Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2011 Regency Energy Partners LP Conference Call. My name is Stephanie and I'll be your coordinator for today. [Operator Instructions] I would now like to turn the presentation over to your host for today, Shannon Ming, Senior Vice President of Finance and Investor Relations. Please proceed. Shannon A. Ming: Good morning, everyone, and welcome to our call today. We will cover Regency's performance for the fourth quarter and full year 2011. Presenting will be Mike Bradley, President and Chief Executive Officer; and Tom Long, our Chief Financial Officer. In addition, Jim Holotik, our Chief Commercial Officer is also available for Q&A. 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 website following today's call. Also please note, we plan to file our 10-K on February 22. 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 appendix of the presentation today are various non-GAAP measures that have been reconciled to the comparable GAAP measures. Before we turn to today's presentation, we would like to say a brief word about Regency's 2012 Annual Investor Day. It will be held at the Crescent Hotel in Dallas on March 28. At this event, we will provide an in-depth look at our operations and discuss our growth opportunities. We hope that you'll be able to join us. If you're interested in attending, the invitation is posted to the homepage of our website. Please RSVP by e-mailing ir@regencygas.com or call us at (214) 840-5477. With that, I'll turn the call over to Mike. Michael J. Bradley: Thanks, Shannon, and good morning, and thank you for joining us today. I'm very pleased to say that Regency generated strong results for both the fourth quarter and the full year during, which we continue to grow our adjusted EBITDA, saw a significant increase in volumes in our Gathering and Processing segment and increased our distribution from an annualized rate of $1.78 in 2010 to $1.84 in 2011. 2011 was a significant and transformational year for Regency during which, we added a major NGL logistics platform with our acquisition of a 30% interest in the Lone Star Joint Venture. And as a result, we have a much larger scale and more diverse platform of services to offer our customers going forward. Additionally, our footprint within the major liquid-rich plays like the Eagle Ford Shale in South Texas and the Permian Bone Spring formation in West Texas have created tremendous growth opportunities. This footprint, coupled with the addition of the Lone Star assets, enables us to provide producers with a complete range of services from wellhead all the way to fractionation and NGL storage in Mont Belvieu, one of the largest NGL storage, distribution and trading complexes in North America. We have announced and plan to spend over $1 billion in organic growth capital over the next 18 months primarily in liquid-rich regions. These large-scale growth projects as well as the strategic location of our assets and active and emerging plays position Regency for additional growth over the next several years. We are very excited about the potential we see for Regency. I would like to briefly discuss our opportunities by business segment. Starting with Gathering and Processing, in 2012, we expect a total Gathering and Processing throughput to increase 25% to 30% over year-end 2011, primarily driven by growth in the Eagle Ford Shale and the Permian Bone Springs regions. In West Texas, it produces our targeting the liquids-rich plays and we have seen rig counts increase 35% from the fourth quarter of 2010 to the fourth quarter of 2011. We recently announced the Ranch Joint Venture for which Regency will construct and operate a new "100 million cubic feet a day cryogenic processing" facility and a new refrigeration plant in the Bone Spring and Avalon Shale formations. Our 2 partners are subsidiaries of Chesapeake and Anadarko. The refrigeration plant is expected to go into service in the second quarter of 2012 and the cryogenic processing plant is expected to go into service by the end of 2012. This joint venture increases Regency's footprint in the Bone Spring area, while also creating expansion opportunities around our Waha facility. In South Texas, we continue to see increasing producer activity in the Eagle Ford Shale, where rig counts have increased 47% from year-end 2010 to year-end 2011. Construction on our $450 million Eagle Ford expansion is underway and approximately 185 million cubic feet a day flowed in the fourth quarter versus approximately 110 million cubic feet a day in the third quarter. Additional volumes will be phased in as the project is completed with all capital expected to be deployed by early 2014. Upon completion, our entire South Texas system should be capable of gathering, compressing, treating and transporting up to 1 Bcf a day of natural gas. These expansions of these facilities and the increase of our geographic footprint in the area will allow us to create opportunities to attract and access new volumes to our system, again, offering the full-service package of gathering, processing, compression, treating and condensate stabilization. Additionally, Lone Star's new gateway pipeline will provide an NGL outlet for these liquids. Also important is the location of our Fashing in Tilden treating facilities, which provide us with a unique opportunity to offer sour gas treating services in the Eagle Ford Shale. Moving on to North Louisiana, our Gathering and Processing assets are seeing some slight volume growth from new drilling techniques in the Cotton Valley formation. The emergence of the liquid-rich Brown Dense formation in North Louisiana and Southern Arkansas were also likely to provide potential or additional opportunities as this play is developed. In our Transportation segment, total throughput volumes on our rigged assets were down 32% from the fourth quarter of 2010 to the fourth quarter of 2011 driven by the following 2 items. One customer has been offline since June due to an operational upset. Based on conversation with this producer, we anticipate a portion of these volumes will begin flowing again by the end of the first quarter. In addition, we have reached contract expiration on a portion of our agreements on our legacy system and based on current gas price environment, we do not expect volumes to return until drilling picks back up again. We currently have 8 years remaining on contracts with 85% demand charges on our expansion system. Moving on to Lone Star, in May of last year, we acquired a 30% interest in the Lone Star Joint Venture, which we are very excited about. This added a significant, primarily fee-based NGL logistics platform to our portfolio and the joint venture has since announced 3 major expansion projects. First, construction is underway on the 209,000-barrel-per-day gateway NGL pipeline which will deliver natural gas liquids from West and South Texas to Mont Belvieu. Regency's portion of the capital expenditures for the NGL pipeline is expected to be approximately $275 million. Lone Star will soon be completing an expansion of their existing West Texas Pipeline system which will allow additional interim barrels to be transported from West Texas processing facilities to Mont Belvieu utilizing their existing system. In the second quarter, Lone Star also announced it will construct a 100,000-barrel-per-day fractionator in Mont Belvieu to be completed in the first quarter of 2013. This fractionator is fully contracted. Additionally this morning, Lone Star announced that it will be constructing a second fractionator due to the continued strong demand which is expected to come online in the first quarter of 2014. This fractionator is presently 65% contracted under multiple long-term agreements. Regency's portion of the estimated capital expenditures for the 2 fractionators is expected to be approximately $225 million for both, and are supported by multiple long-term contracts, as we have indicated. For the Contract Compression, we have seen the compression market stabilize over the last quarter and we're now seeing growth opportunities primarily in some of the key liquids plays including the Eagle Ford Shale, the Permian Basin as well as in Southern Louisiana. We still also expect to see additional growth in the Marcellus and Barnett Shales in 2012. Our goal is to manage our idle fleet and to maintain a utilization above 90%. In the first quarter of 2012, over 85% of the horsepower expected to be set will be placed in liquid-rich plays, a portion of which will come from our idle fleet. On a previous call, we mentioned that we had approximately 50,000 horsepower under contract coming online in the first half of 2012. Approximately 30,000 of this horsepower will come from our idle fleet. We continue to secure additional commitments for horsepower and expect our revenue-generating horsepower to grow by approximately 15% to 20% by year-end 2012. And for Contract Treating, our focus in 2011 was to transition and modify our strategy to place more emphasis on liquid-rich regions and begin the process of adapting our fleet to make it more capable of handling higher concentrations of H2S versus CO2 for which the fleet was previously configured in 2011. In 2012, we expect our growth to primarily occur in the liquids-rich Eagle Ford Shale, Permian Basin and in the Utica Shale. In addition, we see other growth opportunities in the Fayetteville Shale, the northern part of the Barnett Shale, as well as in East Texas and in the Haynesville Shale. Given our current pipeline of opportunities and business strategies, we expect revenue generating GPM to grow by 25% to 35% in 2012. In summary before I turn the call over to Tom, I believe we are sitting on the strongest platform for organic growth Regency has ever had, thanks to the efforts and strong focus of the entire Regency team. We have approximately $720 million to $700 million of growth capital that we expect to invest in 2012, with the majority of these projects coming online in early 2013. This significant potential for growth over the next several years should position us to meet our goals of increasing distributions and achieving investment grade ratings. With that, I'll turn the call over to Tom, who will take you through a review of our financial and business unit performance. Thomas E. Long: Thanks, Mike. Taking a closer look at our fourth quarter and full-year performance on Slide 5, as Mike mentioned, Regency delivered solid financial results for the fourth quarter and full year. Regency's adjusted EBITDA increased 13% to $115 million in the fourth quarter of 2011 compared to $102 million in the fourth quarter of 2010. For the full year, adjusted EBITDA increased 29% to $422 million compared to $327 million in 2010. These increases were primarily driven by the acquisition of a 30% interest in the Lone Star Joint Venture, increased volumes in South and West Texas and in addition, the full year increase was also impacted by the full-year contribution from the Mid-Continent Express Joint Venture that we acquired in -- at the end of May of 2000. So we got 7 months worth of contribution out of that in 2010. Looking at Slide 6, it shows our Gathering and Processing segment's performance. Adjusted segment margin was $234 million for full year 2011 compared to $226 million for 2010. This increase was primarily due to volume growth in the Eagle Ford Shale in South Texas and in the Permian Basin in West Texas. Fourth quarter margins were impacted by some operational upsets at our South and West Texas Gathering and Processing assets. Throughput increased to 1.2 million MMbtus per day in the full year of 2011 compared to 1 million MMbtus per day during 2010. NGL production increased to 36,000 barrels per day for the full year of 2011 compared to 26,000 barrels per day in 2010. Despite a 19% decline in natural gas prices from the third quarter of 2011 to the fourth quarter of 2011, margins were still up as our fee-based business mix, hedges and increased NGL prices helped offset this drop in gas prices. Taking a closer look at our volumes by region, starting with North Louisiana, the volumes increased 7% from the fourth quarter of 2010 to the fourth quarter of 2011. This was due to additional drilling in the Logansport area of the Bossier and Haynesville formations. We expect drilling to continue in the Cotton Valley, and believe there is potential for Brown Dense volumes to start coming on to our system later in the year. For North Louisiana, volumes are expected to remain flat for 2012. In our Mid-Continent region, comparing the fourth quarter of 2011 to the fourth quarter of 2010, volumes, excluding Frontstreet, declined by 4%. Frontstreet volumes were down 10% compared to the fourth quarter of 2010. But as a reminder, since the Frontstreet asset provides fixed rates of returns and are not dependent upon throughput, there was no impact to the Regency's margin. For 2012, we expect Mid-Continent volumes to remain relatively flat. Now looking at West Texas, the fourth quarter 2011 volumes increased 30% compared to the fourth quarter of 2010, primarily due to increased volumes associated with additional Permian base and production. At the end of January 2012, we were able to ramp up NGL production as interim capacity became available on Lone Star's West Texas Pipeline. For 2012, we anticipate West Texas volumes will increase by approximately 40%. Now moving to South Texas, as we saw volumes increased over 100% from the fourth quarter of 2010 to the fourth quarter of 2011, this includes incremental volumes associated with the Eagle Ford expansion project. And for 2012, we expect volumes in South Texas to increase by approximately 25% over 2011, as we continue to expand our footprint. Moving on to Slide 7 and looking at the Joint Venture segment, adjusted EBITDA was $120 million for the full year of 2011 compared to $69 million for 2010. The Haynesville Joint Venture contributed $49 million for 2011 compared to $48 million for 2010. The MEP Joint Venture contributed $43 million for 2011 compared to $21 million for the June through December of 2010 period. The Lone Star Joint Venture contributed $28 million, since we acquired it in May of 2011. For the Haynesville Joint Venture, total throughput volumes on the RIGS pipeline averaged 1.3 million MMbtus per day for full year 2010 and 2011. Comparing the fourth quarter of 2010 to the fourth quarter of 2011, total throughput volumes decreased from 1.5 million MMbtus per day to 1.1 million MMbtus per day. As Mike mentioned, this was primarily due to one producer being offline since June of 2011. We are still receiving the demand-fee component of their rate and we expect some of these volumes to be back online by the end of the first quarter. Now looking at the Midcontinent Express Pipeline, total throughput volumes for MEP averaged 1.4 million MMbtus per day for the fourth quarter of 2011 compared to 1.5 million MMbtus per day for the fourth quarter of 2010. For the full year 2010 and '11, total throughput volumes averaged 1.4 million MMbtus per day. And for the Lone Star Joint Venture, for the fourth quarter of 2011, total throughput volumes for the West Texas Pipeline averaged 129,000 barrels per day compared to 133,000 barrels per day in the third quarter of 2011, and the NGL fractionation throughput volumes increased to an average of 18,000 barrels per day compared to an average of 14,000 barrels per day in the third quarter of 2011. Looking now at Contract Compression business, this is on Slide 8, from full-year 2010 to full-year 2011, segment margin increased from $131 million to $139 million primarily due to an increase in the revenue-generating horsepower, which grew from 767,000 at December 31, 2010, to 777,000 at December 31, 2011. For the fourth quarter, fleet utilization was approximately 86%. Now moving to the Contract Treating segment, segment margin increased to $30 million for the full-year 2011 compared to $11 million for 2010. And just as a reminder, we closed on that acquisition in September of 2010. So you have 4 months worth of contribution in 2010. From the fourth quarter of 2010 to the fourth quarter of 2011, segment margins decreased slightly from $9 million to $8 million. This decrease was primarily due to higher-than-anticipated installation expense that impacted segment margin during the year. Revenue generating gallons per minute increased slightly to 3,465 at year-end 2011 compared to 3,431 at year-end 2010. We believe our focus on liquid-rich plays positions us well for growth in 2012. Turning to Slide 10, you can see how Regency has increased its fee-based margins over time. Approximately 83% of full year 2011 gross margin came from fee-based activity. For full year 2012, we expect the fee-based portion to be approximately 81% of margins. Now moving on to our DCF, distributable cash flow sensitivity from Slide 11. Based upon where we are currently hedged for 2012, a $10 per barrel movement in crude, along with the same percentage change in NGL pricing would result in a $4.4 million impact to our 2012 DCF. And a $1 dollar per MMbtu movement in natural gas pricing would result in a $3.2 million change in Regency's 2012 DCF. And a $0.05 per pound change in the pricing of olefins would result in a $1.9 million change in Regency's 2012 DCF. Now turning to our liquidity position on Slide 12, as of the end of December, we had approximately $550 million of available liquidity on a revolving credit facility. And we will continue to, of course, use the revolver for short-term liquidity needs. And for 2012, we will continue to target a debt-to-EBITDA ratio in the 4 range, 4x range. Looking ahead to Regency's 2012 capital expenditures. In 2012, Regency expects to invest $720 million to $770 million in growth capital expenditures. The majority of the cap that will be spent for the Lone Star Joint Venture, as well as the Gathering and Processing growth in South and West Texas. This includes our share of expenditures for the second fractionator that was announced this morning, which -- yes, which we announced this morning. In 2012, we expect maintenance CapEx of $28 million and this is inclusive of joint venture spend. With that, I'll now open it up for questions.

[Operator Instructions] Your first question comes from the line of Ethan Bellamy with Baird. Ethan H. Bellamy: It looks like the gross DCF sensitivity to a change in natural gas prices changed from about, I think it was specifically $1.6 million to $7.6 million from 2011 to 2012. Just looking at the sensitivity table which you guys have provided in the opening presentations to the earnings calls. And I'm just curious, is that due to a change in the hedge amounts, the strikes or GNP contracts or to the LDH acquisition? Thomas E. Long: Yes. Yes, it really is more of a change in the level of hedging that we have owned. We -- I think, as you noted in the Slide 15 in the package here, we're at about 38% hedged now for 2012, which is quite a bit lower than where we were, as we were looking at 2011. Ethan H. Bellamy: Okay. And with respect to the activity that you have in the Marcellus on compression, are you seeing anything there that would interest you on expanding on GNP there? Michael J. Bradley: Yes, I think there's -- continues to be opportunities in the Marcellus that would be interesting to us. And I think, as we stated before, when we approach producers on the Compression business, we're also talking about the potential to gather and process our gas as well as treat. We're approaching them on a complete package. Ethan H. Bellamy: Okay. And it looks like there's really no one in sight to NGL production growth. Do you see any potential for incremental frac expansion beyond the incremental 100,000 amounts today? Thomas E. Long: I think we'll continue to look at the market. Obviously, we're very excited with our current demand for frac space. And if we continue to see strong demand, we can always take a look at expanding the fractionators further. Ethan H. Bellamy: Okay. And just one clarification in the organic expansion number in the release today that includes the fractionator announced this morning as well, right? Thomas E. Long: Correct.

Your next question comes from the line of Helen Ryoo with Barclays Capital.

First question is related to your Ranch JV, what will be ownership interest on that JV would be 1/3 each between you guys and Anadarko and Chesapeake? Thomas E. Long: That's correct. We're the operator of that.

Right. And I guess Anadarko and Chesapeake will be kind of contributing sort of the 1/3 of the total capacity on that plant each? The portion is for their interest? Thomas E. Long: Yes. The plant is built primarily for the Anadarko and Chesapeake volumes that are in that area.

Okay. Okay. And I guess you're just putting in the 25 refit -- refrige to have the capacity available for when the volumes show up. But ultimately, you will be running the 100 cryo when it comes online? Thomas E. Long: That's correct. The 25 million a day refridge was something that we could get in quickly that would help us to remove some of the constraint that we had on our Waha facility, and allow us to open up additional capacity at Waha. So we were able to get that in quickly and we would most likely continue to run it as a front-end unit when the cryo was in, full cryo was in. We would be able to get that in probably sometime in the second quarter where the full cryo will be in at the end of the year.

Right. Okay. And I guess all the liquids would be going to the Lone Star? Thomas E. Long: That's correct.

Okay. And is the 100 enough? I mean, do you see the need for further expansion on the Ranch JV planned capacity? Thomas E. Long: Well we certainly have our anticipated -- or hopeful that we'll be able to expand this facility. So we're -- when we install it, we want to install it with that in mind. Well currently, for the area though, we're thinking that 100 would be available and then we -- our debate is to whether to we'll further this to expand at this particular side of the Waha facility or further back into the field.

Okay. Got it. And then during the prepared remarks, the -- you mentioned, I guess, West Texas volume was increased 40% this year? I think that was my comment but... Thomas E. Long: Yes, that's correct.

Right. And just wondering, would you have to take away capacity to -- 2012 it would be before gateway comes into service. So -- and you did mention that you had some capacity available at these Lone Star lines this quarter to accommodate the volume growth there. But just wondering, when you see that 40% growth in West Texas volume, would that be able to come to market on the, I guess, that there would be enough takeaway capacity to take that? Thomas E. Long: Yes. To answer your question, #1, there was an expansion of existing Lone Star system which will allow additional interim barrels to come out of the West Texas region, so we'll be able to utilize that. Additionally, at the Ranch JV, we're anticipating a solid and a truck loadings racks to where we'll be able to truck some of the volumes out, if it's necessary.

Okay, got it. And just moving over to the CapEx number, I think the total CapEx included about 245 on the GNP spending. Is that all going into the Eagle Ford gathering project, the 450 gathering project that will, I guess, that will be completed in 2014? Or is that something else? Thomas E. Long: Just primarily the Eagle Ford and West Texas.

Okay, Eagle Ford and West Texas. Right. Okay. The -- and that project, the Eagle Ford gathering project, would you be seeing some cash flow before the full completion date in 2014 or what we have to...? Michael J. Bradley: Yes, as we are expanding the system, volumes are coming on. So we are seeing cash flow from that project increase, as again, as we continue to build out. So it's not -- we don't have to spend all the capital and wait for the cash. It's coming on as we build.

Okay. Got it. Okay. And then just lastly, what was your debt-to-EBITDA ratio for this quarter? Thomas E. Long: Yes, the debt-to-EBITDA, we were at 3.6.

Your next question comes from the line of Cathleen King with Bank of America.

Just one question for me. I was wondering if you could clarify what was in that -- your adjustments line on your DCF? There is about $12 million of positive adjustments there in that line? Shannon A. Ming: It's asset sales and stand and adjustments from management services fee that we get from our joint venture. It has $13.8 million of asset sales.

$13.8 million for the quarter? Shannon A. Ming: $13.8 million of asset sales and of that $13.8 million, roughly $10.5 million is from compression assets that we contributed to the Ranch JV.

Okay. Okay. So similar to that $12 million is basically non-recurring, then? Shannon A. Ming: I'm sorry, Cathleen, you are breaking up pretty...

I'm sorry. Just saying similar to that $12 million are positive debt and is not recurring, is that correct? Shannon A. Ming: That is correct.

Your next question comes from the line of Scott Fogleman with Morgan Keegan.

I just have a question, excuse me, regarding compression and what are you seeing especially in the Fayetteville and South Louisiana in particular with, obviously, natural gas prices are quite low. Are you having difficulties recontracting or are people just packing up and leaving? Michael J. Bradley: I don't know. I think that the Fayetteville, we expect to stay pretty steady. As volumes decline, pressures typically decline along with those. So the need for compression remains in South Louisiana. We're seeing pretty good opportunity with the particular producer that has acquired some production in the area and we will be adding compression to the system over the course of 2012.

Okay. You mentioned that you're about at 86% utilization rate currently. Are you -- I mean, that's a little bit, I think, lower than what you've guided to in the past. Is that a good number to look at going forward? Or do you think that you'll get back up to like 90% or so, 88%, 90%? Michael J. Bradley: No, we expect and our target is to be above 90% utilization by the end of 2012. As I mentioned, we contracted for about 50,000 horsepower. I think we mentioned that in the third quarter. That was coming online in the first half of 2012 and about 30,000 of that horsepower is coming from our idle fleet. We continue to find opportunities to further utilize our idle feet. So we're targeting above 90% by the end of 2012.

Great. And just one last item, I think when you originally bought the Zephyr business a year ago, you had given guidance towards about 10x EBITDA for the first year then 7x thereafter. Are you confident with that scenario? Or has there been any change to that? Michael J. Bradley: I can't comment on the 10x or 7x since I wasn't really here at the time. But I can tell you that the EBITDA multiple on that business will continue to improve.

[Operator Instructions] The next question comes from the line of Avi Feinberg with Morningstar.

On the Haynesville Joint Venture, I think you said you expect some of the volumes to come back online by the first quarter. Do you expect all those volumes to come online within that timeframe or by this early portion of the year? Or is that kind of ongoing event? Thomas E. Long: That could be ongoing determined by the producer and by the facilities that they are repairing and putting in place. We know that -- we're hoping that the majority of the facilities will be finished by the end of the first quarter that will allow the majority of the gas to come online. But it's going to be up to the producer and the facilities when they complete them.

Okay. Is it fair to assume that most or close to all of the contribution from the joint venture during the quarter was driven by the reservation charges? Thomas E. Long: Well, on our expansion, we've got 85% of our agreements are demand-based. But -- so we have the large or a portion of that, it's also commodity. Then on -- and then we have our legacy shippers also that are demanding commodity.

Okay. Okay. I'm moving to the Ranch Joint Venture, just was curious if you could talk a little bit more about the saw process on how that arrangement came to be? I mean, I guess both Anadarko and Chesapeake could have their own respective MLPs, where they've dropped down midstream assets? And was that just a function of Regency's footprint in the area or what kind of brought that together? Thomas E. Long: Well, primarily, yes, that's correct, regency's footprint in here. And one thing's that -- is helped us both in West Texas and in South Texas that's allowed us to be one of the -- a very good competitor in those areas is that we have existing facilities in the area. So that we can utilize our Waha facilities to process their volumes out of the Bone Spring to West Texas, while we step into this Ranch JV. Additionally, the addition of the Lone Star helped with the takeaway capacities that they were able to offer during their West Texas expansion.

Okay that's helpful. One other question, just was curious if you could talk about the -- with the fractionators, you mentioned investing into connectivity that you're building out and I'm curious how that kind of factors into Regency's competitive advantages with respect to other competitors who offer, or I should say, compare to some of your competitors who offer the similar full-package type of services? I mean, does that -- do you think that, that differentiates Regency in any way? And what specifically does that connectivity include? Michael J. Bradley: Well, I think it does differentiate Regency and I think it's been a benefit that we have seen since the acquisition and I think it's been a benefit to energy transfer as well. We're very excited about the Lone Star Joint Venture. I think that you can tell we had some excellent ideas going into that acquisition and we're executing on those via the expansion of the pipeline, 2 fractionators and we're moving very quick. And I think that has been a benefit to our partnerships to have that available to producers, and I think it's provided a very important competitive advantage. I think the connectivity we're able to offer today, full service from wellhead whether it's treating compression all the way just to Mont Belvieu's storage and fractionation. And I think that's an attractive set of services that we can provide our producers today.

Okay. And just with some of those expansions, are the additional connectivity you're investing in, does that require permitting processes? And I understand that sometimes it can be difficult to obtain those permits or the land that's necessary to build those. I mean, is that all possible based on Lone Star's existing assets? Michael J. Bradley: Well, I think all of the new expansions require permits to move forward with a drive away or environmental permits, but we're well down the road on those and don't expect those to cause any problems for us.

With no further question in queue, I will now like to turn the call back over to Mr. Mike Bradley for any closing remarks. Please proceed. Michael J. Bradley: Okay. Well thanks everybody for joining us today. And again, in conclusion, we're very excited about what we see ahead for Regency. And as I mentioned, have approximately $1 billion in organic growth projects coming online over the next 18 months. These clear assets are positioned to capitalize on more growth in the Eagle Ford Shale and the Permian Basin along with the emerging regions like the Brown Dense and the Mississippi in shale formations. We believe Regency is in an excellent position to achieve additional growth and further expand our service offerings to our customers. And again, as I always say, and I want to iterate our commitment, is to increase shareholder and unitholder value and to continue to grow our distributions. With that, have a great day.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Great day.