Regency Energy Partners LP. Q4 2008 Earnings Call Transcript

| About: Regency Energy (RGP)

Regency Energy Partners LP. (RGNC) Q4 2008 Earnings Call March 2, 2009 11:00 AM ET


Byron Kelley - Chairman, President, Chief Executive Officer

Stephen Arata - Chief Financial Officer, Executive Vice President

Dennie Dixon - Senior Vice President - Operations

Shannon Ming - Vice President - Investor Relations & Communications


Michael Blum - Wachovia Securities

Chris Holt - Barclays Capital

Xin Liu - JP Morgan

Lenny Brecken - Brecken Capital

John Edwards - Morgan Keegan

Adam Rosenberg - GLP


Good day ladies and gentleman, and welcome to the fourth quarter 2008 Regency Energy Partners LP earnings conference call. My name is Louisa and I will be your operator for today. At this time all participants are in listen-only mode. We will conduct a question-and-answer session towards the end of this conference. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the call over to Ms. Shannon Ming, Vice President of Investor Relations & Communications. Please proceed maam.

Shannon Ming

Good morning everyone, welcome to our fourth 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.

Distribution of the release and the slides that we will be using today are available on our website at 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. So please read the slide.

Also included in the presentation today are various non-GAAP measures that have been reconciled back to GAAP or Generally Accepted Accounting Principles. These schedules are at the end of the presentation starting on slide 27.

Before I turn the call over to Byron Kelley, Regency’s CEO I would like to announce that Regency will be hosting an Investor Day in Dallas on March 31, to discuss our 2009 goal, our growth strategy and our guidance discussion for 2009. As well as provide an update on our Haynesville Expansion Project. Please feel free to contact me with any questions that you might have.

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

Byron Kelley

Well good, morning and let me add my welcome to each of you for joining us today. Before we move into our presentation I do want to take just a minute to introduce the newest member of our Senior Management Team Mr. Dennie Dixon. Dennie joined us in February as Senior Vice President of Operations.

His career covers gathering and processing, natural gas transportation and really span the full spectrum of operations, commercial activities and development with companies such as Tenneco Energy, El Paso Energy and Louis Energy. So we are pleased to have Dennie as part of our organization, part of our management team.

During the question-and-answer section, if you have some specific questions around operations, we will make Dennie available although he is only been here short period of time. So, we may put him the fire pretty quick, but we are all glad to have him on our team and look forward to you get to know him better as we move through the reminder of the year.

As you know, last Friday we announced the formation of a joint venture that allows us to finance the Haynesville Expansion Project. We are very pleased to enclose that this milestone and continued moving forward with the construction phase of the expansion. We are also pleased and excited to have a long term partner and Alinda who shares the same objectives as Regency and GE Energy Financial Services around infrastructure development opportunities for the fast growing Haynesville Shale play in North Louisiana.

Without a doubt last Friday was an important day for us, it was an exiting day for us, and this morning we look forward to providing you more color around the joint venture structure, but I’m also pleased to be able share with you this morning, details regarding Regency’s strong fourth quarter performance and our strong year-over-year growth.

I like to begin with just some highlights related to the transaction and one of the important objectives of Regency and of GE Energy Financial Services was to be able to partner with a long-term investor that meet our criteria related to financial and strategic goals. We were successful in meeting this objective, Alinda’s investment thesis is to be a long-term partner and we expect them to be part of funding future growth through contributions of additional equity or debt at the joint venture or combination of both.

We believe this structure is in the best interest of our unit holders and our debt holders and it’s our plan to maintain current distributions of $0.445 throughout the construction period of the Haynesville Project and we believe this structure presented us, with one of the most efficient cost of capital options available in today’s market.

The base returns exceed the cost of new equity capital and the potential to use debt at the joint venture to fund further expansions will lower the overall cost of capital at the joint venture level.

The financing plan allows us to move forward on a timely basis, construction on this project will start on schedule. It enables us to honor our vendor commitments made last year and it also increases liquidity due to a one-time distribution to Regency for reimbursement of all Haynesville Project cost up to the date of closing.

This structure also allows Regency to continue to operate the assets in the joint venture. I would ask you to turn to Page three of the presentation, and I’ll cover some of the details of the structure itself.

A subsidiary of Regency has entered into a joint venture with an affiliate of GE Energy Financial Services and two funds managed by Alinda Capital Partners. Upon closing of the JV, Regency will acquire 38% of the equity interest in exchange for deemed $400 million capital contribution consisting of its Regency Intrastate Gas System assets.

GE Energy Financial Services will acquire an equity interest representing 12%, in exchange for $126.5 million cash contribution. The Alinda investors will acquire a 50% acquiescing interest in exchange for $526.5 million of our cash capital contribution.

Alinda Capital Partners is one of the world’s largest investors in infrastructure, through the Alinda infrastructure funds. These funds are unlisted institutional funds with over $5 billion in capital commitment. Fund investors are predominantly pension funds for public sector and private sector workers.

Alinda has ownership interest in Airports, roads, retail gas distribution and transmission, water and waste water and other infrastructure assets that provide essential services to communities, governments and businesses and additionally, as part of the structure all cash contributions from Alinda and GE Energy Financial Services will be contributed to the joint venture at closing.

Turing now to Page four of the presentation; I’d like to talk about the transaction overview and how the assets will be managed. The other side of the business and the fair to joint venture will be managed by our management committee consisting of four members. Each investor will have the right to appoint one member. Two members will be nominated from Alinda. They are actually investing through two separate funds, so they’ll have a member nominated for each fund. There will be one member nominated from GE Energy Financial Services and one from Regency.

Each member of the committee will have a vote equal to the sharing ratio of the investor that appoints such member. So in this case, Alinda will have a total of 50% of the vote; GE Energy Financial Service will have 12% of the vote and Regency 38%.

All cash will be distributed readably to investors on a quarterly basis and each partner has the right of first offer to purchase other investors or sale equity and in Regency and GE Energy Financial Service can’t sell their interest to each other without triggering the right of first offer provision.

Under an area of Mutual Interest Agreement, the joint venture has the first option to acquire or purchase certain natural gas transportation and storage opportunities in a defined area of North Louisiana and as I mentioned earlier, Regency will receive a cash payment from the joint venture partnership at closing equal to the total Haynesville Expansion Project capital expenditures paid through that date. In closing it is expected to stay before the end of March.

Slide five gives you an overview of the assets that are being contributed by Regency. It’s the Regency Intrastate Gas System we refer to it often as RIGS. These are the assets that we are contributing and these are also the assets that are the foundation for Haynesville Expansion Project. This system is a 320 mile natural gas pipeline in North Louisiana with a posted capacity of 910 million cube feet a day. It transports gas from Northwest Louisiana to North east Louisiana connecting producing fields such as Sligo, Sibley, Ada, Elm Grove, Vernon and VIXON fields to a number of interstate markets.

This system provides a platform for Regency Gas marketing, but the marketing company is not a part of the joint venture, it is not part of the contribution. The system also connect Regency Gas gathering to intrastate markets including the union power and Swepco. Regency gathering and processing assets are not part of the assets contributed to the joint venture.

The system is connected to Gulf States Transmission, Regency 10 mile FERC regulated interstate pipe. These assets are not part of the joint venture. So our interstate pipelines are gathering the process in the business, and our marketing businesses all remain within Regency.

On slide six, listed some other join venture benefits for Regency and there are many benefits out of this join venture, but by partnering with the GE Energy Financial Services and Alinda, Regency has secured financing for the Haynesville Expansion Project under terms accretive for our unit holders in 2010 and beyond.

The joint venture allows Regency to develop a fully financed strategic project, a projects that has minimum sensitivity to volumes and commodity price fluctuations. You may recall that as of December of 2008 Regency had approximately $220 million of commitments related to this project, these commitments will be transferred to the joint venture once it closes.

This firmly establishes Regency as a significant player in one of the most active natural gas players in North Louisiana. It provides much needed takeaway capacity for the expected Haynesville production.

The pipeline and the expansion of the pipeline itself is economically expandable, we’ll begin with 1.1 billion cubic feet a day, you can easily move this to 1 / 4 out of 1 / 7 as gas production grows through out the region, but this one has positioned Regency to participate in future upstream gathering opportunities that are outside of the joint venture and it de-leverages Regency’s balance sheet by providing sufficient liquidity to fund 2009 growth.

I would like you to turn to Page eight, and we will do a brief overview of the project. You may recall that this expansion project is 1.1 billion cubic feet a day capacity project, 925 million of that capacity or 84% has been contracted and remaining capacity is under negotiations.

Some of the major shippers for the project or the major anchor shippers or Petrohawk and Exco, and between a combination of Petrohawk, Exco [inaudible] GMX, we have contracted 825 million of capacity, remaining 100 million that is under contract is with two other shippers, who at this point we are not allowed to disclose their names, but they are very active players in the region.

All other agreements are for firm transportation capacity and their 10-year contract and approximately 85% of the revenues are from reservation fees. This project, as I mentioned early expect to be online by the end of 2009 and it will be the first major Haynesville project placed in service.

It adds 101.1 billion cubic feet of capacity and it consist of 128 miles of 36 and 42 inch pipe, well over 14,000 horse power compression at Elm Grove and Haughton and it interconnects with Columbia, Gulf Texas Gas frontline and ANR pipeline.

If you’ll turn to Page nine, this map depicts the pipe crossing those interstates, we are connected with them today, but they will be expanding all those connections, we’ll be increasing our capacity by 150% or 2.4 billion cubic feet a day. So, our 1.1 pipeline project will be adding delivery capacity in theses interstates of 2.4, more than twice the capacity of the pipe. Shippers themselves are responsible obviously for securing the downstream market and transportation once we deliver at the interconnects.

Moving to Slide 10, as I mentioned this project will provide an initial take away capacity option for the Haynesville producers. This Slide is based on some work we’ve done that believe is fairly conservative in nature. What we’ve done to develop this slide is assume that a 100 RIGS per year for the next three years with initial production rates of $8 million per well, stay active and you will see in a chart in a minute that $8 million a day is well below what we are seen out of many, many of the well in the Haynesville area that is coming on.

By using those conservative assumptions by the end of 2010, production is expected to increase 2 billion cubic feet a day out of the Hayneville shale play and Haynesville producers is estimated to reach between 3.5 and 4.5 billion cubic feet a day by 2012, but if you look at the build up on this slide you can tell that even once we finish our project and even if we complete a major expansion that we’re to take that to 1.4 and 1.5, 1.7 billion cubic feet a day that other large capacity additions are going to be required in the future to meet the plays forecasted requirements.

This is an area that’s going to be producing significant gas, I would say one thing about our predictions on 3.5, 4.5 Bcf is that should you see a strengthening in the gas prices, you could actually see those numbers actually be able to large about 2012 as well.

If you turn to Slide 11, just a few comments about the project cost and a break down of that cost, there is $653 million estimated cost, there is $577 million associated with pipeline, $37 million for the interconnection and $39 million for the compression.

Within the $653 million total cost, we build in some pretty good level of contingency and it includes about $108 million of indulgency to cover items such as re-routs, terrain modification and weather impact on going forward, but based on our progress to-date and based on our expenditures to-date we believe we are on target to complete the project for that $653 million or less.

On a commercial update, I would invite you to look at the Slide 12. This slide basically outlines the fact that there is 3 million acres that have been leased in this Haynesville area and hope we have overlaid is those that leased area along our pipeline and we are tracking the drilling of wells and you can see that there is a large portion of the wells that have been drilled are close to us and a large portion of acreage really overlaps the rig system in our expanded project.

Our pipeline, quit frankly is in the right place at the right time to be a significant player in this area and we’re excited to be able to move forward, we are building the system and moving this producer of gas.

Well quickly on Slide 13, I’m not going to go through all the data here, there is a lot of information here, but we’ve listed just six of the producers. There are many other producers, more than a dozen additional producers in this area, but we’ve listed six here that have been very active today. You can work through the numbers but in aggregate, you can see that just out of these six producers they are expecting to spend in 2009, $2.3 billion of capital, let’s put that in context.

Our project is $650 million and this project will be build to move the first 1.1 billion of gas, but the producers in aggregate in one year will be sending well over 2.5 times that amount, well actually approaching almost 3.5 times that amount in drilling wells in one year. So this is a large program, a larger commitment and the producers are quite active in this area.

Right now, extrapolating data from this slide you can see that producers expect to drill probably 400 wells in 2009 and this is just six producers and there are obviously many more who are drilling as well.

Let’s talk about construction update and move over to slide 14, our operations team continues to make significant progress in securing right-of-way and environmental permits and clearances. On the 36 inch Bienville line, we have acquired the Louisiana Department Natural Resources permit we have acquired other four of engineering permit, we have acquired all of our environmental permits and a 100% of the right-of-way.

On a 36 inch Elm Grove line, the central line and environmental surveys are 100% complete. We have the core permit, approximately 75% of the right-of-way has been purchased and Louisiana Department of Natural Resources has approved our permit and is in process of issuing us an order.

On the 42 inch Winnsboro line, the central line and environmental surveys again are100% complete, right-of-ways at about 25% and again that Louisiana Department of Natural Resources has approved to permit and we are in the process of receiving that order.

Air Permits for our Haughton Compressor Station were received last week, in the last week of February and we expect to receive the aircraft permit for the Elm Grove Compressor stations in the first week of March.

Within the process or forming and executing the agreements with the downstream market pipeline for the upsize of inter-connects that I mentioned earlier. We also executed our time frame with the contractor that will be building the pipeline and this is a unit price contract and this is executed just a few days ago.

You all are aware that the major pipe, fittings, valves, vessels and compressor packages, we already hence the orders has already placed for those required materials and compression packages.

In summary, this expansion is an excellent project and surprising that it has strong market support from day one. We at Regency have never wavered in our commitments to planning or wait to meet the needs of our shippers.

Certainly we were presented an unexpected challenge with the change in capital market last fall, which required us to seek alternative financing, but after considering many options we believe that this joint venture is the right answer for Regency, we believe it’s the right answer for our unit holders and we are pleased to have our new partner Alinda, joining our ranks as we drill and expand this major infrastructure project in the Haynesville shale. We are exited about the future and we are exited about what can be accomplished through this joint-venture.

Before closing out this section and talking about the financials though, I do want to just say a special word of thanks to our regional shippers, who is staying with us over the last five months as we recopied the projects and as we work through our financing. I’m very appreciative of their support through this process.

We’ve covered a lot of ground and we will whole obviously be taking questions later related to the joint-venture, but I would like to change gears for a moment and turn our attention to Regency’s 2008 result.

I’ll in invite you to turn to Page 16, I would like to start first with our year-over-year results comparing full year 2008 to full year 2007. Revenue increased 57% from $1.2 billion in 2007 to $1.9 billion in 2008. Our adjusted total segment margins increased 93% moving up to $441 million in 2008, and our adjusted EBITDA increased 75% moving from $142 million in 2007 to $254 million in 2008. Anyway, you want to measure that straight year-over-year growth.

Looking at a year-over-year on a quarterly basis from Q4 ’07 to Q4 ’08, total revenue increased by 9% to $365 million. Adjusted total segment margins increased by a 64%, moving from $68 million to $111 million and our adjusted EBITDA increased 43% from $42 million to $61 million.

Total throughput in Gathering and Processing Segment increased 22%, moving up to 1.1 billion cubic feet a day and then our total throughput in our Transportation Segment increased 5%, to 772,000 MMbtu from the 734000 MMbtu in the fourth quarter of ’07.

Stephen will come back and provide and little more color in details around 2008 numbers later in the presentation. I would like to touch on a few of the highlights from the Gathering and Processing and Transportation sections and we will begin with North Louisiana.

In North Louisiana, we had increased volumes driven by terrible activity in the Terryville field and the Haynesville drilling. We do believe and what we have seen is that at least in the interim those Terryville field volumes have peaked as producers are driven some what by pricing. Producers are reallocating rig count and are moving some of these rigs to the Haynesville Shale play and so we think we peeked for the time being in that region until we see some pricing recovery that would bring some rigs back into the area.

The initial Haynesville gas has been lean and we are starting to see slightly lower recovered barrels from Elm Grove and Dubberly as this gas has leaned down our total gas stream through the plants. Our volumes at our Dubach plant again peaked we think for the time being and we’ve seen a lowering of rig counts there with the pricing decline in natural gas prices that can recover once we see stronger prices.

However, on the positive side volumes on our Nexus gathering system continue to run at capacity, demand for ability to move gas to that system continues to grow and we are currently evaluating a number of options for expansions out of that system.

Moving to West Texas, our Woodford Mountain, $17 million expansion project was completed in October and it’s bringing in an additional 8 million to 10 million cubic feet a day into the Waha plant. This project moves Regency into a new geographic area and will give us ability to compete for additional packages of gas that we previously didn’t have the ability to access.

We completed the acquisition of DCP’s interest in the [Calanaso] plant affective December the 1, and helps Regency to secure wellhead gas and provides additional uplift and processing margins at to the plant, as well as increased fee based revenue. You may recall that last year, there were curtailments from a downstream transportation provider at Waha; we’ve seen some of that capacity come back from the market but not at full levels yet.

Moving up to the mid continent region, the FrontStreet acquisition we did early last year increased our footprint in the region and this business is all fee based margin. For most of the year it operated as expected, however we have seen some declines here in infield drilling and we expect to see this trend continue in the near term due to depressed natural gas prices in the region; partially the result of the supply and fusion from the first phase of the Kinder Morgan Rex pipeline project.

Moving over to the East Texas region, the operations are running as planned. Sulfer prices remained high in October at approximately $508 per long ton, but just as a little back ground, we began the year at prices at about $30 per long ton. We saw those prices move up to a peak in July, August time frame of approximately $650 per long ton, but in October, we saw they still remained high at $508 a long ton, but then we begin to see those prices move down and we saw a net price of approximately $90 per long ton for November and $83 per long ton for December, and so with sulfur prices coming down along with rest commodities, we continue to expect that this area will not see much drilling with sulfur prices moving down to where they currently are?

South Texas, we completed the consolidation of the assets in the region; we consolidated the Panama rig, the LaSalle, and the Tilden Gathering Systems and we also did consolidation of two plants at Tilden and Fashing. These consolidations will allow us to reduce volume of fuel burn, it allows us to increase recoveries; it also increases our ability to treat both rich and sulfur gas and provide producer with processing upgrades.

All in all, we’ve seen some volume declines in several area as prices have come down for natural gas, but we are obviously seeing growth in the Haynesville area; we’re seeing some early volumes there and we’re seeing growth on the [Annexes] system. We may also see in South Texas, growth related to the Eagle Ford Shale drilling activity that is taking place there and it has seen some pretty good success today.

Moving to our transportation segment, volumes decreased about $23 million from the third quarter of ’08 to the fourth quarter. The real driver here was the seasonal load swing of Union Power; this is not an expected. Remember they are gas fired power plant that we supply gas and their heavy loads are obviously in the hot weather months. So, we saw that impact in the third to fourth quarter.

We although have seen there is some early volumes, Haynesville volumes that are looking for way to be moved out of the region before we get our project built, and so our commercial team is evaluating a number of potential opportunities to increase volumes on rigs in the near team to help move some of those early volumes.

Moving now to our compression segment, the segment margin was $33 million in the third quarter of 2008 versus fourth quarter; margin moved up to $40 million. The revenue generating horsepower increased by almost 36,000 horsepower, moving upto over 778,000 horsepower of revenue generating horsepower. We added over 200,000 horsepower in 2008 through the end of December and its certainly exceeding our expectations for that business.

Growth in the Fayetteville Shale and North Louisiana should continue in 2009, but we expect other regions to expect zero or minimal growth as a response to some of the lower drilling activity. Certainly, we expect the ability to grow in the Fayetteville and North Louisiana and we think our growth expectations of this business are inline with the reduced capital allocation we previously announced for the business late last year.

Overall, the average horsepower for generating compression unit was 856, which is up slightly from Q3 which was 851. The significance of this number is that this is significantly higher than contract compression, the average compression for our peers in the industry and you know that we focus our business on trying to essentially use the larger horsepower centralized compression projects.

Few words about fourth quarter 2008, compared to the third quarter of 2008. Gas prices on the Texas gas index were down $2.66 or 30% relative to the third quarter. Crude oil was down $38.26 or 32% over the previous quarter that averaged 79. NGL products were down at Mount Belvieu, Ethane was down 62% in the fourth quarter and generally our propane’s, and butanes, and normal butane ranged in order being down from 34% to 39%.

The realized sulfur prices, I mentioned earlier dropped from third quarter to the fourth quarter. The average for the third quarter was $461 per long ton and the average for the fourth quarter was $227 per long ton. You may remember that as we went through the year last year, we never rolled through the benefits of sulfur into our distribution string, we didn’t think those half prices were realistic to stay there and so we maintained pretty conservative ratios without rolling those through our distributions and so this is not a surprise to us at all to see sulfur prices moving back down significantly.

Drills from the segment performance that we compared the third quarter versus the fourth quarter in 2008, relative to the fourth quarter Regency’s adjusted EBITDA has decreased from $67 million in the third quarter to $31 million in the fourth quarter, and this principal is driven by the change in commodity impact, the $12 million which had a impact on our margins.

Natural gas, a reduction of $5 million and you may recall we were not hedged to natural gas in 2008; we are hedged for a large portion of our long position in 2009. Natural gas liquids, we saw a reduction from quarter-to-quarter of about $3.3 million, sulfur reduction at $3.8 million impact and these were offset though. In the third quarter we had a $4 million negative impact from hurricane Ike that was obviously not there in the fourth quarter and then there was an offset from $2 million reduction in G&A expenses in the fourth quarter.

A little bit about our organic growth initiatives and our revised growth capital. For the full year 2008 we incurred $355 million of growth capital; in the fourth quarter that number is a $123 million, but on a year basis of the $355 million, $177 million was for the fabrication and new compression packages, $123 million was invested in our Gathering and Processing Segment and $55 million was invested in the Haynesville Expansion Project and of course I mentioned these costs; we will be reimbursed for these costs by the joint venture.

To reduce dependents on capital markets, we revised our 2009 and 2010 growth plans to reduce our total debt and equity requirements. The joint venture itself reduces Regency’s capital commitments for the Haynesville project. We forecast spending roughly a $120 million in 2009 and $100 million in 2010 for our base business growth capital.

Spending roughly $95 million in the compression segment and about $25 million in Gathering and Process in 2009 and through February, we’ve spent approximately $22 million on compression and we recently finalized a lease arrangement with Caterpillar and if needed we can finance $75 million of the compression needs off balance sheet through this arrangement.

A few words about our cash distribution; we announced a $0.445 as you know distribution for the fourth quarter ended December 31, 2008. This is a 11% increase over the fourth quarter of 2007. The distribution is equivalent to $1.78 on an annual basis and it was paid on February 13, 2009 to the unit holder records at the close of business on February 6.

Cash available for distribution during the quarter was $41.4 million. This provided a coverage ratio of 1.2 times the amount required to cover our distribution to our common unit holders and our subordinate unit holders and it provided a coverage ratio of 1.1 times the amount required to cover all distributions, including the Class D units.

Let me just say a few words about guidance before I turn the remainder of the presentation over to Steven. Looking forward to 2009, we plan to maintain our current $0.445 distribution through the construction of the Haynesville project. Of course, our distributions are set by the Board of Directors and it’s driven by the long term sustainability of the business and in the event of any drastic change in market conditions or cost of capital or produced drilling activity, this distribution guide us could be reevaluated.

Given Friday’s joint venture announcement and the significant impact it will have on our business we have elected to not give earnings guidance for 2009 related to EBITDA and cash available for distribution at this time. However, as Shannon mentioned early, we’re hosting an Investor Day on March 31st of 2009 in which time we will have a guidance discussion and we’ll provide further insight into our 2009 outlook. I would ask you to please mark your calendars for that date. That meeting will again be held here in Dallas at the Crescent hotel.

All in all, 2008 was a good year for Regency. We have far exceeded our growth and EBITDA objectives that were set out at the beginning of the year and so we are very pleased with our performance and are looking towards the future. We are looking forward to implement the construction of our Haynesville Expansion Project and then utilizing through the joint venture the Board that will continue to grow that projects. So we are excited about the future of where we’re headed here at Regency.

With that I’m going to turn the program over to Stephen, who will now take us through the remainder of the presentation. Stephen.

Stephen Arata

Thanks Bryon. I am going to start with the review that fourth quarter and full year 2008 performance before I discuss the joint venture and its impact in our liquidity. In addition, I’ll be discussing changes to our credit agreement and our commodity risk management program.

On page 18, we have our consolidated operating results for 2008. Our net income for the fourth quarter was $32 million compared to $5 million last year. Our full year 2008 net income was $101 million compared to a loss of $14 million in 2007. These improved results were driven by the contribution from our early 2008 acquisitions, returns on organic growth projects, improved commodity pricing on unhedged volumes in the absence in 2008 of a $21 million loss on debt refinancing that was incurred in 2007 related to a termination penalty associated with redeeming 35% of our senior notes.

The partnerships adjusted EBITDA increased from $42 million in the fourth quarter 2007 to $61 million in the fourth quarter of this year. Our full year adjusted EBITDA increased 79% to $254.5 million, inline with the updated guidance we provided with our fourth quarter cash distribution announcement. You can see more details on EBITDA and adjusted EBITDA in the appendix on slide 27. Finally, I would note that our fourth quarter EPU, excluding the mark-to-market gains we recorded in the fourth quarter of $14 million was $0.21 per unit.

On page 19, we have the gathering and processing segment update. Total throughput in the gathering and processing segment increased from 923,000 MMbtu per day in the fourth quarter of ’07 to $1.1 million MMbtu in the fourth quarter of ’08. NGL production decreased by about 10% to 21,000 barrels a day, primarily due to ethane rejection in our Mocane, Waha in Dubach facilities.

Our adjusted segment margin increased by 9% to $55 million; this increase was primarily attributable to increased throughput volumes in North Louisiana, which accounted for about $2.8 million of the change; about $1 million from increase sulfur prices from our East Texas assets; $1.8 million from the operations of our Nexus assets and those items were partially offset by about $1.1 decrease from various other sources.

Our adjusted segment margin per MMBtu decreased from $0.60 in the fourth quarter of 2007 to $0.54 in the fourth quarter of 2008, and which is primarily attributable to higher low margin volumes at our Nexus facility in our Elm Grove refrigeration plant.

Our adjusted segment margin for the full year 2008, increased to $242 million compared to $170 million for full year 2007. Several items went into this increase including $25 million from a full year’s operation of FrontStreet assets, which were consolidated from an accounting perspective on June 18th of 2007; $19 million from increase throughput and organic growth in South Texas; $12 million from increase throughput in organic growth in North Louisiana; a $10 million increase from sulfur prices; $8 million from operation of our Nexus assets, all of which we’re offset by $2 million of decreases from a variety of other sources.

On page 20, we have the transportation segment update. Our throughput increased by 5% in the fourth quarter, our adjusted segment margin increased by $3 million in the fourth quarter of 2008 compared with the fourth quarter of 2007. Our adjusted segment margin for the full year increased to $78 million, up from $59 million in 2007, primarily due to three items; $12 million due to increased operational efficiencies coupled with increased commodity prices; $5 million due to increased margins associated with our limited marketing function; and $2 million attributable to increase throughput volumes and changes to contract mix. Our adjusted segment margin per MMBtu increased from $0.25 to $0.28 quarter-over-quarter, primarily due to additional revenues generated by our marketing affiliate.

On page 21, we have our contract compression segment update. Contract compression segment margin was $40 million in the fourth quarter compared to $33 million in the third quarter of 2008. Our revenue generating horsepower as Byron mentioned increased, nearly 36,000 horsepower, up to over 778,000 horsepower as of the end of the year. 82% of the revenue generating horsepower in this segment is greater than a 1000 horsepower in size and as Byron mentioned, our average horsepower per unit increased slightly to 856 horsepower per unit.

Next, I would like to review some of the important elements of the joint venture we announced on Friday. First, we are pleased with the value we receive for RIGS in the transaction. RIGS is valued at $400 million in the joint venture giving us a 38% stake. This compares favorably to the expected 2009 EBITDA contribution to Regency from RIGS of approximately $42 million.

The key reason we are able to realize this value for RIGS was the Haynesville Expansion Project, including the significant potential upside from economical expansion opportunities. As Byron mentioned, one of the important aspects of the joint venture is the enhance liquidity it provides Regency. This is both a short term liquidity between now enclosing and longer term liquidity throughout this year.

First, I’d like to address the short-term liquidity which is between signing and closing. As part of the overall transaction, Regency has entered into a $45 million revolving credit facility with general electric capital corporation at our MLP. This facility is designed to provide Regency with additional liquidity prior to the closing of the joint venture. This facility can only be used for Haynesville Expansion Project capital expenditures and once the joint venture closes, Regency will be required to repay any borrowings enter the facility and terminate the facility.

Looking out to 2009 full year liquidity, on page 22, you can see a chart we put together giving a liquidity update. It compares our liquidity to our remaining 2009 capital commitments. As of the end of February, we have $42 million available on our revolver. We expect to spend approximately $14 million on the Haynesville Expansion Project due in the middle of March. Assuming a mid March closing, we will receive approximately $90 million dollars as a reimbursement of our Haynesville Expansion Project capital spending to that date.

In addition we have entered into an operating lease facility with caterpillar financial services. This will allow us to fund up to $75 million of our compression capital spending, due ten year leases which has early buyout options in year five and seven. This lease was done in approximate 8% to 8.5% all in cost to capital depending on if the early buyout options are exercised. This brings our total available liquidity to a $193 million this year.

On the bottom half of the page you can see the break down of our 2009 capital spending, excluding the Haynesville expansion project which will be funded through the joint venture. In total we have budgeted $120 million of which approximately $33 million has been spent through the end of February, leaving $87 million remaining to spend. This leaves us with over $100 million of liquidity in excess of our capital spending requirements this year. The net effect of the joint venture is the de-leveraging of our balance sheet providing us with sufficient liquidity to execute our 2009 business plan.

Any capital market activity would be completed when the financial conditions of the markets improve in order to further strengthen our financial position or to finance currently unidentified attractive growth projects. As part of the overall transaction we received approval from our bank group to amend our credit agreement to allow us to contribute RIGS to the joint venture and to receive pro forma credit for the Haynesville expansion project during construction.

On page 23, I like to talk a bit about our commodity price risk management activities. On this page you can see our quarterly NGL equity positioned on the top of the page compared to our hedge position. For 2009 we have hedged 97% of our NGL equity production through product specific swaps. In 2010, we’ve hedged approximately 70% of our non-assigned equity exposure, but we have not yet hedged any of our expected assigned equity production, bringing our overall 2010 NGL hedges to 33% of our equity production. We anticipate entering into additional hedges soon to bring our 2010 total NGL hedge positions to 75% of equity production, as well as entering renewing the hedges for 50% of our expected 2011 NGL equity production.

On the bottom half of the page you can see our quarterly condensate equity production and barrels per day. For 2009 and 2010 we’ve hedged approximately 75% of our condensate equity production to WTI crude slots. We anticipate entering into additional hedges to hedge approximately 70% of our expected 2011 Condensate equity production. Finally we have hedged approximately two third of our expected 2009 natural gas exposure.

On slide 24, you can see that based on our hedging program for 2009, Regency has only 3% of our estimated 2009 adjusted segment margin subject to commodity price fluctuations, with 68% of our margins coming from fee base contracts and 29% of our margins from hedged commodity margins.

Finally on page 25, you can see a table of our executed hedges by product. On an average our executed hedge pricing in 2010 is significantly higher than in 2009 which we’ll translate into build in growth and adjusted segment margins year-over-year.

With that I would like to begin the question-and-answer session.

Question-and-Answer Session


(Operator Instruction) Your first question comes from Michael Blum - Wachovia.

Michael Blum - Wachovia Securities

A couple of questions; one, are you still expecting the project, the Haynesville Project to generate roughly $100 million of EBITDA and is that based on what you have contracted today or is that based on the 100% committed capacity?

Byron Kelley

Mike, our numbers is that 100, a little bit higher, and that’s based on the expectations that we will contract, the full amount under the contract on a 100% basis. But, it does not necessarily assume that you’re flowing a 100% of those volumes on day one, but we are assuming the demand charge will be received from day one.

Michael Blum - Wachovia Securities

Okay and then you mentioned that you could upsize the capacity on the pipe to 1.4 to 1.7 Bcf; what would the cost be roughly to do that, and is that just compression?

Stephen Arata

Most of that is compression, there are several projects that we are looking at and if we would just wanted to move more gas to the existing delivery points, it would basically be compression. We are also looking at another project that has a small extension of 10 or 11 miles on the 36 inch that would allow access to some additional gas and then we are looking at little bit longer, a term of project that might move to some additional delivery points that would include significant, not a significant, but a fair amount of pipe. That project you could be looking up something in $200 million plus range and so if you wanted to move up say 1.7 billion cubic feet a day, we would probably looking all in between compression and pipe, somewhere in the $250 or $260 million range.

Michael Blum - Wachovia Securities

Okay, great. Just two other quick ones; one, can you just talk about plans to may be some sort of some sort of debt financing after JV and what their margin looks like, right now?

Byron Kelley

Michael, I’ll address this, it’s a good question. We’ve agreed with our partners not to rise debt at the JV level until the expansion project is complete, which we anticipate near the end of the year and we likely would raise money primarily to expand the system in 2010 and beyond. We haven’t actually gotten any indications of what data that level would look like, but I can say that with the business producing around $150 million of EBITDA, nearly all of which will be from fee based long term contracts, I think it probably will have the fairly good credit profile.

Michael Blum - Wachovia Securities

Okay and then last question Stephen; can you provide the percentage you have and what prices you are hedged with natural gas for ‘09?

Stephen Arata

Yes. We are hedged at two thirds, 167% and the pricing I believe was on page 25, its $6.69.


Your next question comes from Chris Holt - Barclays Capital.

Chris Holt - Barclays Capital

I got a few questions here. First off, what’s the approximate EBITDA impact from the decline in NGL equity volumes hedged from 2009 and 2010 at current stock prices? So, I just want to make those hedges going from 97% plus from 33%, what do you think the EBITDA is at the current stock prices?

Byron Kelley

That’s a good question, I’m not sure I have an exact answer for that, Chris. The actual prices however which we’ve hedged 2010 compared to 2009 actually more than offset the lower volume amount of hedges we’ve actually put in place. So, at the same price say for ’09 and ’10, even with the lower volumes, we get a bigger contribution from 2010 than we do from ’09 hedges.

Chris Holt - Barclays Capital

Okay. Now under the JV, do the unsecured notes allow the movement of RIG assets for the JV, without receiving any cash consideration? Is that a problem under those notes?

Byron Kelley

That’s correct.

Chris Holt - Barclays Capital

That’s not a problem you are saying.

Byron Kelley

Yes. We don’t have a problem with that.

Chris Holt - Barclays Capital

Is that a restricted payment or is that something else for the joint venture?

Byron Kelley

I probably would need my lawyer to answer that question. Yes, that’s probably question we should take offline.

Chris Holt - Barclays Capital

And is there any risk tripping any of your leverage ratios into your existing bank agreement or your new unsecured facility in 2009, do you all see any problems with that?

Byron Kelley

No, we don’t see issues with that. The agreement we reach with the banks allow us to perform in this project during construction, which gives us significant head room below our agreed covenants with the bank group.

Chris Holt - Barclays Capital

Okay. Is that 150; is that what the pro forma number is?

Byron Kelley

The pro forma number is for the actual expansion piece and that’s about a little North of a $100 million pro forma treatment.

Chris Holt - Barclays Capital

Okay, alright and the RIGS EBITDA for 2008, is that a pretty much to same as what you guys give for the 2009 number, approximate.

Stephen Arata

The numbers in 2008 were actually slightly different than what we are projecting for 2009, primarily for a couple of reasons. The 2008 numbers, if you look at our transport numbers that we report in our 10-K, include the results of both our marketing affiliate and they include our Gulf States assets which are obviously a fairly small contribution.

They also include significantly higher prices on retained fuel on that system. Then we’re expecting to experience in 2009 and we did have some operational efficiency in the system in ’08, which we don’t think are repeatable in ’09. So, it’s really a bit of apples and oranges as to what we actually achieved in the system in ’08 versus what we’re expecting in ’09.

Chris Holt - Barclays Capital

Okay and I just want to confirm a couple of numbers too; I guess, you all spent about $76 million on Haynesville through 12/31, is that correct, based on reading on slide 22, I think?

Stephen Arata

That’s actually to the end of February. We spent $55 million to the end of the year.

Chris Holt - Barclays Capital

And you would expect them to get about $90 million at closing of that transaction based on your estimates.

Stephen Arata

Yes, assuming a mid-March closing.


Your next question comes from Xin Liu - JP Morgan.

Xin Liu - JP Morgan

A couple of questions; so, at the end of the closing of the JV, you were really losing 62% of your RIGS cash flow, is that correct?

Stephen Arata

That’s correct.

Xin Liu - JP Morgan

So, can you put down how much is it for 2008 EBITDA; how much is it for marketing and how much is it for assets you contribute to the JV?

Stephen Arata

Well, I don’t think we disclosed the actual amount, we made a marketing, but if you look at 2009 assuming in mid-March close, we will be paying out roughly $19 million to $20 million of cash to our 62% partners in the JV during 2009.

Xin Liu - JP Morgan

So even considering that, you expect to cover your current distribution?

Stephen Arata

As Byron mentioned, we haven’t released our guidance for this year. So, I can’t answer that question directly. We do expect covered ratios to be lower in 2009 and then 2008 obviously and we’re going to be going over all this in detail at our Investor Day later this month.

Xin Liu - JP Morgan

Okay and another question just to clarify your hedge position; your 97% hedged and you say you’re 97% hedge on NGL’s, but that is excluding, I think is that correct?

Stephen Arata

No, in 2009 it’s inclusive of all products; in 2010 it excludes ethane. If you look on page 25 of the presentation you can see we’ve hedged over 1900 barrels a day ethane for 2009.

Xin Liu - JP Morgan

Okay. So, when I compare your percentage, hedged NGL positions, it seems there is a drop off for NGL, total NGL equity positions, 2009 versus 2008 is there any reason behind it?

Stephen Arata

Well, yes. Part of it we talked about is the expected; we’ve seen ethane rejection at some of our facilities and we continue to expect to see that given market dynamics in each of the markets. We also are forecasting some lower volumetric contributions in some of our regions which are also reducing our volumes and they were also seeing cleaner gas coming to our facilities in North Louisiana, as more Haynesville gas comes on line, but that Haynesville gas is leaner than the pre-existing streams of gas that were going to the facilities. So as Byron mentioned, we are seeing at our Elm Grove and Dubberly plants reduced recovery of barrels at those facilities.


(Operator Instructions) Your next question comes from John Edwards - Morgan Keegan.

John Edwards - Morgan Keegan

I apologize for asking questions that you may have already addressed, because I was jumping over to over the call. In the press release you indicated you get paid the total amount that you spend on Haynesville to-date and I wondering if you could clarify about what that number is.

Byron Kelley

Yes, whatever the number is, at closing we’ll be reimbursed for it and if you see in March, that number’s about $90 million.

John Edwards - Morgan Keegan

Okay and I was curious, the way you structured, in the future would you be able to if you so chose to separate this asset as its own separate MLP?

Byron Kelley

That’s a good question. Its not one we actually if considered at this point. That may be possible. But it’s certainly not something that’s in our plans.

John Edwards - Morgan Keegan

Okay, because it looked like the way, at least my reading of the instruction that you preserved for yourself that option, but it sounds like that was not an act of consideration, at least set it up?

Byron Kelley

It was not a consideration in where we set it up, no. It might be a by-product to where we set it up.


Your next question comes from Lenny Brecken - Brecken Capital.

Lenny Brecken - Brecken Capital

Just a macro level question, even the public GNP companies are stressed to the extent of which they are being forced to pull back, not only on their capital expenditures but I would assume even their processing activity to some extent. Can you just give us an idea of how the supply demands of the industry overall is going to change throughout 2009, and whether a company like yours is in a position to actually capture some business market share wise, exclusively of your capital expansion projects at Haynesville.

Byron Kelley

Well I mean obviously there are a lot of factors; let me start on the supply demand in 2009. As you see, drilling activity vary from region to region and as we mentioned, obviously we’re going to see strong drilling activity in the Haynesville drilling around our expansion project. We’re also seeing strong well basically Haynesville drilling and Boursoure drilling along the Nexus system which is good for us and we’re seeing strong drilling down in the Eagle Ford shale area.

Outside of those, with until we see some pricing come back, I think that you won’t see a lot of gathering activity around some or the other regions, but within those regions we mentioned, obviously we’re well positioned to look at growth opportunities and continue to find ways to expand the existing assets we’ve got to serve those markets.

There is no question there’s a capital constraint in many aspects in the industry and hopefully through this joint venture and the other actions we’ve taken, it strengthens our balance sheet that we’ll be in a position to participate in those. I would say that there are no gimmicks though that although there are a number of players that may be who have capital constrains always and there are some others who don’t.

So we expect that we will be pretty much in line of what we’re looking at, except pretty much our existing asset that we’re expanding that we will be competing with other players for those growth opportunities.

Lenny Brecken - Brecken Capital

Just one follow-up, just specifically, so the companies that are stressed to the extent of which they are cutting their distributions basically this year and contracting their business, I mean do see that sort of those companies are going to just die on the volume or whether the assets are going to get stressed enough, so that companies like yours would find it attractive or you think the industry pricing is just going to correct to that. Those players somehow worked their way through their operations with just a small business profile and footprint. How do you think its going to play out, do you think there’s going to be consolidations?

Byron Kelley

Let me tell you, first of all I’m not going to speculate on what any other company, how they are handling issues that they are dealing with in the markets. I mean obviously if you look over the last few months we’ve already seen some asset sales that have been announced and parties who would like to sell assets; some of that may continue; right now we are not really focusing on acquisitions.

We are focusing pretty much on organic growth around the assets we’ve got. So, I don’t think that we are looking to go out and be participating in an acquisition market at this point. We do as you know, we still have one option on an asset we might acquire, that’s in front of the FERC, but I’ll tell you that we really have a lot of organic growth and opportunities around our assets and that’s going to be our focus.


Your next question comes from Adam Rosenberg - GLP.

Adam Rosenberg - GLP

As far as your compression spending for 2009, you guys said that it will be about $95 million. So with the operating lease you have with Caterpillar, is that included in that $95 million?

Byron Kelley

Well, that lease, we could utilize to purchase $75 million of the $95 million. Today we spent about $22 million, so if we needed to for the rest of the year, we could put the rest of that under the lease.

Adam Rosenberg - GLP

Okay and then is there any time range on that, as in could you use some of your 2010 anticipated spending under that operating lease as well.

Byron Kelley

It’s a one year operating lease and so if we want to utilize that facility, we would have to draw it down this year.

Adam Rosenberg - GLP

Okay, also I missed what you said your anticipated 2010 gross CapEx would be?

Stephen Arata

2010 is a $100 million.

Adam Rosenberg - GLP

Lastly, so in terms of your overall 2009 expected volumes on the gathering and processing system, it sounds like you expect them to be down a little bit?

Stephen Arata

That’s great. We didn’t.

Adam Rosenberg - GLP

And in terms of sort of quantifying that, any help there?

Byron Kelley

I will give you more details on that on the 31, we’ll get into that. I mean it varies by regions and so we would rather talk about it in terms of the total activity on the system; its pretty good detail behind it.


With no further questions in the queue, I would like to turn the call over to Ms. Shannon Ming for closing remarks. Please proceed ma’am.

Shannon Ming

Thank you guys for taking the time for join us today. We look forward to seeing you in Dallas at our Investor Day on Tuesday March 31, and if you have any additional questions, I know we went over a lot today, please give me a call. Thank you.


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

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