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Executives

Shannon Ming - Vice-President, Investor Relations

Byron R. Kelley - President, Chairman of the Board & Chief Executive Officer

Stephen L. Arata - Chief Financial Officer & Executive Vice-President

Patrick Giroir - Executive Vice-President & Chief Commercial Officer, Gathering & Processing and Transportation

Analysts

Michael Blum - Wells Fargo

Helen Ryoo - Barclays Capital

John Edwards - Morgan, Keegan & Company, Inc.

Noah Lerner - Hartz Capital

Lenny Brecken - Brecken Capital

Chris Holt - Barclays Capital

Regency Energy Partners (RGNC) Q3 2009 Earnings Call November 9, 2009 11:00 AM ET

Operator

Welcome to the Regency Energy Partners Third Quarter Earnings Release Conference Call. My name is Chenille and I’ll be your operator for today. (Operator Instructions). I would now like to turn the conference over to your host for today, Ms. Shannon Ming, Vice - President for Investor Relations.

Shannon Ming

Good morning everyone and welcome to our third quarter 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 release and the slides that we will use today are available on our website at www.regencyenergy.com.

The first slide of the presentation describes our use of forward-looking statements and lists some of the risk factors that may affect actual results. Please read this slide. Also, including 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 Byron Kelley.

Byron Kelley

Let me begin by wishing ach of you a good morning and adding my welcome to you for joining us today. As always, we look forward to providing you with a detailed update on the company’s performance as well as sharing our thoughts about the market in general.

I would invite you to turn your presentation to page three, and we’ll talk a little bit about some of the year-to-date highlights in our business.

I’d like to begin with our operating performance and take a quick look at some of the year-to-date accomplishments.

Despite the continued low rig counts and weakness in commodity pricing, we have produced three solid quarters of performance with the total year-to-date combined adjusted EBITDA of a $166 million.

We have offset the financial impact of low drilling levels on our compression business by implementing significant cost savings initiatives, and we've completed plant upgrades at our Tilden plant in South Texas and at our Waha plant in West Texas.

Few highlights related to financing, we've raised over a billion dollar in capital year-to-date. In the first quarter, we formed the partnership with Alinda and GE Energy Financial Services to co-develop the Haynesville expansion project. In that quarter, we raised $653 million through that joint venture to fund that project.

In the second quarter, we priced $250 million of 9.38% senior unsecured notes that are due in 2016. And then in the third quarter we followed on with a -- by completing a private placement of $80 million of redeemable preferred units.

In looking at the Haynesville Shale, activity continued strong in this area. Our project is on budget and on schedule for in service by the end of the year.

We also increased our ownership in the Haynesville joint venture by 5% moving our total ownership up to 43%.

Additionally related to the Haynesville project, we announced a $47 million Red River Lateral Extension, which extends the current project further into the sweet spot of Haynesville Shale play and adds approximately 100 million a day of additional capacity.

And then in our gathering business, we announced a $44 million Logansport Expansion, which is also allowing us to capture volume from the Haynesville Shale.

Moving to slide 4, we'll talk about some third quarter highlights. Our third quarter's combined adjusted EBITDA of $55 million was relatively flat compared to the second quarter EBITDA of $56 million.

In spite of an extended turnaround and upgrade at our Waha plant that ran nearly four weeks. Combining this $55 million with Q1 and Q2 results provides us, as mentioned earlier, with the year-to-date combined adjusted EBITDA of $166 million.

We expect for the full year 2009 to achieve a combined adjusted EBITDA within the prior guidance range of $220 million to $240 million, assuming a 100% ownership of rigs.

A one-month early startup for the Haynesville Expansion Project was included in the high end of our initial range. Through September, we were on schedule to initiate this early startup, however with the record high levels of rain we saw on October, we currently do not anticipate meeting that objective.

As a result, we expect full year 2009 results to be in the lower half of our guidance range on a combined basis again assuming a 100% ownership of rig.

However, based on our pro rata JV ownership, we expect to be the near the midpoint of the previously stated $200 million to $214 million adjusted EBITDA pro rata guidance for 2009.

Also as you aware, our third quarter 2009 distribution was inline with our expectations at $0.445, $1.78 annualized. In the third quarter, Regency generated $36 million in cash available for distribution representing a coverage ratio of 0.97.

And as discussed, over the past few quarters, we anticipated a drop below 1X during the construction of the Haynesville Expansion Project.

We plan to maintain our current $0.445 distribution through the construction of the project, but as always I remind you, distributions are set quarterly by our Board of Directors driven by long terms sustainability of the business and available cash flows.

I like to spend just a few minutes on some quarter-over-quarter results. Comparing the second quarter of 2009 to the third quarter of 2009, our combined adjusted EBITDA decreased slightly from $56 million to $55 million.

This decrease was currently driven by the extended turnaround and upgrade of Waha Plant, which had an impact of approximately $2 million, but this is partially offset by a $1 million increase in EBITDA on the rig system.

Our pro rata adjusted EBITDA decreased from $51 million in Q2 '09 to $49 million in Q3 '09 again related to the same factors around the down time and upgrade at the Waha Plant, partially offset by our increased ownership interest and increased rigs results.

Actual financial results reported for the quarter are as follows. We had a net loss of $11 million in third quarter of 2009, compared to a net income of $6 million in the second quarter of 2009.

This loss was primarily due to a $14 million decrease in other income and deductions due to a non-cash value charge associated with long-term derivatives included within a redeemable preferred units issued in September and a $3 million increase in interest expense due to higher borrowing cost on our 2016 high yield notes.

Additional EBITDA and adjusted EBITDA details are outlined in the appendix on slide 31 and slide 34.

I'd like you now to turn to slide 6. I like to talk a little bit about some general industry trends regarding drilling activity. It looks like drilling by producers has finally hit the bottom and we are starting to see signs of stabilization.

During the third quarter, total U.S rig counts increased by 9% to 1016 rigs. And an even more positive indicator for Regency is that the land rig counts in the areas in which Regency operates increased by approximately 10% to 660 rigs at the end of the third quarter. And this data come from the Tudor Pickering Weekly Rig Roundup of November the 2nd.

In the counties in which we operate our gathering assets, the rig counts increased in North Louisiana by 16, in South Texas by 7, West Texas by 2, while remaining flat in East Texas, and we saw a decline of one rig in the mid-continent region.

On a broader basis, we continue to believe that drilling levels are still not sufficient to meet ongoing demand for normal natural gas consumption levels and further increases will be necessary to meet this demand over the next year.

Turning to slide 7, we'll talk a little about the trends that we are seeing in commodity prices. Cash prices for natural gas trended lower through early September.

But they did recover strongly to finish the third quarter just slightly below where they began with average natural gas price for the third quarter at $3.12. More recently, we've seen cash prices trade back to levels that we've not seen since February of this year.

West Texas intermediate crude continued its rebound with an average price of $68.24 during the third quarter compared to $59.54 in the second quarter, and $42.97 in the first quarter.

NGL prices increased relative to the second quarter continuing their rebound from first quarter lows. The increases for ethane were 10%, propane 19, iso-butane 8%, normal butane 19% and natural gasoline by 16%.

And then the current forward curves for the natural gas and crude oil pricing suggest that gas will rebound to $5.38 per MMBtu for gas, and crude will rebound to $81 per barrel for the full year 2010.

Slide 8, we continued to focus on our fee-based business and our cash flows represent a growing of Regency's adjusted segment margin. Only an estimated 2% of our adjusted segment margin will be subject to commodity price fluctuations for the balance of 2009.

For the full year 2010, we estimate approximately 5% of our margins will be subject to commodity price fluctuations. However, we've not finished laying on our 2010 hedges at this time.

Currently we have hedged approximately 70% of non-ethane equity exposure for 2010 and we've hedged approximately 75% of ethane for the first half of 2010.

Over the next 30 days, Regency expects to execute additional hedges to bring our 2010 hedge percentage up to 85% across all products.

Turning to page 9, and looking at volume comparisons for the business, when you compare the second quarter of 2009 to the third quarter of 2009, gathering and processing and combined transportation throughputs were down slightly.

However, year-over-year volumes continue to demonstrate resilience despite the severe drop in commodity prices and the rig counts that we've seen throughout the earlier part of the year.

Year-to-date in the gathering and processing segment, we’re slightly ahead of year-to-date 2008, but we’re slightly behind where we were last year in the transportation segment.

Quarter-over-quarter, we have seen volumes driven down by plant down time at the Waha plant that I mentioned earlier, where we had a turnaround and where we made some system improvements.

In the gathering and processing segment, when we compare the first nine months of 2009 to the first nine months of 2008, our total through-put increased from [998,000,518] MMBtu a little over a billion MMBtu.

Quarter-over-quarter, in this segment, the total through-put decreased from 984,718 MMBtu per day, down to 981,925 MMBtu in the third quarter.

As I mentioned earlier, we had the plant outage Waha and a short outage at Tilden allowing for those two outages in both quarter would of accessing our third quarter underlying volumes in gathering and processing up by 1.5% compared to second quarter of 2009.

In our combined transportation segment, when we compare the first nine months of 2009 to first nine months of 2008, again assuming a 100% ownership of rigs, our total through-put decreased slightly from 773, 562 MMBtu to 763,588 MMBtu.

Quarter-over-quarter, in the combined transportation segment, the total through-put decreased from 745,000 MMBtu to roughly 735,500 MMBtu in the third quarter of 2009.

Specifically looking by region in north Louisiana, our volumes 7% during the third quarter out of Dubach facility driven by the short decrease of drilling in the Terryville field, this is not been surprise, we’ve seen this all year.

As you were aware, our Terryville field volumes peaked in Q3 2008, but its produces began ramping up the Haynesville drilling activity, they moved rigs from the Terryville field to the Haynesville field and so we have seen this drop off in that area.

Additionally, low commodity prices have also curtailed drilling activity by some of the smaller producers. The lower than expected volumes were partially offset by higher NGL recoveries at the Dubach plant as well as lower fuel usage.

On a very positive note, in the Nexus system, this system continues to run at full capacity with volume ramp-ups due to the Haynesville gas coming into the system.

As you recall, we did announce the Logansport expansion to our Nexus system in September. This will improve system hydraulic and greatly increase our throughput capabilities as well as provide additional fee based revenues for our business.

Moving to West Texas, we completed an extensive maintenance and upgrade of the Waha plant to improve overall system capabilities and throughputs.

Although there was a negative impact to this third quarter due to the down time since completion of this work, we have seen volumes increase from $90 million a day to over a $105 million a day.

As I mentioned earlier, we have increased the throughput capacity on this plant through this maintenance project approximately 18%.

Favorable ethane spreads have also made it economical to begin processing approximately 10 million a day of keep-whole gas from interconnected pipeline in this area.

And our business development teams and regional service teams have continued to pursue opportunities for new supply and were currently running ahead of plan in West Texas for the year.

Moving to the Mid-continent's, on our assets including FrontStreet we were down $2.7 million a day. And although those volumes were down, our recoveries have been above plan and financially these assets have actually performed better than expected for the first nine months in 2009.

Moving to East Texas, volumes for the third quarter were unfavorable by $1 million compared to the second quarter of 2009.

Softer pricing continued to have a negative impact on margins in the third quarter, but on a positive note, we have seen prices improve in Q4 as a result of improved supply and demand market dynamics for this product.

Generally, what we’ve seen happening in the fourth quarter, we’ve moved from a negative $40 per long ton to a negative $20 per long ton, which is a positive shift of $20 a long ton in sulfur prices.

In South Texas, volumes around our South Texas gathering and treating system continue to ramp up with the continued drilling of the Eagle Ford shale plate.

We added 5 new Eagle Ford wells to our system in the third quarter and we expect an increase in drilling activity going forward.

Currently, we are flowing out of the Eagle Ford shale area, approximately 70 mill cubic feet per day. That’s a significant increase from where we were at the beginning of the year with very low volumes. So this area is getting very active and we’re seeing the results in our South Texas region.

In the second quarter, we did have some maintenance on the Tilden plant, which carried over into a little bit early in the third quarter and that had a slight negative impact on our volumes at the Tilden plant.

In our combined transportation segment, the rig system, as mentioned earlier, volumes decreased by roughly 9 million a day from second quarter to third quarter really driven by the lower drilling activity in the Terryville field and the compressed basis spread between East Texas and North Louisiana also impacted lower volumes across that system.

Turning to slide 10, and a little focus on our compression business, we have continued to feel the impact of declining activity in the challenging environment of reapplying horsepower that comes up for contract renewal in our compression business.

This is really due to the production levels remaining low, which has reduced the demand for compression and increased pressures on pricing.

But as you look at this chart despite a 52% decline in U.S. onshore rig counts since September of 2008, Regency revenue generating horsepower remained relatively flat over that period of time.

Quarter-over-quarter, we did have a decrease moving from 760,000 horsepower to little over 743,000 horsepower and most of this impact has been in North Louisiana.

Our southwest region basically was up slightly on compression. The southeast we were down about 200,000 horsepower, in our northwest region we are basically flat and as I mentioned in the northeast region, which is center of North Louisiana, we are down most of this horsepower is in that region at about 200,000 for the region.

But the management team at CDM has worked to offset the financial impact of this reduction through aggressive cost management practices and have realized significant savings in a number of areas.

Commodity driven price release on lube oil and fuel have resulted in savings of approximately $1.7 million.

Operating less horsepower resulted in expense savings of approximately $4.8 million year-to-date, and aggressive expense management resulted in additional savings of $8.4 million year-to-date.

On a positive note, I'm pleased to let you know that we in the past two to three weeks have seen enquiries up fairly significantly regarding new horsepower additions and that we are in the final stages of negotiations regarding our first horsepower replacement in the Marcellus shale and all things going well we hope to have that wrapped up over the next few weeks.

Moving to slide 12, and I'd like to spend sometime talking about Haynesville shale in general and our expansion project. As you will note from this chart, the horizontal rig count in East Texas in North Louisiana reached a 111 at the end of the third quarter.

As this horizontal count has gone up over the past seven quarters you can see that its initial production rates have also continued to increase.

This trend continued in the third quarter, as initial productions were up quarter-over-quarter by 7% moving from an average of 11.5 MMcfe per day to 12.3 MMcfe per day according to the RBC Capital Markets, Haynesville-Lower Bossier shale weekly of November 5th.

This increase in IP rates also represents a 24% year-over-year increase. Our early Q4 result show a further upward trend in the increase in initial production rates and also I'd like to point out that end of October just one month pass the end of the quarter, horizontal rig counts have moved up to a 142 working rigs in this area.

So, obviously this is the most active area in which we will participate and probably one of the most active regions in the United States if not the most active region.

I mentioned earlier and let me turn to page 13, but I mentioned earlier that in the fourth quarter, we did the joint venture and then we came, in the third quarter, we acquired additional 5% interest in the joint venture bringing our ownership up to a total of 43%.

And this chart just gives you a breakdown of how those percentages worked of how the initial project worked and then how it translated but in the bottom you can see that through this transaction we have now moved our ownership interest by 5% and we own 43% of the joint venture.

On slide 14, this is the project construction update, you'll notice in the top half of the slide on our 36 inch pipeline construction its 100% complete. That line has been purged in fact and is ready to flow as soon as the 42-inch line is ready to flow.

Construction on the 42 inch Winnsboro line continues with clearing and grading and stringing, really basically complete. Welding on the 42 inch is 85% complete and lowering in and back fill is 74% complete.

Despite the significant amounts of rainfall that we saw in October, which exceed 20 inches, the entire project remains on schedule to be in service by the year-end 2009.

The cost of this project, just a brief update, the project is expected to come in under budget which is, the initial budget was $653 million, we expect to come in under that.

Through September 30, we have incurred $517 million in Haynesville related cost for the base project and that's exclusive of the Red River lateral extension and of course all of these costs are incurred by the joint venture and do not affect Regency's balance sheet.

We've begun working on the Red River lateral expansion and as of September 30, the joint venture had incurred $7 million of total project -- of the total project estimate of $47 million.

Now in this extension Regency will contribute $20 million to the joint venture for the Red River lateral and to-date we have incurred approximately $3 million of cost.

Page 15 just shows you that lateral and as I mentioned earlier. This is the $47 million expansion project, it adds a 100 million a day of capacity that brings the total capacity up to 1.2 billion on the system.

This project gets 12.5 miles of 36-inch pipeline to the original expansion project and it reaches further southwest and crosses the Red River Parish, its reaching further southwest. The importance of this, in addition to the capacity it continues to move us deeply into the suite spot of the play.

Construction on this project began in September and it is expected to be completed in of 2010. We've also announced, on slide 16, is an overview of our Logansport expansion project.

This was the $44 million Logansport expansion. It is an extension of the Nexus Gathering System in North Louisiana.

This project was announced at $44 million as a 20-inch pipeline. We have recently upsized this to 24-inch pipeline to meet expected increase in demand and that added about $2.5 million to $3 million for the cost of project, sizable up tick in capacity for very small dollars.

But we have a lot of interest in this project and lot of interest in seeing those move additional volumes out of this area above what this initial project forecasted.

But this project, we laid approximately 17 miles of 24-inch pipeline. It will add some compression and some dehydration facilities and will gather gas from the Nexus Gathering System and move it to 300 million a day interconnect with CenterPoint Energy on their land CP.

This provides gathering customers with additional high value takeaway options in Desoto Parish, Louisiana, Shelby County, Texas and these are areas currently experiencing significant drilling activity.

Overall, this expands our gathering presence significantly in the Haynesville Shale and as I mentioned earlier, we targeted this for being in service in the second quarter of 2010.

Moving to slide 17, and looking at third quarter basically just a summary of the third quarter. Financial results, as I mentioned despite the continued weakness in overall natural gas industry and the continued low rig counts, our third quarter results positioned us to be near the mid point of our 2009 pro rata adjusted EBITDA guidance range.

In our gathering & processing business allowing for the plant outages in both quarters, then our third quarter underlying volumes in our gather and processing business would have been up approximately 1.5% compared to the second quarter of 2009. We will continue to see benefit of the expanded capacity in the Waha plants in the fourth quarter.

We also announced $44 million expansion project in our Haynesville shale, and we continue to pursue additional opportunities in the gathering business in both Haynesville and Eagle Ford shale.

On the transportation business, we announced the $47 million Red River Lateral, which added to $100 million capacity to the Haynesville expansion project.

And there we continue to also pursue additional opportunities in the transportation segment via the joint venture on a looking for opportunities, and in discussions on opportunities on expanding that system even further.

In our compression business, the horsepower levels seem to have stabilized during the quarter. And we’re receiving increased customer enquires for new horsepower, and we’re in the final stages of negotiation of installing our first horsepower package in Marcellus shale.

So all in all, when we look at what happened in the third quarter and year-to-date, we’re pretty pleased with results in a tough market. I'm very proud of the things that our team has done to continue to find opportunities to grow, continue to manage cost and to manage our company on a very positive basis through some difficult market dynamics.

And then on a positive note, we’re beginning to see some positives in those dynamics as we’re seeing increased drilling count come up, and we’re seeing as I said earlier discussions now accelerating around additional horsepower.

So, we feel good about where we are and we are very pleased to see the positive signs in the marketplace that we've seen over the last month.

So with that, we will come back later for question and answers and will be glad to talk more detail. But with that I'm going to turn over to Steven, who will talk more about some of our consolidated operating results.

Stephen L. Arata

Thanks Byron. Just turn to page 19, we have out consolidated operating results. For the three months ended September 30th 2009, Regency had a net loss of $11 million, which compared to net income of $6 million in the second quarter of this year.

The decrease in net income was primarily due to two items; most importantly we had a $14 million decrease through other income and deductions due to a non-cash value change which was associated with the long-term derivatives that are embedded within the recently issued redeemable preferred units.

The other item was a $3 million of additional interest expense, which was due to higher borrowing cost following the issuance of our 2016 high yield notes in May. For the quarter, our revenues were down about 1% from $254 million to $251 million.

Turning to page 20, our gathering and processing segment results are shown there, quarter-over-quarter, our total throughput decreased slightly to 982,000 MMBtu per day in the third quarter from 985,000 MMBtu per day in second quarter.

As Byron has mentioned, some of this was due to the downturn at the Waha plant for part of July and August but also there were declines in Cotton Valley production in North Louisiana.

These decreases were partially offset by volume ramp ups from Eagle Ford shale gas coming on to out south Texas system and the volume increases at Logansport System in north Louisiana.

Normalizing for all, the adjustments related to plant turnarounds in both quarters, our underlying volumes were up about 1.5% quarter-over-quarter.

Our NGL production remained flat quarter-over-quarter at 22,000 barrels a day, as the volume declined had minimal impact in our liquid recoveries.

Our adjusted segment margin also remained flat at $55 million quarter-over-quarter and our adjusted segment margin per MMbtu also remained flat quarter-over-quarter at $0.61.

On page 21, we have our transportation segment results. You will note at the top of the page of transportation segment only includes basically data from the March quarter, given the formation of the joint venture.

On the bottom of the page, we have put combined transportation segment results, which include 100% results from the transport business, including the portion that our joint venture partners own.

Looking at the business as a whole, segment margin increased $14 million in third quarter from $13 million in the second quarter.

Our throughput decreased about 1% quarter-over-quarter from 745,000 MMbtus per day in the second quarter to 736,000 MMbtus per day in the third quarter.

This decrease in volumes is primarily due to a weakening basis spread between the [Carthage] and Terryville, which had a large impact on our interruptible volumes we have been moving on rigs.

On an adjusted segment margin per MMbtu basis, the margins increased from $0.19 in the second quarter to $0.20 in the third quarter.

On page 22, we have our Contract Compression Segment results, compared to the second quarter of 2009, our segment margin was $2 million to $34 from $36 million. This decrease is primarily attributable to the decrease in ending revenue generating horsepower during the quarter.

As we maintained CDM’s experience and that decrease in revenue generating horsepower and we responded to this development by aggressively managing cost.

The net impact of the current environment and our response to it has enabled this segment to exceed our budget through the third quarter of this year.

Quarter-over-quarter, our average horsepower or revenue generating compression unit decreased to approximately 1%, from 846 to 836 leaving us significantly higher than our peers in this space.

On page 23, we cover come commodity price risk management details. Our hedge position is unchanged since the last time we spoke although we plan to enter into additional hedges prior to year-end.

By year-end we expect to execute additional hedges to bring our 2010 hedge percentages to approximately 85% of NGLs and Condensate and 75% for Natural Gas.

By year-end, we also expect to hedge approximately 25% NGL and Condensate exposure for the first three quarters of 2011 and approximately 50% of Natural Gas exposure for the first two quarters of 2011.

This plan is consistent with our new policy of rolling hedges in on a quarterly basis to reduce our overall risk.

Finally, I’d like to conclude with a liquidity update. Our anticipated 2009 organic growth CapEx is now at a $169 million. $84 million of that was for additional compression for our contract compression segment, $65 million was for expansion of our gathering and processing facilities and $20 million relates to the Red River Lateral expansion of the Haynesville expansion project, which is our proportionate of the $47 million total cost of the project.

Of the $169 million in CapEx, we have incurred $104 million as of the end of the third quarter. We expect our growth CapEx to be approximately $100 million in 2010 exclusive of subsequent expansions to the rig system or any additional North Louisiana Gathering projects not currently announced. We are well positioned to meet all of our funding needs for our current well capital plans for both 2009 and 2010.

Our total amount available under our credit facility as of September 30th was $269 million and in addition to that we have $65 million available under our Caterpillar operating lease facility as of end of the quarter.

One final update on our redeemable preferred units. On September 2nd we partnered with MTP Energy and Harvest Partners to provide us with a creative and attractive approach to continuing to execute our growth strategy by issuing $80 million of redeemable preferred units.

These units were priced with $18.30 per unit, approximately 4.37 million units in total. Net pay of six quarterly distribution of $0.445 per unit and they're convertible into common units on a one-for-one basis.

After March 2nd 2010, $63 million of the net proceeds from this offering were used to purchase additional 5% ownership interest in the Haynesville joint venture affiliate of GEEFS with the balance of the proceeds from the offerings used to fund ongoing fee based growth projects and to further strengthen our position in the Haynesville Shale.

With that I'd like to open it up for Q&A.

Question-and-Answer Session

Operator

(Operator Instructions). Your first question comes from Michael Blum - Wells Fargo.

Michael Blum - Wells Fargo

Few questions. First, Stephen can you just walk through on the Preferred Units, what was just, specifically what causes that change in value that most of the income statement?

Stephen L. Arata

Sure, it's little bit complex but it blows down to the fact that there are embedded call options in the security and those have to be mark-to-market every quarter. If you notice on our balance sheet that shows up just above our partner's capital in a separate category.

So, from a accounting perspective, it's treated as temporary equity but because of the accounting rules we have to follow, we have to flow through the change in the value of the options every quarter that are embedded within the actual security itself.

So, it is going to cause some ongoing volatility in our earnings stream effectively if our price of our underlined units goes up, we're going to have a charge and if the price of our underlined units goes down, we're going to have a gain. And there's some other minor impacts, some other items but that's going to be the biggest driver of whether we have a gain or a loss.

Michael Blum - Wells Fargo

And then in terms of the 2010 capital that you laid out there. Where generally are you spending that money?

Stephen L. Arata

A lot of that, well the vast majority of that is in our gathering and processing business. We have some capital in there for completion and packaging of some compression units. But the vast majority of it is to complete projects in North Louisiana and in South Texas.

Michael Blum - Wells Fargo

The last question for me is just in the compression business, can you talk about where utilization is and also, based on with the trends you are seeing do you feel like this -- you've seen the bottom in that business and you are going to see a trend up from here or where do you see that going?

Stephen L. Arata

Michael obviously as seen, utilization rates come down when you go back and look at the chart on page 10 down to 743.

That seemed to have levelized and seemed to have stabilized. With a couple of things ongoing now, we think that it may actually come up a little bit before year end.

So, we are hoping not and expecting not to see anymore declines and maybe a little slight up tick in that, not a big number by year end.

What we are working on right now, I am getting enquiries for people who are going to need compression next year. Marcellus shale being an area where there is a need for significant amount of compression.

As I mentioned earlier, we actually have signed a letter of intent for our first transaction there and in the final stages of negotiating a contract that would allow us to put a very nice package in Marcellus shale.

Maybe a little bit by the end of the year and the rest going in next year, to the extent that we continue to see these positive enquiries in the other areas and we get some price strengthening, which we are seeing at least from the forward curve and we saw getting some pick ups in some other areas perhaps the Barnett shale.

The continued growth in the Fayetteville shale and as well as Marcellus, we think we are going to have opportunity to place some additional sizable packages next year in that business.

The good news is, we have prepaid for that capital as Stephen said, there is a bit of money in our capital budget for repackaging, but that’s not a lot of money.

So, we've essentially this year, through our capital program, purchased compression that will have horsepower available to carry us well through next year.

So, as we place that, we should be able to start building some good growth out of that as we come out of next year and start getting full year results from that compression without having had to spend a lot of capital.

Byron R. Kelley

Michael, our utilization is around 85% right now of our horsepower.

Operator

Your next question comes from Helen Ryoo - Barclays Capital.

Helen Ryoo - Barclays Capital.

First, just housekeeping, what was your debt-to-EBITDA ratio based on the credit [agreement]?

Stephen L. Arata

It was approximately 4.7 times.

Helen Ryoo - Barclays Capital.

And then second question is on the Logansport expansion, the project will add 300 million per day capacity. When do you think you will fill that capacity?

Patrick Giroir

This is Pat Giroir. The project should come online by the early part of the third quarter and of course it will wrap up over the course of rest of 2010 and 2011.

Helen Ryoo - Barclays Capital.

So by 2011, is that your expectation?

Patrick Giroir

Well, I don’t know it will be at the 300 million and as Bryon said, we expanded the project from a 20-inch to 24-inch so that we have more capacity, so that we can add additional interconnects along that pipeline quarter when the market meets the need.

Operator

Your next question comes from John Edwards - Morgan, Keegan & Company, Inc.

John Edwards - Morgan, Keegan & Company, Inc.

Just along the lines of Michael's question, could you talk a little bit about order of magnitude on the Marcellus shale compression placements? Or can you not say right now?

Byron R. Kelley

In aggregate, in the discussions that we've been in with at least four or five different players, there’s the potential that us or someone could place well over 100,000 horsepower for the next year.

We’re one of the several players, we’re not going to get - we don't anticipate we’re going to get a 100,000 horsepower.

But this first transaction, without going into the specifics of the contract, one of the things I'll just say is in the past we've always said we needed at least 10,000 horsepower to move into a new area, this is going to meet those parameters.

But since the terms of the contract we are negotiating are not public, I don't specifically want to say how much is in that package, but it will meet our parameter to get us past that threshold.

That's with one party, we’re in discussion right now with about four other parties about their needs up there as well.

John Edwards - Morgan, Keegan & Company, Inc.

I'm just curious, given the slowdown in drilling and so on, in terms of pricing, can you talk about how that’s holding or how much discount you're having to contemplate?

Byron R. Kelley

Our pricing is holding up pretty well John. The way we measure this typically is in revenue for horsepower per month and that is down slightly less than 3% from the beginning of the year.

So, while we had to make some concessions to work with our customers, to meet their needs, it hasn't had a huge impact in terms of our overall pricing across the whole fleet.

John Edwards - Morgan, Keegan & Company, Inc.

I was thinking actually on the new discussions.

Byron R. Kelley

Those are very much inline with our existing rates.

John Edwards - Morgan, Keegan & Company, Inc.

On the Eagle Ford shale, given the push by enterprise in that areas, well how are your, how is margins holding up on the volumes coming in there?

Patrick Giroir

This is Pat Giroir, the margins are holding on quite well, I mean we have through the couple of different contracts, been able to provide some effective out takes for the liquids for our customers. So in terms of the gathering margins they are holding at this time.

Operator

Your next question comes from Noah Lerner - Hartz Capital.

Noah Lerner - Hartz Capital

Two questions, one is a follow up to something John was just talking about in the Marcellus. I was just curious, are you focused in on the eastern, the western part of the play or basically through out the entire play where your focus is right now?

Byron R. Kelley

Right now, we are in basically sort of the northeast corner of Pennsylvania and the southwest corner of Pennsylvania.

Noah Lerner - Hartz Capital

So, the two prime zone, you are basically focused on right now?

Byron R. Kelley

This compression, this not gathering business, this is purely in our compression sector, you are right.

Noah Lerner - Hartz Capital

No, I understand but its still going to be in the hot zone.

Byron R. Kelley

That’s right.

Noah Lerner - Hartz Capital

I guess, the second I had gets back to something Byron, you said early in your presentation. Just curious, with storage being pretty full up and no side of an increase in really demand on the horizon.

Just curious if you have any thoughts along the line that maybe what the producers have done is they've started to ramp up their drilling and increased their rigs to bring their volumes up for the financial statements for the fourth quarters.

So, they can show growth and they’re really borrowing from 2010 and you might have another fall off in rig count and slow down, once the calendar turns. Do you have any concerns or thoughts on those lines?

Byron R. Kelley

Not yet. Basically, what we’ve been saying that with the low rig counts, one of these days we’re going to see the impact of the plans.

I think, as we are finally getting ready for winter, there are some producers that do believe that some of that plan is going to start showing up through the winter and that maybe production rates will get up some. And this is assuming we just have some normal cold weather.

I think, also you have to look at - especially in our area, where a large part of this increase is Haynesville, and it’s not driven at this point by just getting through this winter.

It’s driven by the thought that as we come out of the spring and get into next year, that with the decline rates we’ve seen in general, that they’re going to have the opportunity to move higher volumes out of the Haynesville shale.

And with that being their lowest cost production and drilling area, that’s where the biggest ramp up on our system is going.

West Texas that ramp up we’re seeing out there is really driven by the higher ore prices and we’re getting associated gas out of that.

So, I wouldn’t say that you couldn’t be right to some extent, but I really think it’s more driven by fundamentals at this point and a belief that the fundamentals are going to begin moving as a result of the nine months of very low rig count.

Noah Lerner - Hartz Capital

A quick follow back to the Marcellus. You emphasized again, that’s just a compression. Have you looked at or do you anticipate starting to expand into some gathering and maybe even some processing down in the southwest corner or are you just going to focus on compression for the Marcellus?

Byron R. Kelley

While our first focus is compression if getting a compression precedence should lead us to an opportunity to do something in that area we would look at it, but we are not pushing that right now, we've got a strong focus on essentially, sanctioning up all the opportunities we can get out of the Haynesville and the Eagle Ford Shale.

Have plenty of opportunities for capital investment there and there are already number of players on the ground up in Marcellus.

So, unless that was just a unique opportunity presented itself we're not ready to move into that area on our gathering and processing business.

Noah Lerner - Hartz Capital

I just wanted to say really nice job all year for the last 12 months fighting the headwinds and coming out with a little tailwind, did really a good job as an investor I really appreciate it.

Operator

Your next question comes from Lenny Brecken - Brecken Capital

Lenny Brecken - Brecken Capital

Did you quantify the actual contribution to volumes for Eagle Ford for the quarter?

Byron R. Kelley

Let's get exact number we're moving 70 now we did an average 70 for the whole quarter though, I'll let my numbers do to look that up.

Lenny Brecken - Brecken Capital

So it's definitely up substantially sequentially?

Byron R. Kelley

That's correct.

Stephen L. Arata

It's up every month.

Byron R. Kelley

That’s right and we had five wells in the quarter.

Lenny Brecken - Brecken Capital

Can you please just review to us what your capacity is there to expand that?

Byron R. Kelley

Pat, you want to go around?

Patrick Giroir

The capacity I mean it just depends on where we take the gas and the one nice piece to our system down there is we have a number of key takeaways by the different takeaway locations on several or the other pipelines in the processing folks down there.

So, we can probably load up that line depending on whether the gas comes in another 100 million plus, I mean it's easily expandable.

Lenny Brecken - Brecken Capital

Easily expandable, is that capital or --?

Patrick Giroir

With the limited amount of capital we can probably get another $50 million to $75 million a day out of the line.

Lenny Brecken - Brecken Capital

So, it is bringing close to 250 to 300 then?

Patrick Giroir

Right.

Lenny Brecken - Brecken Capital

Total?

Patrick Giroir

It's just a factor of the key line that we have down there that is ideally suited for this, it goes right through kind of the heart of the current drilling that you're seeing down there.

The impact in the third quarter, the increased drilling down there was about three-quarter to a million dollars of margin for us.

Operator

(Operator Instructions). Your next question comes from Michael Blum - Wells Fargo.

Michael Blum - Wells Fargo

Just a couple of follow-ups for me. One, I just want to make sure, I'm understanding correctly, your volumes in the gathering business were slightly down but the NGL line was pretty much flat. Are you seeing richer gas through your system or is there something else going on there?

Byron R. Kelley

We've had slightly enhanced recoveries during the quarter that offset the lower volumes.

Michael Blum - Wells Fargo

Two other questions. One, you did a nice job of going through by geography what you're seeing now, but I'm curious if you have any general thoughts on where you see volumes in the gathering business going in 2010?

Byron R. Kelley

Well, obviously we expect the Eagle Ford shale area and South Texas continue to add volumes. West Texas, we think we've got a chance to add a little volume in West Texas with the increased prices in oil and associated gas as well as with the higher capacity we now have through our upgrade in our plant.

We have the opportunity to go try to capture some additional packages there. I don't see anything happening really in the mid-continent. I don't see much happening in East Texas, although I'd really say probably not a lot happening in East Texas.

In North Louisiana, I think we have seen indications that there are some producers next year who want to move back into Terryville field and start drilling in that region. They are not drilling yet, but we've heard rumors that they are coming.

That could be positive for us, then obviously the drilling activity is.- we bring on our assets in Haynesville shale are going to add very significant volumes. I mean on the pipe we are going to be doubling at least capacity more than double in it and we expect pretty strong volumes be falling out of there next year as well.

And in our gathering businesses, we mentioned we are going to continue. We've got the expansion project we've announced and there are several others we are working on related to Haynesville gathering.

I think some of that Michael, I think we expect the growth in North Louisiana and South Texas to more than offset some of the declines in East Texas and mid-continent. We expect to be up for the year on a volumetric basis.

Operator

Your next question comes from John Edwards - Morgan, Keegan & Company, Inc.

John Edwards - Morgan, Keegan & Company, Inc.

Just wanted to follow-up. Are you seeing, as far as any competitive pressure with the recent announcements from Enterprise in the Eagle Ford area and also into the Haynesville?

I guess a) how that's impacting you and then b) in terms of taking your Haynesville expansion sort of backup to the original design before you had to downsize, if you could kind of comment on those couple of things?

Byron R. Kelley

Well, couple of things in South Texas, a lot of the announcements that we've been seeing with enterprise has to do with moving gas from the outlet of their plant, through their liquid plant in Mont Belvieu, that’s not anything we are competing with them on that, that’s a service we can offer. Really we are upstream of that plant, to gather the gas and essentially get it to that plant or one - two of the other plants in the region.

We are not building a new processing plant. There is plenty of capacity already in that region. So the growth for us then there is in the gathering side of the business.

And so, that’s what we are pursuing. I mean there's some, not necessarily an enterprise, there are other people that are competing for some of that.

We happen to be in with our assets, in a very nice spot down there and have signed recently a couple of transactions to lock up some of that gas and you are seeing the results of that on the system.

So, in what market we are after, I really don’t see them as our competitor for what we are trying to do in that region.

Moving back to North Louisiana and talking about the pipeline, that original project was little over 1.4 billion per day; we have moved it back to 1.2 billion.

As we built its expansion southwest across the Red River, it continued to move our access into probably one of the hardest regions in that whole play.

And so we at the joint venture level, are very interested and is in discussion with a number of players that could lead eventually to an expansion of the system. How big could it get?

Well if there’s interest there economically, we could move that up to a 2 billion a day system and that is something that we’re pursuing.

There are other projects in the region that you’re aware of that in one sense are competing but quite frankly when you look at the total amount of capacity that needs to built out of that region over the next three years versus where we expect the total supply to go.

We really think there’s room for our project to move up significantly in size as well as the other projects to be complete. And I'm talking about the ones that are pretty well publicized and far down the road with capacity sales.

Operator

Your next question comes from Chris Holt - Barclays Capital.

Chris Holt - Barclays Capital

In regards to that Haynesville expansion opportunities, I know before you mentioned that you'd like to fund that at the JV level with banks financing most likely, what’s your current capacity there and how much you think you can kind of finance through just bank debt?

Byron R. Kelley

We believe that we can fund the entire anticipated expansion cost there. That business we expect, prior to any future expansions, from its current capacity to be produce approximately $160 million of EBITDA. And the expansion obviously would move it up beyond that.

So we think a project of similar magnitude to be existing project that we're completing now because we fully financed with debt at the joint venture.

Chris Holt - Barclays Capital

What's the current facility in place allow, I guess?

Byron R. Kelley

The current facility there is just a working capital facility, the $25 million. So this would be a totally new financing.

Chris Holt - Barclays Capital

At the Regency partners that you obviously pretty well drawn on your current credit facilities, are there any plans in trying reduce that amount in 2010?

Byron R. Kelley

Yeah, we've drawn little over $600 million out of $900 million. We don’t have any current plans in place to reduce that, we have reduced it significantly during the course of this year.

But, we may opportunistically look to access the market and term out some of that debt but there is nothing currently, rising for that.

Shannon Ming

We appreciate you all joining the call today and please feel free to give us a call with any additional questions you might have. Thank you.

Operator

Ladies and Gentlemen, that concludes the presentation. Thank you for your participation. You may disconnect. Have a great day and enjoy your week.

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THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

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Source: Regency Energy Partners Q3 2009 Earnings Call Transcript
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