel-a-day facility, remains on schedule to be in service by January 2016. And Frac IV, a 120,000-barrel-a-day facility, remains on schedule to be in service by December 2016. Both fractionators are fully subscribed by long-term, fee-based contracts.

As to the Lone Star Express NGL pipeline, the 533-mile natural gas liquids pipeline from the Permian Basin to Mont Belvieu remains on schedule to be in service by the third quarter of 2016. And the conversion of the existing West Texas 12-inch NGL pipeline into a crude oil/condensate line remains on schedule to be completed in the first quarter of 2017.

The Trans-Pecos and Comanche Trail pipelines, which will expand our intrastate pipeline capacity by approximately 2.5 billion cubic feet per day to carry gas from the Permian Basin into Mexico, are expected to be in service in the first quarter of 2017. We will have a 16% equity ownership interest and manage the construction, as well as operate the header in both pipelines. This project is in partnership with Carso Energy and MasTec.

The REM II plant, also known as Kennedy II plant, is now in service. In addition, the in-service date for both the 24-inch Volunteer Pipeline and the East Texas Plant, also known as the Alamo Plant, remains the fourth quarter of this year. These two 200 million-cubic-foot-per-day cryo plants, coupled with the King Ranch Plant that we acquired at the end of March, expands our South and Southeast Texas processing capacity from about 1.4 BCF per day to approximately 2.4 BCF per day.

In the Northeast, construction of the 2.1 BCF-per-day Utica Ohio River expansion continues, and Phase 1 is expected to be in service in Q3 of 2015. And Phase 2 and the Harrison County lateral are expected to be on line by year end.

As we mentioned on our first-quarter call, the 200 million-cubic-foot-per-day Mi Vida Plant in the Permian is on line, as well as the 200 million-cubic-foot-per-day Dubberly processing plant and related NGL pipeline in North Louisiana. Volumes continue to grow on both assets and are exceeding our expectations.

Now, moving into our CapEx discussion, ETP invested over $1.4 billion during the second quarter in growth capital projects, with the majority allocated to our Liquids Transportation and Services -- Midstream, as well as the Interstate segments. For the six months ended June 30, ETP has now invested more than $3 billion in growth CapEx projects in 2015. When you include our indirect growth capital expenditures at SXL and Sunoco LP, Q2 consolidated growth CapEx was approximately $2 billion. And for the six months ending June 30, 2015, it was more than $4 billion.

We're now forecasting full-year 2015 CapEx for ETP to be in the range of $5.4 billion to $5.8 billion. This includes Bayou Bridge. This is down approximately $200 million, primarily due to the expected timing of the CapEx spend. With Bayou Bridge Pipeline, SXL's CapEx is expected to be between $2.4 billion to $2.6 billion.

Before moving on to discuss our distribution, let's take a quick look at ETP's liquidity position. We were very active in Q2. We ended the quarter with a debt-to-EBITDA ratio of 4.5 times per our credit facility. Subsequent to the Regency merger, ETP has undertaken a series of liability management steps, including: first, the repayment of $2.3 billion under Regency's credit facility, and cancellation of the facility upon closing of the Regency merger; second, the redemption in June 2015 of all the outstanding $499-million aggregate principal amount of legacy EROC 8 3/8% senior notes due 2019; third, in June of 2015, we issued $3-billion aggregate principal amount of ETP senior notes, with coupons ranging from 2 1/2% to 6 1/8%, and maturities ranging from 2018 to 2045; and lastly, in July, we issued calls on the $390 million of 8 3/8% notes, and on the $400 million of 6 1/2% notes. These will be fully retired on August 13. We also issued approximately $590 million of equity during the second quarter of 2015 under our ATM and [RIP] programs.

Now I would like to touch on our recent distribution announcement. Last week, we were pleased to announce the eighth-straight quarterly distribution increase for ETP, to $1.035 per unit, or $4.14 per unit on an annualized basis. This represents a distribution increase of $0.32 per common unit on an annualized basis, or 8.4%, compared to the second quarter of 2014. And it will be paid on August 14 to unitholders of record as of the close of business today.

We feel very pleased to be able to share with our unitholders the benefits of our diversified business model, the synergies from our Regency merger, and the growth projects that we've been investing in. For ETP, DCF coverage ratio was 1.03 times. Since Q2 is typically a shoulder period for the sector, we think this is a tremendous achievement, given the backdrop of the current commodity price environment.

As we mentioned on our first-quarter call, we closed the Regency merger on April 30. As a result of the great work done by the employees at both ETP and Regency, the integration has continued to surpass our internal expectations. We have started realizing G&A and interest expense savings related to some of the liability management steps that I mentioned earlier.

We also anticipate a significant amount of commercial synergies, including opportunities related to, for example, the complementary nature of Regency's Marcellus and Utica assets with ETP's PEPL, Trunkline, and Rover Pipelines; the potential to capitalize on ETP's broadband capabilities with SXL Mariner East and West franchise, and the existing Mariner South NGL export model at Marcus Hook; also, increased NGL production and volumes to further support Lone Star's Frac III and IV at Mont Belvieu, and potentially create additional export opportunities for the Mariner South JV with SXL; also, crude oil partnership opportunities with SXL, like the Delaware Basin Crude Oil Gathering Pipeline project we announced yesterday; and opportunities to utilize available processing in South Texas once legacy RGP third-party processing contracts roll off.

We remain confident that the benefits we expect to realize from the merger will be reflected in new opportunities in the future. With that, I'll turn the call over to Jamie, who will walk through ETE's results.

Thank you, Tom. Good morning, everybody. We will first discuss the ETP/ETE Sun GP IDR exchange that Tom alluded to earlier in the call, then provide a liquidity financing update, then a brief update on Lake Charles LNG, to be followed by second-quarter results, before concluding our prepared remarks with an update on ETE's proposal for Williams. We'll then take your questions.

We were pleased with second-quarter results for SXL and ETP. As Tom mentioned, SXL had its strongest quarter ever, as a result of project start-ups and increased volumes, which continues to demonstrate the strength and resilience of that business. ETP had a solid overall performance for the quarter from all segments, including Midstream.

We're very pleased with the progress made to date on the integration of ETP and Regency, which has exceeded our expectations and is a testament to the hard work of all of our employees. Tom has already gone over the details for the ETP/ETE Sun GP IDR exchange, as well as the strong benefits to ETP the transaction provides. So I will just summarize the rationale for ETE.

The exchange is expected to be accretive in 2017 and beyond, whilst it is modestly dilutive to ETE's DCF for the balance of 2015 and 2016. The transaction reinforces ETE's clearly articulated strategy to become a traditional GP within the Energy Transfer family. We are confident that Sun GP will continue to grow in value. That said, the increasing cash flow and value in the underlying Sun GP creates incremental upside to ETE.

Along the same lines, ETE will benefit from third-party growth at Sun. And it is our intent to focus even more on third-party accretive growth, since the dropdowns will be completed by year-end 2016. And finally, we expect continued upside from ETP IDRs, as ETP provides even higher future distribution growth.

So now let's look at liquidity and financing. ETE continues to have a very healthy liquidity position. We ended the quarter with a debt-to-EBITDA ratio of 2.93 times per our credit facility. In May, we issued 1 billion of senior notes at 5 1/2% that are due June 2027. And just a quick reminder that we amended ETE's revolving credit facility to increase the capacity to $1.5 billion, which does give us additional financial flexibility.

As of June 30, 2015, there were $230 million in outstanding borrowings under that facility. Therefore, at the end of quarter-two 2015, the overall ETE stand-alone debt was $5.75 billion, with a blended interest rate of 5.12%, and with no pending maturities until almost 2019. With a strong distribution coverage of 1.19 times that we opted to maintain for quarter two, this continues to allow us to drive value creation for ETE holders in the future.

The additional cash on hand and balance sheet strength has allowed us to commence our $2-billion buyback program. And during the quarter of -- the second quarter of 2015, we repurchased approximately $294 million of ETE common units. We will, of course, continue to be opportunistic in our continued purchases, depending on price and trading performance of ETE common units. Clearly, we are well positioned for even stronger distribution growth going forward, and we have a lot of optionality in where and how we drive value for our unitholders.

Now turning to Lake Charles, which, to remind people, is owned 60% by ETE and 40% by ETP, progress continued to be made during the second quarter. We have purchased the additional land from Alcoa that is needed for the project. In response to the draft environmental impact statement received April 10 from FERC for Lake Charles LNG and the expansion of the Trunkline Interstate Pipeline, we have filed the additional data and information request required thereunder. We expect to receive the final environmental impact statement from FERC next week on August 14. The next milestone after that will be the FERC authorization that we would expect to receive by October. At that time, we intend to launch our debt financing for this project.

We have also continued our work with a short list of EPC contractors as we continue to refine the cost structure for the project. With the expected emphasis on capital discipline and overall cost, we continue to believe that Lake Charles LNG is one of the most attractive pre-FID projects for both Shell and BG, and that, as a result, we remain on target to sanction FID of this project in 2016.

Turning now to the financial results, as a reminder, ETE's cash flows now come from the General Partner and IDR and LP interest at ETP, which now includes Regency; 90% of the economics of the GP and the IDRs from SXL through the Class H units; and through the ownership of Lake Charles LNG. However, beginning next quarter, ETE cash flows will also come from the GP and IDRs of Sun. ETE will also consolidate Sun's results directly, rather than through ETP, which has been the case to date. Our distributable cash flow as adjusted for the second quarter totaled $335 million, or $0.31 per unit, an increase of $117 million, or 54%, compared to the second quarter of 2014. Distributions from ETP accounted for 74% of ETE's total cash flow in the latest quarter. SXL contributed 15%, and Lake Charles, approximately 11%.

Before talking about the distribution increase, let me please remind you that we completed our two-for-one unit split after the market closed on July 24. With the unit split completed, therefore doubling the number of ETE units outstanding, the Partnership's distributions going forward, including for this second quarter, will reflect this split, and therefore be paid on a post-split basis.

ETE announced last month the 11th consecutive increase in its quarterly distribution, to $0.53 per unit on a pre-split basis, or $0.265 on a post-split basis. Annualized, this equates to $2.12 per unit pre-split, or $1.06 on a post-split basis.

Our distributable cash flow coverage ratio, as I mentioned earlier, was 1.19 times for the second quarter. The quarterly cash distribution represents a 39% increase in distribution per unit compared to a year ago. It will be paid on August 19 to unitholders of record as of the close of business today.

Williams update. As had been highlighted in the media, we formally entered Williams' strategic alternatives process. We were very impressed with the Williams team, and found there to be very good chemistry between our teams when we met.

We continue to believe in our ability to create significant value from this combination for all stakeholders. In fact, we remain very excited by the commercial and revenue synergy opportunities from this combination, and believe that the magnitude of such opportunities will exceed what has been mentioned in various research reports.

Overall timing will be driven by the Williams Board and their strategic alternatives process. Respecting the confidentiality and integrity of this process, we will not respond to questions on the Williams process on today's call. We do understand people's interest and desire for information. But at this point, we can do no more than reaffirm our excitement about this transaction and the compelling strategic benefits of the proposed combination.

So before opening the call to your questions, I would like to just say that some incredibly exciting things are continuing across the Energy Transfer family that we believe will build strong value for our unitholders. We continue to be very proud of our overall financial performance. We have continued our distribution increases, and we expect to be able to maintain these level of increases through this challenging cycle. We now see the clear benefits of our diversified business model, which has the most strategic and financial optionality in the industry.

Our overall growth capital program remains without peer. Our projects are contracted with demand fees, and every project in our current $22-billion backlog is actively moving forward. This growth plan sees ETP and SXL being set up for another period of transformation and even higher distribution growth from 2017 onwards.

Our franchise is unique. We are different from our peers. And, as such, we can continue to grow in the current commodity price environment. We appreciate the continued support of our customers and our investors, and we appreciate the hard work of our employees, who have contributed to this strong overall Group performance.

Operator, that concludes our prepared remarks. Please open the line for questions.

(Operator Instructions)

Our first question is from Brandon Blossman of Tudor, Pickering, Holt. Please go ahead.

Good morning, guys.

Hey, Brandon.

Jamie, this may be off limits, but I will try anyway. Any update on the timing for the creation of the ETP/Equity SEC filings, or otherwise?

It's a good question, Brandon. I think in all fairness, it is so wrapped up right now as we -- on the whole Williams side, we want to see the realization of that process. And then we will go from there.

All right, fair enough, and probably as expected. How about this? Conceptually, or philosophically, share repurchases versus share count and longer-term distribution growth -- how does that thought process work, particularly in light of the sector performance recently?

Look, I would say, from just a traditional buyback standpoint, looking at obviously the cost of your debt capital to support a buyback versus the embedded cost -- the yield that you are buying back the units at, it's pretty much a push. In fact, I would say it's probably near-term slightly dilutive to our current cost of debt capital, given somewhat of a move in rates -- but obviously much longer-term benefit.

We, of course, have such ample amount of distributable cash flow right now, that we've got this flexibility to think about the levers. So it's just something that we sit down, we run through a bunch of math between Kelcy and myself, he then calls the play on what we want to end up doing. But we do look at it on the basis of there is a trade-off, near term versus longer term, and we've got to manage that.

Okay, fair enough. And then really quickly, Charles, can you give some color on where you are in terms of understanding exactly what the EPC cost will be here? And then just directionally, have you been surprised with the outcome over the last six to nine months?

Look, I think we originally said last year when we did the November 18 presentation that we thought it was, all-in costs, including contingency, were slightly over $9 billion. As one would expect with obviously a slowdown in overall infrastructure spending in a lot of the large energy-related projects now being either shifted to the right, or in fact, frozen out entirely, we're seeing some significant concessions as it relates to labor and costs.

We're seeing that also in a lot of our ETP projects, where we're seeing some net benefit as well. So it's hard to say exactly what the percentage decline will be relative to our original -- versus our expectation last November. But it will be meaningful. And since we earn a rate of return on whatever that amount is, that will obviously, we see, translate into net benefit to Shell BG.

Great, perfect color. Thank you Jamie, and I'll jump into the queue at the end. Thanks.

Thank you.

The next question is from John Edwards of Credit Suisse. Please go ahead.

Good morning. Can you hear me?

We can, John.

Jamie, in light of some of the comments that are made by some of your peers regarding overbuild, as it will, and you seem pretty bullish on all your projects. Maybe if you'd give us a little bit of your insight on what you are seeing in terms of the areas you are developing? Are you seeing that kind of thing, or is it just isolated to certain areas?

Just so we understand the question, the question is, are we seeing any concern about over-building in any of the regions in which we serve?

Yes.

I will let Kelcy and Mackie answer certainly some elements of that. I want to say, by and large, I mean, we listened to Mike Hennigan's call earlier. Our projects -- when you have a philosophy that says you need this thing to be -- any project that we go forward with needs to be close to 90%-plus completely demand fee-based, with very little commodity element retained fuel revenues or anything else to basically run an IRR that allows us to determine whether in fact to move forward with a project. We are in the very early innings of pretty much most of our projects. And that gives us tremendous runway benefit over the next almost decade as we look out across.

As we continue to see new opportunities come, we come with the same philosophy, right? We are very much, as you have seen with Rover, with our 15-year, 20-year contracts, right, Mackie? I mean, this is the way we run.

Really to reiterate what Jamie said, it doesn't really matter on the base project that we build, because we have accretive projects with, as Jamie said, with demand charges. So really, where we're limited is the upside on the overview on any additional volumes on any capacity we may have on an IT basis. But fortunately, the way we focused over the years, and especially on these bigger projects, are, they're 100% demand-based projects with guaranteed returns.

John, this is Kelcy. Let me add to that. The pipeline business will overbuild until the end of time. That's what competitive people do. We've done it; others have done it around us. And then you find yourself -- you must scavenge a product from others when you see volume decline.

How do you do that? Well, you provide more services than your peers do. You provide more optionality. So this is something we will always live through.

But I'll tell you, people that give guidance and then turn around and have a bad financial reporting period, and then throw all of us under the bus, they say by the way, don't focus on us; focus on the industry, this is an industry problem. That gets a little frustrating for me.

Okay, that's helpful. And I'll just keep it to the one more question. In terms of -- I put the same question to Mike Hannigan. In terms of your overall opportunity set, looking forward, are you seeing it now about the same, say, as the quarter back? Or do you see it actually continuing to increase a bit? Or do you see it falling off a bit?

John, this is Mackie. We're really going the opposite way -- some comments that Kelcy just alluded to. If you line up our projects, it is beyond belief what upstream synergistic value we have with any projects we announce.

For example, we announced just a moment ago, or mentioned just a moment ago from Tom, that our West Texas -- our CFU projects out in West Texas delivering gas to New Mexico, we only have 16% ownership. But we will be the operator, both commercially and operationally. What we see on those projects is significant upstream revenue opportunities on our extensive intrastate and interstate pipeline networks. So not only do we have great projects, but we have significant revenue that we will definitely play a part in, that has not even been recognized yet.

And then if you move around the country and you go to the Northeast with our Regency acquisition, there's a significant fit right off the bat with the Utica Ohio -- 36 inches coming online this year, to deliver additional volumes into Rover, to make it even a better project.

And then you look at all the projects and processing plants that we're building out in West Texas and the additional revenue volumes into our intra and interstate pipelines, and the additional liquid volumes into our Lone Star facility.

So we couldn't feel better about how we're set up, both on the projects that we're building, and the synergistic revenues related to those projects that we haven't even recognized yet in any of our economics.

Okay, thank you very much. I appreciate the color.

The next question is from Michael Blum of Wells Fargo. Please go ahead.

Thanks, good morning. I am wondering if on Lake Charles LNG -- you talked about FID in 2016. Can you put a finer date on that, a rough date? And then talk about when would be the sequence of a potential equity component to the financing?

Sure, Michael, we would love to put a finer date on it, if we actually could. We do have this little merger between our counter-party right now that's going on. I think we are just trying to calibrate when, in fact, that is likely to close. I think in all fairness, given this, will require the sanctioning of our expectation right now, the Shell Board.

There's a period of time post the closing of that merger that they will need to, in fact, be fully -- well, they will be fully informed. But they'll have the opportunity to make sure that their people in fact reaffirm everything they've been told, and they have obviously looked at and evaluated.

So I imagine it will take 60-plus days, maybe 60 to 90 days after they close. I think at its earliest, it would be quarter two. And at its latest, I think it's probably the beginning of quarter three. So it's really in that straddle period. Because otherwise, from a timing construction timetable standpoint, they lose -- there's a slippage of too much time.

Your other question around equity -- as we've always said, there is no equity coming into Lake Charles from either ETP or ETE. Any external equity requirements needed to finance the project will be sourced from third-party sources. So we'll give them a piece of the future cash flow when the project comes on-line. So hopefully, that is at least clearer now, as to the overall sources and uses and requirements.

Okay, thank you. And then on Revolution, do you have any updates on further commitments beyond the anchor shipper?

No, we don't, Michael, at this time. However, we're very optimistic that we will be making announcements in the fairly near future about potentially expanding that project. But in the meantime, that project couldn't be going better, from a construction perspective, from a cost perspective. And we're very confident that we will not only add to that project, but also add to the Mariner East expansion projects.

Okay, great, thank you.

The next question is from Jeremy Tonet of JPMorgan. Please go ahead.

Good morning.

Hey, Jeremy.

Congratulations on the strong quarter there. Great to see. I was just wondering, Kelcy, if you could provide some thoughts for us -- ETE hasn't been immune from the weakness in the space. But still it seems like the currency has held up much stronger than other peers out there. The Williams process is obviously a very large initiative. But would ETE look at this period of weakness as a chance to acquire other GP peers that have fallen on harder times?

Jeremy, absolutely. At any given time, we have multiple models that we are analyzing. Not to suggest that we're preying on the weak, but there's some assets that fit us very well, that we believe, consolidated into the Energy Transfer family, would make more money. And that's just reality. Mackey's point he made a minute ago -- projects in certain areas feed other distributable cash flow of other assets. And that we've worked very hard to create this, and we're not done, by a long stretch. So to answer your question, absolutely, we are modeling a lot of consolidation at this time.

That's great to hear. And I think at points in time, there has maybe been some concern in the marketplace as far as ETP and equity needs are concerned. By our math, given the recent transactions that have been done within the family, it feels like those needs could be quite modest, especially given PES and the potential there. I was wondering if you could share any thoughts on that?

Yes, Jeremy, this is Tom Long. And you're exactly right. I think you stated that very well. We clearly have taken a lot of steps here to be able to fund the CapEx program that we have out in front of us. I mean, as you look at our balance sheet today, as far as our credit facility, no balance drawn on that. You heard me talk about the leverage with where we are, which -- the rating agencies are very comfortable. And then you saw what we really pushed out with the ATM program, the $493 million during the second quarter.

So as you look out, you look at the continued drop potential with Sun, and you look at, like I said, the various options we have. And we are sitting with that cash on our balance sheet right now also, from the announcement with the Sun -- with the transaction with the Sun that we just closed on July 31. So you can see that we do have a lot of flexibility here, from that standpoint, not to have to put pressure on our equity side of our capital raise.

Great. That's it for me. Thank you.

Thanks, Jeremy.

The next question is from Darren Horowitz of Raymond James. Please go ahead.

Hey, guys, good morning. Mackie, quick question for you on that Bakken line. You all had mentioned that it was at 470,000. I know you want to get to 570,000. I'm just curious, with what's going on regarding regional differentials, what are you hearing from producers with regard to committing volumes? Is it just specifically an economic netback issue? Or is it a situation where they're not necessarily going to commit necessarily to the duration? Or maybe a mix of both? Or is it just purely based on reduced CapEx through the drill bit?

Darren, the way answer I'd answer that is that certainly the fall and the collapse in oil prices has slowed down the interest of potential shippers to jump onboard to 10- or 15-year contracts. However, we are continuing to have significant dialog. We do expect to increase the commitments on that project.

And with our announcement of the Bayou Bridge project, even enhanced and probably made that much more likely, sooner. Because of the access not only to the SXL Nederland Terminal, but also to the St. James and Lake Charles markets, which are some of the biggest refining markets in the world. So we will be diligent. We'll remain working very hard to fill that capacity. However, it's a fantastic project if we don't sell another barrel.

Okay. And then if I could just jump back to Revolution for a minute, as you talked about with that Utica Ohio 36 feet in gas into Rover, and obviously the benefits of liquid going into the Mariner projects. And I recognize that, like you said, you guys are hoping to talk about expanding that project pretty soon.

But it seems like the line -- at least that 100-mile line -- could maybe be 30, if not a little bit bigger. And it sounds like the line that could be going to the cryo plant in Western Pennsylvania could possibly be a little bit bigger. So is it possible at this point to put a rough estimate on ultimately where you think CapEx for the aggregate project could be?

No. As busy as we are up there -- we have two major focus areas on our midstream United States of course, Permian and the Delaware Basin, and Marcellus and Utica. We, of course, can't talk on this call or publicly of all the things that we have going on, but we have huge aspirations for growth in the Northeast. It would be hard to even guess a number. But we're very optimistic of the projects we announced, building those projects out, adding to those projects, and expanding our footprint up in one of the biggest shales in the country.

Okay and then last question from me, Jamie, more of a housekeeping question on the synergy side pro forma of the Regency integration. You guys had talked about re-occurring annual synergies of $160 million to $225 million a year. I think at last quarter, when that was discussed, a lot of that was commercial and operational.

And to Tom's comments earlier about redeeming that legacy Eagle Rock debt, there is obviously, at least the way we look at it, significant financial synergies. So I'm just curious. In total, is that still the target? Or has any widening of bond spreads out there in the market altered that expectation?

Hey, Darren, I suppose, just to correct you, when we said cost savings, they're actually much more than the real costs. They weren't so much commercial; not a lot of operational. It was actually much more, I want to say, back-office and more consolidation. There was some financial that was in there. There were some assumptions. But I will hand it over to Tom to talk to you about how we feel about the overall range, and where we think we are.

Yes, like I probably mentioned a little bit earlier, the range we've given, we actually feel very good about, as we continue to find more opportunities on the cost side. I will say on the -- I think one part of your question was about, even going forward, some additional opportunities. We did make, of course, a redemption notice on some 8 3/8%s. These were all associated with PVR bonds. As well as some 6.5%s. So that's nearly $800 million of additional redemptions that will be coming in on August 13.

I think you are going to see us continue to stay really active, as far as we look at some of the other indentures out there, as far as some of the other bond issuances, et cetera. I know I'm focusing more on the financing side of it. It's not just the financing that we still see a lot of opportunities, but it's likewise on the cost side, we continue to see more opportunities.

Thank you.

Thanks, Darren.

The next question is from Helen Rue of Barclays. Please go ahead.

Thank you, good morning. Just a couple of questions. I will start with follow-up on Mike Blum's question. Jamie, you mentioned doing a third-party equity on Lake Charles funding. But has your thought changed around whether you would do an ET LNG, a publicly traded NLP, versus going with a private investor?

No, I think what we said back in November, Helen, is that we are open to both. We're just looking from where we can get the best return and what's the most attractive cost of capital. This is not going to be a significant capital raise, from our standpoint, on the equity side. So I suppose we don't have a predisposition one way or the over.

We will have ET LNG. We want that to be a second vehicle, I think, in large part because we want the debt encapsulated in that vehicle. And create some separation of, almost, church and state, if you will, for ETE consolidation purposes.

I think also if we're going grow anything on the LNG side, having that separate vehicle will allow us to do more things going forward. So I think that's certainly first and foremost in our minds. But as we look to raise the capital and how we source that, and from where we source it, we will just look at where we in fact can get the most attractive return.

That's helpful. Then your comments about your projects, that they're all pretty much backed by long-term demand charges and therefore, even with concerns of over-building, you're really not anticipating any of these projects to not go forward. I know that Rover and Bakken, those projects have more than 10-year take-or-pay, with very good counter-party. Could you talk a little bit about other projects like the NGL and crude pipeline out of Permian, your frac projects, what are the terms, duration of those contracts there, and the quality of the counter-party there?

Helen, this is Mackie. Just on the fracs, as we've stated before, when we go to build those fracs, they're fully contracted at somewhere in the neighborhood of 85% demand charges. So regardless of whether the gas shows up or not, those do come from a whole lot of different producers, primarily out in West Texas, and also along the Eagle Ford. We don't have any kind of significant exposure to any one producer to the frac capacity. And in fact, any frac capacity that's available, we can sell it the day that it becomes available. That's how we're set up at Mont Belvieu. Out west, on our new crude system, we haven't announced who our foundation shipper is, and who is the additional shipper that we anticipate signing up. We do have a very strong Company to support that project, and we do have a lot of interest in [your] goal of filling that up project once we complete the open season.

So the crude project is also 10-plus years of take-or-demand charge type of a contract you have?

Yes. Well, it's probably -- a better terminology is true-ups -- volume true-ups. But yes, they are demand charges, guaranteed revenue for the capacity on that project.

And then your comment about the frac project -- it goes up to the Frac IV, about 84%, plus contracted. It applies up to Frac III and IV as well?

Yes. I think the ex III and IV are actually even higher.

Yes, we have three 100,000-day fracs. The fourth one is 120,000-day fracs. All four of them have been sold at 100%, at approximately 85% demand charge.

Okay, great. Then just lastly, your Delaware Crude Gathering Pipeline project that was just announced, just curious about doing this kind of a project at SXL versus ETP. What was the thought process doing it at ETP?

I think Mike Hannigan described it very well on his call this morning. We work together so well, where we have assets, where we can feed both their crude system and also their NGL systems, where we can work together on assets we have, for example, at Mount Belvieu, and connect the dots over to Nederland. So we work together very well, our family of assets, to utilize them in a manner that makes it the most efficient and the best returns we can have for our unitholder.

So is it safe to assume, going forward, crude gathering-type of projects will probably be done at ETP and will probably link into SXL's takeaway or long-haul pipe? Is that how you guys think about dividing projects between the two?

We really don't do that. We look at all the assets we own, we look at re-purposing assets for different types of uses. We look at analyzing what we have and how it might fit into the family of assets -- in this case, into SXL. So no, we don't have any ironclad rules that we do certain things and they'll do certain things. We're separately run Limited Partnerships, and where it makes sense to fuel our assets in one manner, we do it. Same with SXL. Where it makes sense as a team not to, we'll do that.

All right, thank you very much.

Thanks, Helen.

The next question is from Ross Payne of Wells Fargo. Please go ahead.

How are you doing, guys?

Hey, Ross.

Nice quarter there. Also it looks like, on a combined basis, the leverage did tick down, if I combined ETP and Regency last quarter and what happened this quarter. We're calculating about 4.9 times leverage for the quarter. I know you've got 4.5 pro forma for your growth projects. Do you expect to move that gap EBITDA down -- that EBITDA number down over time from the 4.9 level we're seeing today? Or what level of comfort do you have at looking at that number? I know rating agencies may give you some benefit for construction, but historically, they've stuck to debt-to-EBITDA.

Yes, I'll take that, Ross. First starting, when you have the, for example, the $11 billion worth of growth projects we have out in front of us, obviously it's common in all these pressed facilities to be able to have the material project adjustment that occurs here. I will say, and even talking with the rating agencies, what they do in all of our dialogue is, they look at what kind of pro forma adjustments that we put out there, and then they see how we perform against those. And we've done a very good job of hitting all of our numbers. So I feel like we do get a lot of credit for those with the agencies, and that they are very comfortable with where our leverage is right now.

I think the first part of your question was, do you see that gap narrowing a bit? That's a tough one for us to say that you're not going to always have those out there. Just going back to Mackie's comments of the continued projects that we see, and the opportunities we see, I think you are going to see those projects remain out there as you look out. Which is always going to have a gap. And that's the dialogue we have with the agencies. And once again, they're very comfortable with what we see. Our target is to always look at that 4.5 times, so obviously we were very pleased when we saw it tick down a bit to the 4.59.

Then I would like to add that we've got some of the liability management that I went over a little bit earlier, that will continue to bring some of the higher coupon debt back in. So hopefully that answers your question there. But I think as we look out, we feel comfortable with where the balance sheet is, and the funding flexibility that we have.

Okay, thanks so much, Tom.

The next question is from Shneur Gershuni of UBS. Please go ahead.

Hi, good morning, guys. Most of my questions have been asked and answered. I was just wondering if we can just focus on the Regency assets a little bit, and not specifically about the synergies. We've been hearing, as earnings season has progressed, that volumes have surprised many of the processors to the upside. And at the same time, in certain regions, there seem to be contracts that are up for bid that there's some market share changes occurring as well, too. I was wondering if you can talk about the landscape across the legacy Regency footprint? And how you are positioned, given these changing dynamics?

This is Mackie, Shneur. What a great question. The reason it is -- after closing on the Regency, we can't move fast enough to build capacity that's already been contracted. There are hundreds of thousands of acres that are dedicated, that were dedicated to the Regency assets, now ours, both from a gathering and a processing perspective. So we are moving forward as quickly as we can to build a much bigger system in West Texas, the Delaware Basin, to add processing plants. For example, a plant that we're building next to Red Bluff called Orla. We expect to bring that on in the first quarter of 2016. It will be full within 30 days of bringing it on. So the biggest challenge we have with the Regency acquisition is building the assets quick enough to accommodate the volumes that are committed to them.

Cool. All right, thank you very much. Appreciate the color. Good luck today.

Thanks.

Thank you. At this time, I would like to turn the conference back over to Mr. Welch for any closing remarks.

Thank you, everyone, for your time this morning. And we look forward to talking to you next quarter.

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.