Filed by Energy Transfer Equity, L.P.
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: Southern Union Company
Commission File No.: 1-06407
TRANSCRIPT
The following is a transcript of a conference call held by Energy Transfer Equity, L.P. (the “Partnership”) at 8:30 a.m. Central time on February 16, 2012. 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. The Partnership believes that none of these inaccuracies is material. A replay of the recorded conference call will be accessible for a limited time through the Partnership’s web site at www.energytransfer.com.
MANAGEMENT DISCUSSION SECTION
Operator
Good day, ladies and gentlemen, and welcome to the Energy Transfer’s Fourth Quarter Earnings Conference Call. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes.
I’d now like to turn the conference over to your host of today, Mr. Martin Salinas, Energy Transfer’s Chief Financial Officer.
Martin Salinas, Jr.
Thanks, operator, and good morning, everyone. Thank you for joining today’s call. As always, I have Kelcy, Mackie, Tom Mason, and John McReynolds with me to help answer questions after my prepared remarks. If you’ve kept track with a number of press releases we’ve sent out since the last call, you can pretty much tell we’ve been pretty busy around here. I’d like to take some time today to highlight what we’ve accomplished over the last few months that demonstrates the execution of our strategic goal of continuing to be the premier energy services provider. I’ll also summarize our fourth quarter and year end 2011 financial and operating results.
I’d also remind you that copies of our earnings releases, which were issued yesterday after the market closed, are available on our website. We also intend to file our 10-Ks next week, which will also be available on the website.
And as usual, during the call, I’ll make forward-looking statements within the meaning of Section 21E of the SEC Act of 1934, based on our beliefs as well as certain assumptions and information available to us.
I’ll also refer to adjusted EBITDA, which is a non-GAAP financial measure. A reconciliation to net income is provided on our website as well. I’d like to start off with an update on ETE’s pending acquisition of Southern Union, as we get closer to closing on that acquisition, a transaction we’ve embarked on since the beginning of June of last year. And we’ve achieved a key significant milestone in December, when we received overwhelming support from Southern Union shareholders with 98% voting in favor of the merger.
We’ve also been working intensely with the Missouri Public Service Commission staff for the last several months. And I’m happy to say that yesterday, we reached an agreement in principal with the staff related to the terms of a negotiated settlement, and we expect the formal agreement with the staff will be reached today.
With this agreement, we expect the staff to recommend to the Missouri Public Service Commission, an approval of our application related to the Southern Union acquisition in the very near term. With this, we’re on track for closing sometime in mid-to-late March.
We also intend to mail shareholder election forms to Southern Union shareholders on Friday as soon as a joint stipulation agreement is signed, and we’ll be looking to finalize financing over the next several weeks as the final cash and equity considerations are determined, and I’ll remind you that we do have a $3.7 billion syndicated bridge facility back-stopping the transaction.
I’d also like to recall that Southern Union shareholders have the option to elect $44.25 per share in cash or 1.0 times ETE common units with a maximum cash component capped at 60% of the total considerations, and a maximum equity component capped at 50%.
Also, recall that ETE and Southern Union will contribute the Citrus entity which owns 50% of FGT, that’s Florida Gas Transmission, to ETP for $2 billion, of which $1.9 billion will be cash. ETP has already completed the financing of the Citrus drop-down with a successful bond offering, which will reduce ETE’s financing needs by $1.45 billion.
And a couple of comments on integration…
Integration of Southern Union is well underway and teams comprised of both ETP and Southern Union employees have been working very hard to manage all aspects of integration.
Our goal is to execute this transaction as seamlessly as possible, and to minimize disruptions to our customers, suppliers and employees. And we still are well on our way to achieving that goal. Furthermore, we remain very confident in our ability to achieve commercial and operational synergies of at least $75 million to $100 million per year – that’s consistent with what we announced back in June of last year.
In fact that figure may grow as we identify further opportunities during the integration process. We couldn’t be more pleased with Southern Union as it continues to execute on its business plan, and has experienced little impact on its business performance since the merger announcement, and we continue to believe that this transaction will create significant value for all stakeholders once complete.
Let’s shift gears now a little and talk about a few achievements that ETP has recently accomplished. As I mentioned, on January 9th of this year, ETP successfully priced a $2 billion of senior notes comprised of two $1 billion tranches of 10- and 30-year notes to fund its obligation on the Citrus transaction that I mentioned earlier.
The order book was over-subscribed within an hour of this announcement, and was ultimately more than three and half times over-subscribed and $7.3 billion of total orders. This offering provides us not only financing certainty for the Citrus acquisition, but as I mentioned before, reduced capital requirements needed at ETE to fund the Southern Union acquisition.
Also in January, we contributed our propane business to AmeriGas in exchange for $1.46 billion in cash and 29.6 million AmeriGas common units, which represented approximately 34% of total AmeriGas units outstanding. With this transaction, ETP becomes one of the largest pure play natural gas and NGL operators with a focus on long-term, fee- based businesses.
It also allows us to focus our efforts and resources on opportunities in the pipeline sector, our primary business, while reducing our external capital requirements.
Furthermore, the transaction was deleveraging to ETP as cash proceeds were used to repay borrowings under ETP’s revolving credit facility of roughly $420 million, and to fund a $750 million tender offer that I’ll speak to here in a minute.
The remaining proceeds were used to offset or will be used to offset other near term capital requirements. As it relates to the AmeriGas units, we’re required to hold on to them until the beginning of 2013, and we also expect to receive approximately $90 million of annual cash distributions to ETP.
And to wrap up our most recent accomplishments, I’d also like to highlight the results of our recent $750 million tender offer. We launched this tender offer on January 9, which was funded with a portion of the cash proceeds from the propane contribution. The offer included two components: an any and all tender of our senior notes due August 2012, and a maximum tender of our 2013, 2014 and 2019 senior notes.
The results of the transactions were in line with our goals, and allowed us to retire $292 million of our senior notes due in August of this year, $58 million of senior notes due in 2014, and a combined $400 million of our senior notes due in 2019.
In addition to deleveraging ETP, the tender offer will also lower our annual interest expense by approximately $55 million to $60 million, and reduce capital market risk by taking out almost three-fourths of our scheduled 2012 debt maturities.
Now, I’ll talk about some of the growth opportunities that we have announced over last 12 to 15 months, starting with new projects that were recently announced. As you may have seen, ETP issued a press release this morning announcing a 37-mile expansion of the Rich Eagle Ford Mainline, and a new 200 million cubic feet per day natural gas processing facility in Karnes County. These projects are supported by new long-term fee-based arrangements, which include volume commitments in excess of 300 million cubic feet per day of natural gas from multiple producers.
The Rich Eagle Ford Mainline expansion, expected to go in service in the first quarter of 2013, and the processing facility scheduled to go in service in the fourth quarter of this year, is estimated to cost a combined $210 million. And for those keeping count, we’ll have one Bcf a day of new processing capacity in the Eagle Ford by this time next year.
Also announced this morning was a new 100,000 barrel per day NGL fractionator that ETP and Regency through the joint Lone Star will construct at Mont Belvieu. This new fractionator – Lone Star’s second – is already 65% contracted under multiple long-term agreements, and is expected to cost $350 million, and be in service by the first quarter of 2014.
As you may recall, Lone Star previously announced a 100,000 barrel a day NGL fractionator, which is now 100% contracted and is expected to go in service in the first quarter of 2013.
Both fractionators, once complete, will take volumes from Lone Star’s new 200,000 barrel per day West Texas Gateway NGL pipeline, which is expected to go in service in the first quarter of 2013. The pipeline is currently 60% contracted under long term agreements and we expect to grow that percentage to 75% to 80% by the end of the first quarter of this year.
Including these projects, we have announced more than $3.5 billion of new growth opportunities over the past year with a focus on liquids rich opportunities in not only the Eagle Ford, but also the Permian and Woodford areas. These projects, which are expected to go in service are ahead of schedule, are supported by long-term contracts with principally demand fees and minimum volume commitments, and provides good visibility for distributable cash flow growth for the next several years. It also highlights that we continue to see attractive opportunities as we look into our producers’ needs.
So, as we look forward to 2012, we expect to spend between $2.1 billion and $2.4 billion on growth CapEx, which includes $800 to $900 million in our midstream and intrastate segments, and $1.3 billion or $1.5 billion in our NGL segment. I do want to point out that the spending on the NGL segment does include 100% of Lone Star, because as I previously mentioned, we consolidate the JV in our financial statements.
We do expect to receive contributions from Regency related to their 30% share, which will equate to approximately $350 million to $400 million in 2012. So, as you can see, we’ve been pretty busy with some very exciting developments and achievements for Energy Transfer.
Let’s now talk some numbers and go on into ETP’s fourth quarter and full year 2011 results. Adjusted EBITDA for the quarter was $479 million, up 17% from the fourth quarter of last year, and distributable cash flow is $310 million for the quarter – an increase of roughly 9% from the same quarter a year ago.
However, as we stated in our earnings release yesterday, 2011 results were impacted significantly by our propane operations due to the extremely mild weather during the fourth quarter. And for the year, adjusted EBITDA was $1.74 billion, an increase of 13% over last year. And DCF, that’s distributable cash flow, was $1.14 billion, up 10% from 2010.
And similar to the fourth quarter, our annual EBITDA was also impacted by negative variance of roughly $47 million related to our propane segment results.
For the fourth quarter, as it relates to distributions, ETP paid its unitholders 89 and 3/8 cents on a quarterly basis or $3.575 on an annualized basis, and those distributions were paid on February 14th.
And before I turn to our segment results, I like to point out that, beginning this quarter, we revised our segment reporting to focus on adjusted EBITDA instead of operating income. We believe adjusted EBITDA not only provides a better measure of segment performance and operating income, but also removes certain non-cash items, and also reflects the amount for our JVs based on our proportionate ownership in those JVs.
So, let’s begin with our intrastate transportation and storage segment, where adjusted EBITDA for the quarter was $153 million, a decrease of $13 million from last quarter of 2010. That’s attributable to several factors. Our average transportation volumes were down approximately 1.5 Bcf quarter-over-quarter, primarily due to a lower basis differentials that we continue to experience although we did see higher volumes in our rich natural gas areas where our assets are located.
In addition, retained fuel revenues were down $9 million for the quarter, primarily due to lower natural gas prices. For your information, spot natural gas prices averaged $3.16 per MMBtu during the fourth quarter of 2011, that compares to $3.84 on a MMBtu basis in the fourth quarter of 2010.
We’re also further impacted by lower storage withdrawals in the fourth quarter of 2011, with only 84 million cubic feet withdrawn as compared to the 4.4 billion cubic feet withdrawn in the fourth quarter of last year. And we do expect this to continue in the first quarter of 2012, due again to the unseasonably warm temperatures experienced across the country.
To help mitigate our exposure to low natural gas prices, we have hedged our expected net retained fuel at an average of $3.53 for 2012, and $3.72 for 2013.
And for the year, our adjusted EBITDA for our intrastate business was $667 million, that’s down $49 million from 2010, again primarily due to unfavorable gross margin impacts from trading and system optimization activities and a decline in realized storage margin.
And as it relates to our Bammel storage facility, we have approximately 20 Bcf contracted under fixed-fee contracts, which represent about one-third of our total storage capacity. And as of December 31, we had approximately 45.8 Bcf in the ground that we do manage for our own account.
Let’s now look at our interstate transportation segment, where we saw significant increases in the adjusted EBITDA. For the fourth quarter of 2011, EBITDA was $107 million including $17 million related to our 50% share of FEP. This represents a 110% increase from the fourth quarter of 2010, primarily due to replacing Tiger and FEP in service in late 2010, and early 2011, and contractual fee ramp-ups we recognized throughout 2011. And for the year, adjusted EBITDA was $373 million, up from $220 million in 2010, again attributable to FEP and Tiger coming online.
And as of January 2012, both FEP and Tiger have completed their contractual fee ramp-up period, so we will now be collecting on the full demand fee that we’ve entered into with our shippers on these two pipelines. That’s over 4.25 Bcf a day of take-or-pay fees for the next nine to 14 years.
Looking now at our midstream segment where we continue to see very strong results. Our fourth quarter 2011 adjusted EBITDA was up just over 17% from the fourth quarter of 2010. For the year, adjusted EBITDA was up more than 18% to $389 million.
For both the fourth quarter and the year 2011, fee-based revenues increased due to additional volumes for production in the Eagle Ford shale and growth in our Louisiana and North Texas systems. For the fourth quarter 2011, total NGLs produced, including equity NGLs produced averaged 80,000 barrels per day, that compares to 73,000 barrels per day in the third quarter of 2011, a 9% increase in just three months.
Our non-fee based contract and processing margin also increased primarily due to the favorable NGL pricing environment. And we expect margins to continue to remain strong, not only with the commodity price environment, but also the increased capacities we’re building and placing in service over the next several years. Now these increases in margins were partially offset by higher operating expenses.
Turning to our newest segment, and that’s the NGL transportation and services segment, which just includes our Lone Star JV. If you recall, we formed this JV with Regency back in May of 2011 to acquire the assets of LDH Energy.
Lone Star is 70% owned by ETP, and 30% by Regency and is consolidated by ETP. As a result, our adjusted EBITDA and distributable cash flow calculation are adjusted to remove Regency’s 30% non-controlling interest in Lone Star.
For the fourth quarter, adjusted EBITDA was $33 million, and for the year, adjusted EBITDA was $88 million, again that’s our 70% share. On a 100% basis, average NGL transportation volumes were 131,000 barrels per day, and average NGL fractionation volumes were 19,000 barrels per day for the fourth quarter of 2011.
Full-year NGL transportation volumes averaged 133,000 barrels per day, and average NGL fractionation volumes were 16,000 barrels per day. And as we stated in past calls, Lone Star has proven to be very successful for us. It’s performance has consistently exceeded our acquisition economics and has also created a number of attractive growth opportunities for us because of the greater service capabilities we’re now able to provide our customers.
Lastly, looking at our propane segment, fourth quarter and year-end 2011 adjusted EBITDA decreased from the prior year due to the warmer than normal weather and a decline in average gross margin per gallons sold, as I mentioned earlier.
Fourth quarter 2011 EBITDA was $71 million - that’s $23 million lower than the fourth quarter of last year - and full year adjusted EBITDA was $222 million, down $47 million from 2010.
Moving on from our financial results, I’d like to provide some detail on our 2011 growth capital expenditures. In the fourth quarter, we spent a total of $471 million, with a majority spent in our midstream, intrastate and NGL segments, primarily on our Eagle Ford shale and NGL pipeline and fractionation projects at Lone Star. Approximately $47 million was invested in our interstate transportation segment, and the balance spent on our propane and other segments.
This brings total of 2011 growth CapEx to $1.38 billion, including $1.16 billion for our midstream, intrastate and NGL segments, $181 million in our interstate segment and roughly $36 million in our propane and other segments.
Our maintenance CapEx for the fourth quarter was $54 million, and for the full year of 2011 totaled $134 million.
That’s it for ETP, let’s now talk about ETE’s financial results for not only the quarter but also the year. For the fourth quarter of 2011, ETE had distributable cash flow, as adjusted, of $135 million. That compares to $118 million for the fourth quarter of last year.
For 2011, full year, ETE’s distributable cash flow as adjusted was $511 million, compared to $498 million in 2010. Distributable cash flow was adjusted to exclude certain acquisition related costs incurred related to the pending Southern Union acquisition, and also in 2010 related to the acquisition of the general partner of Regency.
Distributable cash flow was also adjusted for the loss for the termination of interest rate swaps in the third quarter of 2010 related to our debt refinancing at that time. ETE’s adjusted cash distribution from ETP and Regency increased 11% or $17 million when comparing fourth quarter of 2011 to fourth quarter of 2010. For the year, distributions from ETP and Regency increased 8%, or roughly $52 million compared to 2010.
And ETE distributions to ETE unitholders were $0.625 per unit on a quarterly basis, or $2.50 on an annual basis, and will also be paid on February 17th.
ETE remains poised to grow distributable cash flow to its unitholders but not only at the ownership both GP and LP interest in ETP and Regency but also it – as it acquires Southern Union and the cash flow is generated from those assets.
In conclusion, we here at Energy Transfer can’t be more excited about not only what we’ve able to accomplish over the last couple of years, both from a commercial and financial perspective, but also what lies ahead in terms of not only growth but more opportunities to come as we continue to build out our infrastructure to meet our customers’ needs.
We said couple of years ago that we’re a looking for a transformational transaction and lo and behold are close to accomplishing three of them within a 12-month time span. That being in the purchase of LDH, getting us into the liquids business, announcing the Southern Union merger in June 2011, which is on target to close within the next month or so, and the sale of our propane business that now makes us the large pure-play natural gas NGO operator. Not bad for a 12 months of work. But guess what – we’re nowhere near done.
Every day that passes we get more and more excited but not only what our existing assets can deliver in terms of growth and opportunity but also integrating Southern Union and delivering on the increased unitholder value that this acquisition will generate. We look forward to what the future holds for us, and we thank you for your continued support.
Operator, let’s open the lines to questions? Thank you.
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Q&A SECTION
Operator
[Operator Instructions] and your first question will come from the line of Mr. Darren Horowitz with Raymond James. You may proceed.
<Q - Darren Horowitz>: Good morning guys.
<A>: Good morning, Darren.
<Q - Darren Horowitz>: Martin, couple of question for you. The first regarding the second fractionator, what’s the average term for that 65% of capacity that is contracted? Is it similar to the first frac - about 10 years?
<A - Mackie McCrea.>: Yes, it is.
<Q - Darren Horowitz>: Okay. And Mackie what’s the contract type? Is it mostly frac or pay?
<A - Mackie McCrea>: Yes they range between 80% and 90%, on average about 85% demand.
<Q - Darren Horowitz>: Okay. And then just kind of thinking about the internal rate of return for frac two relative to frac one, obviously recognizing that frac one is looking to cost about $50 million more. Maybe that included a bit more interconnectivity infrastructure and storage, but how should we think about the rates of return ramping when frac one is fully up and then frac two starts to come up and you kind of get a synergistic benefit from having a lot of that downstream connectivity already built?
<A - Mackie McCrea>: Yeah, as we’ve explained in our initial frac press release, the initial frac includes a considerable amount of infrastructure that was necessary, if we were going to build a second frac and now that we have announced that the returns not only will be better because of lower CapEx cost but also we have increased our rates from customers on the second frac.
<Q - Darren Horowitz>: Is it too early to quantify what do you think those returns are going to be?
<A - Martin Salinas, Jr.>: Darren, this is Martin, I think as we’ve guided before, we shot for somewhere in the seven, eight multiple range (EBITDA multiple) on these projects with the thought process and the confidence that we would drive that multiple down as we fill up more of the capacity with commitments and this is just another example of us doing that.
<Q - Darren Horowitz>: Okay, and then last question for me on the West Texas Gateway line, once you all get to 70% or 80% of that capacity committed. Is it fair if we are assuming roughly a 7% to 10% rate of return, to start and then that kind of ramps up over time?
<A - Mackie McCrea>: No, the 70% to 80%, it’s north of 10% rate of return on that project.
<Q - Darren Horowitz>: Okay. Thanks guys, I appreciate it.
<A - Martin Salinas Jr.>: Okay.
Operator
Your next question comes from the line of Cathleen King with Bank of America Merrill Lynch. You may proceed.
<Q - Cathleen King>: Thanks. Good morning.
<A - Martin Salinas, Jr.>: Good morning, Cathleen.
<Q - Cathleen King>: Wanted to talk a bit more about storage for the winter heating season. I know you said you are going to have about 45 Bcf for your own account, are you going ahead and hedging those spreads, summer/ winter spreads, for next winter?
<A - Martin Salinas, Jr.>: Yes, we’ve rolled those spread or at least those into next winter, I think given just where the calendar spread is today, we’re not seeing a whole lot of summer spreads. So all that 45, 46 Bcf in the ground today is hedged into next winter.
<Q - Cathleen King>: And average price there – should I just look at my Bloomberg screen or do you have an estimate there, what you are locking in at?
<A - Martin Salinas, Jr.>: Yeah, I think taking a look at the Bloomberg screen would give you a fair representation of what we’ve done.
<Q - Cathleen King>: Okay, okay, fair enough. And then to think about the contract profile at the intrastate pipelines, do you have any contracts rolling over in the near-term and then also are you seeing an opportunity to transfer some of your contracts to more fee-based in areas like the Permian, Eagle Ford where you obviously have some associated gas that needs a home in those areas?
<A - Martin Salinas, Jr.>: Did you say intra- or inter-?
<Q - Cathleen King>: Intra.
<A - Mackie McCrea>: Yeah, no there are no significant intrastate contracts ending anytime soon, in the next year or so. Our focus out in West Texas primarily has been on transporting liquids as we – as those volumes come on there certainly will be opportunities to move residue volumes, however, most producers are not that interested in contracting to move across the state at rates that we’ll be willing to do long term.
<Q - Cathleen King>: Okay, understood. And then also on reverting to the – the propane sale to APU, can you remind us the limitations on how many APU units you can sell in a given year? I understand that you have to wait a year to do that, but then are there restrictions at that point on how much you can sell?
<A - Martin Salinas, Jr.>: Yeah, Cathleen, this is Martin. We – as you’ve mentioned, we’ve got through the end of 2012 to hold those units - after that we can sell in the open market. We have a limitation of two secondary offerings in any one year at 500 million apiece.
<Q - Cathleen King>: Okay.
<A - Martin Salinas, Jr.>: So call it $1 billion on an annual basis in terms of our limitations to sell those units.
<Q - Cathleen King>: Okay, got it. And then last one from me, if you don’t mind. I know you talked about hedging retains fuel and you talked about this prices but can you clarify the percent that you guys are hedged on retained fuel in 2012 and 2013?
<A - Martin Salinas Jr.>: That’s pretty much all, 100% of our estimated volumes for both of those years.
<Q - Cathleen King>: Got it. Okay, thanks a lot.
<A - Martin Salinas Jr.>: Yeah, you bet.
Operator
Your next question comes from the line of Ross Payne with Wells Fargo. You may proceed.
<Q - S. Ross Payne>: How are you doing guys?
<A - Martin Salinas Jr.>: Hi, Ross.
<Q - S. Ross Payne>: Kelcy or Martin, can you comment on any further potential drop-downs in conjunction with the SUG acquisition and any further consideration to potentially selling any non-core assets that are assumed as a part of the acquisition?
<A - Kelcy L. Warren>: Yeah, Ross, this is Kelcy. Nothing has really changed. I think the – I shouldn’t call it guidance, but the dialogue we’ve had regarding drop-downs in the past remains the same, we have been – I will tell you from the time of the shareholder both to now we – it’s allowed us with a great degree of comfort to dive in a little bit more into these business and we – let’s just say we are extremely pleased as
to what we’ve seen and we think there is a great deal of upside. So the only thing that might have changed is I think that there is probably less desire on our part to have any substantial divestitures outside of the drop-down scenario.
<Q - S. Ross Payne>: Okay, great. Thanks guys.
Operator
Your next question comes from the line of Helen Ryoo with Barclays Capital. You may proceed.
<Q - Helen Jung Ryoo>: Thank you. Good morning.
<A - Kelcy L. Warren>: Good morning, Helen.
<Q - Helen Jung Ryoo>: Yes. My first question is related to your new processing plants that you will put in, I guess you will have Chisholm plant coming online in the first quarter and then this Karnes plant will come online fourth quarter of this year. Do you expect Chisholm plant to be pretty much full by the time the Karnes plant comes online?
<A - Mackie McCrea>: Yes, we do. 100%.
<Q - Helen Jung Ryoo>: And then after Karnes you’ll have series of, I guess, capacities coming online on the Jackson Plant. Do you expect the Karnes plant to be full by the time these Jackson capacities come online?
<A - Mackie McCrea>: Yes, we do. The Chisholm, the Karnes and the Jackson we expect to be full very shortly after bringing them online.
<Q - Helen Jung Ryoo>: Okay, great. And you said I think you said this is a fee-based plant, the Karnes plant.
<A - Mackie McCrea>: Yes.
<Q - Helen Jung Ryoo>: Okay, great. And then I guess just to – just switching over to interstate, just wanted to understand a little bit better what’s going on at Transwestern. It seems like you’re seeing a bit of volume or margin decline there and could you just talk about contracting rates? Has it been coming down? Has your contracting terms been coming down on Transwestern and what’s the trend there and what may reverse the trend?
<A - Mackie McCrea>: The primary impact is - same impacts across the country that basis is just so flat between California and San Juan and Phoenix and of course West Texas and the available capacity we have to move volumes to the east out of San Juan - there is just no basis to justify moving much volume. We do stay full moving gas to the West, it’s just that is the basis is so narrow, it certainly impact volumes. And then the decline in natural gas prices have certainly over the last couple of years hurt our retained fuel revenue.
<Q - Helen Jung Ryoo>: Okay, so once the basis, once we see a better gas price environment and better basis I guess, do you see that Transwestern, I guess cash flows turning around?
<A - Mackie McCrea>: Well, we do see that. We also have recently signed not a huge deal, but a new customer in Phoenix we do continue to focus on customers in the Phoenix area and also along the TW system. And so, we do anticipate growing our customer base over the next two or three years and adding volumes and those new customers will pay a longer term, better rates than the existing day-to-day basis for instance.
<Q - Helen Jung Ryoo>: Okay, would you say order of magnitude Transwestern accounts for 30% to 40% of your interstate cash flow?
<A - Martin Salinas Jr.>: This is Martin. I think that’s right, although once you get a full year impact of FEP and Tiger, I think that number comes down a little bit.
<Q - Helen Jung Ryoo>: Okay. And I guess you have one more – I guess by 2012 you’ll be getting the full demand charge on Tiger and FEP so…
<A - Martin Salinas, Jr.>: That’s right.
<Q - Helen Jung Ryoo>: Okay, okay, got it and I guess just some housekeeping questions: Martin did you say that the total CapEx for 2012 will be 2.1 to 2.4 including the Lone Star spending, net to your ownership?
<A - Martin Salinas, Jr.>: That’s right, Helen. It is 2.1 to 2.4, but that does not include contributions of $350 million to $400 million from Regency. So you will need to subtract that $350 million to $400 million from that 2.1 and 2.4.
<Q - Helen Jung Ryoo>: Okay. That’s your net number, okay.
<A - Martin Salinas, Jr.>: That’s a net number right.
<Q - Helen Jung Ryoo>: And outside of what you’ve – outside of I guess 2012 spending, what’s the remaining spending based on all the projects you’ve announced thus far?
<A - Martin Salinas, Jr.>: I would say that we’re probably a little bit north of $1 billion.
<Q - Helen Jung Ryoo>: Okay, got it, all right and then what was your cash and debt balance in the quarter?
<A - Martin Salinas Jr.>: Our debt balance is a little less than $7.5 billion.
<Q - Helen Jung Ryoo>: Okay.
<A - Martin Salinas Jr.>: Cash I don’t have in front of me. But I’ll get that to you.
<Q - Helen Jung Ryoo>: Okay, great. Thank you very much.
Operator:
Your next question comes from the line of Curt Launer with Deutsche Bank. You may proceed.
<Q - Curt N. Launer>: Good morning, thank you. Most of my questions have been asked and answered already. One more for a little bit more granularity, if you could, relative to the basis differential area. Where is that best, where is that worst, what’s going now in the fourth quarter – in the first quarter coming off the declines that you showed in the fourth quarter?
<A - Mackie McCrea>: As far as the intrastate business as we just talk about TW basis really hasn’t changed much. It’s been narrow for a period of time. It moves in and out but the range certainly across Texas remains somewhere between $0.03 and $0.06 and then the TW, it hasn’t changed much too as far as from the San Juan to the West. So it remains narrow pretty much nationwide, it’s fairly narrow.
<Q - Curt N. Launer>: So if I was going to try to make a point relative to cross-Texas being worst in the Gulf Coast, that’s not what you’re experiencing right now?
<A - Mackie McCrea: I’m sorry, could you ask that again?
<Q - Curt N. Launer>: And so if I was going to try to make a point about cross-Texas being worse than what’s going on in the Gulf Coast right now, that’s not what you’re experiencing?
<A - Mackie McCrea: Yeah, I don’t totally understand the question. As far as the Gulf Coast, basis from the standpoint of gathering and transporting production from say the Eagle Ford to plants, that’s a different basis, that’s just a market-based negotiation. Basis between big points – from Waha to Katy, or Auga Dulce to Katy – those remain $0.03 to $0.06 between those trading areas.
<Q - Curt N. Launer>: Okay, thanks. Yeah, that is the question.
Operator
Your next question comes from the line of John Edwards with Morgan Keegan. You may proceed.
<Q - John D. Edwards>: Yeah, good morning everybody.
<A - Martin Salinas, Jr.>: Good morning John.
<Q - John D. Edwards>: Just to clarify the announcement this morning, was that included in your CapEx…
<A - Martin Salinas, Jr.>: Hey, John, I can barely hear you.
<Q - John D. Edwards>: Can you hear me now?
<A - Martin Salinas, Jr.>: It’s much better.
<Q - John D. Edwards>: Okay, sorry about that. The numbers, your CapEx guidance numbers, does that include the announcements you put out this morning?
<A - Martin Salinas, Jr.>: Yes, sir.
<Q - John D. Edwards>: Okay, great. That’s all I had thanks.
Operator
And at this time we have no further questions. I will like to turn the call over to Mr. Martin Salinas for closing remarks.
Martin Salinas Jr.
Again, thanks everyone this morning for your time and attention. We look forward to a very strong 2012. Thank you.
Operator
Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Have a wonderful day.
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Additional Information
In connection with the proposed merger, ETE filed with the SEC a Registration Statement on Form S-4 that included a proxy statement/prospectus. The Registration Statement was declared effective on October 27, 2011. Southern Union mailed the definitive proxy statement/prospectus to its stockholders on or about October 27, 2011 and again on February 17, 2012. Investors and security holders are urged to carefully read the definitive proxy statement/prospectus because it contains important information regarding ETE, Southern Union and the merger.
Investors and security holders may obtain a free copy of the definitive proxy statement/prospectus and other documents filed by ETE and Southern Union with the SEC at the SEC’s website, www.sec.gov. The definitive proxy statement/prospectus and such other documents relating to ETE may also be obtained free of charge by directing a request to Energy Transfer Equity, L.P., Attn: Investor Relations, 3738 Oak Lawn Avenue, Dallas, Texas 75219, or from ETE’s website, www.energytransfer.com. The definitive proxy statement/prospectus and such other documents relating to Southern Union may also be obtained free of charge by directing a request to Southern Union Company, Attn: Investor Relations, 5051 Westheimer Road, Houston, Texas 77056, or from the Company’s website, www.sug.com.