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Executives

Shannon A. Ming - Vice President - Investor Relations & Communications

Byron R. Kelley - Chairman of the Board, President, Chief Executive Officer of Regency GP LLC

Stephen L. Arata - Chief Financial Officer, Executive Vice President of Regency GP LLC

Richard Moncrief - Chief Operating Officer

Analysts

[Gabi Moeen] - Merrill Lynch

Michael Blum - Wachovia Securities

John Edwards - Morgan Keegan

Gregg Brody - J.P. Morgan

[Shawn Grant - ZLP]

Gary Stromberg - Barclays Capital

[Yves Seagel - Aroyo Capital]

Regency Energy Partners LP (RGNC) Q3 2008 Earnings Call November 10, 2008 11:00 AM ET

Operator

Welcome to the third quarter 2008 Regency Energy Partners earnings conference call. At this time all participants are in a listen-only mode. We will be facilitating a question and answer session towards the end of today’s conference. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today’s conference, Ms. Shannon Ming, Vice President of Investor Relations & Communications.

Shannon A. Ming

Welcome to our third quarter conference call. Today you’ll 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. We distributed the press release this morning and the slides that we’re presenting from as well are available on our website at www.regencyenergy.com.

The first slide in the presentation describes our use of forward-looking statements and lists some of the risk factors that may affect actual results. Please read that slide. In addition we also have provided 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 13.

With that I’ll turn the call over to Byron Kelley.

Byron R. Kelley

This is the third time I’ve had the opportunity to share with you our quarterly results, the last being on August 11. I’m sure that everyone on the call to some extent stands a little amazed at how much worldwide change we’ve seen in the economy and its impact on the capital markets since that August 11 call. These changes obviously have impacted businesses across the globe including Regency.

There’s a famous baseball coach and sometimes humorous philosopher by the name of Yogi Berra and Yogi once said, “The future ain’t what it used to be.” Well, obviously none of us have had a lot of fun over the last 45 days or so in dealing with the future but sometimes a little humor I believe can keep life in perspective. I think what Yogi was trying to say in that little quote was that as much as we all try to predict the future, occasionally it simply takes an unexpected turn and we just have to deal with it.

Also part of keeping life in perspective is doing our job in both the good times and in the tough times, and over the past six weeks the entire team at Regency has been diligently focusing on the appropriate course of action for our business under this current environment. The outcome of that work was outlined briefly in our earnings release this morning in which in addition to some very good third quarter results we announced a revised growth plan which reduces our growth capital needs for 2009 and 2010 by $850 million or 50%.

But I think it’s also important that each of you should note that the revised plan does preserve two very key components. It retains the opportunity for a very solid growth profile over the next two years and it retains our capability to pursue significant growth of our North Louisiana pipeline capacity over the longer term.

Now we will tell you that there is work ahead for us in the coming months to finalize key elements around this downsized project and we’re going to talk about that in more detail later in the presentation. That said, if we are able to execute on the redesign project with all its constituents that are involved, I’m pleased that the project can place in operation 1.1 billion cubic feet a day of needed capacity by the end of 2009. This capacity would still serve a large portion of the initial producer requirements in the Haynesville Shale area.

But before we get into the details on the project, let’s turn our attention to some excellent third quarter results from our businesses.

Page 3 in the presentation. We had very strong quarterly results and I’d like to do some comparisons on the third quarter of ’07 to the third quarter of ’08. Total revenue increased by 85% to $547 million. That’s up from $296 million a year ago. Our adjusted total segment margins increased 84% from $64 million to $117 million. The adjusted EBITDA increased 69%, up $28 million from $39 million to $67 million.

Throughput in the gathering and processing segment increased from 882,000 MMBtu to nearly 1.1 million MMBtu. Total throughput in the transportation segment averaged about 795,000 MMBtu compared to 789,000 in the third quarter of 2007. Stephen is going to give you more details around year-to-date numbers in his discussion a little later on.

I’d like to touch on a few key highlights from the gathering and processing and transportation segments.

In North Louisiana we had increased volumes that were driven by growth in the Terryville field and Elm Grove fields. Moving forward we do expect that in those areas for volumes to be flat as we’re seeing rigs being relocated to the Haynesville area.

At our Dubach plant though our volumes are up by 50% from where they were in the beginning of the year as we continue to expand that plant. In August we brought on the fourth processing facility at Dubach which will increase our recovery of heavy liquids going forward.

The Nexus acquisition is operating at 25% above our forecast for the year, well over $1 million ahead of where we had expected.

In the West Texas regions, this is an area where we were impacted by Hurricane Ike. As a result of Hurricane Ike the Gulf Coast fractionators were shut in. This created a ripple effect on processing activities in both North Louisiana and in Texas. Generally if you look at what that impact was in North Louisiana on average we curtailed about 6 million a day of gas that we could not process; in West Texas we curtailed about 30 million a day of gas that we could not process; and in the Mid-Continent we also had some impact there of about 5 million a day. Obviously as those fractionators come on, we’ve seen our volumes come back on and are seeing stronger processing flows in the fourth quarter.

You may remember a number of months ago I think we mentioned that we were experiencing some downstream transportation curtailments in moving gas. We still see that right now. It’s running about 10%. It’s our understanding from the transporter that we should see those lifted sometime in December and be back and have the capability of moving our full well streams.

On the good news, in West Texas we were doing the Woodford Mountain project. That project was placed in service in October and it’s moving 8 million to 9 million cubic feet a day. It’s fairly rich gas at three gpm.

Moving to East Texas, due to Ike our Eustace plant NGL production was shut down for 21 days in October which reduced our equity production about 15,000 barrels there. On the other side of the equation though, the sulfur price is at an all-time high in that area so we had some much stronger margins out of our sulfur sales in the third quarter. Additionally we’ve had a producer that recently completed re-stimulation of the well based on the stronger sulfur prices and picked up additional volume of 1.2 million out of that well. That’s about 47% of H2S.

Moving out in the Mid-Continent, FrontStreet acquisition is operating as expected. We did have some down time at the Duke National Helium plant. They had a scheduled outage for three days’ maintenance. Unfortunately as they moved into that work it took about eight days to complete. But that plant’s now back in service and so our NGL production at the Mocane plant. As I mentioned earlier we had the reduction at Mocane by the Hurricane Ike. That was about 20 days that we were down there but that’s back up and running.

In South Texas we continue to see improved margins from the consolidation of the various gathering systems in that area. That’s been a big focus of ours to pull together and consolidate and do some re-piping in that area. We’re out of that consolidation. We’re achieving better fuel efficiency. Also the Edwards line joint venture project came into full operations in the quarter and we’re seeing volume increases now. The current run rate in that joint venture is a little over 30 million cubic feet a day.

Turning our attention to the transportation segment volumes from the second quarter related to third quarter, just slightly increased 2 million a day. We have seen the overall margin on a throughput unit basis down from what we saw in the second quarter a little bit more in line with historical. Some of this was driven by the change in commodity pricing. So we’re there running. I would say that what we’re seeing here is stronger than we saw last year but probably a little bit more in line with what we expected. We were a little surprised with the strength in the second quarter.

On the other hand, our gas marketing company has continued to see higher spreads across the system and that is showing up in their margins. Their margins were up in the third quarter from the second quarter about $300,000.

Let’s turn our attention now to our contract compression segment. The segment margin in the second quarter was $30 million. In the third quarter it’s $33 million so we had a 10% increase quarter-to-quarter there. The revenue generating horsepower obviously drives that and it was up by 73,000 horsepower from a second quarter number of roughly 670,000. It moved up to about 743,000. We’ve added 174,000 horsepower through September.

The contract compression business remains strong. It continues to exceed our expectations especially in the Fayetteville Shale and in North Louisiana. Average horsepower which we monitor closely in that business because we think the best model is higher horsepower units was up slightly to 851 horsepower on average from 849 in the second quarter. All-in-all that number though is significantly higher than our contract compression peers.

We’ve talked to you a little bit in the past about our integration efforts. Our contract compression group now manages 100% of Regency’s compression fleet. You may recall that I discussed during the first quarter earnings call how asset optimization fits in our strategic initiatives. We’re executing on what I have referred to as Phase I efforts in that regard and this phase is focused on organizational structure, operational procedures and consolidated purchasing. We think that over the long term we’re going to see enhanced margins out of this effort.

You may recall that Regency has been developed through a combination of acquisitions and this reorganization really hasn’t adjusted to creating one culture. Our focus is on defining and establishing clear goals and objectives at all levels of the organization, a focus on continuing to operate our assets in an efficient and environmentally conscious manner, and focus on the safety of our employees, customers and communities in which we operate. Those are our top priorities through this restructuring of our cultural efforts.

We’ve implemented since we last talked a quarterly review process with all of our employees. We just went through that in the third quarter and those quarterly reviews are tied to bonus payments that we have for our employees based on performance.

We’ve also in the third quarter made several improvements to our benefit package for our employees that we think are going to strengthen our ability to attract and maintain the talent that we’ll need in the future years.

That’s sort of a summary of Phase I. The Phase II work is underway. It’s a little bit more long term in focus. Here we’re looking to improve fuel efficiency, run times, maintenance procedures and our team is working on this. They are to present me a full system-wide plan around the end of the first quarter next year and an implementation related to Phase II would be something that would happen over a number of years, especially as it would relate to any change-out for compressions.

Let’s take a look at a few comparisons related to commodity prices. Gas prices based on the Texas gas index declined $2.33 or 21% relative to the second quarter of 2008. Crude oil was down $6.23 or 5%. Our average for the entire quarter was $117.72. NGL products at Mount Belvieu, we had sort of a mixed bag during the quarter. Ethane was up 4%, propane was down 1%, butanes were down about 4%, and natural gasoline was down about 5%.

Realized sulfur prices on the other hand have risen from the second quarter. Our second quarter realized average price was approximately $299 per long ton and the third quarter realized average price was around $461 per long ton.

A little bit of focus on our operating performance looking at second quarter versus third quarter. Relative to the second quarter of 2008 our adjusted EBITDA decreased from $71 million in the second quarter to $67 million in the third quarter. This decrease was mainly driven by just really two impacts.

We had $4.1 million of impact from Hurricane Ike that was related to the curtailments I mentioned to you earlier related to the fractionators being shut down on the Gulf Coast. We also had an impact on the decline in natural gas of about $3.2 million. Natural gas liquids was a slight decline to $100,000. It was pretty neutral.

On the other hand, on the sulfur we had an increase of $1.9 million and our gas marketing based on basis spreads was up $300,000. Higher volumes added back about $1.2 million. So in summary, Ike and natural gas prices had a negative impact of $7.4 million, volumes and margins had a positive impact of $1.5 million, and sulfur price $1.9 million.

Quarter-to-quarter all factors put in the equation, it was down $4 million and really you can just come back to Ike. Had we not had the hurricane impact we would be up about $4 million.

A word or two about guidance. Based on the current commodity price assumptions of $7 for natural gas and $70 for oil and in our model we’re assuming $200 per long ton; and as I mentioned to you earlier those were actually $461 in the third quarter but in our model we’re assuming $200 per long ton for sulfur; based on those commodity fundamentals we are reiterating our guidance range of $255 million to $270 million. But we anticipate coming in on the lower half of that ranged based on the commodity prices that I shared with you.

Turning to organic growth initiatives. In the first nine months we incurred $231 million of growth capital. $99 million of that was in the third quarter.

This growth capital was primarily related to our compression segment where we spent $126 million for the purchase of additional compression systems and then in the gathering and processing segment $19 million for the construction of a 20-mile 10” pipe and related plant modifications to connect our Fashing processing plant to our Tilden plant in South Texas. We spent $17 million for the construction of 40 miles of a 10” diameter pipeline and compression facilities in West Texas and $6 million for the construction of pipeline compression and treating facilities related to a joint venture in South Texas.

On the transportation segment our capital in the first nine months was $3 million for the Haynesville expansion project.

Looking at 2008 our view is we’ll be spending $356 million cap ex on organic projects in aggregate. The breakdown on that is approximately $143 million for the compression segment, approximately $116 million in gathering and processing, and the remaining $97 million will be spent on the Haynesville transportation project.

As I mentioned in my opening comments, we are establishing a revised growth capital and financing objectives for the company. To reduce dependence on the capital markets we’re revising our 2009 and our 2010 growth plans to reduce our total debt and equity requirements by approximately $850 million.

This reduction is going to be accomplished by one, reducing our base growth capital by $400 million. We forecast that our new spending will be roughly $100 million a year versus our previous forecast of $300 million a year.

Two, we’re reducing the capital requirements of our Haynesville expansion project by $450 million and we’re doing this through redesigning and downsizing the project. I would remind you though that we’re downsizing to 1.1 billion which is still a very sizable and significant project in today’s market.

I would tell you that as we went on through this process we worked very closely with our general partner on all issues affecting Regency. They remain committed to Regency’s long-term success. They stated publicly that Regency will be their platform for growth in the midstream space, and we’ve worked hand-in-hand with them to structure the best financing options for Regency as a company and for this project.

I would remind you that they are a significant investor in our company and they have a strong history of demonstrated support. You may recall that when we acquired FrontStreet that was acquired with equity and that earlier this year we did an equity offering in a market that at the time we were doing it turned a little tight because of some things outside of our control. The market did have a little tightness in it and our general partner there took 25% of that equity offering or $50 million.

Overall as we’ve looked at how we’re structuring our plans we really don’t believe that now is a good time to issue equity when we look across our broad spectrum of shareholders. We think that the plan that we’ve put together actually represents the best course of action for Regency and our shareholders as we look across the next two years.

Let’s turn and give you a little bit more detail on the Haynesville project and on the downsized project as we referred to it. Really we’ve re-scoped the project in a number of ways but I would remind you as I said earlier the original project was 1.45 bcf of capacity. This project is going to retain nearly 1.1 bcf of that capacity.

The cost for the project as we have re-scoped it should run about $650 million excluding capitalized interest and labor. We expect that 80% of the fees that we’ll receive for this project will be demand charges and the remaining will be commodity charges. This is very similar to the original project.

I think you have access to some maps that I would turn your attention to under the Haynesville Update section. There should be two maps there. One shows the original project and the one behind that shows the revised project.

I would draw your attention first on the upper left-hand corner of the original project. You’ll see a lateral referred to as the Blanchard Loop. Of all the pieces of this project, that was probably the most expensive piece of the project because of location. We are eliminating the Blanchard Loop from the project.

Secondly you’ll look at the bottom left-hand and you’ll see a lateral called the Logansport Lateral. We are eliminating that. The elimination of that essentially will impact all producers with production down in the Logansport area as we’ll not have direct access from those producers to the revised project.

There’s a small lateral on here called the Elm Grove Lateral. We’re eliminating that lateral. It will require that some producers move gas a little bit further southeast to connect to the Elm Grove pipeline.

There’s some compression at Woodardville Station. That compression is being eliminated at this point in time. It’s something that could be put in later years if we need to add volume.

Far on the right-hand side, the Cane Hill compressor station is also not a station that we’re going to need under the redesigned project.

I think it’s important to note though that what we have retained within this project is that beginning where the Bienville Loop comes into the RIGS system we are retaining the 42” pipeline that is essentially looping our existing system. By retaining the full 42” capacity it really maintains flexibility and optionality at a later date to add compression and move substantial incremental volumes above this redesigned 1.1 bcf per day.

Where are we today? We’re in ongoing discussions with producers, suppliers, contractors, banks and other financing providers related to this redesigned project. We believe that in spite of some of the recent reduction in commodity prices that the producers in the Haynesville area remain extremely interested in additional capacity being built in this region. Our preliminary discussion with producers that were the original producers that were committed to our larger project suggests that we are going to have comparable percentage commitments as we did in the original project.

We shared with you before when we announced the project that 75% of that was committed through some anchor shippers. We think those same anchor shippers will be committing to about 77% of this project. Some of those shippers based on location do not have access to the system such as the shippers in the Logansport area; otherwise you would have seen this number be a larger number.

In addition to them we have had very favorable response with other shippers that do have access to this redesigned project and based on those discussions I would expect that rather quickly we can move up into the 90% commitment range for this project. Before it goes in service I would be surprised if it wasn’t 100% committed. There is very, very strong interest in a project being built to move these volumes.

We made from our operations teams significant progress in securing right-of-way permits, securing contracts with suppliers, route reconnaissance for the pipeline, and a lot of the route work that we had done on the old project is still applicable to this project. Basically if you just look at the revised project, route reconnaissance is virtually complete so I would expect that we’d have fewer reroutes or contingencies with the redesigned project.

I would mention in that cost number of $650 million there’s approximately 18% of contingencies built into that number as well.

Over the next 30 days we will be focusing intently on obtaining firm transportation agreements for this resized project; we’ll be working diligently to seek and obtain the acceptable financing for the project; and also satisfactory supplier arrangements. If these conditions are met and as I mentioned earlier there’s work to do, we expect that this project could be in full service by the end of 2009.

In regard to economic impact on the project we expect that the economics to be comparable to the original project. We shared with you before that you would be looking at a multiple in the 6 to 7 range. The EBITDA on this project as it is currently envisioned should be somewhere between $90 million to $100 million in the first full year of operation.

Turning our attention now to cash distributions. You saw our announcement earlier of $0.445 per outstanding common and subordinated unit for the third quarter ended September 30, 2008. That represents a 14% increase over the third quarter of 2007. The distribution is equivalent to $1.78 on an annual basis and will be paid on November 14, 2008 to unit holders of record at the close of the business on November 7, 2008.

The cash available for distribution during the quarter was $48 million. That’s a coverage of 1.4 times the amount required to cover our distribution to our common unit holders and subordinated unit holders. That’s a coverage of 1.3 times the amount required to cover all distributions including the Class D units. These are very strong coverage ratios and we continue to prudently manage our balance sheet and will reinvest cash into our business. Over the long term we expect to continue to maintain coverage ratios in the range of 1.15 to 1.25.

We covered a lot of ground. Obviously you’ll have questions and I’ll look forward to your questions after Stephen finishes his further review on the consolidated operating results.

Stephen L. Arata

On page 8 we’ve put our consolidated operating results. Our net income for the three months ended September 30 was $49 million. That compared to a net loss of $10 million for the same period last year.

The increase in net income was primarily due to first of all a $22 million mark-to-market gain on hedges which reversed $21 million of mark-to-market losses in the first two quarters of this year. It was also due to an increase in adjusted total segment margin of $54 million and the absence in the current period of a $21 million loss on debt refinancing for the early termination penalty associated with the redemption of 35% of our senior notes last year.

Those items were partially offset by several items: First of all an increase in O&M expense of $16 million which was primarily due to O&M expenses in the contract compression segment which was acquired in January and is not represented in our ’07 results; and also a smaller increase in employee related expenses mainly in the gathering and processing segment.

We had an increase in depreciation and amortization of $11 million primarily due to the CDM and the Nexus acquisitions as well as from the organic growth projects we’ve been executing. We had an increase in G&A of $7 million again which is primarily related to the acquisition of the contract compression assets in January. Finally we had an increase in interest expense of $5 million due to increased levels of the borrowing which were somewhat offset by lower interest rates this year versus last year.

Our partnership adjusted EBITDA nearly doubled from $35 million in the third quarter of last year to $67 million in this quarter. If you want further details on those EBITDA numbers, they are on slide 13 in the Appendix.

With respect to earnings per unit, the partnership reported EPU of $0.56 in the third quarter which includes the $22 million of mark-to-market gains. Because the GP gets a disproportioned allocation of that mark-to-market gain because we have to work the gain through the high splits calculations, our EPU excluding the gains cannot be adjusted by just dividing the $22 million by the number of units we have outstanding. If you run those gains through the splits, our EPU excluding the mark-to-market gains is $0.36 per unit.

Additionally as Byron mentioned, Hurricane Ike reduced our net income by about $4 million. On a recurring basis our third quarter earnings per unit was $0.41.

On page 9 you can move to our gathering and processing segment update. As Byron mentioned, our throughput in the gathering and processing segment increased substantially in the quarter from 0.9 million MMBtu’s a day to nearly 1.1 million. Our NGL production decreased by 6% to 21,000 barrels a day and that was primarily due to curtailments in East and West Texas. Without these curtailments our NGL production would have been up slightly year-over-year.

Our adjusted segment margin increased by 34% to $65 million. There were several items that’s attributable to. First of all, we had a $7 million increase throughput volumes in North Louisiana but we had a $5 million positive adjustment from increased sulfur prices year-over-year. We had a $4 million positive adjustment for projects placed into service in South Texas that were not in service in 2007. We had a $3 million contribution from Nexus assets. Those four items were partially offset by a $2 million decrease that came from a variety of other sources.

Our adjusted segment margin per MMBtu increased from $0.60 in the third quarter of last year to $0.65 in the third quarter this year. That increase is primarily associated with the completion of our organic growth projects in South and East Texas and an increase in commodity prices year-over-year.

On page 10 we have some information on our transportation segment. Our throughput increases slightly as Byron mentioned to 795,000 MMBtu’s per day from 789,000 last year. Our adjusted segment margin increased $5 million year-over-year. Our adjusted segment margin per MMBtu increased from $0.21 last year to $0.27 year-over-year and as Byron mentioned that’s a much more normal operating margin than last quarter’s $0.33 which had some one-time items in it.

We had $2 million in increased margins associated with our limited marketing function year-over-year. We had about a $1.5 million improvement from increased operational efficiencies coupled with some increased commodity prices. Finally we had a $1 million benefit from increased throughput volumes as well as a change in contract mix that benefited us.

On page 11 there’s some data on our contract compression segment. We had a segment margin of $33 million in the third quarter. Our revenue generating horsepower increased 11% year-over-year by 73,000 horsepower. 81% of our revenue generating horsepower is greater than 1,000 horsepower in size currently. As Byron mentioned, our average horsepower per unit increased from 849 to 851.

Moving on to some of our commodity positions and I wanted to give you a few thoughts on where we are currently.

With our current business mix at least 60% of our margin across the entire business is now fee based. We are a net seller of both NGLs and condensate and we have executed swap contracts to hedge our exposure.

On the NGL side for the fourth quarter this year we have hedged 94% of our expected equity volume exposure. When we talked recently that number was 88% but due to the curtailments at our Waha and Eustace facilities that percentage has moved up slightly for the balance of this year. For 2009 we have hedged 88% of our expected equity volume exposure and in the second quarter we hedged 31% of our expected 2010 equity volume exposure.

On the condensate side we’ve hedged between 70% and 72% of our exposure for the balance of this year, 2009 and 2010. Those have been executed through WTI swap contracts at approximately $68 per barrel this year and next year and $121 per barrel in 2010.

Due to the execution of some of our existing projects in South Texas our natural gasoline has increased and we’ve seen greater fuel efficiencies across our systems such that are currently now approximately 15,000 MMBtu’s per day. We are currently evaluating hedging options to take some of that commodity exposure away.

I’ll remind you that we have not posted any margins for our hedges. Our hedge counterparties are considered [inaudible] with our senior secured debt under our credit agreement.

Finally, an update on our Sim Group exposure. I mentioned during our last earnings call that we had ceased conducting business with Sim Group as of July and we signed a long-term contract with another crude buyer. During the third quarter we reserved the entire amount of receivables due from Sim Group of approximately $0.5 million.

For the rest of the year with respect to commodity exposure, I want to give you an update on how things look. We typically give you an estimate of how our margins will change given a change in prices of commodities. For the balance of the year a 10% change in prices will result in a 1.4% movement in gross margin. To put that in dollars, based on the current price deck a 10% increase or decrease in oil, NGLs and natural gas prices would impact our margins by about $440,000 per month.

Moving on to some discussion on our liquidity and capital needs. At the end of the third quarter our capital structure was composed of 51% equity and 49% debt. As Byron mentioned we are working with our banks to secure debt financing related to our revised capital spending plans.

Our previously discussed commitments were subject to the execution of definitive loan documentation as well as other terms and closing conditions. Given the recent disruption in the credit markets, we currently believe we will not be able to access these commitments. We are working with our banks to amend our credit agreements and raise the financing required for the completion of our capital spending plans.

Our current revolver is a $900 million facility. We completed a $204 million equity offering during the quarter and we’ve used the proceeds from that offering to pay down the revolver. We have a $35 million commitment as part of our bank group from Lehman. Lehman’s bankruptcy has effectively reduced our access to the revolver by $9 million. To the extent that we pay down the revolver we will be unable to redraw Lehman’s pro rata portion that we have repaid. As of the end of October we have $668 million drawn on the revolver; we have posted $16 million of letters of credit which leaves $207 million remaining undrawn.

I would now like to open the microphone for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Our first question comes from [Gabi Moeen] - Merrill Lynch.

[Gabi Moeen] - Merrill Lynch

In terms of the scaled back base capital expenditures I wonder if you could elaborate a little more on that. Does that $100 million versus the $300 million annually include contract compression? And maybe you could just give a little more color in terms of what you’re not going to be pursuing given that scaled back number?

Byron R. Kelley

Yes, we’ll add a little bit to that. Obviously if you take that $100 million a year, it can move around based on some priorities. We would see a substantially higher portion of that allocated to the compression business and then with some remaining in our gathering and processing business to do some smaller things that we may want to do over that timeframe.

[Gabi Moeen] - Merrill Lynch

You feel comfortable with the returns? Is that just because compression’s highest returning and least commodity sensitive in terms of your business mix?

Byron R. Kelley

Actually if we were doing fee based gathering, that wouldn’t be commodity sensitive and I think that at this point that’s what we would be looking at. We’re going to try to direct our capital to the highest return projects but I would remind you a little bit that when it comes to our compression segment we do buy equipment in advance. You have to. So we have some commitments for compression equipment out through next year and will be a big driver on how much is allocated to them next year for that segment.

Overall both these businesses give us very acceptable returns and you remember on the compression business those returns tend to get better over time the way their contracts are structured.

[Gabi Moeen] - Merrill Lynch

In terms of the new project financing on the resized Haynesville project, should we assume that the proportion of the financing you’re looking to get for the resized project is proportional to the old project capital? In other words, it was $600 million of $1.1 billion so approximately 2/3 in terms of lining up project finance for the resized project?

Stephen L. Arata

I think the way we think about it is we’re trying to keep our long-term debt-to-EBITDA ratio around 4 times so I think initially we’re looking at financing the project with debt and then we expect to issue equity some time later next year to get the overall amount of debt down to around the $400 million number you mentioned. We would expect to initially fund up to $600 million of the project with debt and then come back and issue equity in about a year or so.

Byron R. Kelley

I think in general you need to look at this as just sort of a two-year plan and not project specific to that but our overall two-year plan for our capital needs.

[Gabi Moeen] - Merrill Lynch

To that can you talk a little bit more about what your discussions with GE? We’ve had some other MLPs come out and have their general partners make significant support and clearly GE has demonstrated that historically. Should we be expecting near to medium term coming from GE and also I guess the trade-off between distribution growth, distribution maintenance and capital growth? And maybe some color on how they’re thinking about things if you’ve got some?

Byron R. Kelley

I would say that in general what we’ve tried to look at in our plan is what is the best plan for all of our unit holders based on both the capital needs and the equity needs. We don’t see a need right now for pushing towards any large equity infusion this year so as we develop this plan we think that this plan is implementable in a manner that doesn’t require a general partner to make a huge equity infusion.

We think we can implement the plan without any equity infusion. We’re going to move forward with that but I would just remind people that it is a strong general partner that’s been with us in the past and we expect them to continue to support this company. We just don’t think there’s a need for that at this point.

[Gabi Moeen] - Merrill Lynch

By this point you mean at least give you running room for another couple quarters?

Byron R. Kelley

No, not just that. We think that the plan that we implemented as we’ve got it laid out we are going to be able to access the debt in equity markets in a manner that all this can be done without a reliance on the general partner.

Operator

Our next question comes from Michael Blum - Wachovia Securities.

Michael Blum - Wachovia Securities

In general looking at the Haynesville project, would you say the revised project is driven more by changes in the development plans of the producers given the change in the commodity environment, etc. or is it more driven by capital constraints on your side in terms of how big a project you wanted to pursue?

Byron R. Kelley

I would first say that this has not been driven by changes in producer plans although there are some changes out there as you’re aware of as producers look at their own equity. This is driven by us looking at what we think is the appropriate way to manage our own balance sheet and still retain strong growth but to be able to manage this within things that are more within our control.

So it’s not driven by the producers. There is strong interest in this project. There is as much interest today as there ever was. If you think about this, the resized project is taking out about $300 million to $350 million of capacity, but it is still a very large project, it’s still going to move a lot of gas, and it’s still going to be very timely.

It does have a different impact on different producers depending on where they’re located but as I mentioned earlier every shipper that has access to us that we talked to earlier is essentially taking all of the capacity that we’ve got available to them at their points of receipt and then we have other shippers that are interested in the remaining capacity. Interest is very strong.

I think one of the things that when you’re trying to look at the interest in the market in general about capacity out of the Haynesville area, you’ve seen a recent public announcement of one company asking for an interest in building another pipeline. So there is no waning of interest. The Haynesville area generally has the highest returns that we can tell for almost all of these producers in terms of things that are in their portfolio.

Michael Blum - Wachovia Securities

The 77% that you cite in terms of producer interest, have those producers signed letters of intent or is that just a verbal commitment or what’s the level of that?

Byron R. Kelley

This is preliminary discussions. Once we completed our thinking on this and redesigning this and our own estimation of how this would have different impacts on different players, we went back to the shippers that had the original letter of intents and we’ve talked to them on a preliminary basis about their interest in this project. Obviously we have a lot more discussions to have with them over the next few weeks but in their preliminary indications they gave us numbers based on the new project that they would want and where they would want to deliver that. Those numbers add up to about 77% of the 1.1 billion cubic feet.

Michael Blum - Wachovia Securities

Just to clarify, in terms of the funding plan you’ll initially fund with debt and then in terms of equity your plans would be in the latter half of 2009?

Byron R. Kelley

That’s correct.

Michael Blum - Wachovia Securities

Last question for me is just generally across your systems and your business, are you seeing any reductions in volumes coming through your systems now and do you expect to see that looking into the next quarter and next year?

Byron R. Kelley

As I mentioned earlier, in North Louisiana the plans we’ve looked at we think there are some movement of rigs from North Louisiana to the Haynesville Shale. What we think we’re seeing is a plan that basically those are pretty close to flat. As they move more rigs in the Haynesville and South Texas on the other hand we’re seeing some producer drilling there that’s looking very favorable.

There’s a producer that recently announced on gas that would come into our Tilden Fashing area a 5 million a day well that’s already been connected to us and they expect to bring on very shortly another well. In talking to them we’re seeing that we may see as high as $30 million in incremental volumes there by the end of the year. We see in Mid-Continent it’s sort of flat going forward but with the growth right now I think South Texas and certainly the Haynesville area.

Operator

Our next question comes from John Edwards - Morgan Keegan.

John Edwards - Morgan Keegan

I think originally you had budgeted around $94 million towards Haynesville spending this quarter. It sounds like from scaling things back that’s not happened. Could you tell us how much has been spent?

Byron R. Kelley

$3 million through the end of the third quarter has been spent.

Stephen L. Arata

We expect to spend $97 million by the end of the fourth quarter so our full year ’08 numbers have not changed materially.

John Edwards - Morgan Keegan

Back to the financing questions, you’ve indicated that issuing equity at current levels would not be acceptable but you plan on issuing late next year. Where would equity yields have to be to make it an acceptable environment in terms of a range in which to issue equity?

Stephen L. Arata

Well, I don’t think we have a specific target yield. I think trading around 14% to 15% yield we don’t think is acceptable. We haven’t determined a specific price but we would expect at some point the markets to get somewhat better.

John Edwards - Morgan Keegan

There’s a statement on the press release. Maybe you guys can give me a little insight into this. It says that if Regency is not successful in securing anchor shipper contracts necessary that Regency’s cash flow may decrease possibly resulting in a reduction of distributions to unit holders. I realize part of that is legalese but maybe you could explain that a little bit more clearly.

Byron R. Kelley

Obviously we’ve got work to do and what we’re saying is we’re really doing a hard focus on what we want to accomplish over the next 30 days or say; 30 or 45 days. Part of that is re-signing agreements with shippers and if the shippers were not interested in this project, then obviously we would not go forward with building the project. Then at that point we would have to essentially have a mitigation plan for what we would do with some pipe that we have commitments to buy and those are things that we are thinking about at this point.

I think generally we are very optimistic at this point that there’s strong shipper interest in this project and that we will have plenty of interest. But we’ve got work to do on the financing side.

Stephen L. Arata

I have one follow up on your prior question on the target yields for equity. I would want to emphasize that the economics for this project are very robust. We certainly don’t want to issue equity at a 14% to 15% rate but even if we were to do that, I think this would still be a positive return project for us. We just think that the market is going to improve at some point and allow all of our shareholders not to be so significantly diluted by issuing equity at that price.

John Edwards - Morgan Keegan

Right. Obviously you’ve got things working in parallel process here. You’re trying to make some commitments on the front end to enable you to get the producer agreements signed but by the same token you want to balance that. You don’t want to get too far down the road and then be halfway through a project say; I’m not saying you get that far; but you get to a project where you don’t know where the financing is coming from. You don’t want to be in that vulnerable position. I’m just trying to get a sense of how you’re balancing those issues.

Stephen L. Arata

Currently our desire would clearly to be issue equity in the second half of ’09 but this initial financing we’re talking about to finance the project will actually be sufficient to enable us to complete the project without having to raise any more funds. The equity issuance in the second half of next year would get our balance sheet back where we want it to be. But we would not be going down the path of not having enough financing to finish the project.

John Edwards - Morgan Keegan

So there’s enough. In effect you’re doing a project financing type revolving facility that you can get it done?

Stephen L. Arata

It’s not technically a project financing but it’s enough financing to enable us to complete the project.

Operator

Our next question comes from Gregg Brody - J.P. Morgan.

Gregg Brody - J.P. Morgan

You mentioned this financing that seems like it’s in place or at least you’re starting something. Can you provide a little more color around what that is?

Stephen L. Arata

We’re working with our key banks to structure the financing for this project. We’ve gone back to them. Most of the banks, although not all of them, are in our current facility. We’ve had very positive discussions with most of them. We haven’t yet launched the new financing. We expect to do so shortly. We’re optimistic we’ll be able to raise a significant part of the funds we’re looking to raise as part of this effort.

Gregg Brody - J.P. Morgan

Is it expected to be long-term in nature or is it expected to be a bridge?

Stephen L. Arata

It will likely be co-terminus with our bank facility which is a three-year facility for now.

Gregg Brody - J.P. Morgan

For the cap ex in ’09 can you provide a little more detail about the timing of the cap ex over the year? You mentioned in your release as well as the Q that there may be some flexibility with some of the commitments. If you could provide some color around that, that’d be great.

Stephen L. Arata

The commitments for next year, we are still working with the suppliers to determine the final phasing of the commitments. Currently now we are taking delivery of some pipe but that’s the $97 million this year. We expect in the early part of next year the monthly spend will slow down significantly but then as we begin construction closer to the summer and the fall that’s when the most significant cash flows would be required.

Gregg Brody - J.P. Morgan

Is it fair to say that if you don’t have some of the firm capacity in place from some of your end users, that’s when you would likely revise your program by next summer?

Stephen L. Arata

I’m not sure I understood the question.

Gregg Brody - J.P. Morgan

The commitments from the shippers.

Stephen L. Arata

Byron, do you want to answer that?

Byron R. Kelley

We expect to have our commitments from the shippers. Our objective is to have that sewn up in the next 30 to 45 days. We’re going back to them and we’re talking about the delivery points. We’re not going to build the project till we have commitments, if that’s where you’re coming from. We’re not going to start construction on this project until we have a level of commitment that we feel gives us a very high level of confidence that we’re going to move the volumes we expect. I think that will happen.

Gregg Brody - J.P. Morgan

I appreciate that. I was just trying to get a sense of timing around that. So that’s very helpful. And then just a general question. You mentioned with the reduced scope of your project in Logansport and Blanchard Loop, I’m just curious. What’s there to pick up that capacity for any of the producers over there? Is there an alternative or how in effect are they going to get their gas to market?

Byron R. Kelley

I think it would depend on the producer and in each location they have some different options. Some of those options could be to move gas westward back into Texas. There may be some smaller amounts of capacity out there on a few other pipes that are there. I’m sure these producers are back talking to other people with different assets out there.

Our limitations with the new project at Blanchard, originally we were going to move 400 million there. We have capacity for 200 million so we’re allocating that 200 million back to the original producers. In the Logansport area there’s also been a producer recently that has signed an RFP asking for an interest in somebody else to build additional pipe out of that area.

Richard Moncrief

One other option we’ve got is our Sonat abandonment opportunity that we’re still waiting on there and there is a third party gatherer that’s looking to bring some gas from the Logansport area back into our system at our Elm Grove delivery point.

Byron R. Kelley

I would just remind you too that somewhere down the road the system we’re building has the optionality to be increased so at some point we or somebody else may well build a link from Logansport up to us in the Elm Grove area in addition to what we might ultimately get out of the Sonat project.

Operator

Our next question comes from [Shawn Grant - ZLP].

[Shawn Grant - ZLP]

On your guidance it seems like the reason that’s coming down towards the lower end is mostly due to hurricane impact, at least $4 million in Q3. Is that true and then how much are you expecting or anticipating in that revised number for the fourth quarter?

Stephen L. Arata

That is correct. As we said the hurricane was about a $4 million impact in Q3. We expect it to be about another $1 million in Q4 for a $5 million total for the year. If not for the hurricane, we would not have made the comment that we expect to be in the lower half of the range.

[Shawn Grant - ZLP]

Was that impact from lost volumes or higher O&M or one-time charges?

Stephen L. Arata

There’s a little bit of higher O&M but the vast majority is because we weren’t able to process NGLs at a couple of our facilities because the fractionators were off line downstream.

[Shawn Grant - ZLP]

On the $600 million facility that you guys originally had in place to finance the Haynesville, is that officially off the table and why is that? It sounds like you’re looking to upside your revolver instead of that. Could you talk a little bit about the pricing would be in that scenario?

Stephen L. Arata

To answer your first question, the first option is not off the table. We just don’t believe we’re going to be able to execute on that primarily because the other options we’re looking at with the bank groups we believe are more economic than what we could do under the original commitments. The upside of the revolver is not an option we’re looking at. We’re looking at more on the term loan side than in the revolver side.

[Shawn Grant - ZLP]

So you’ve got $200 million on the revolver approximately and then $250 million accordion and then you could go out and get another $450 million term loan or something like that? Is that the thought?

Stephen L. Arata

Our accordion can be used both for revolver or term loans so it would likely be all in a term loan. But you’re right. We would likely go out and look to increase the size of the term loan as well.

[Shawn Grant - ZLP]

Do you know what kind of pricing you’d be looking to get there?

Stephen L. Arata

We don’t know at this point. We’ve certainly had indications from people but until you put an actual deal out there in this market it’s hard to tell what the actual numbers would be. But I think the pricing indications we’ve received have been in a range that we think would be acceptable.

Operator

Our next question comes from Gary Stromberg - Barclays Capital.

Gary Stromberg - Barclays Capital

Some additional questions around the financing that you were discussing. What is the unsecured notes? What is the capacity for secured debt under that instrument?

Stephen L. Arata

Offhand I don’t know the answer to that question.

Gary Stromberg - Barclays Capital

Would the term loan facility you’re discussing be under the unsecured notes or is it going to be a separate stand alone financing arrangement?

Stephen L. Arata

It would be done under our current existing secured credit facility. We believe we have enough capacity to do this. That hasn’t been an issue.

Operator

Our next question comes from [Yves Siegel - Aroya Capital].

[Yves Siegel - Aroya Capital]

Could you give some color on what you’re seeing on the contract compression business and are you seeing any compression coming back to you at this juncture? What I’m thinking is given the capital markets, are you seeing any sort of increased demand from producers deciding that rather than spend the money they’d rather rent? That would be the first part. The second part is are you seeing any compression coming back to you?

Stephen L. Arata

I think with respect to compression coming back to us, our business model is such that we move a lot of compression every month to relocate it and optimize its use. But we’ve seen in every month net placements of additional compression of significant amounts. We’ve seen shifting areas where people want compression and I think our most active areas right now are Fayetteville and the Haynesville/North Louisiana area. But we haven’t really seen reduced demand.

Byron R. Kelley

I would add a little bit to that in that we order compression in advance so we’re constantly talking to the producers about what their needs are. They’re not telling us that there’s going to be a reduction. Now we all look at the world and look at what’s going on and do wonder will people stay as strong with their drilling programs over the next few years until the markets stay strong. So we try to analyze that.

I will tell you that with the plan that we put out here and our plans for the capital that we will put in CDM over the next two years, that is as you recall from our earlier discussion significantly less than we had. I’ve got very little concern that the amount of demand we’re building into this program that we’re going to be able to place that. Right now I can tell you there is a stronger market than we’re building into our plans.

Operator

Our next question comes from John Edwards - Morgan Keegan.

John Edwards - Morgan Keegan

Along the lines of the compression side, it looks like the costs coming in here was quite a bit less or I guess I should say the margin per machine was a little bit lower at least than what we were thinking about. It’s kind of a follow on to Yves question. You’re not seeing any real change in that market or the amount that you’re able to obtain per unit of compression?

Stephen L. Arata

Not really. The business model that we use in contract compression generally assumes an EBITDA margin of about 45% and that’s what it’s historically been prior to our ownership. We’ve seen it right at 45% or a little bit above this entire year and we expect it to remain there or slightly above that.

Operator

That concludes the question and answer session. I would now like to turn the call back over to Shannon Ming for closing remarks.

Shannon A. Ming

We appreciate you joining the call today and know that we covered a great deal. If you’ve got follow-up questions, please don’t hesitate to call. Thank you.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Have a great day.

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Source: Regency Energy Partners LP Q3 2008 (Quarter End 9/30/08) Earnings Call Transcript
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