Energy Transfer LP (ET) 2011 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Third-Quarter 2011 Energy Transfer Conference Call. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session toward the end of the conference. (Operator Instructions)

I would now like to turn the call over to Mr. Martin Salinas, Chief Financial Officer. Please proceed.

Thanks, Operator, and good morning, everyone. Welcome to the Energy Transfer Q3 2011 Earnings Conference Call, where I'm joined by Kelcy, Mackie, John McReynolds, and other members of our senior management team who are here to answer your questions after I first cover a high-level review of our third-quarter earnings for both ETE and ETP. As well as providing an update on our recently announced contribution of our Propane operations to AmeriGas, as well as our pending Southern Union acquisition, and of course other growth projects that we have recently announced.

I would also encourage you to visit our website where you can access our earnings releases, which were issued yesterday after the market closed.

And as always, I'll make forward-looking statements within the meaning of Section 31E of the SEC Act of 1934, based on our beliefs, as well as certain assumptions and information available to us.

And I'll begin by reviewing ETP's consolidated Q3 2011 results. Our adjusted EBITDA for the quarter was $404.2 million, up approximately 44% from the Q3 of 2010. The increase was largely a result of contributions from FEP and Tiger, plus the acquisition of our Lone Star NGL JV assets, which closed in the second quarter of this year.

And as you recall, Tiger was placed in service December 2010, and the 400 million cubic feet a day expansion was completed in August of this year, while FEP was placed in service in January. Both pipelines have contractual ramp ups of demand fees over the course of the year, which contributed to growth through the end of this year.

Having these pipelines in service has also resulted in us transporting more gas for our customers than ever before, with total volumes approaching 15.5 billion cubic feet a day. That includes the FEP volumes.

We also experienced strong adjusted EBITDA growth in our Midstream segment, which was up over 35% period over period. With more than $1.6 billion of capital committed to new Midstream projects, we expect this business to continue to deliver significant EBITDA and DCF growth in the years to come as these projects go in service.

And for the quarter, our distributable cash flow was $266.1 million, compared to $160.5 million in Q3 of 2010. And for the third quarter of 2011, ETP will pay its unit holders $0.39375, or $3.505, on an annualized basis per unit on November the 14th.

Looking at our business segments, let's begin with our Intrastate business. Intrastate operating income for the quarter was $128.5 million, compared to $133.8 million for the third quarter of 2010.

And that was affected by several factors. When comparing Q3 2011 to Q3 of 2010, lower transported volumes led to a $3.9 million decrease in transportation fees, and along with lower natural gas prices, a $3.4 million decrease in retained fuel revenues.

Spot prices averaged roughly $4.12 per MMBtu for the current period. That compares to an average of $4.19 for the third quarter of 2010.

Our margins from sales of natural gas and other marketing activities increased by $15.5 million compared to the Q3 of 2010, and that includes a $5.6 million increase from sale derivatives and a $3.7 million gain from non-cash derivatives.

Increased margins and volume on our HPL system also contributed to the period-over-period growth.

And for the quarter 2011, reported Storage margin decreased by $19.1 million, primarily due to the effects of fair value hedge accounting. During the quarter, we experienced a $0.41 per MMBtu widening of the spread between the spot price of inventory and forward prices, which we use to value our derivatives, resulting in a non-cash loss.

Conversely, during the quarter 2010, we saw a $0.32 per MMBtu narrowing and recorded a non-cash gain.

And as we've mentioned in the past, we lock in margin on our natural gas store in Bammel for our own account, and therefore eliminate commodity volatility risk.

When excluding derivatives and inventory adjustments, cash storage margin decreased approximately $3.6 million from the third quarter of 2010. And that was due primarily to lower margin on physical sales and reduced fee-based storage revenue. The decline was offset by a $13.9 million increase in settlements of financial derivatives.

And as it relates to our storage facilities, we had approximately 15% of our storage capacity, roughly 39.5 Bcf, contracted under fixed fee contracts, with remaining contract terms of 1 to 3 years.

And as of September 30, we had approximately 30.5 Bcf in the ground for our own accounts at Bammel for expected withdrawals during the 2011and 2012 winter season.

For our Interstate segment, we achieved operating income of $67.2 million for the quarter. That's roughly an increase of $32.6 million from the third quarter of last year, and was driven primarily by higher transportation revenues from our Tiger pipeline.

And as I mentioned earlier, we expect to see additional period-over-period revenue increases on Tiger and the related expansion from these contractual demand fee ramp ups.

In terms of average volumes, we saw a net increase of 1.3 Bcf a day for the quarter, primarily driven by volume shift on the new Tiger pipeline, offset by slightly lower volumes on our Transwestern pipeline, compared to the same period in 2010.

And for our FEP JV, we recorded equity and earrings of almost $6 million, and received cash distributions of $14 million for the quarter. We do expect to see these results continue to increase during the remainder of 2011 and into 2012 as demand fees increase under the terms of our long-term contracts.

Now turning to our Midstream segment, where we also experienced substantial growth, operating income increased by $21.3 million. That's roughly 40% to $74.1 million for the quarter.

Overall, NGL production was approximately 7% higher from Q3 2010 as a result of increased LaGrange plant volumes, fueled by strong Eagle Ford production, which outweighed volume decline in our Godley plant. This overall volume growth resulted in a $6.8 million increase in fee-based revenues for the quarter as compared to third quarter of last year.

Additionally, increased volumes resulted from growth projects, primarily in Louisiana and West Virginia, provided a $6.3 million boost in our fee-based margins.

Looking at our non-fee-based Midstream business, gross margins increased $19.5 million in the quarter. And that was primarily driven by favorable NGL prices, which also drove increased production. The composite NGL price for Q3 2011 increased to $1.33 per gallon from $0.91 per gallon during Q3 of 2010.

A decrease of equity NGL production, due to a higher concentration of volumes under fee-based contracts during Q3 of 2011 as compared to the same period in 2010, partially offset the increase in the NGL price's activity.

Now looking at our NGL Transportation and Services segment, which operates through our Lone Star JV, as a reminder, Lone Star, which is 70% owned by ETP and 30% owned by Regency, was acquired from LDH Energy on May 2 of this year.

For the third quarter of 2011, average NGL Transportation volumes averaged approximately 133,000 barrels per day, and NGL fractionation was about 13,800 barrels per day.

Our gross margin for the period was $65.4 million, and operating income for the period was $30.9 million. These results include the impact of planned outages at the Geismar, Chalmette, and Motiva refineries, which negatively impacted gross margin by approximately $7 million.

And as I've mentioned before, we continue to be very pleased with the performance of our Lone Star management team and assets, and have definitely seen the benefit of owning these assets, as it's given us greater service capabilities for our producers.

And now for our results in our Propane segment. Operating income for the quarter 2011 was a loss of $27.3 million, that compares to a loss of $13 million in Q3 2010, due to period-over-period volume decline and lower average gross margins per gallon sold.

We'd like to remind everyone that we recently announced an agreement to contribute our Propane operations to AmeriGas in exchange for approximately $2.9 billion, which includes $1.5 billion in cash and $1.3 billion of AmeriGas common units. The transaction is subject to customary closing conditions, and is expected to close in late 2011 or early 2012.

All right, that wraps up our results. Let's now take a look at our growth CapEx.

We invested a total of $338 million in the third quarter of 2011, with $311 million spent in our Midstream, Intrastate Transportation and Storage, and NGL segments, primarily on our Eagle Ford shale projects. And approximately $15 million was spent in our Intestate segment, primarily on the completion of the Tiger expansion, with the remainder spent in our Propane and other segments.

For the fourth quarter, we expect to spend between $460 million and $570 million, which includes $200 million to $250 million in our Midstream and Intrastate Transportation and Storage segments; $5 million to $10 million in our Interstate segment; $200 million to $250 million in our NGL segment; and the remainder in our Propane segment.

Maintenance CapEx for the quarter was approximately $32 million, and we expect to spend an additional $40 million to $50 million in the fourth quarter of this year.

And turning the calendar to 2012, we expect to spend between $1.3 billion and $1.5 billion on growth CapEx. That's split almost evenly between our Midstream and Intrastate Transportation and Storage segment and our NGL segment.

We also expect to spend between $120 million and $130 million on maintenance CapEx.

Note that spending on our NGL segment includes 100% of Lone Star, because we consolidate that JV in our financial statements. We do expect to receive capital contributions from Regency for that 30% share of growth CapEx related to Lone Star. That's roughly $60 million to $75 million in the fourth quarter of this year, and $250 million to $300 million in 2012.

To touch further on some of our growth projects over the past several quarters, we have announced what has become a robust portfolio of more than $2.8 billion of growth opportunities. We are very excited about these projects, which we expect to deliver mid-teen or higher returns, and help us achieve our long-term growth objectives, including resuming our distribution rate growth.

In our Midstream segment, we are well underway on more than $1.25 billion in announced Eagle Ford projects, and are beginning to see the results of our investment in Dos Hermanos, Chisholm, and as of last week, phase one of our Rich Eagle Ford Mainline, which is now in service.

We also announced a new $360 million gathering, processing, and transportation project in the Woodford and Barnett shales, which will include an expansion of our Godley plant.

And in our NGL Transportation and Storage segment, we are investing approximately $350 million for ETP's Freedom, Liberty, and Justice pipelines. And our Lone Star JV has approximately $1.2 billion or so of growth spending underway.

And before we move to ETE, I would like to briefly mention that last week we closed on a new $2.5 billion, 5-year revolving credit facility for ETP. This amends our existing facility by increasing its size to $2.5 billion from $2 billion, and extends the maturity to October 2016.

With almost $575 million drawn at the quarter, that leaves us approximately $1.9 billion in available borrowing capacity. And I'm very pleased with the outcome, given the credit market volatility we are currently experiencing. And amending this facility certainly continued our commitment to maintain our strong liquidity, which is more than sufficient to handle on our ongoing capital needs, while addressing the rating agencies' concerns of extending the facility's expiration.

Now I'd like to highlight ETE's financial results for the quarter. ETE had distributable cash flow, as adjusted, of $126.4 million for the third quarter of 2011. That compares to $125 million in Q3 of 2010.

ETE's distributable cash flow was also adjusted for the loss on the termination of interest rate swaps in connection with our debt refinancing in Q3 of 2010.

We also saw ETE's cash distributions, expected to be received from ETP and Regency, increase by 6%, or almost $10 million, when comparing Q3 of this year with Q3 of last year.

And distributions through our ETE unit holders will be $0.625 per unit on a quarterly basis, and will be paid on November the 18th.

Before we go in to Q&A, I would also like to quickly provide an update on our pending acquisition of Southern Union by ETE.

The distribution of the proxy statement and prospectus has already begun, and the Southern Union shareholder vote has been scheduled for the morning of December the 9th. As a reminder, approval of the transaction requires a simple majority of Southern Union shareholders. And certain shareholders, who own approximately 13.4% of Southern Union's outstanding shares, have already agreed to vote in favor of the agreement, and have also agreed to elect to receive ETE common units as consideration.

We have also locked up financing and continue to move forward on other required approvals and believe we are still on track for closing in Q1 of 2012.

Operator, that concludes my prepared remarks. Let's open up the lines for questions. Thank you.

Thank you. (Operator Instructions). Your first question comes from the line of Ross Payne with Wells Fargo. Please proceed.

How are you doing, guys? Nice quarter there. One of the things that you mentioned on the analyst meeting a couple weeks ago was the potential for additional asset sales that may not fit into your core portfolio. I just wanted to kind of get your thoughts on that right now. And the timing, if you had any kind of thoughts on when that might happen.

Ross, this is Kelcy. I'm sorry; I've got an allergy so my voice is bad. As you know, it's difficult for MLPs to ever justify selling the asset since we're expected to demonstrate growth.

However, where we are right now in our partnership, we do feel it is the right thing to explore what we believe to be non-core assets, and we are doing that. Propane is an example of that. We won't go back into the rationale for doing that, but it was the right thing to do. And we're considering other assets as well. I don't expect-- Ross, I don't expect you'll see anything substantial like Propane, but we may announce something else.

Okay. And then finally, obviously there was discussion about Williams being interested in some of your assets. Do you ultimately see Williams potentially purchasing any of the assets as a part of the sum transaction? Thank you.

Ross, I would not rule that out. They like us. I don't mean to speak for them. My opinion of them would be that probably some of the assets fit them as well or better than they fit us. And so I would not rule out that we could in fact enter into further discussions with Williams down the line. We are not engaged in those discussions now, but I like those people. They're good to work with, and I would not rule that out.

Thank you. Appreciate it.

You're welcome.

And your next question comes from the line of Helen Ryoo with Barclays Capital. Please proceed.

Thank you. Good morning. Couple of questions. On Propane, once you close the sales of that asset, and you would end up holding the AP units, will you be showing equity income on the AP units that you are holding?

Helen, this is Martin. That is correct. The investment in AmeriGas will be accounted for in the equity method. And so we'll take our respective or per rata ownership of that income in our income statement.

Okay. So that would add to your EBITDA number.

Yes.

Okay, great. And then just on the potential tax expense related to that sale, I know it would be dependent on other factors, but just on a very basic level, what is the basis of that asset, and will you be taxed on capital gains tax rate of 15% on the gains you made on that asset sale?

Well, I guess to answer to the second question, any tax would be passed up through the unit holders. So that will get taxed at whatever the unit holders' [who is] holding the rate is. I guess if the unit holder has owned the-- [each] the assets, I guess whether it be AmeriGas, longer than a year, then I think you'd have a long-term capital gains (inaudible). But again, it's going to be dependent on the individual unit holder's tax situation.

With respect to the first answer, I don't know if we provided what that tax basis is, but we can tell you it's a pretty big number. The way we structured the transaction with the cash and equity component, that has deferred that tax gain, again, to the extent that we do not sell the AmeriGas units over time.

Okay, all right. That's helpful. And then just on the Justice pipeline in Eagle Ford, I guess that's at a leased line, correct? Or--

Leased.

Is that a leased line?

No. The Justice line is on the MGL pipeline that we're building from Jackson to Mont Bellevue via 100% owned by Energy Transfer.

Okay. So it's a new build?

Yes, it's a new build.

Okay. And then the cost of the project, the cost of building that line is 300.

Yes, that's the high range of our estimates.

Okay, got it. Well, thank you very much.

Thank you, Helen.

Your next question comes from the line of Louis Shamie with Zimmer Lucas. Please proceed.

Hi. Good morning, guys. Great quarter. Just had a couple of questions. First one was on the Interstate segment, and particularly Tiger, can you talk about how much gross margin was attributable just to Tiger in the quarter? And kind of what level of contract commitments that's associated with versus the ultimate 2.4 Bcf that you're going to ramp up, too?

Louis, I don't have the breakdown with me, but I can get that to you. What was your second question?

Was just the level of utilization on Tiger in this quarter versus the 2.4 that you're ultimately going to be running at.

We'll jump up an additional 200,000 a day January 1st, which will be 100%. 100% of utilization; not just demand fees.

Right. What's running through the pipeline?

Today, what's running through the pipeline is approximately 1.4 Bcf, 1.5 Bcf.

Demand fees being paid.

Demand fees being paid are I believe 2.2 Bcf.

Going to 2.4 January 1st.

Correct.

Okay, great. So it was 2.2 in Q3, also, in terms of those demand fees?

Correct.

Okay, that's good.

Just a clarification, that 2.2 jumped up when the expansion was completed, which I believe was in August. So we didn't see the full benefit in Q3. We'll see the full benefit in Q4.

Got it. Okay. And then my other question is kind of related to the balance sheet. The AmeriGas transaction definitely helped a lot in terms of getting cash in the door to fund the Citrus acquisition and a lot of that CapEx that you have scheduled for next year. But I was wondering what you guys think in terms of equity financing and kind of about how much you think you'll need or what timing we can expect on kind of fixing that kind of commensurate with the capital spending?

I mean one, while we've announced the AmeriGas transaction, we've got a number of things that we need to accomplish there, including regulatory approval to get that through. And we're very confident that we'll get there, but cash hasn't hit the bank accounts quite yet.

So, having said that, and that's something that we'll continuously look at, we've also got the Southern Union shareholder vote coming up on December 9th. Again, very confident that we'll get an affirmative vote there.

With all that said, then you've got the timing of when those transactions close. So, I think from a balance sheet, liquidity, and leverage credit metric perspective that we'll evaluate, I think it's easy to see that with the robust capital growth spending that we have, and will have, for these projects that we are investing in, it's something [that is going to be] looked at.

And if you look at history, we've been prudent and opportunistic with our capital raises, whether it be equity or debt. And we're going to continue to do that.

Our target metrics are such to maintain our investment-grade credit metrics. We've gotten feedback from the agency that at 4.5 or less, I think they can get somewhat comfortable with where we are today.

I'll tell you what; we're not comfortable with where we are today. I do not like having that negative outlook. And so we're going to work on getting that back to stable and hopefully up to positive. And with that means managing the balance sheet while also getting some of these projects in line and seeing the cash flow come through.

Great. Can you give any commentary on the synergies that you'd expect from SUG and when we might see those start to show up?

Yes. I think when we announced the merger, we threw a number out there of I believe $75 million to $100 million of synergies. Some of that coming from your typical corporate-to-corporate type merger where you've got public company fees, consolidated facilities, etc. We believe a bigger and probably better type of synergies are going to be coming from the assets, whether it's in West Texas, Panhandle, stuff that's on the east side of the system. And that's going to take some time.

So I think you may see half of that number in the first 12 to 18 months. I think to get the full benefit, you're probably looking 18 to 24 months before we see the full breadth of those synergies. Which, again, you can go back and look at our track record, we've been pretty conservative in what we've estimated and believe that there could be some opportunities to the high side of that number.

Great. Thanks a lot, guys.

Thanks, Louis.

Your next question comes from the line of Darren Horowitz with Raymond James. Please proceed.

Hi, Mackie. Just a quick question for you. I'm thinking about what you all are doing in terms of adding process capacity at that kind of LaGrange and Chisholm area, recognizing that phase one of REM basically fills up LaGrange.

With everything that you all want to do, and the gas that you want to move through the system, do you think that the 120 MMcf a day [cryo] that you're adding at Chisholm is going to be enough?

When you say enough, there's a tremendous amount of assets that need to be built to handle the volumes that all the producers are projecting in the coming years. But I guess I'd answer it this way. As quickly we have it built, we'll have it full. As quickly that we have Jackson built, we'll have those full also. So we're building it as quickly as we can, and we have contracts, fee-based contracts to back those up once they're online. There's a lot of production that is ready to flow.

Are you still thinking that that looping initiative that you guys were looking into could add another 300 of Mcf a day on the REM system?

Certainly. There's several projects we're looking at on increasing the capacity of our REM project, and one of those is increasing it to somewhere between 200,000 and 400,000 a day. And we will continue to look at those possibilities.

I appreciate it, Mackie. Thanks.

At this time, I would now like to turn the conference over to Mr. Martin Salinas for closing remarks.

Great. Again, everybody, thank you for joining us this morning and have a great day. Thank you.

Thank you for joining today's conference. That concludes the presentation. You may now disconnect and have a great day.