Good day, ladies and gentlemen, and welcome to the Second Quarter 2011 Regency Energy Partners LP Earnings Conference Call. My name is Anna. I will be your coordinator for today's call. As a reminder, this conference is being recorded for replay purposes. [Operator Instructions] I would now like to turn the presentation over to Shannon Ming, Senior Vice President of Finance and Investor Relations. Please proceed.

Good morning, everyone, and welcome to today's call. Today, we will cover Regency's performance for the second quarter of 2011 as well as review industry trends and fundamentals. Presenting on today's call would be Mike Bradley, our President and Chief Executive Officer; and Tom Long, our Chief Financial Officer. Following our prepared remarks, Regency will open the call to participants for questions. You may access the earnings release and presentation news on today's call through Regency's website at regencyenergy.com. Our call is being recorded and is also being broadcast live over the Internet on the Regency corporate website. An archive of the webcast and presentation will be available on the corporate website following today's call. Slide 2 of the presentation describes our use of forward-looking statements and lists some of the risk factors that may affect actual results. Also included in the presentation today are various non-GAAP measures that have been reconciled back to GAAP. I would also like to note that we will be filing our Form 10-Q on Monday, August 8. With that, I'll turn the call over to Mike Bradley, our President and CEO.

Thanks, Shannon. And good morning, everyone, and thank you for joining us today. I'm very pleased to say that Regency had a strong quarter during which we continued to grow our adjusted EBITDA, announced several growth initiatives and also increased our cash distribution for outstanding common units. Before I go into our second quarter highlights, I would like to take the opportunity to discuss a more recent announcement. On July 29, Regency announced that it was approved to list its common units on the New York Stock Exchange, and we anticipate that our common units will begin trading on NYSE under the new ticker symbol, RGP, on August 9. We're excited to make this move to the New York Stock Exchange, which is a leading listing venue for energy companies. And many of our energy industry peers, including our general partner, ETE, are listed on NYSE. Now taking a closer look at Regency's highlights for the second quarter on Slide 3. Regency delivered solid financial results in the second quarter of 2011 with our adjusted EBITDA increasing to $103 million, which represents a 40% increase over the second quarter of 2010 and a 13% increase from the first quarter of 2011. In addition, we announced a quarterly distribution of $0.45 per outstanding common unit, which represents a $0.005 increase over our first quarter distribution. For the second quarter, Regency generated $71 million in cash available for distribution, which represents a coverage ratio of 1.03x. And then in May, we completed our public offering of $500 million of 6 1/2% senior notes due in 2021 to refinance revolver borrowings used primarily to fund the acquisition of the Lone Star Joint Venture. Looking at our operational highlights. Total Gathering and Processing segment volumes increased to 1.1 million MMbtus per day or 6% from the second quarter of 2010 to the second quarter of 2011. This increase was primarily driven by increased volumes across our South Texas and West Texas gathering systems. Total RIGS volumes increased 32% from the second quarter of 2010 to the second quarter of 2011 to 1.5 million MMbtu per day. This increase was due to the continued ramp-up of Haynesville Shale production over last 12 months. In addition to strong financial and operational performance, during the second quarter, Regency announced several organic growth projects. First, we're expanding our wellhead gathering system in the Eagle Ford Shale for approximately $450 million. The Eagle Ford expansion will include the construction of a 400-mile wellhead gathering system on approximately 150,000 dedicated acreage located in a liquids-rich producing area of South Texas as well as associated compression. In addition, as part of the agreement, Regency purchased certain existing midstream assets. The assets began generating revenue on June 1 of this year. For the month of June, Regency gathered approximately 100,000 MMbtus per day of gas through these assets, and we expect this volume to continue to ramp up over the next few years as we continue to build out the system. The Eagle Ford expansion is underwritten by long-term, fee-based contracts and significantly broadens Regency's South Texas gathering platform. The capital expenditures are expected to be incurred primarily over the next 3 years. And for 2011, $105 million of this project is already included in Regency's previously disclosed organic growth capital budget. Second, within the Lone Star Joint Venture in which Regency acquired a 30% interest in May of this year, we announced 2 significant growth projects, which we believe will help address the high demand for NGL transportation and processing that we see in the market, the first of which is the new 100,000-barrel per day NGL fractionation facility in Mont Belvieu, which is expected to be in service in early 2013. Total project costs are estimated to be between $350 million and $375 million, with Regency's proportionate share as being 30% or $110 million. The second major growth project announced by the Lone Star Joint Venture is the construction of a 530-mile NGL pipeline that will extend from Winkler County, Texas to Energy Transfer's Jackson County processing plant in Jackson County, Texas. The NGL pipeline will have a capacity of approximately 130,000 barrels per day with the potential to upsize. Total project costs are estimated to be no more than $700 million with Regency's proportionate share being approximately $210 million. The new pipeline is expected to be in service by the first quarter of 2013. We are very excited about Lone Star, which adds a significant strategic NGL platform, complements our existing asset base, expands our abilities to provide full-service capabilities for our producers in the midstream space and positions Regency for further significant growth over the years to come. Finally, we remain focused on growing our Compression and Treating business. As Tom will mention later, we have recently contracted an additional 50,000 horsepower that's expected to come online in the first half of 2012. Moving to our fundamentals, a slide on Slide 4. I first want to cover drilling activity. Total U.S. rig count increased approximately 22% from the second quarter of 2010 to the second quarter of 2011, primarily in rich gas regions. The land rig count in areas in which Regency operates increased to approximately 1,500 at the end of the second quarter of 2011, up from a little over 1,200 in the second quarter of 2010. This represents over a 20% increase year-over-year. Rig counts in West Texas increased by 141 from Q2 2010 to Q2 2011 or 51%. Although West Texas producers are primarily targeting oil-rich plays, these wells produced associated gas, and we are seeing increased activity around our Waha system. South Texas rig counts increased by 45 from Q2 2010 to Q2 2011 or 52%, which continues to support additional growth opportunities for our South Texas gathering system and the Edwards Lime joint venture. We continue to see declines in rig counts in North Louisiana as producers have moved rigs from the lean Haynesville Shale to more oil- and liquid-rich plays, but the Haynesville Shale remains a prolific field. We expect strategic drilling in the fairway of the Haynesville Shale to continue in 2011, and we anticipate there will be additional Cotton Valley wells drilled as long as we continue to see higher liquids prices. Moving on to Slide 5 and taking a look at commodity prices. The August NYMEX contract settled at $4.37 per MMbtu, and WTI crude averaged over $100 a barrel for the second quarter of 2011. Average pricing has improved across all liquids as record-high cracking margins have driven U.S. petrochem exports up, increasing demands for NGLs. And Slide 6 shows an overview of NGL fundamentals. High NGL demand and lower natural gas pricing have driven frac spreads to an all-time high. The high NGL frac spreads have led to increased NGL production over the past several years, and NGL production in the U.S. is expected to surpass 2.2 million barrels per day in 2012. And, as we have discussed, the Lone Star Joint Venture is well positioned to provide additional infrastructure necessary for increased NGL production. In summary, before I turn the call over to Tom, I believe Regency's recently announced growth initiatives and expanding portfolio position Regency to meet both our goal of increasing distributions as well as our goal of achieving investment-grade metrics. As the recently announced growth projects come online, this will create potential for further distribution growth over time without the need for additional acquisitions. I want to reiterate, management's focus is to increase shareholder value and grow quarterly distributions. This is what we wake up thinking about every single day. And with that, I will turn the call over to Tom who will take you through a review of our financial and business unit performance.

Yes, thanks, Mike, and good morning, everyone. Taking a closer look at our second quarter performance on Slide #8. As Mike mentioned, we are pleased with Regency's second quarter results. From the second quarter of 2010 to the second quarter of 2011, adjusted EBITDA increased by 40% from $74 million to $103 million. This increase was primarily driven by the acquisitions of a 49.9% interest in the Midcontinent Express Pipeline; Zephyr Gas Services, our contract Treating business; and most recently, a 30% interest in the Lone Star Joint Venture. These were partially offset by lower hedge prices in 2011 compared to 2010. Moving on to the segment margin, and we'll start with the Gathering and Processing. Adjusted segment margin decreased from $55 million for Q2 of 2010 to $53 million for Q2 of 2011. This decrease was primarily due to a $5 million impact from lower hedge prices. That was partially offset by higher volumes, which increased from 1 million MMbtus per day to 1. million -- to 1.1 million MMbtus per day in the Q2 of 2011. While total volumes increased overall, we saw the largest increase in our South Texas gathering system. NGL production increased to 28,000 barrels per day for Q2 of 2011 compared to 25,000 barrels a day for Q2 of 2010 primarily due to the increased production in South Texas. Taking a closer look at our volumes by region. For North Louisiana, volumes increased 2% comparing the second quarter of 2010 to the second quarter of 2011. This was primarily due to Logansport, where volumes from the expansion completed last year continued to ramp up as well as the drilling in the Logansport area of the Haynesville Shale. This was partially offset by declines around our Dubach system due to lower Cotton Valley production, as well as some declines at our Elm Grove and Dubberly plants due to Elm Grove field decline and the leading of the gas stream from Haynesville production. For the remainder of 2011, we expect total volumes in North Louisiana to remain relatively flat. Looking at West Texas. Second quarter of 2011 volumes increased 10% compared to the second quarter of 2010, and this was primarily due to the additional Bone Springs production. Excluding optional keep-whole processing, wellhead volumes were up 8% from Q2 of 2010 to Q2 of 2011. In West Texas, we did expect total volumes for the remainder of the year to increase. In the Midcontinent region, comparing the second quarter of 2011 to the second quarter of 2010, volumes, excluding the FrontStreet, increased by approximately 3%. FrontStreet volumes were down 7% compared to the second quarter of 2010. But since these assets provide fixed rates of returns and are not dependent upon throughput, there was no margin impact. For the remainder of the year, we expect Midcontinent volumes to hold relatively flat. Now looking at South Texas region. Volumes increased by 27% from the second quarter of 2010 to the second quarter of 2011 as producers continued to ramp up their Eagle Ford drilling program. For the remainder of the year, we expect volumes to continue to increase on both our South Texas system as well as the Edwards Lime joint venture. Moving on to Slide 10, our Joint Ventures segment. Our adjusted EBIT was $55 million for the second quarter of 2011 compared to $25 million for the second quarter of 2010. The Haynesville Joint Venture contributed $20 million, the MEP Joint Venture contributed $25 million and $11 million was from the first 2 months of operations at the Lone Star Joint Venture, which we acquired in May of 2011. For the Haynesville Joint Venture, total throughput volumes increased by 32% to 1.5 million MMbtus per day in the second quarter of 2011 compared to 1.2 million MMbtus per day in the second quarter of 2010. For the MEP Joint Venture, overall total throughput volumes averaged 1.2 million MMbtus per day in the second quarter of 2011 compared to 1.3 million in the second quarter of 2010. With subcontracts of 100% demand charges, financial performance was not impacted by this decline in volumes. And for the Lone Star Joint Venture, we are pleased with the performance of the asset. Since closing, total throughput volumes for the West Texas Pipeline averaged 128,000 barrels per day, and NGL throughput volumes for the refinery services were 15,000 barrels per day. Moving on to Slide 11 in our Contract Compression segment. In order to focus more on enhancing our services to our external customers, we are shifting the majority of the horsepower related to the -- to our Gathering and Processing segment to that segment and shifting the operations of those units to the shared services group under which we have an operating agreement with Energy Transfer Partners. Looking at revenue-generating horsepower, you will notice we are presenting this information differently than we have in the past to reflect this change in business focus. Going forward, we will only report horsepower that is owned and operated by our Compression business on behalf of external customers as that is the key driver of performance for this business along with fleet utilization rates. We plan to manage our fleet to maintain above 90% utilization based on horsepower owned and operated by the Contract Compression segment on behalf of the external customers. For the second quarter of 2010 to the second quarter of 2011, segment margins, excluding the margins from the horsepower owned and operated on behalf of the Gathering and Processing segment, increased from $32 million to $34 million primarily due to an increase in revenue-generating horsepower from 727,000 to 758,000. Utilization improved slightly from 86% to 87%. For the first quarter of 2011 to the second quarter of 2011, segment margin was flat at $34 million. We have recently contracted, as Mike mentioned, an incremental 50,000 horsepower primarily in the Marcellus, Eagle Ford and Barnett Shales, which is expected to come online in the first half of 2012. A portion of this horsepower will come from idle fleet. We currently have a little more than 110,000 horsepower in our idle fleet, and we expect to work this down as we continue to contract additional horsepower. Moving to our Treating segment. Segment margin was $8 million for the second quarter of 2011 compared to $7 million for the first quarter of 2011 -- 2010. As of June 30, 2011, revenue-generating gallons per minute was 3,368 compared to 3,268 at March 31, 2011. We believe our treating assets continue to be well positioned for growth in 2012 driven by demand from producer -- producers in the Haynesville and Eagle Ford shale. Now turning to our hedges on Slide 12. As of June 30, 2011, we have hedged 71% of NGLs, 81% of condensates and 63% of natural gas length for the balance of 2011, including our exposure through the ownership interest in the Lone Star Joint Venture. For 2012, we have hedged 39% of NGLs, 70% of condensates and 53% of our natural gas exposure. Looking at Slide 13. You can see a summary of our executed hedges by product. With the completion of the Lone Star Joint Venture with Energy Transfer Partners, our commodity price exposure has increased due to additional lengths in NGLs. We have combined our proportionate share of the equity NGL volumes with our other businesses to determine hedge volumes under our risk management policy. As to the sensitivity to commodities, for the balance of 2011, a $10 per barrel movement in crude oil, along with the same percentage change in NGL pricing, would result in an approximately $3 million change in our forecasted DCF. And a $1 per MMbtu movement in natural gas pricing for the remainder of 2011 would result in an approximately $1 million change in our forecasted 2011 DCF. Both oil and gas prices are positively correlated to Regency's DCF. And on to Slide 15. As you can see how Regency has increased its fee-based margins over time, approximately 82% of full year 2011 margins are expected to come from fee-based activity. Now looking at liquidity on Slide 16. As Mike mentioned, during the second quarter, Regency issued $500 million of 10-year senior notes at 6 1/2%. This transaction extended Regency's debt maturity profile from 6 years to 7 years. As of June 30, 2011, we had approximately $560 million of available liquidity on our revolving credit facility. And on to our capital expenditures. For 2011, our $345 million of projected organic growth capital expenditures included $168 million for the Gathering and Processing segment, which is inclusive of the 2011 expenditures related to the South Texas gathering system expansion; $95 million for the Contract Compression segment; $55 million to fund our proportionate share of the growth associated with the Lone Star Joint Venture; $12 million for the Contract Treating segment; and $5 million related to Corporate and Others segment. As of June 30, 2011, we have invested $124 million of growth capital, of which $73 million was for the Gathering and Processing segment, $45 million was for the Contract Compression segment and $5 million was related to the Contract Treating segment. In addition, we expect maintenance capital expenditures for 2011 to be approximately $17 million. And as of June 30, 2011, we have spent $5 million of maintenance capital expenditures. Now with that, I'll open the call up for your questions.

[Operator Instructions] And our first question comes from the line of Bernie Colson with Oppenheimer.

A question about -- I guess, well, it looks like excluding, well, the assets that, well -- proceeds that you're kind of right around 1, a little bit below. But we got an aid [ph] in the distribution. And I guess from past conversations that your target for coverage is around 1.1x. So I just kind of wanted to ask you philosophically how all that stuff fits together.

Yes. And Bernie, when we look at the decision to increase our distribution, it's really based on the outlook for our business. We felt very comfortable making a bump in second quarter. I think when you look at the fact that with the recent acquisition of Lone Star, the growth -- in fact, we've announced almost $800 million of growth projects that are all organic and primarily fee-based. So we got very comfortable with the distribution bump at this time. We'll continue to look at that on a quarterly basis and believe our coverage will continue to improve.

Okay. So no change, I guess, from that kind of 1.1 over the longer term?

That's correct.

Okay. Okay. And then can you just, I guess, remind us if I missed them, about timing of the projects for the Lone Star, Eagle Ford shale, when those are expected to come online?

Yes, both the NGL pipeline and the fractionator are expected to come online in early 2013.

Okay. Okay. And then one more question really is about Contract Compression. So clearly, the -- so you guys have kind of -- you're going to report it differently going forward? It looks like the margin is the same as the previous reporting, but the revenue-generating horsepower has been restated. Is that correct?

That's correct, Bernie. Once again, what we're focusing on is the external piece of it, and that's the -- these numbers are just stating the third party with a small piece of Gathering and Processing still in there, so.

Okay. So the margin numbers historically will not be restated. Is that correct?

Yes, that's correct. What you have to do, Bernie, is take out the -- in our segment margins, and so if you look back at our -- the charts that we've provided, now sitting down at the bottom shows you how much to back out. So the horsepower numbers we've provided in previous quarters with -- our Page 20 of our presentation gives you the chart, the historical chart. But if you look at our historical horsepower numbers, you would take the numbers we have today plus the incremental horsepower that we had for the Gathering and Processing segment. And then you would be able to get to -- you'll be able to tie those numbers out.

Okay. and then that last one, still on Compression here. It looks like quarter-over-quarter, the margin's down about $4.5 million or so. And since -- that, I assume, is -- I'm just having a hard time figuring out where -- whether that indicates a decline in the profitability there or that is going to show up -- did that show up in a different segment? Or how do we think about that?

It's -- the profitability in our Compression business is a still a very strong. That $4 million decline that you're seeing is the transfer of over 100,000 of horsepower that Tom mentioned in his talking points. This was Regency-owned compression that was operated by CDM. So that $4 million decline is absolutely associated with that.

Okay. And then so do we -- should we expect to see that in a different segment? I mean, I guess I'm just having a hard time figuring out how to...

Yes, Bernie, you should expect to see that in a different segment as far as segment margin goes. Keep in mind when you get to the EBITDA line that all the inter-company stuff is eliminated from an adjusted EBITDA standpoint.

Okay. All right, okay.

And our next question comes from the line of Heejung Ryoo with Barclays Capital.

Just on the Contract Compression segment, you mentioned you had some idle fleet capacity, and at the same -- and which will be used for some of these new contracts you brought in. But you're also spending $95 million for this year. So I'm just curious whether you would -- you are building more capacity in anticipation of robust outlook. If you could comment on that.

Sure. A couple things is, one, as we stated, we've recently contracted for 50,000 of incremental horsepower that come online in 2012. Some of that will be coming out of our idle fleet, and some of that will be new horsepower that we will purchase and package for those applications. Sometimes, in our idle fleet, applications come up where the idle fleet is not a good fit and we require new horsepower. On the other hand, we'll continue to work down our idle fleet as we go forward. So we don't -- we always want to keep a certain percent idle because I think that allows us to respond very quickly in case some new horsepower needs to be put in. So we're very comfortable with what we're targeting and the utilization that we expect to see over the next 6 to 12 months.

Okay. And then just a follow-up to that. What kind -- on your idle fleet, what's the -- is there a certain concentration of horsepower on your idle fleet versus men [ph] on new horsepower that is concentrated out on a different, I guess, different size or a different horsepower?

We have various [indiscernible] units in our idle fleet. They're are not concentrated all in one...

Not concentrated. Okay, got it. And then just switching gears on your new $450 million Eagle Ford gathering project. Could you comment on the return profile of that project? And also, you're not involved in the processing side, but just curious where that -- after you gather those -- I assume it's a rich gas gathering. And where are the downstream providers? Or who will be handling the downstream side of the processing and also for the downstream?

Our producer -- this is Mark Anthony. The producer will be handling the downstream transportation on that. We'll be gathering and conditioning the gas. We're moving the liquids and re-delivering that gas downstream for the producer.

Okay, And then just on the return profile?

Yes, on return profile, we haven't stated what the return is. But this project, we expect to be very accretive.

[Operator Instructions] And our next question comes from the line of Scott Fogleman with Morgan Keegan.

I just -- I hate to beat the dead horse here. But regarding the Compression segment and just the restructuring of it, you had mentioned in your prepared remarks that roughly 110,000 are currently idle. Should we think of those, that 110,000, as the remaining in the Contract Compression segment and are available for customers? Or is that going to be divvied up between the G&P segment and the Contract Compression segment?

That is available to be deployed for third party.

Okay, so it's going to be split between the 2?

No, no, when I say -- that -- those units are available to be deployed for our outside external customers.

All right, okay. And your -- you wanted to be about 90% utilized, and that would just be in your Contract Compression segment, correct?

Yes. First of all, let me just briefly -- I'll cover this, is we think the best strategy for our Contract Compression is to focus on third-party horsepower. CDM provided a lot of good service over the past couple of years in operating some of their Regency units. But we feel like the better strategy and the strategy that's going to provide the most growth in earnings is going to be the focus on third party. With the Energy Transfer operating agreement, we'll shift that horsepower over. And so now CDM is going to be 100% focused on growing our third-party business and servicing our existing client. We think that is the right move to make with this business. And in terms of the idle fleet, like I said, we've got a plan to reduce that fleet with some of the recently contracted horsepower, and we'll continue to move that down. But we think long term, this is a much better focus for our Contract Compression business.

Okay. And -- yes, and just to clarify the future spend. When you're buying more contract machines for Compression, I assume that those will go into the -- I mean, the lion's share of those are going to go into the Contract Compression segment, right, the new machines?

Yes, we expect all of them to go into the Contract Compression segment.

And one last question, just regarding the whole Energy Transfer Southern Union acquisition bid. Considering Regency's cost of equity capital is so much lower than ETP's, why does Regency not seem to be mentioned as a possible home for some of those assets to make it more accretive for all parties involved?

Well I think first of all, this is a transaction that's being worked on between ETE and Southern, and it's really not something that we can comment on at this point. Obviously, we're excited about it and there are some possibilities. But at this point in time, it's really not appropriate for us to discuss, nor have there been any discussions about what the future of those assets would be.

Ladies and gentlemen, there being no further questions, this concludes today's question-and-answer session. I would now like to turn the call back over to Mr. Mike Bradley for closing remarks.

Well, thanks again, everybody. And in conclusion, we are very excited about our business, the increase in distribution, the growth announcements and additional opportunities, we believe, they'll create for our Gathering and Processing business, Compression and Treating business as well as our recently acquired natural gas liquid business. As I stated, on top of the recent acquisition of the Lone Star Joint Venture, we have already announced over $800 million in organic projects. Almost 90%-plus is all fee-based business. So we are very excited about the outlook for our business and the potential to grow distributions over the next several years. We believe these projects put Regency again in an excellent position to achieve additional growth and expand our service offering, very importantly, for existing customers as well as new customers. And again, I want to reiterate our focus is to increase shareholder value and grow quarterly distributions, and that is what this management team is focused on every single day. Thanks again and have a great day.

Ladies and gentlemen, we thank you for your participation in today's conference. This concludes the presentation, and you may now disconnect. Have a good day.