Regency Energy Partners (RGNC) Q2 2009 Earnings Call August 10, 2009 11:00 AM ET
[Elizabeth Huber] – Manager of Investor Relations
Byron R. Kelley – President, Chairman of the Board & Chief Executive Officer
Stephen L. Arata – Chief Financial Officer & Executive Vice President
Michael Blum – Wells Fargo
[Yves Segal] – Credit Suisse
John Edwards – Morgan, Keegan & Company, Inc.
Lenny Brecken – Brecken Capital
Welcome to the second quarter 2009 Regency Energy Partners conference call. My name is Geri and I will be your coordinator today. At this time all participants are in a listen only mode. We will be facilitating a question and answer session towards the end of the conference. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to Ms. [Elizabeth Huber] Manager of Investor Relations.
Welcome to our second quarter conference call. Today you will hear from Byron Kelley, our Chairman, President and CEO and from Stephen Arata, our Executive Vice President and Chief Financial Officer. Following our prepared remarks this morning we will turn the call over for your questions. Distribution of the release and the slides that we will use today are available on our website at www.RegencyEnergy.com.
The first slide of the presentation describes our use of forward-looking statements and list some of the risk factors that may affect actual results so please read this slide. Also, including in the presentation today are various non-GAAP measures that have been reconciled back to GAAP or generally accepted accounting principles. These schedules are at the end of the presentation starting on Slide 32. With that, I will turn the call over to Byron Kelley.
Byron R. Kelley
As always, we look forward to providing you with a detailed update on the company’s performance and also having a chance to share with you our thoughts about the market in general. Before I get in to the presentation, I’d like to say a few words about Shannon Ming. You noticed that Liz did the introduction today rather than Shannon who many of you know. Shannon, as I think most of you may know or be aware of, she had and gave birth to a baby girl last Thursday.
Shannon was determined to work through our board meeting which we held last Thursday as well as make sure that we were prepared for today’s meeting. We actually had board committee meetings all day on Wednesday which she attended but that night at our board dinner, about half way through Shannon admitted finally that she had actually been in labor all day. So, a few of our executives immediately called her husband Tom and then whisked Shannon away to the hospital. Shannon, if you’re listening and I would be sure that you are, we all send you our appreciation for getting us ready for this meeting and our congratulations to you and Tom on the birth of your new baby girl. Not to put pressure on you but, hurry back.
Well, we are glad to have Liz who is with us to step in and help us through today as well. Back to the business, I am pleased to report to you this morning that our second quarter performance was right in line with our expectations, right in line with our internal budget for the quarter. I’d like to begin really on Slide Three of the presentation and begin with some highlights, year-to-date highlights. We had solid second quarter results and that’s despite the continued low rig count and soft commodity prices that the industry is seeing industry wide.
Our second quarter EBITDA of $56 million represents a $1 million quarter-over-quarter increase compared to the first quarter of this year. Cost saving initiatives in our compression business which resulted in consistent quarter-over-quarter performance in that business despite some horsepower usage declines that we’ll talk about later. From a financing standpoint, in the first half of the year we had some very important events, we raised over $900 million in capital during the first half and we formed the partnership with Alinda and GE Energy Financial Services to co-develop the Haynesville project. You are all aware of that and in that process we raised $653 million to fund the joint venture.
Additionally, we priced $250 million worth of 9 3/8% senior unsecured notes that term out through 2016. Everyone has been focused on the Haynesville project, it’s an important project to us and an important project not just currently but in the future of this company. I am pleased to report to you that that project is on budget, that project is on schedule and we fully anticipate being in service by the end of this year. I’ll hedge a little bit and say maybe even a little early. That project is doing quite well.
Construction on the 36 inch pipe is more than half complete, construction on the 42 inch pipe commenced in June and this project is well positioned for additional growth projects. This project is located in the right place and the timing of our in service date certainly puts us in good position to consider some additional expansions as well.
On Slide Four we have some highlights related to the second quarter. Our second quarter performance was in line with expectations and we are reiterating our previous guidance of $220 million to $240 million for the year. That is an [inaudible] number and you can see on the chart that the adjusted number for the joint venture, the guidance would be $200 to $214 million of EBTIDA post JV. Also, as you are aware, our second quarter 2009 distribution was in line with our expectations at $0.445 or $1.78 on an annual basis were in line with our expectations.
We plan to maintain our current $0.445 distribution through the construction of the Haynesville project but as always, distributions are set by our board of directors and are driven by the board’s view of long term sustainability of the business so they are revisited on a quarterly basis. At this point, we fully anticipate to be holding those steady throughout the year.
I’d like to now move in to the business review and invite you to turn to Slide Six. Here we have some industry trends regarding drilling activity and obviously this activity impacts our business across our transportation and our gathering business, processing business and in our compression business. In the past 12 months the total US land rig count declined by approximately 56% down to 932 rigs at the end of the second quarter. The land rig count for areas in which Regency operates declined by close to the same amount, about 58% down to 599 rigs at the end of the second quarter.
During the quarter at looking at fundamentals of natural gas, they traded in a tight range primarily between $3.50 to $4 per MMbtu. Right now we don’t think pricing looks to improve before the winter withdrawal season begins essentially driven by the forecasted storage levels right now are going to reach capacity prior to the winter time frames. But, there are a few positive signs on the horizon for us, over the quarter Regency saw rig counts begin to stabilize in the counties in which we operate with rigs increasing slightly in South Texas by two and West Texas by two and then a slight decline in North Louisiana a negative two, midcon a negative two and East Texas a negative one. So, we basically held flat in total rig count.
Before you can see an uptick you need to see some stabilizations and we were very pleased to see the rig counts seemed to stabilize on our system during the quarter. The forward curves right now point to a rebound in natural gas prices with the 2010 forward strip trading nearly $6 per MMbtu. On a broader basis, we believe that drilling levels are not sufficient today for the industry to meet ongoing demand post 2009 and higher prices should be reflected as deliverability declines from the lower rig counts begin to work their way in to the market. As a result of these dynamics we do expect to see some stronger pricing begin to take place in the first half of 2010.
On Slide Seven we’ve got some trend data related to commodity prices. Over the first half of 2009, gas and NGL prices seemed to have stabilized somewhat and we think we are beginning to see a rebound in West Texas and immediate. The forward curves in addition to the $6 price indicated earlier for natural gas are also indicating that crude will rebound to approximately $75 a barrel for the full year in 2010.
Moving to Slide Eight, I’d like to spend a minute on some quarter-over-quarter results comparing second quarter of 2009 to the first quarter of 2009. Despite the headwinds in the broader market we continue to deliver results in line with our expectations. Comparing the first quarter of ’09 to the second quarter of ’09 to the second quarter of ’09 our combined adjusted EBITDA increased by $1 million from $55 to $56 million. The increase was principally driven by an increase in the second quarter. Combined adjusted total segment margin of a couple of hundred thousand more than we had in the first quarter and then by aggressive expense management which added another $800,000 in the second quarter.
The adjusted EBITDA assuming prorate portion of the Haynesville joint venture decreased by $3 million from $54 million in Q1 to $51 million in Q2 and this was principally related to the contribution of the 60% interest in to the joint venture. There we saw approximately a $4 million increase in the amount of allocated EBITDA to our partners. The actual financial results reported for the first quarter are as follows: our net income decreased from $148 million in the first quarter to $6 million in the second quarter and this was really the delta was principally driven here by the $133 million gain we had in the first quarter associated with the contributions of the rigs assets to the Haynesville joint venture.
On a quarter-to-quarter basis we did have some margin decline but again these were expected and were pretty much in line with what we had in our budget. You may recall that we discussed last quarter some of our thoughts around how we developed our 2009 budget and in our 2009 budget. Last fall when we did that budget we built in the volume declines related to drilling activity. While the impact on the margins in our compression business has been a little more than we anticipated at that time we have offset this through cost management practices and year-to-date have delivered fully on our expected financial results.
I’d have to say that overall in the kind of environment that our industry is dealing with, I really believe that our second quarter performance represents some pretty good, some pretty solid results. There are additional details about our EBITDA and our adjusted EBITDA that are in the appendix. We won’t cover those now but I invite you to look at those.
Moving to Slide Nine, one of the things that we have shared with you consistently over the last year is the relationship of fee and commodity percentages in our business. We have been steadily growing our fee based business and reducing our exposure to commodity. This continues. 3% of our margin in the first half of the year was subject to commodity price fluctuations after hedges and we estimate that for the remainder of the year approximately 2% of our segment margin will be subject to commodity price fluctuations.
This chart by the way, accounts for our 38% ownership in the Haynesville joint venture and you will see that we are at 69% on a fee based business. You may recall some previous charts that showed numbers around 72% but those were [inaudible] charts for the full business. So, rolling in the fact that we own 38% of the Haynesville joint venture, year-to-date we’re at 69% fee based. If you wanted to adjust this for what our percentages look like once the Haynesville project gets in service and we include only the 38%, this number moves back up to 71% and then on a 100% basis, on an [inaudible] basis the fee base for that project fully in service will move up to about 75% maybe as high as 76%.
So, we continue to have a focus on growing our fee based business and continue to make pretty significant progress in that regards. Volume comparisons are on page 10, quarter-over-quarter transportation, gathering and processing throughputs are down slightly however, year-over-year volumes continue to demonstrate some resilience and despite the severe drop in commodity prices from the second quarter 2008 we are seeing some resilience on a year-to-year basis. Year-to-date we are ahead of where we were last year.
In comparing the first half of ’09 to the first half of ’08, our throughput and our gathering and processing segment increased from a little over 956,000 MMbtu today in the first half of 2008 to a little over 1 million MMbtu in the first half of 2009. Our transportation segment also increased from 762,000 MMbtu in the first half of ’08 to 770,000 almost 778,000 MMbtu in the first half of ’09. Year-to-date we are moving higher volumes than we did last year in the same time frame.
As I mentioned, on a year-to-date basis for full half of the year essentially we’re up in volumes from where we were last year. Quarter-to-quarter in our gathering and processing business from 1 million MMbtu to a little over that, down to about 984,000 MMbtu in the second quarter of 2009. We did have a turnaround though at our Tilden plant, it was all in one month but, on a quarterly average it averaged about 15 million a day so when we add that one time event back in to our second quarter volumes we really moved on a run rate more at 1 million MMbtu in the second quarter so we were really only down slightly from the first quarter.
The throughput in our transportation segment was down and effected a little bit more by some market dynamics. It was down from 811,000 MMbtu in the first quarter to 745,000 in the second quarter. Basically, the continued rig count declines coupled with some unfavorable basis spreads and the temporary operational issues I mentioned did contribute to the overall throughput decreased quarter-over-quarter. Based on our current view however, we expect that volumes for the full year 2009 are going to be flat with the full year 2008.
I’d like to move and have a little bit of discussion on a region-by-region basis to give you a little bit more data of what’s taking place with regards to volumes. Volumes decreased 7% during the second quarter at our Dubach facility. Again, this was driven by a sharp decline in the drilling in the Terryville field area. The Terryville field volumes peaked in Q3 of 2008. There was a tremendous amount of activity last year in that area drilling the first three quarters but as producers in that region also began moving and ramping up for their Haynesville production, they moved a lot of their rigs from the Terryville field in to the Haynesville area.
Additionally, just low commodity prices in general have curtailed drilling in that area. These lower than expected volumes were partially offset though by higher NGL recoveries at the Dubach plant as well as better fuel usage and unaccounted for gas at that plant as well. Additionally, in the quarter we began bypassing some lean Haynesville volumes that had been going through the Elm Grove refrigeration plant. We were counting these volumes in our prior processing numbers.
We began bypassing that plant with those lean volumes putting it directly in to the pipeline so that shows up as a volume decrease in our numbers however, this decrease has almost no impact to our financials as by moving this gas around the plant it’s going to allow Regions to recover a greater volume of liquids from the conventional gas streams that are already moving in to the plant.
Then further in talking about North Louisiana, our Nexus system which we acquired last year, that system as you know has been ramping up over time and it is now running at full capacity. It continues to run at full capacity. There is a shortage of capacity in that region with the drilling taking place, much of that Haynesville drilling, and we are currently evaluating some expansion opportunities around that system. So in addition to the pure Haynesville play that we’ll talk more about, the Nexus system has some tremendous opportunities down in that region so you’ll also see some expansions and some capital investments.
Moving to West Texas, Waha as a region continues to be one of the hardest hit regions from a rig decline standpoint but our rig development teams and regional services teams have continued to pursue opportunities for new supply and we are actually right now running a little ahead of plan for the year as to what we had budgeted. We’ve seen some favorable ethane spreads in the last few months that have made it now economical to begin processing approximately 10 million a day of keep-whole gas from interconnected pipeline in that area and this is adding to our volumes in the region. We’ve also made some significant improvements in our losses in unaccounted for, for this area during the second quarter.
In the Midcontinent our second quarter volumes were slightly higher than forecasted, not a lot. This was principally led by the FrontStreet assets. FrontStreet average volumes were about 3 million a day higher than what we had in the budget. The non FrontStreet assets in that region were down about 1 million a day and these were about 50/50 so in aggregate we were up a couple of million a day in that region. But, on the non assets, even though those volumes were down slightly, our ethane recoveries at the Mocane plant were up by 3% over the first quarter so overall these assets performed better than we had expected during the first half.
In East Texas, volumes for the second quarter were unfavorable by 3% to our budget. Softer pricing differences also had an impact on us. Last year we saw high sulfur prices as you are aware, this year we budgeted at about $30 per ton for sulfur prices and during the first half of the year we’ve actually seen a negative price for sulfur out of that region so it has had a negative impact on our earnings year-to-date. Also with the lower gas prices, you’re just not seeing the drilling in this area because a lot of the economics are driven by the sulfur economics.
Moving to South Texas, our volumes around our South Texas gathering and treating system continue to ramp up with the continued drilling of the Eagle Ford shale. If you’ve been following [use] you know this is another shale play that’s been getting a little more and more attention over the last six months and the activity there has continued to increase. We added six new Eagle Ford wells to our system in the last quarter and we expect this trend to continue throughout the balance of the year.
We did have one set back during the quarter, in South Texas we had some issues at our Tilden plant with an [inaudible] treater. We elected to take that plant down and to do a turnaround on that plant that had not been budgeted so that plant that was down for most of the month of June and this created some volume reductions that affected our quarterly volumes on average about 15 million a day. It was actually down for a month at about 45 but if you spread that over the quarter it’s about 15 million. The impact of that onetime event no our margins was about $500,000. That plant is back now and running well and we don’t anticipating having to deal with that issue again and we will see those revenues come back in the third quarter.
In our transportation section, volumes decreased by 66,000 MMbtu from the first quarter ’09 to the second quarter. Down time at our east side compressor station, and this was affected by a number of things. We went in and did some work on our east side compressor station, the timing of this was during bid weak, that potentially impacted nominations. The other big change we saw from the first quarter to the second quarter in this segment was that we had good basis differentials in the first quarter but the second quarter the basis differentials were pretty tough and that affected our IT volumes.
I don’t know if you followed the weather patterns but we had some strange seasonal weather, we had extremely hot weather in Texas but cool weather in the northeast and this was a negative variable to us during the second quarter as well. All-in-all we were down on our transportations in the quarter but the good news is we have preliminary numbers in from July and it looks like our volume numbers from our transportation segment are moving back close to our Q1 levels in terms of total volume throughput on the pipe. So, that’s some good news related to moving in to the third quarter that these volumes look like they have rebounded substantially.
I’d like to move to Slide Seven and talk a little bit on our compression market. The compression market in general has slowed considerably over the last 12 months. The same variables we talked about earlier are driving this, depressed natural gas prices which have led to delayed or discontinued drilling in a lot of areas across the United States and a number of areas where we are active in the lease compression business. Despite a 47% decline in US onshore gas rig counts since June of last year, our revenue generating horsepower over that period actually increased by 15% moving up from 670,000 horsepower at the end of June in 2008 to 767,000 horsepower at June 2009.
So, during this period of great decline we have managed to have some very good growth in this business. However, we did begin to feel the impact of the market dynamics during the second quarter and began to see the impact of the declining rig count and the challenging environment of reapplying horsepower that has come up for renewal under our standard contracts. Quarter-over-quarter our revenue generating horsepower was down 2.8% from 790,000 horsepower down to 767,000 horsepower. We saw most of this impact in West Texas and the East Texas regions and then in the Barnett shale area. We have however continued to see growth in the Fayetteville shale area which is one of our largest growth areas for the last year.
The management team at CDM has worked to offset the financial impact of this horsepower reduction through aggressive cost management practices and have managed significant savings in a number of areas. They reduced lube oil and fuel cost savings in the first half by $1.1 million, with the cost of the lower horsepower we’ve seen an expense savings with this number of $1.8 million and then outside of those two just aggressive expense management across the company has benefited us another $3.4 million in the first quarter.
Now, in addition to focusing on the things that are totally within our control, management is also takings steps to mitigate further economic impacts. They’re working very diligently with their customers, they’re reevaluating the field pressures and conditions at all locations where we’ve got compression. They’re working very hard to optimize horsepower placement with the customer to efficiently meet the customer requirements while still guaranteeing and achieving our 98% run time. This strategy is basically if we can maximize the revenue for the customer then we’ve got much better chance to continue to maintain our full customer base and to be ready there to do additional work for them.
Really what we’re saying is in a downtime not only are we focusing on helping our business run better, we’re focusing on helping our customers run their business better. Overall, we are operating the assets at a higher operated per horsepower tech ratio. This trend is expected to remain at current levels throughout the remainder of the year during this slow growth environment. Basically, barring any further significant declines in rig activity and natural gas prices, we anticipate that our revenue generating horsepower to stabilize over the balance of the year and we estimate that our yearend revenue generating horsepower will be between 750,000 to 780,000 horsepower.
At the end of the first quarter and I discussed this with you on our last earnings call, I had anticipated that we would see approximately a 2% to 4% increase in revenue generating horsepower over the year. As I mentioned the second quarter hit us a little harder than I expected so currently our view is that we expect this business for the remainder of the year that we will not see the 2% to 4% increase but that we’re going to be flat to maybe down 1% to 2% in horsepower. But, we will continue to implement our actions related to cost and year-to-date this impact has fully been offset with cost management actions and the segment has actually exceeded its budget from an EBITDA standpoint year-to-date and we will continue that focus throughout the remainder of the year.
On page 12 I’d like to just do a quick business summary for the year. Throughout the first half Regency had delivered on our financial results that were in line with our expectations. We’ve done this in a little bit different manner than maybe we had anticipated as the market conditions have not been quite as strong as we thought. We have offset those through very aggressive cost management. We are delivering on our promises and we’re meeting our expectations. Our businesses, certainly all of them have found ways to financially perform in line year-to-date with our budget expectations.
Going forward, there are certainly some headwinds that remain for 2009, the low drilling activity is not expected to change during the next quarter or two, we continue to see a softness in a broader commodity markets and then there’s still the uncertainty around the timing of the recovery of the US economy. But, as I said earlier, we’re going to continue to aggressively manage our operating levers and we are reiterating our guidance, that we think we are going to meet our guidance for this year.
The other thing that’s happening on an extremely positive note for us is that in the Haynesville, the drilling results there not only continue to be good they continue on almost a quarter-by-quarter basis to exceed even the expectations that the producers thought they were going to see. So, these extremely positive drilling results are providing additional growth opportunities for our gathering business and our transportation business. So, why don’t we talk a little about Haynesville and about the project and we’ll move on to Slide 14 to the map.
We’ve used this map for a number of quarters now and the main takeaway of the map is just the red dots continue to grow at a very fast pace and each one represents a new well. As of July 30th, there were 111 horizontal wells that were producing in the Haynesville shale. Optimism around the play continues to be supported with strong well results with an average second quarter initial production rate of 11.5 million per day. Remember now, this is across the field and in East Texas which is not our focus, initial production rates tends to be lower and then the further you move in to the heart of Louisiana around our system production rates tend to be higher and we continue to see a number of wells that are going to be connected to our system in the 18 to 23 million per day of initial production rates.
All-in-all at the end of July there are now 110 working rigs in the Haynesville area. This volume is ramping up much quicker than had been previously anticipated not only by us but by the producers and this all speaks very positive for the benefits we’re going to have in our pipe and for some other opportunities in that region as well.
Moving to the construction we have a slide that updates you on the construction. I’ll hit a few high points, construction on the 36 inch pipe essentially on the Elm Grove line is complete. That pipe is fully welded, buried, back filled and if you were to walk out on that right of way there is a lot of green grass already on the right away. So the 36 inch Elm Grove is 100% complete at this point. Construction on the 36 inch Bienville loop is on schedule for October completion. The clearing, grading of pipe and welding is 100% complete and then lowering it back in and back filling that line is 67% complete so that line is moving quite rapidly.
We began construction on the 42 inch Winnsboro line in late June. The clearing on that is 100% complete, grading is 45%, stringing is 30% and welding on that pipe began on August the 5th and I remember one day last week that I had a report that over a mile of that pipe had been welded in one day. So, the project is going well. The other aspects of the project related to our compressor stations are on target and to our interconnects are on target as well so the entire project remains on schedule to be in service by yearend 2009. If weather stays good there’s a possibility we can accelerate that a little bit but our focus is to be there on time and we’re certainly going to do that. On a hydraulic drill, these are always one of the things you watch to make sure that your drills go on schedule. We’re ahead of schedule on those, there are eight in total and four of those are already complete as we speak.
Page 16 has a run down on the cost, you remember that the cost that we have in this project is $653 million. Through June we have incurred $301 million and of course all of that costs are really incurred at the Haynesville joint venture and they do not have any kind of affect or impact on Regency’s balance sheet. In the end, we certainly expect that this project is going to be well within these budget guidelines and overall we’re just very pleased with where we are. The team has done a good job on this project, weather has worked favorably during the summer so we’re very pleased with the status of this project.
Just one note about the joint venture financing, on July 27th the joint venture entered in to a $25 million revolving credit facility. This facility goes until July of 2010 and is secured by the JV assets but is intended – this is really a working capital facility and the joint venture will later look at financing the expansions that we think are going to take place on the project at the joint venture level. This is just a small working capital facility that went in place in July.
In summary, on Slide 17, as I mentioned earlier the project is on budget, it’s on schedule, all of the 36 and 42 inch pipe is well ahead of schedule. Approximately 92% and I’ve used this number before, or a little over 1 billion of cubic feet have been contracted to date. I’ve told you all along we had a lot of interested parties in the remaining capacity. We were working to determine how we wanted to allocate that. I would expect that we will execute contracts for the remaining capacity by the end of the month. We’re well along with that so this project essentially is going to be sold out with long term 10 year firm contracts, 85% demand charge by the end of this month.
I’ll just mention the JV is also – you may have watched some announcements in the last few weeks from some of the producers that their forecasted volumes have exceeded their previous estimates and so there is significant interest in the region to see some additional pipe that can come in line and on service quickly to be placed in service to move higher levels of volumes. So, the JV is evaluating several expansion opportunities and we’ll keep you apprised of this as we move through the process. But, we’re pretty excited about some additional opportunities in that area.
Outside of the pipeline there are also opportunities that we are working on in our gathering business. We think there’s a chance for some fairly sizeable gathering projects already mentioned on the Nexus system for some expansions but there’s also the need for some gathering system to bring gas to the rig system and also to interconnect with some other pipelines as well so we are evaluating a number of those opportunities. This project overall has favorably positioned us to meet these growing requirements and we’re excited about the opportunities going forward.
Just a little bit about our organic growth initiatives for this year, for the first six months ended June Regency incurred about $81 million of growth cap ex. The breakdown on this is $63 million was for the fabrication of new compression packages and ancillary assets for the contract compression business. We had approximately $18 million for the various projects in the gathering and processing segment. Our 2009 total cap ex is expected to be $107 million, this is growth cap ex to be $107 million and roughly $81 million of this in the compression sector and $26 million of this in our gathering and processing facilities.
Looking ahead until next year, right now we’re anticipating that our capital growth capital needs there will be about $100 million for the year 2010. Before I go ahead and turn this over to Stephen and the financial review, I did want to just make a few comments about our management announcements that we made this morning. One of those announcements was regarding Randy Dean who is President and Chief Executive Officer of Regency’s compression segment. As many of you know and we discussed this a little bit back at our investor day, back many months ago, Randy has been on a partial leave of absence for a number of months recuperating from surgery.
I will tell you he is doing well but, he has informed us and we’ve had a lot of discussion that he certainly at this point believes he needs an extended period of time to meet his full health objectives and he and the company have talked about this and we both believe that it’s now in the best interest of him and the best interest of the company that we modify our working relationship. So, effective the end of August, Randy is going to be resigning from his full time role with the company but he’s going to continue to support us through a consulting arrangement.
He’s been a tremendous asset in building CDM, you know a lot of that history and he’s also been a tremendous asset to me during my six month tenure at Regency as not only did he work with CDM, he assisted me in some other areas as well. I’m very appreciative of his contributions. I and all of us at Regency and all the staff at CDM wish him well as he continues to focus on his health. But, I’m also pleased as he makes this move that we have an ongoing arrangement that’s going to allow us to continue to access his expertise and his knowledge through the consultancy agreement that we put in place.
Now, David Mars who many of you have met and who together with Dean and Randy Craf founded CDM in 1997 has served as Executive Vice President of our contract compression business since the acquisition early last year. He will now serve as President and Chief Executive of this segment. David has actually already assumed much of the responsibility of this position over the last four to five months and I assure you that he’s fully prepared to step in to this new role. He and I have worked very closely together and I am really pleased to have someone with his long industry background, his expertise and his experience just ready to step in to this leadership role. So, we’re very pleased about that.
I’d also like to announce, and you may have seen this in our release this morning that we’ve made Patrick Grioir Executive Vice President and Chief Commercial Officer of our gathering, process and transportation segment. Pat previously served as Senior Vice President and his long background in strategic and commercial roles are going to be a great value as he continues to run all our commercial activities and he and his team are aggressively involved in all the things I mentioned around the Haynesville shale and Eagle Ford shale areas as well as finding ways to offset some of the pressures we’ve seen in the markets. So, I’m very pleased to announce Pat’s promotion as well.
All-in-all I am pleased with our results. I think almost all companies in the midstream sector are certainly facing their challenges in this market but our team has continued to find ways to respond to these challenges and have helped us stay focused on meeting our earnings objectives and to date they’ve been very successful. All-in-all I’m very pleased with the second quarter and with the first half and I’m optimistic going in to the second half of the year that we’re going to continue on this path and continue to meet our objectives for the year.
With that I’m going to turn it over to Stephen who will give you a little more details on some of the financials.
Stephen L. Arata
On page 19 you see our consolidated operating results comparing the first quarter of this year to the second quarter of this year. Our net income for the three months ended June was $6 million compared to $148 million in the first quarter. As Byron mentioned, the primary driver there was the $133 million gain we achieved in the first quarter when we contributed our rigs system to the Haynesville joint venture. There is also an additional $1.3 million of net income allocated to our joint venture partners compared to the amount we allocated in the first quarter.
Our revenues overall quarter-over-quarter were down by 12.6% but as Byron mentioned, we’ve had some very good cost management efforts so we’ve been able to hold our expenses down as well and excluding the gains and losses on asset sales line items our expenses are down 11.7% quarter-over-quarter and that is a cost decrease in all of the cost categories from O&M to G&A to cost of sales to depreciation. Our interest expense was up by about $5 million quarter-over-quarter driven in large part by additional interest from our new bond issuance where we termed out some of our revolver and in part from higher interest rates from the remaining amount held on the revolver.
Page 20 we have our results for our gathering and processing segment. As Byron mentioned, the quarter-over-quarter decline in throughput which was primarily driven by a 15,000 MMbtu a day decline associated with the maintenance at our Tilden plant and then about 35,000 MMbtu per day of lower volumes across our North Louisiana gathering assets. However our NGL production has remained flat quarter-over-quarter at about 22,000 barrels per day as the volume declines had minimal impact in our liquid recoveries. Our adjusted segment margin per MMbtu increased from $0.59 in the first quarter to $0.62 in the second quarter so we have been able to partially offset the lower volumes with higher margins.
On page 21, our transport segment results are included. As Byron mentioned we did have a quarter-over-quarter volume decline. About 10,000 MMbtu per day of lower volumes came from lower volumes we flowed to our Union power plant. Then, we did have significantly lower basis differentials in the second quarter than in the first quarter due to the hotter temperatures in Texas and the lower temperatures in the end markets and the Midwest and the Northeast. If you look at our combined transportation segment margin which includes 100% contribution from rigs for the entire quarter, our segment margin decreased by just under $1 million and our segment margin per MMbtu remained flat at about $0.19 per MMbtu quarter-over-quarter.
On page 22 we have some contract compression details. Byron has gone over a lot of this detail so I’ll just give you a couple of additional pieces of information. Compared to the first quarter, our segment margin was down just about $1 million from $37 million to $36 million and that was primarily attributable to a decline of 22,000 revenue generating horsepower. We have anticipated slower than anticipated growth.
As Byron mentioned, we responded to this development by aggressively managing costs and we expect the net impact of the environment and our response to it to continue to enable us to meet our budget for this year. Quarter-over-quarter our average horsepower per revenue generating compression unit decreased about 1.4% from 858 horsepower to 846 horsepower but again, this is still a significantly higher ratio than any of the other peers in our industry.
On page 23 we have a liquidity update for this year. At the end of July we had $285 million available on our revolver. We also had at that same date $65 million available under our Caterpillar operating lease facility for a total of $350 million of potential available liquidity. We have spent $81 million so far of our $107 million growth capital budget for 2009 which leaves about $26 million remaining in growth capital expenditures remaining this year. We feel very good about our liquidity position and our ability to meet all of our growth capital plans for this year as well as in to next year without having to access the capital markets. Any capital markets we do complete would be in order to further strengthen our financial position or to finance currently unidentified attractive growth projects.
Page 24, we have our commodity price risk management summary. You can see our quarterly NGL equity position in barrels per day compared to our hedge positions. For the balance of this year we have hedged 97% of our NGL equity production through product specific swaps. Our overall 2010 NGL hedges are now 56% of our forecasted equity production as we have put on additional swaps in the last three months.
For 2010, a little more detail, we have hedged approximately 70% of our non ethane equity exposure and we’ve hedged 75% of our ethane for the first half of 2010 and we expect shortly to put on additional hedges for the second half 2010 ethane exposure. For 2009 and 2010 on the WTI side, we have hedged approximately 75% of our equity production on condensate and then for 2011 we have entered in to swap contracts for 18% of our forecasted equity production of both NGLs and condensate.
On the natural gas side we have hedged approximately 85% of our exposure for the balance of this year and about 44% of our exposure for 2010. We do anticipate entering in to additional hedges to hedge approximately 85% of our total equity exposure across all products in 2010 and 50% in 2011. As I mentioned last quarter, we are doing this on a rolling basis. Our risk management committee had determined that a rolling hedge strategy would be better than putting trades all in at once to reduce our overall risk so that’s the strategy that we’re pursuing at this time.
On page 25 we’ve put a sensitivity analysis of our distributable cash flow to commodities. You can see from that page that we’re relatively insensitive to commodities. I’ll reiterate we do have length in natural gas because of our conservative effort to minimize our keep-whole exposure and the way to read the chart is a $10 per barrel movement in crude along with the same percentage change in NGL pricing will result in a $200,000 increase or decrease in our full year DCF and a $1 per MMbtu movement in natural gas will result in a $300,000 change in our full year distributable cash flow. On a final note, sulfur prices as I’ve mentioned before cannot be effectively hedged. So, we’ve assumed $30 loss per long ton for our 2009 forecast. A $10 move up or down in sulfur prices will change our segment margin by about $200,000.
With that, I’d like to open it up for Q&A.
(Operator Instructions) Your first question comes from Michael Blum – Wells Fargo.
Michael Blum – Wells Fargo
I just had really one quick question on the hedging strategy, in terms of going to more of a rolling strategy are you doing that in a formulaic way so that you’re doing it once a quarter or is it still sort of opportunistic but rolling throughout the year?
Stephen L. Arata
We’re trying to do it once a quarter, it’s not on a specific date but we are trying to be more intentional about doing it on a quarterly basis than doing it in large buckets.
Michael Blum – Wells Fargo
Then just curious in terms of ethane your decision to hedge is that a function of your view that prices are not going to recover much so you’re just going to take the price that the market gives you right now or is it more sticking to that discipline.
Stephen L. Arata
It’s not really a view on pricing it’s more just trying to reduce volatility of future results. I will add Michael that our expectation is that with our hedged portfolio for 2010 so far plus if you just use the forward curve for prices of the unhedged products, we expect our full year 2010 commodity results to be almost exactly on top of 2009’s numbers. Our hedged positions for 2010 are above our 2009 hedges but if you factor in the market prices for the rest of the unhedge products it brings it right in line and we will be increasingly taking that risk off the table as the year moves on. We’re not anticipating a big impact ’09 to ’10 from commodity prices.
Your next question comes from [Yves Segal] – Credit Suisse.
[Yves Segal] – Credit Suisse
Could you just reconcile for me on the compression cap ex budget how does the decline in utilization fit with the budget right now and when you look at 2010 what are you thinking about in budgeting cap ex for the compression segment?
Byron R. Kelley
I’ll talk a little bit at the macro level, you backed up in to last year the compression business was very active and you traditionally required long lead times. So much of the purchases that we’re doing this year are a result of commitments that were made last year so we’re seeing some purchases this year that are going not all of that is being placed at this point some of that is going in to inventory. But, we’re not making commitments for purchases for next year so we will utilize this excess equipment this year that we may end up with. We’re going to place some of it but what we don’t place we will then utilize this next year for our business and so you could expect to see capital requirements in 2010 for this business will be in terms of cash outlays much less than they were this year. That’s on a macro basis, if you want some specific numbers we can delve in to that a bit.
[Yves Segal] – Credit Suisse
Sure if you have them.
Stephen L. Arata
We probably have approximately 100,000 horsepower currently unutilized. Some of that we had in the inventory last year, some of it relates to additional compression purchased this year that hasn’t yet been utilized. We’ve also been looking for opportunities to sell excess compression. We’ve had some success in that arena but one of the interesting things this does and we’ve never really been in this situation before is it gives us a bit of an opportunity to pursue large scale growth opportunities which we never really had compression on hand to do before.
So, we are looking at larger opportunities to take over compression from customers. One of the areas we’re looking at now, David Mars and his team are looking at moving in to the Marcellus shale with some of our customers who have been requesting us to look at that opportunity. We’ve made some field trips up there to try and see what kind of opportunities that could play for us. There is a positive side to having a little excess compression but it is going to reduce our cash commitments for next year but we’ll continue growing this business.
[Yves Segal] – Credit Suisse
When you look at the budget for next year if compression is coming down, it sounds like it will come down next year, where do you see spending the balance of that budget? Is it primarily to hook up more wells? How do you think of that?
Byron R. Kelley
When I look at next year and actually the things that we are working on now that could get started a little bit this year but have most of the expenditures in to next year is in two areas. Obviously the pipeline we believe has some good growth opportunities but they’ll fund that on their own but looking at our gathering business I mentioned earlier down around Logansport area where our Nexus system is there’s some gathering opportunity there. There are gathering in the Haynesville region up in the [Vistano] region that we are expecting and are hopeful that we’re going to be able to put together some opportunities there. Then, there’s some things around the Eagle Ford shale play.
Most of those dollars essentially that we’re hopefully going to have an opportunity to spend are going to be in the gathering. It’s going to be a fee based business which is obviously a focus of ours is to continue to grow that. So, we’ve got right now a long list of potential opportunities that would far exceed $100 million if we were to get all of them. Obviously, that’s the way you work, you build up a long list of opportunities and if you get your share you’re going to have some good growth. That’s where the focus is going to be, it’s going to be in the gathering sector.
Your next question comes from John Edwards – Morgan, Keegan & Company, Inc.
John Edwards – Morgan, Keegan & Company, Inc.
I missed on your 2011 hedges, did you say you had about 45% or so at this point or maybe you could repeat that?
Stephen L. Arata
Actually, at this point we have 18% of our NGL and condensate hedged. We’re anticipating moving that to 50% by the end of this year.
John Edwards – Morgan, Keegan & Company, Inc.
In terms of your G&A and O&M came down quite a bit, what’s your expectation I guess for quarterly run rates on those?
Stephen L. Arata
We expect those to continue to remain flat or decline for the balance of this year.
John Edwards – Morgan, Keegan & Company, Inc.
On the compression, there was a little bit of a decline here this quarter so as far as where you expect the horsepower, are you expecting it to be relatively flat to this quarter or coming down a little bit further?
Stephen L. Arata
I think Byron mentioned that we expect it to be somewhere between flat to slightly down to the balance of the year?
Your next question comes from Lenny Brecken – Brecken Capital.
Lenny Brecken – Brecken Capital
I just wanted to ask in terms of the Haynesville expansion opportunity if you look out a ways, can you just help me understand how that potentially is going to be structured? Is Regency going to take a bulk of the investment in terms of expansion or will it be shared among the joint venture? Just give me an idea how you’re thinking albeit it’s a bit early. On another note, the shale plays in Texas which you sort of touched upon but didn’t quantify can you help us understand what the volume opportunities are there? I know you mentioned compression as well in Marcellus but just some understanding of what the volume impacts will be out 12 or 18 months from now if any?
Byron R. Kelley
I’ll first touch on the Haynesville expansion opportunities and we’re talking about the pipeline opportunities there through the joint venture. As you are aware, the joint venture other than the $25 million working capital facility I mentioned really has no debt. It’s an entity that by the end of this year is going to have assets of just to call it a round number $1.1 billion of assets. So, it’s going to be a well rated entity so the plans at the joint venture are to raise the debt at the joint venture level is to as we look out in the foreseeable future to at least fund the first $300 or $400 million of opportunities that we have on that pipeline at the joint venture level.
So, there will not be an equity requirement or an equity call from Regency for its 38% share to do it. It’s a self funding entity, that’s one of the good things about the joint venture. As of now, they can raise debt and with their rating they’re likely to get debt at very good costs. So, that’s a positive on the joint venture as we look to grow that. Of course, we’ll get 38% of the benefit of the returns out of that without having to push in the cash.
Looking at the Texas shale plays, we’ll start first with the Eagle Ford shale area, by the end of this year we will probably add about $30 million a day of volume coming out of the Eagle Ford shale area. Then obviously if that trend continues down there or accelerates there will be additional volumes that can be picked up down there. We’re looking at how to do expansions down there. We’re really looking at gathering expansions there and I mean it’s not going to be a Haynesville shale but it looks like it’s going to be nice and the good news is where a lot of the activity is, is right on top of our assets.
We’ll see a good volume pick up this year and if the drilling keeps going we should see some nice pick up in 2010 as well and a chance to invest some capital down there in 2010. The other Texas shale plays we do do a lot of compression in the Barnett shale play. That has been a big growth area for us in the past, it’s basically not growing at the current time. What I would anticipate is I mentioned that when you look long term we’re expecting cash prices next year to get back up in to a run rate of $6 at least. If we get to that range you may see some drilling activity pick up back in the Barnett shale area which will be good for our business.
The Fayetteville shale, the primary producer there and a large customer of ours has continued to drill and we have added there and we would expect that to continue as well. Then getting out of Texas we mentioned earlier that we’re very interested in the Marcellus shale. When you look at what’s happening there right now it’s not a lot of production at this point, they’re spacing the wells pretty far apart to prove up the activity but now we’re looking for the producers pretty soon to start coming back in and filing in the gaps.
I think the producer is expecting that they’re going to start bringing volumes on there sometime next year. So, we’re looking to move in with some people that we’ve got good relationships to take us in there and hopefully be an anchor for us to move in with something let’s say 18,000 to 20,000 horsepower. We’re not going to go up there with one unit but our goal is if we can aggregate and go in with a nice package then it would make sense to move in to that market.
Lenny Brecken – Brecken Capital
Just one follow up, in terms of the Haynesville will you be adding any gathering and processing assets there in conjunction with the expansion?
Byron R. Kelley
What we’re pursuing and expecting, if we’re successful, we’ll be adding some gathering and treating but not any processing. Both of those are fee based, the treating will be a fee based structure just like the gathering.
Stephen L. Arata
I would add those will be at the Regency level not at the joint venture.
Lenny Brecken – Brecken Capital
Is there any sense of how big with the corresponding investment in transportation what kind of increments? I think you already quantified that in the past but in terms of the volume upside there over the coming years?
Byron R. Kelley
If I were to tell you what my opportunity looks like up there it’s well north of $200 million. We haven’t won them yet so we’ve got to go work it but that’s the opportunity list is somewhere really if you look at it is probably $250 to $275 million of opportunities that we’re looking at in the gathering sector for that area.
This concludes the question and answer session of the conference. I would now like to turn the conference over to Ms. [Elizabeth Huber] for closing remarks.
Ladies and gentlemen thank you for taking the time to join us today. If you have any additional questions please give me a call.
We appreciate your participation in today’s conference. This concludes your presentation you may now disconnect and have a great day.
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