Good day ladies and gentlemen and welcome to the first quarter 2010 Regency Energy Partners LP earnings conference call. My name is Eric; I’ll be your audio coordinator for today. At this time, all participants are in a listen-only mode, and we will facilitate a question-and-answer session at the end of the presentation. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to Shannon Ming, Vice President of Investor Relations and Corporate Finance Support. Please proceed.

Good morning, everyone. Welcome to our first conference call. Today, you will hear from Byron Kelley, our Chairman, President and CEO and from Stephen Arata, our Executive Vice President and Chief Financial Officer. Following our prepared remarks this morning, we will turn the call over for your questions. Distribution of the press release and the slides that we use today are available on our website at www.regencyenergy.com. The first slide is a 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 or generally accepted accounting principles. These schedules are at the end of the presentation starting on slide 27. With that, I will turn the call over to Mr. Kelley.

Well, good morning. Let me add my welcome to each of you for joining us today. We always look forward to providing with you an update on the Company’s performance as well as reviewing with you the current market trends that are taking place in our industry. We will begin really the presentation on slide three, and I would invite you to turn to that page and presentation. I’d like to being with touching on some highlights from the first quarter and begin with our operational achievements. Our diversified assets generated a very solid adjusted EBITDA growth in the first quarter of 2010. I think this performance is a testament to our strong fee-based set of assets, and to the focus and hard work of all our employees. First quarter was also an important juncture for Regency as we placed the Haynesville expansion project in service in January, late January and this as you recall the first major pipeline extension to come online in the Haynesville region. Our capacity on both the expansion and on the Red River Lateral extension that we added after the project began are fully subscribed, and the time of completion of this project to meet our customer commitments as well as bringing the project to fruition on the budget is indicative of the quality of our commercial technical operation and the financial teams at Regency in. I certainly want to extend my sincere appreciation to all of the Regency employees for job well done with this project. Moving on to some highlights on our financial achievements; we successfully refinanced our credit facility in March extending the maturity date to June of 2014. Also during the first quarter, Regency’s outlook was modified from negative to stable by Moody's and Standard & Poor's. And as you're aware, our first quarter 2010 distribution was online with our expectations at $44.5 for outstanding common unit or $1.78 for outstanding common unit on an annual basis. And as a reminder, our distribution is offset by the Board of Directors, and is driven by the long-term sustainability of the business. And then too finally in the first quarter, Regency generated $45 million in cash available for distribution representing our covered ratio of 1.06. Moving to growth achievements, I already mentioned the placement of our rig system and expansion of that system in service. Additionally, we continued construction on phase I and phase II of the Logansport expansion project. Both are expected to be completed in July 2010, and we’ve already seen some volume ramped up based on the interconnect work that’s already complete. Moving to Eagle Ford Shale, we added new volumes to the addition of five new wells during the first quarter, and we continue to work on ways to expand, enhance our facility to make produce remains in that region. In Marcellus Shale, we have now established a solid foundation, a solid footprint in that area with compression contracts already signed to add over 20,000 horsepower in 2010, and we believe there is more to come in that compression region as well. I’d like to move to our fundamentals on slides on page five, contrary to the decline in natural gas prices that we saw in the first quarter in 2010, the U.S. land rig count continued to increase reaching a high of little over 1400 rigs at the end of the first quarter. This represents a 6% increase year-over-year compared to the 1338 rigs at the end of the first quarter in 2009. It also represents a 19% increase quarter-over-quarter compared to the 1188 rigs at the end of the fourth quarter of 2009. And even more positive indicator for Regency is that the land rig count in the areas in which Regency operates increased to 1065 rigs at the end of the first quarter of 2010. This is a 11% increase compared to the 956 rigs that were in operation at the end of the first quarter 2009 and a 20% increase quarter-over-quarter compared to the 889 rigs at the end of fourth quarter of 2009. Generally the high crude gas ratio has increased the relative attractiveness of rich gas plays which have a higher ore component supporting increased drilling activity around our assets in both South Texas and in West Texas. And we are once again beginning to see some producing interest around Cotton Valley drilling on our Dubach system in North Louisiana. In the region in which we operate our gathering assets comparing the first quarter of 2010, to the first quarter of 2009 rigs increased year-over-year in West Texas by 81% and Appalachian region by 45% and the Mid-continent region by 17% and the South Texas in 15%. With the largest decline as you can see on the charts be on the Barnett Shale at a negative 32 rig count. Generally as we look at the increased efficiencies in drilling technology. We believe that the current rig counts are sufficient to meet the expected natural gas demand in the market over the next four to five years. Now moving to slide six, we will look at some of the fundamentals around commodity prices. Although NYMEX prices have declined from their peak settlement of $5.81 per MMbtu in January of 2010, the Q1 average settlement price was still higher than average settlement price for Q4 in 2009 after hitting this peak natural gas prices declined throughout the remainder of the first quarter of 2010 as supply demand imbalances led to some rapid inventory bills. Exacerbating the issue really was as extremely mild March and record warm temperatures in April. In April, we saw inventory builds of over 10 Bcf per day brining in the total gas and storage to nearly a 100 Bcf average above a year ago levels. But the news on the crude front in much better, West Texas Intermediate Crude averaged $84 a barrel for April which is up approximately 70% from a year ago and while NGL prices did see some volatility throughout the first quarter. The average prices were all components throughout the peak as compared to any quarter in 2009 with heavier products maintaining a strong relationship crude and trading up over the fourth quarter. Ethane prices did after seeing a peak in February declined throughout the balance of the quarter primarily driven by two factors, there was lower petrochem demand; of ethane is a feedstock and additionally ethane supply as were brought into the market due to the high natural gas to ethane frac spreads. The current forward curves for natural gas and crude pricing suggest that natural gas will average a little under $4.60 per MMbtu for the year and then crude will average approximately $80 a barrel as well. Now to move to slide eight is where we announced April the 30th that we had acquired approximately 7% in Haynesville joint venture from an affiliated GE Energy Financial Services for approximately $92 million. In that transaction we also acquired the right to vote the interest retained be GE Energy Financial Services so that we have voting rights on full 50% interest. The transaction was funded using Regency revolving credit facility and we expect that this addition of this asset into our portfolio will add an incremental $7 million in adjusted EBITDA for 2010 for the eight months of operation. I would remind you as we presented to you in our investor day that the $7 million is already built into the EBITDA guidance that we provided you on that day and that range was $255 million to $285 million. Including the additional 7% interest, Regency's total interest now is $49.99%. Alinda Capital Partner retains their 50% ownership interest and Regency continues as operator of the asset. From page nine, there is a slide here; you have seen the slide before. It shows the location of the pipeline and has a summary of our activity in this region over the past several years. Regency's increased stake in the Haynesville joint venture is consistent with our long term strategy of increasing fee based assets and of expanding our pipeline transportation. Both of these are smaller contributors to long term stable cash flows. This is an extremely important region for Regency and as a long supply basin for the United States natural gas market and the joint venture continues to be very interested to validate additional expansion opportunities in the region. Actual timing of an expansion will be producer and market demand driven but we believe the Regency Intrastate Gas System is the best positioned pipeline to offer a cost effective and timely solution for incremental pipeline takeaway capacity in the region. I'd like to move into our business review section and get a little bit more details around our first quarter performance and I would invite you to turn to page 11, slide 11 at this time. Despite the continued overall lower U.S demand for natural gas and competitive pricing environment in our contract compression business, Regency's first quarter results remained very strong and we were very pleased with our success in this quarter. Comparing the first quarter of 2010 to the first quarter of 2009, our adjusted EBITDA increased by 11%, a year-over-year from $54 million for Q1 2009 to $60 million for Q1 2010. For the first quarter of 2010 we generated $136 million of combined adjusted total segment margin, compared to $106 million for the first quarter of 2009. This is a 28% increase and I would mention that each of Regency's four businesses experienced gains in a year-over-year comparison. The increases in adjusted EBITDA and segment margin were principally driven by incremental revenues associated with the completion of the Haynesville project while higher realized commodity pricing by an increase in South Texas volumes as a result of the increased drilling in the Eagle Ford Shale region, by higher West Texas processing volumes and higher West Texas margins and additional details around our EBITDA and adjusted EBITDA are outlined in the appendix on slides 27 and on slide 30. Moving into the details around our transportation segment on slide 12. Our combined transportation segment margin accounts for 100%, and these numbers account for 100% contribution from rigs for the entire quarter. And in comparing the first quarter of 2009 to the first quarter of 2010, the combined transportation segment margin increased by almost 150% from $14 million Q1, 2009 to $34 million in Q1, 2010. Total throughput increased from 811,000 MMBtu per day in the first quarter of 2009 to 883,000 MMBtu in the first quarter of 2010, and this represents a 9% increase. Although this is a sizable increase, there were a number of factors that did negatively impact throughput in the first quarter. Our legacy volumes were down year-to-year primarily as a result of the decline in the Cotton Valley drilling, and we talked a lot about that last year, and are also as a result of the low basis spreads impacting interruptible volumes. I would also remind you that the first quarter of 2010 results include only two months from Haynesville expansion project, is that project going in service on January the 27th. And then the foreign volumes were also on this pipe, were also impacted by some weather-related construction delay on upstream producer facilities. As these facilities replaced in service, and some of that is taking place as we speak, we expect our transportation segment volumes to further increase throughout 2010. I would mention, remind you that because of the vast majority of our rates are collected and fixed demand charges that’s reduction in foreign volumes related to the expansion, did not have a significant impact on our combined transportation segment margin in the first quarter. But with the added fixed demand charges from the expansion project and affect for two months of the first quarter are just a segment margin for MMBtu increase year-over-year from $0.19 in Q1 of 2009 to $.43 in Q1 of 2010. Moving on the gathering and processing segment on slide 13. our volumes were relatively flat, as compared to the first quarter of 2009, as and the first quarter of 2010, but our adjusted segment margin increased by approximately 6% from $55 million to $59 million contributing to the strong performance in this segment during the first quarter were increased volumes of rich gas in South Texas associated with the drilling and Eagle Ford Shale. Higher margins associated with gathering and processing of additional volumes in West Texas improved processing economics in general in North Louisiana and West Texas and a prudent expense management. These factors basically served offset some of the lower volumes we had in North Louisiana and the Mid-continent and in East Texas. Although, volumes were basically flat. Our NGL production increased 13% year-over-year to 26,000 barrels a day in the first quarter of ’10 from 23,000 barrels in the first quarter of 2009. and overall our adjusted segment margin for MMBtu increased 7% year-over-year from $0.59 to $0.63 in the second quarter of 2010, and this increase was pr9imarly driven by higher realized commodity prices and by an increase in amount of the rich gas that we gathered in process. We like to give you details on a region-by-region basis, and I’ll walk through this beginning with North Louisiana comparing the first quarter of 2010 to the first quarter of 2009 In North Louisiana volumes decreased by 31% over the year and our Dubach facility driven by the sharp decrease in drilling in Terryville field. As you recall we talked about this subject last year with the high prices there was a lot less drilling in that area and so with those low gas prices we saw drilling in the Terryville field area essentially shutdown with the associated production steadily declining from a $144 million in the first quarter of 2009 to approximately a $100 million MMbtu per day at the end of the year. The good news is though that we are again seeing producing interest in the Cotton Valley around at least around our Dubach gathering and processing system. We think this is going to result in stabilization of volumes and we are now expecting this asset to remain relatively flat for 2010. As we look at North Louisiana, the story is much better and the Logansport area as you know we have been expanding that system and expanding in addition to the projects that we have announced, we have also expanded our take away capacity by almost $40 million a day by adding an interconnect with Tennessee Gas pipeline and an interconnect with CrossTex LIG's pipeline system. So, volume for the first quarter of 2010 on a Logansport system were up 22% compared to the first quarter of 2009. Moving to West Texas, drilling on our West Texas footprint has rebounded to its highest level since prior to the collapse of the financial markets in the second half of 2008. Our business development and our regional service teams continue to add new well head supplies during the first quarter of 2010 and year-over-year volumes increased by 27% on a quarter-to-quarter comparison from 2009 to 2010. Moving to the Mid-continent, our volumes declined there on a first quarter of ’10 to first quarter of 2009 comparisons of those volumes declined excluding FrontStreet by approximately 10% year-over-year which is fairly close to the traditional decline curve. As you are aware we exclude the FrontStreet because our contracts there are essentially a rate to return type contracts and we are really not impacted by the volumes through that system. So, we would like to compare the volumes on our non- FrontStreet assets and they were down about 10%. This is not a surprise to us and we expected it in our plan. Just very little producer activity around those assets during the first quarter, we did sign up one small package of gas contractually at our Logan system and that gas will start producing in the third quarter of this year. East Texas comparing the first quarter of 2010 to the first quarter of 2009 our volumes declined about $3 million per day. However, late in the quarter we did add about $8 million of new supplies towards the very end of the quarter and got very little – and looking at our average numbers that very little impact from those numbers. Another important and good news out of the East Texas region as sulfur prices have improved from the first quarter of 2009 to the first quarter of 2010. As of May 1st, the second quarter sulfur contract settled at a $145 for long term which equates to approximately $80 for long term net to Regency. You may recall for a number of quarters last year we actually had negative margins after we paid shipping on sulfur prices, so this has been a very nice ship back to seeing demand of sulfur increase in the move to this very strong prices in East Texas for our sulfur products. In South Texas for the full region year-over-year volumes increased 43% from the first quarter of 2009 to the first quarter of 2010. On the South Texas gathering system itself, volumes increased 48%. On our Edwards joint line venture the volumes increased 25%. We added five new wells to our system. Three of those were on the South Texas gathering system and two of those were on the Edwards line joint venture system. The volume asset ramp up, although very strong has been a little less than we previously forecasted but at the same time we've seen a shift in the drilling activity to richer areas of the Eagle Ford Shale and this has resulted in higher per unit margins and higher overall margins for us in the regions. We do expect to see activity continue to ramp up in Eagle Ford shale in the second quarter and throughout the rest of the year. But as we look at our comparison of what we produced in 2009 to our estimate for 2010, we previously gave you an expectation that volumes for that region would increase about 67%. With some of the slower ramp up, we are now expecting that volumes will increase for the year about 50%. But I would also remind you that we are seeing much higher per unit margins and we don’t think that the volume decline is going to having any significant impact on our forecast for the year. I'd like to now talk about the contract compression segment on slide 14. As you know, last year was a challenging year for the contract business in general but we came through that year with some pretty good results, meeting our expectations for that business and despite the low production levels in some of our compression markets right now and the continued competitive pricing environment, our contract compression segment again performed inline with expectations for the first quarter. The Q1 2009 to 2010 major comparisons are as follows. Our revenue generating horsepower increased a little less than 1% from 753,000 to 760,000 horsepower continuing the slight upward trend that began in this business in Q4 of 2009. Segment margin remained flat at $37 million and our average horsepower per revenue generating compression unit also remained flat at 858 horsepower and that’s a ratio that remains significantly higher than any marked contract compression peers. We placed in operation our first units in the Marcellus Shale in January. We've established a strong footprint in this emerging play, requiring [ph] commitments over 20,000 horsepower. We're in discussions with potential customers for additional commitments and we continue to believe this market represents an attractive growth opportunity for Regency for many years to come. With our recognized commitment to highest service levels in the industry and corresponding value proposition for our customers, we are well situated to take advantage of increasing demand for compression in the near term that we see in the Marcellus Shale, Eagle Ford Shale and some in the Fayetteville Shale and over the longer term, we see opportunities that will continue in the Barnett Shale, Haynesville Shale and then some of the conventional maturing plays along the Gulf Coast. So this summarizes our business review for the first quarter. We will have questions later around any details you'd like to discuss further but at this point I’m going to turn the presentation over to Stephen Arata to walk us through the financial section.

Thanks Byron. If you turn to slide 16, we have our consolidated operating results year-over-year. For the three months ended March 31st, Regency had a net loss of $0.6 million compared to net income of $148 million for the first quarter 2009. The year-over-year change was primarily due to the assets of the gain associated with the contribution of rigs to the Haynesville joint venture, which accounted for $134 million of the difference. In addition, we had a $7 million decrease primarily related to a mark-to-market change in the value of our commodity derivatives and a $3 million decrease in other income and deductions, which primarily relates to the non-cash value change associated with the embedded derivative related to the Series A preferred units, which we issued in September of last year. Quarter-over-quarter, we reduced our O&M cost by 10% and while our G&A cost have increased less than 4% year-over-year. on slide 17, we show our commodity price risk management status. We currently have 73% of NGLs hedged, 84% of condensate and 74% of natural gas linked hedge for the balance of 2010. In the first quarter, we executed additional hedges for 2011, and as a result we have now for 2011 hedged 41% of our NGL equity linked. We’ve hedged 50% of our condensate equity linked through WTI crude swabs, and 23% of our 2011 natural gas links. A summary of our executed commodity hedges is shown on slide 18. Consistent with our quarterly hedging program, we implemented a few quarters ago, we plan to begin layering in our 2012 hedges during the current quarter. Slide 19 shows our sensitivity to commodity price changes for the balance of this year. As the chart shows the $10 per barrel movement include along with the similar percentage change in NGL pricing resulting a $2.4 million change in our balance of the year DCF and a $1 per MMBtu movement in natural gas pricing would result in a $0.8 million change in our 2010 balance of the year DCF. I’d like to finish up on slide 20 with the liquidity update. During the first quarter, as Byron mentioned we successfully refinanced our credit facility extending our maturity from August of 2011 out to June of 2014. We maintain the size of our facility at $900 million while reducing the number of lenders from 26 to 19. We did this all with no change to our pricing grid well improving several other key terms and conditions in the agreement. Importantly among those, we have an increase in the amount of lot of investment into the Haynesville joint venture from $135 million to $250 million. We have the addition of an allowance for additional joint venture investment up to $75 million outside of the Haynesville joint venture. We’ve modified the financial covenants to give credit for projected EBITDA associated with future material Haynesville joint venture projects, and lastly we have an increase in the general asset sales permitted from $20 million annually to 5% of our consolidated net intangible assets annually. In April, we entered into $250 million of interest rate swabs effectively lock-in a LIBOR base rate for borrowings of 1.33% to April of 2010. On the organic growth side, our capital now for the 2010 is expected to be $180 million, which is up a little over $10 million from our last update primarily in the contracting compression segment is that business continues to deliver on expected opportunities. We now have a $148 million expected of spending related to the gathering and processing segment, $24 million for contract compression, and $8 million in our corporate and other segment. In addition to our expected organic growth, on our wholly owned business, we expect to invest $23 in 2010 to fund our share at the Haynesville joint venture growth off which $20 million is already been funded to the end of the first quarter which was our piece of the Red River Lateral capital. In the first quarter of 2010, we expanded our business to approximately $29 million of organic growth projects excluding any spending related to the Haynesville expansion projects, $21 million of that was spend on the gathering and processing segment and about $21 million of that was spent on the gathering and processing segment and about $8 million was spent on the fabrication of new compressor packages in our contract compression segment. In the first quarter, we incurred approximately $4 million of maintenance capital expenditures to replace partially or fully depreciated assets or to maintain the existing operating capacity of our assets and extend their use. The total available to Regency under our credit facility as of May 1, 2010 was $318 million and that was after the $92 million we spent on April 30 to purchase the additional interest in the Haynesville joint venture. We believe our balance sheet is strong and we are well positioned to meet all of our growth capital needs for 2010. With that I would like to open it up for Q&A.

Thank you. (Operator Instructions). Your first question comes from the line of Jeremy Tonet with UBS. Please proceed.

Hi. Good morning.

Hi, morning Jeremy.

I was wondering at the JV level, the Haynesville JV, is there any leverage currently employed or what’s the thinking around that for your future expansions?

This is Stephen, Jeremy. We have very small working capital facility at the joint venture now; it’s a $25 million facility. At the end of the first quarter we had about $4 million drawn on that just for purposes of running the business. We do not have any leverage now although we do expect future capital projects at the JV to be funded through that which would eventually give us capital structure more in line with our peers at that asset. But for now we don’t have any plans to put leverage there.

Okay great and then shifting over to the corporate and other segment, it came in a bit stronger than we anticipated. Would you be able to provide a bit more color on what the drivers were driving the increases year-over-year?

The biggest driver there is well there is two significant businesses there; one is our Gulf States, our pipeline interstate pipeline that connects into rigs. That business did a little bit better year-over-year but the real driver here is the function of how we account for the Haynesville joint venture. We get reimbursed by our partners for the general and administrative cost and that we bear to run that joint venture and that reimbursement shows up as a margin in our corporate and other segment. And so we would expect that to continue to be relatively strong throughout the rest of the year.

So, is this kind of a good run rate for us then at these levels or?

It's probably a little bit high but it's going to be much more in line than what you've seen historically.

Great, that’s helpful, thank you.

Your next question comes from the line of Lenny Brecken with Brecken Capital. Please proceed.

Yes, I know you've done this, I think at the annual meeting but the $148 million to be invested in the processing and gathering segment, can you just elaborate what opportunities exist?

Yes, I'd be happy to give you a little more insight. The vast majority of the dollars are related to the two Logansport projects we have. In addition we have some capital set aside to grow our business in South Texas. As you can see, as Byron talked about, that’s where most of our volume growth is coming from and we're going to spend some capital to achieve that growth. So I would say probably 80% of the capital is dedicated to those two regions and the rest of it is spread out among the rest of the business.

So is there any particular field that they are tied to that we should be aware of? The obvious ones are…?

Well in South Texas it’s the Eagle Ford Shale play and in Logansport, obviously it’s a Haynesville area and the bossier area and then out in West Texas we're spending a little money as oil prices have come up in a number of wells. A lot of activity there. We've been collecting some additional supplies out there and that’s principally where the capital is going.

Want to give us a hint that where your Eagle Ford capacity will be? Is that the processing or gathering you're investing in there?

It's all gathering and we have some capacity there that we've been filling up. I think we've said in the past that we expect to maybe get our gathering system recently full with existing capacity by the end of the year and then we're looking at options and ways to expand that capacity and increase efficiency down there while rerouting some of our flow lines in that direction to pick up additional volume.

In processing you don’t plan on making any investment?

We right now have capacity in some facilities down there that we will need to full utilize over time before we'll be looking in the market to do any expansion on the processing side.

So is that, just to be clear, is that a function of just over – not oversupply but supply from your competitors and excess capacity or do you have and you don’t think the business opportunities will be able to fulfill?

There is a sizable amount of processing capacity in the area that if you just look at a general market trend, will need to be utilized before there are major investments in processing and so somewhere down the road, someone is going to be looking at some bigger projects but it's where we're looking for investments this year. We don’t see any investments really in the processing side of the business down there which are really focused on gathering.

Okay.

Now that’s aside from maybe a little efficiency increases that we're doing on some of our existing facilities.

Okay, just one last question. It seems the industry as a whole is just expanding capacity. Can you just give us some color as to, at the macro level, what's driving that? Is that the exports to Asia or something? Is it the replacement that’s going on in the petrochemical industry? It's just maybe a simple question but I just want to hear your opinion about that and depending on your answer is there any risk you see in maybe the industry maybe going into investing too much money in supply.

Thank you to answer that. You really need to backup about three or four years ago, and look at the supply-demand dynamics that were taking place. There were several things taken place. First of all, projections of decreasing Gulf Coast supply over time, some of that’s still going to happen. Lot of the traditional basins were decreasing, you had some pretty good forecast for growth in the power market because we’re back before the recession came in, and slowed that down a little bit. Those factors were showing a big supply-demand imbalance. You overly that with some technological improvements that came into the industry that allowed the horizontal drilling in the Shale plays, which made those plays generally much more economically than conventional plays to drill and so you had some tremendous activity that began when the Barnet, Barnett, Woodford, Fayetteville and then moved on and to the Haynesville area. Now we’re seeing that activity in Marcellus and South Texas and so it’s really economic-driven that this is where the producers can get their better returns and so they have addressed within drilling those. Now in general is there a little slowdown in demand that we’ve seen from the recession, yes and so you’ll have to work back through that. But if you look at the longer term hitch in the U.S. these basins that have been drilling are all going to be needed in the capacity to move this gas, it’s going to need, is will be needed and actually there will be some incremental capacity, it’s going to have to be build. If you want to start looking at post, say four, five years down the road because conventional supplies will declines. We also – I don't know if anybody has a full handle on LNG gas, but it’s certainly looking like LNG is going to be directed more to Asia, and a lot more to Asia and to some extent in Europe and the United States. So, our analysis which shows that we’re going to need all of this gas it’s been real – we're short of a little bubble right now. There is no question, and that's what's beginning to push some of the prices back.

Okay. Thank you. I will enter another question in queue.

Your next question comes from the line of John Edward with Morgan, Keegan. Please proceed.

Yes. Hi, it's John Edwards. Good morning everybody.

Good morning, John.

Just real quick, are you changing your guidance at all for the acquisition of the 7% from GE?

No, that was built in to our original guidance that we previously gave, and so we're not making any modifications to that number.

Okay, great, all right. That's all I have. Thank you.

Okay. Thank you.

(Operator Instructions).

Thank you for taking the time to join us today. If you any additional questions, feel free to give us a call.

Thank you for your participation in today's conference. This concludes our presentation. You may now disconnect. Have a good day.