Regency Energy Partners LP. Q1 2009 Earnings Call Transcript

May.11.09 | About: Regency Energy (RGP)

Regency Energy Partners LP. (RGNC) Q1 2009 Earnings Call May 11, 2009 11:00 AM ET


Byron Kelley - Chairman, President & Chief Executive Officer

Stephen Arata - Executive Vice President & Chief Financial Officer

Shannon Ming - Vice President Corporate Finance Support & Investor Relations


Lenny Brecken - Brecken Capital

Xin Liu - J.P. Morgan

John Edwards - Morgan, Keegan

Noah Lerner - Hartz Capital

Helen Rue - Barclays Capital

Bob Martin - Unidentified Company


Good day ladies and gentlemen and welcome to the first quarter 2009, Regency Energy Partners LP earnings conference call. My name is Josh and I’ll be your coordinator for 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 this conference. (Operator Instructions)

I’d now like to turn the presentation over to our host for today’s call, the Vice President of Corporate Finance Support & Investor Relations, Shannon Ming; you may proceed.

Shannon Ming

Good morning everyone. Welcome to our first 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 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 this slide carefully.

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 19.

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

Byron Kelley

Good morning and let me add my welcome to each of you for joining us today. I look forward to sharing with you this morning, the details regarding Regency’s first quarter performance.

As you’re aware, the fundamental market changes that we’ve seen over the last six to nine months have been fairly dynamic and presented the sector some challenging economic conditions to deal with and so in light of these challenges, I’m very pleased that our first quarter performance was right inline with our expectations. We came in approximately within $100,000 of our internal budget for the quarter.

I would ask you to turn to slide three, as we began the presentation this morning. As you can see on the slide, our adjusted EBITDA was $54 million, inclusive of the joint venture and $55 million assuming Regency 100% ownership of the RIGS for the entire quarter. I believe this performance is a testament in light of the market conditions to our strong fee-based set of assets and to the focus and hard-work of all of our employees.

In light of Q1 performance and our expectations for the remainder of the year, we are reiterating our previous guidance of $220 million to $240 million of adjusted EBITDA for 2009. Also as you are aware, our first quarter 2009 distribution was inline with our expectations at $44.5 for the quarter or $1.78 on an annual basis.

We planned to maintain our current $0.445 distribution during the construction of the Haynesville Project and of course our distributions are set by our Board of Directors and it is driven by the long term sustainability of the business. Obviously, if there were drastic changes in market conditions or cost to capital or drilling activity, the Board would reevaluate our position, but currently it is our objective to maintain this level of distributions throughout construction.

Between market fundamentals, our Haysville joint venture and details on our quarterly results, we have a lot of information to share with you this morning. So before I jump in to covering the information we’re going to cover, I thought it might be helpful to give you a quick outline of how our discussion is going to flow this morning.

To begin with, I want to spend some time on two major items that are important to our performance going forward; first, an update on our Haysville Project and the joint venture. This is obviously a significant event for us and one where we are extremely focused on execution. Then second, I want to cover some of the industry trends and their impact on the entire sectors, as well as the impact on Regency.

Many of these trends were anticipated by us and included in our budget process last fall; however, I think it’s important to have a good understanding with them, as we begin looking at some of the quarter-to-quarter comparisons that we will evaluate this morning. Then after setting the foundation on the trends, I will comeback to a more detail decision around our business segment performance and then Stephen will provide additional insight around our financial and capital performance for the quarter.

Let’s spend a few minutes on the Haynesville project and the joint venture and give you an update related to that. Obviously, an important financing milestone was completed when we closed on the Haynesville Joint Venture in March of this year. This closing allowed us to finance $653 million for the Haynesville Expansion Project and this just as importantly allowed us to move forward on a timely basis, with implementing the project. That’s important for us and that’s important for the producers in the Haynesville Shale of area.

An important objective of ours and of GE Energy Financial Services was to be able to partner with a long term investor that met our criteria related to financial and strategic goals and 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 the future growth, through a combination of additional equity or debt at the joint venture level.

We believe this structure is in the best interest of both our equity and debt holders. It provided us with one of the most efficient cost of capital options available in the market over the past six months. The base project returns exceed the cost of the new equity capital and the potential use of debt at the joint venture to fund further expansions will lower the overall cost of capital going forward, but we are very pleased to have that closed and to be moving forward with the project.

I’d invite you to turn to slide five and would like to give you a brief update on the drilling activity around the Haynesville area. We’ve used a slide internally and a few times in the past on our public presentations and if you were to compare this with the same slide from a number of months ago, the big difference you would see is there are a lot more red dots on this slide that continues to grow and each dot representing a new well.

Optimism around the play continues to be supported by strong results, with regular initial production rates about 20 million cubic feet a day. For 2009, operators plan to spend more than $3.5 billion drilling perspective acreage in the Haynesville Shale.

The horizontal rig count in Haynesville Shale has resin more than 400%, since March 2008. Haynesville now account for nearly 30% of all horizontal shale rigs, and this includes the Barnett, Marcellus, Fayetteville, Haynesville and Woodford areas; about 30% of all those horizontal rigs are now drilling in the Haynesville Shale.

Additionally, a few points of good news in the recent weeks as Petrohawk announced last weeks, it’s increasing its rig count that it originally projected for the year, from 10 horizontal rig drilling program to 16 horizontal rigs by the end of the year. Six rigs on an annual basis add up to about 40 additional completions per year. So, this is sizable upsides of their program.

Exco also has just had an announcement that by mid-2009, they’re going to add three additional horizontal rigs to their program, bringing them up to nine rigs drilling in the Haynesville area.

Based on our production estimates and these are pretty conservative given the actual rates that we’ve seen from the deliverable from this field on the current IP rates. We believe the deliverables from this field is going to increase rapidly and the Haynesville will become one of the major producing fields in the United States.

So, just taking our conservative assumptions of a 100 rigs per year for the next three years, with initial production rates of $8 million and that’s concurrent to what we’re seeing of many of the wells being 20 million plus per day, but using $8 million and 100 RIGS, by the end of 2010, the production is expected to increase to over 2 billion cubic feet per day and then moving that forward through 2012, you’re probably looking at 4 billion cubic feet a day.

I think, what we’re seeing is the increase in rigs we’ve just seen added to this area and the rates that these numbers may well be conservative, but in the end a tremendous amount of gas, coming fairly rapidly from this play. Even if we complete an expansion to our project that’s currently underway, a major expansion, it’s pretty obvious that other capacity additions are going to be required in the future to meet the long term forecast for gas coming out of the Haynesville Shale.

Looking at slide six, just an update on our contracting; approximately 92% or a little over 1 billion cubic feet a day has been contracted out of our $1.1 billion capacity. Petrohawk and Exco are the major anchor shippers for the project. The shipper base includes an addition to Exco and Petrohawk, J-W Operating, [Fitz Canor], GMX, Questar and El Paso, ENP.

We also have request an excess of the remaining $100 million a day and we would expect that we will have those contracts signed in a matter of weeks and be fully sold out, far in advance of this project going into service.

All of our agreements are for firm transportation capacity, all of our agreements are for 10 year terms and approximately 85% of the revenues are from reservation fees. This project in addition to being a great increase in volume for us, it also favorably positions us for future expansions to meet the growing produce requirements that I talked about a minute ago. John Victor is currently evaluating several expansion opportunities.

Looking to page seven, a little bit on the construction update and I’ll start with to us, some very exciting news; and that is that construction began on the 36 Bienville line on May 1, right on schedule with our internal plans, and obviously to start construction on May 1 meant that we had in-hand all of our core permits, all of our road crossing permits, all of our Louisiana Department of Natural Resources permits and we had received our FERC approval letter in late April.

Then looking at 36 inch Elm Grove line, we also have all permits and clearances to move on forward with that construction. So, all of the 36 inches underway, all the permit's in place and construction is underway.

On the 42 inch line, the Centerline as you remember, we staggered these projects, so that we would start 36, ahead of the 42 and the 42 is scheduled again later in the summer, but on the 42 inch line, all of our Centerline environmental surveys are 100% complete. 99% of the write-away tracts have been acquired. Actually there’s only one remaining tract on the 42 inch and we finalized and purchased our wetland mitigation credits.

We’ve already received all our in-state environmental permits and clearances for the 42 inch pipeline in the Haughton and Elm Grove compression stations and we expect to have our core permits later this week. From the receipt of that permit we’ll immediately file the FERC 30 day advance notice for the 42 inch pipeline and the compressor stations. So we remain right on schedule for being in service by the end of this year.

In relations to cost, if you’ll turn to page eight or to slide eight; the total cost of this project is $653 million and obviously we’re pretty far down the road in the project with our pipe, supplies and our valves, all of those have been purchased.

So quite a bit of this project, when you look at the $653 million, essentially the cost is already known and fixed and over 0.5% of this project I would say is essentially already locked out and that includes the materials, as well as the work we’ve done today on write-away acquisition, permitting and engineering and by having finished all of our engineering work, obviously we’ve pined down all the final routes on the project.

So, a lot of uncertainty has already moved out of this project, with the remaining piece in front of us really related around construction and the normal things that have to go with construction. I would remind you that construction contract is a unit based contract and so we feel real good about where we are on this project. We expect the project to be completed within budget today [Technical Problem] under budget when we expect to complete.

Through March 31, we disbursed $143 million in Haynesville related costs and all of these costs are actually incurred by the joint venture and they do not affect the balance sheet. Overall, we are very pleased with this project status. It’s right on target both from timing and a cost standpoint.

I want to now spend a few minutes talking about some of the industry trends around drilling and pricing in general. If you’ve been following the market, you know that the active rig count has declined significantly; U.S. land rig count for 2009 has declined 808 rigs in a four month period. Essentially, that ended on May 8 as through last week, that’s about a 47% decline over four months and that’s general industry wide.

Now, the decline on rig count on our system has followed a similar pattern. Overall, we expect to see a decline in volumes in traditional plays and an increase in unconventional production, with a net result being a small decrease in year-over-year production for the systems.

However, this was anticipated in our budgeting process, this is not a surprise and so excluding the Haynesville activity, we have seen declines slightly higher than we expected in North Louisiana, but we expect the accelerated drilling in the Eagle Ford Shale in South Texas. It will keep us right inline with our original forecast and volumes for the year.

Although the market conditions have created challenges, we are well positioned for several unique opportunities. Our assets are located in two areas of increased activity, the Haynesville and the Eagle Ford Shale, both of which I had mentioned. Both of these provide a strong fee based gathering and transportation opportunities and we continue to be proactive with our producers to meet their changing needs.

Also as mentioned earlier, the activity around Haynesville is accelerating and although this is not an impact on our 2009 volumes, it is certainly positive for our expected volumes next year as we ramp up the pipeline.

So looking at all of these trends, I guess the question maybe out there, is there any hope on the horizon? Maybe a little bit; key priced drivers maybe pointing to a little stronger outlook for natural gas prices in the near term. The June contract is currently trading higher than the May expiration and this is the first time this year that prices have risen month-over-month, so that’s a good news.

On a broader basis, we believe that drilling levels are not currently or not sufficient to meet ongoing demand and that higher prices will be reflected as deliverability declines from the lower rig counts begin to work their way into the market. So as a result of these dynamics we expect to see stronger pricings beginning to take effect later this year and early next year.

I would ask you now to turn to slide 10. There’s a little comparison between our first quarter 2008 and first quarter 2009. These first quarter results remained strong despite the approximate 50% decline in commodity prices across all products. Our net income increased from $10 million in the first quarter of 2008 to $148 million in the first quarter of 2009. A large piece of this is related to the gain related to the sale of the Regency to joint venture.

Adjusted EBITDA decreased by 3% from $56 million in Q1 2008 to $54 million, primarily related to the following factors. We had an additional $7 million of O&M expenses; $6 million of this is related to additional compression installed in 2008 and I’ll share those revenues associated with the year end on that.

$4 million increase in G&A from quarter-to-quarter and $2 million of this again was related to the additional compression we installed last year. So, $8 million of that $11 million was related to increased revenues, specifically related to compression and then we had a $1 million decrease that came from the implementation of the joint venture.

Now these were offset by total segment margin that increased 9% from $95 million to $104 million; contract compression made up $14 million of that increased; G&P had a $3 million decrease quarter-to-quarter, and this was primarily related and associated with commodity pricing.

Basically if you look back in Q1 2008, we had a larger un-hedged position, which received the value of our commodity prices than our 2009 hedged position will allow us to capture. So transportation also had a $2 million decrease attributable to the formation of the joint venture.

All-in-all, when you look at these results and the environment that we were operating in, I really think these were some pretty strong results under the conditions of the market. I would refer you for additional information on EBITDA and adjusted EBITDA to the details that are on slide 21. I would also like to reiterate that as we move through the year, only 3% of Regency’s estimated 2009 adjusted segment margin is subject to commodity price fluctuations.

Now turning to slide 10, I would like to spend some time talking about first quarter 2009 comparisons to fourth quarter 2008 results. Many of the same factors that were in play a minute ago, when I talked a minute ago about our Q1 ’08 to Q1 ’09 comparisons, were also in play as we looked at Q4 ’08 to Q1 ’09.

Relative to the fourth quarter of 2008, Regency’s adjusted EBITDA decreased from $61 million in Q4 to $55 million in Q1 and this $55 million assumes a 100% contribution of RIGS asset for the entire quarters, so that you can get a good comparison. We’ve included that, so you can get a good quarter-to-quarter comparison.

Decline was principally driven by four factors. You can see from the chart the dramatic change in commodity price that are here, that’s not news to any of us and overall, the commodity price impact was a $3.5 million decline in margin.

When I break this down into two pieces, the liquids represented all liquids together by $1.8 million reduction and you’ll see that sulfur had a $1.7 million impact from the fourth quarter to the first quarter and I’ll touch a little bit later on some more details around sulfur.

One thing I would say, last year when we had the higher sulfur prices, we never did consider that as a permanent part of our business and we did not adjust our distribution related to some of the high prices we saw last year. So, we never expect that sulfur price is to holdup. Even in a normal market, we didn’t expect it at the levels we saw last year.

Additionally, we saw a decrease in our marketing margins of $6 million quarter-to-quarter and this is not unexpected and the fourth quarter is usually one of our strongest quarters every year and we usually see a difference between fourth quarter and first quarter in our marketing margins. We did have a good first quarter, just not quite a strong as the fourth quarter.

Then in the G&P segment, we had a margin decrease, $1.7 million of that was related to a decline in volumes from the lower drilling and a margin reduction of $1.8 million related to a contract renegotiation with the counterparty that filed for bankruptcy in this part of the settlement.

I would say that in that settlement, we did collect all arrears in that account, but we were required to negotiate some rights going forward to satisfy the bankruptcy course. All-in-all it’s still a pretty good deal for us, but that was an impact quarter-to-quarter; and then those impacts were partially offset by $1.0 million in expense reductions from quarter-to-quarter.

Moving to slide 12, I’d like to touch on some of the key highlights from our Gathering & Processing Transportation segment. Despite the declines in rig counts, our contract compression horsepower and our natural gas throughput continue to experience solid growth over the last 12 months.

If you compare first quarter ’09 versus first quarter of ’08, you can see that the throughput in the Gathering & Processing segment increased 13% over the 12 months and the total throughput in the transportation segment increased 11% over that timeframe and so that was a very good year of growth. However, I would point out that in the first quarter of ’09, we began to see the impact of the lower drilling activity on certain segments and we look at this on a region-by-region basis.

I’d like to first talk about North Louisiana. In North Louisiana, we saw volume decrease at 12% during the first quarter at our Dubach facility, driven by the sharp decline in drilling at Terryville field.

Those volumes out of that field peaked last year in the third quarter and we’re still extremely strong in the fourth quarter, but most of the producers have moved their drilling rigs out of that area and into the Haynesville area and so we have seen a significant decline that we saw beginning in the fourth quarter of last year. So, we’ve got lower commodity prices that have been impacting drilling, but also the need for rigs in the Haynesville Shale has impacted some of the drilling in North Louisiana.

Some of the good news in looking at North Louisiana is on our Nexus system, the system we acquired last year. That system throughout the year built up to the point that it was running full, it continues to run full and in reality, it is an area where there’s lots of drilling taking place, some of that Haynesville related.

We’re actually evaluating several opportunities to expand that system, because there is a shortage of infrastructure in that area. So, despite the declining volumes, because of the ramp up that we saw in 2008, we are overall forecasting for North Louisiana an increase for 2009 in volumes of about 3% for the entire region.

Moving to West Texas, volumes there right now are approximately $10 million ahead of the fourth quarter and this is due to additional processing at our Waha plant, but this is one of the regions and one of the hardest hit regions in rig declines, but we continue to have our business development teams and regional service teams pursue opportunities for new supply in 2009 and 2010.

We did complete our Woodford Mountain expansion in October last year and that continues to bring an additional $8 million a day to our Waha plant and gives us ability to compete for additional packages that previously we did not have access to compete with.

The recently acquired [Carnosa] plant helped Regency secure additional well ahead gas and helped us maintain volumes in the existing system. Run times at that plant have increased, providing a small boost in margin and we continue to evaluate some compression projects that would optimize that systems and further increased margins, but looking out for the year, in West Texas we expect to see volumes decline about 6% for the balance of the year.

In the mid-continent, the bad news here is that we expect volumes to decrease 15% for 2009, the good news here is that FrontStreet assets located in that region are cost-to-service fixed margin assets and our probability is really the same, irregardless of the volumes falling through the system. So the volumes are down, but really we’ll have a sense of no impact on us this year, because we have a contract to structure.

Looking at East Texas, reduced sulfur pricing as I mentioned earlier led to a $1.7 million decline in margins compared to the fourth quarter of 2008. The net rollout sulfur price to Regency has dropped to a current negative or $49 per long term, basically with transportation costs greater than the Tampa market pricing.

Obviously, at this point it’s still economical to run this plant for the benefit of the system as we need to continue to process the gas, but we’re running roughly $50 negative per long-ton, versus last year at the peak. You may recall that we saw $650 or plus per long-ton for sulfur prices. So a big change year-to-year and even in the fourth quarter of last year, we were still running well over $100 per long-ton. So, that was expected to see those prices come down, maybe not quite as far as they have.

Some research indicates, there maybe a little relief coming on those prices as we move through the year, but overall as we look into East Texas, we’re forecasting an average volume decline of about 11%. So with the lower sulfur prices and the lower prices for commodities, drilling has just essentially been significantly reduced and that will resolve in average volume declines of 11% for the year.

Moving to south Texas though, we’ve got a different story there, a much more positive story. Volumes there continue to increase on our gathering systems, with the continued development of the Eagle Ford Shale and Regency is well positioned to continue to benefit from this new developments.

Our kiln plant was shutdown for week in March, due to some rework on our gas injection that impacted volumes for the first quarter, but overall this is a bright spot for us and we’re forecasting a 15% volume increase in South Texas for 2009. On the transportation segment volumes have been increased by $41 million MMbtu per day from the fourth of the first quarter, primarily attributable to additional volumes following under Union Powers firm transportation contract.

I would like to now turn our attention to the bottom left hand corner of this slide and a few comments about our contract compression segment. Our contract compression segment increased revenue to generating horsepower of almost 174,000 horsepower; from Q1 2008 to moving up to well under 790,000 horsepower in Q1 of 2009. So over the last twelve months, we saw a 28% increases in our horsepower there.

Now, as we moved into the first quarter with a significant decline in rig count, the rate of horsepower addition in this segment has definitely been impacted. We are also experiencing a challenging environment in reapplying horsepower that comes up for contract renewal, but in spite of these dynamics, we did maintain growth in the first quarter.

We saw additions of about 11,000 horsepower and our projection for the full year is to have an annual growth rate of about 8%, moving up to 840,000 horsepower of revenue generating horsepower by the end of the year. So in spite of a difficult market, this business is still doing quite well under the circumstances.

A few statistics around the horsepower additions; year-to-date these additions have averaged 1083 horsepower per unit. This compared very favorably with our budget of 836 horsepower per unit. As you know, our model is to place the larger horsepower units in the field.

Our growth in Fayetteville Shale and North Louisiana, a lot of that around Haynesville, we think should continue to’09, but our other regions are experiencing probably minimal growth as we go through the year. Our operating horsepower for technician has trended higher. This is good and this is a result of very aggressive expense management that we put in place, as well as higher horsepower installation.

Now, this trend is expected to remain at the higher levels for the balance of the year, due to our continued emphasis on the expenses management equation. Average horsepower per revenue generating compression unit for our full fleet was 858, which is up slightly from 849 in Q1 of 2008. All-in-all, this is a significantly higher ratio than our contract compression peers have in the industry.

A few minutes on our organic growth initiatives and our revised growth capital; for the three months ended March 31, 2009, Regency incurred $45 million of growth capital; $39 million was for the fabrication, new compression packages and ancillary asset or contract compression segment and $6 million, which were various projects in our Gathering & Processing segment.

I anticipated 2009 organic growth capital had been reduced by $13 million to $107 million. The $107 includes $82 million for additional compression for our contract compression segment. Now this number is where the reduction came from. It was reduced from our previously stated budget of $95 million, down about $13 million; $10 million of that came from elimination of commitments. So we have this year that we no longer have and $3 million came from deferral of some commitments from this year into 2010.

In 2009, after factoring in our reduced compression commitments and spending to-date, we expect to use about $40 million of the Caterpillar lease facility for the year and then we expect to spend $25 million for the expansion of our Gathering & Processing facilities. Looking to 2010, our current forecast right now, our thinking is approximately $100 million of growth capital for our base business in 2010.

In a minute I will turn the mic over to Stephen, to talk about more details related around our financial results, both in earnings and related capital, but before I do that, I would like to take a minute just to comment on the announcement we made on Friday regarding Dan Fleckman.

Dan is Regency’s Chief Legal Officer, our Executive Vice President and Secretary. Now, Dan has made a personal decision to return to private practice and he will be moving back to Huston as a partner in the firm of Mayer Brown. He will continue full time with Regency through the end of May and he will serve as our General Counsel and as a consultant, until we find a replacement and that search is underway.

Since joining Regency in May of last year, Dan’s been an integral part of my team, in advising me and the company on everything; from fund raising to the recently announced Haynesville Joint Venture. His strategic advice and his council over the past year have been very important to me and I can assure you, he is going to be greatly missed. While I hate to see him leave, I will always be appreciative of his contribution to us and we wish him well as he moves forward with his new endeavor in his career.

If you get a chance, some of you know Dan and you can always give him a call and wish him well, but he’s been a great addition to our team and we do hate to see him leave, but people make decisions sometimes and have drivers of their own. So, Dan will be solely missed.

So with that, I will turn the mic over to Stephen, who will give you some additional detail. Stephen.

Stephen Arata

Thanks Byron. On page 14, we show our consolidated operating results. Our net income for the three months ended March 31 ’09 was $148 million, which compared to a net income of $10 million for the same period last year. This increase in net income was primarily due to the recording of $134 million gain associated with assets that we contributed to the joint venture.

We also had an increase in total segment margin of $16 million and we also in 2009 did not incur the $4 million in management services termination fees related to the acquisition of our FrontStreet assets that we did have in 2008. We also had a $1 million decrease in interest expense and these were partially offset by a couple of items.

An increase in operation and maintenance expense of $7 million, primarily due to an increase in consumables and employee related expenses in the contract compression segment, as well as a small amount in the Gathering & Processing segment; and then an increase in depreciation and amortization expense of $6 million in 2009, which is related primarily to organic growth projects in the contract compression segment and again a small amount in the Gathering & Processing segment, as well as the acquisition of Nexus in the late first quarter of last year.

Our Q1 EPU was $1.86; obviously, significantly from the gain from asset sales. If you exclude the gain from the asset sales and our mark-to-market impact of commodity hedging, our EPU for the quarter would have been $0.12 per unit.

On page 15, there is an update on our Gathering and Processing segment results. Our total throughput from the Gathering and Processing segment increased from 919,000 MMbtu per day in the first quarter of last year to 1 million MMbtu per day in the first quarter of ’09. Our NGL production was flat at 23,000 barrels a day comparing both quarters.

Our adjusted segment margin decreased by 3% from $256 million from $58 million. This decrease is primarily attributable to $5.5 million related to lower commodity prices compared to 2008 price levels and Byron has gone over some of this already. A significant piece of that was related to sulfur price reductions which are very difficult to hedge on a financial basis.

There was also a $2 million decreased from various other sources. These were offset by an increase of $3 million from our producer services function, which had previously been reported on the transportation segment and a $2 million increased from the operations of our Nexus assets, 2009.

Our segment margin per MMBtu decreased from $0.71 in the first quarter of 2008 to $0.60 in the first quarter of 2009. This decrease is primarily due to lower commodity prices and lower fee based gathering margins associated with our Nexus gathering system. As I mentioned before, Nexus was acquired late in the first quarter of last year.

On page 16, we have our transportation segment update. As Byron discussed, we closed the Haynesville Joint Venture during the quarter. Now, I would like to walk through two sets of numbers for this segment. First, the numbers as reported which are on the top of the page, which take into account the joint venture impact.

Our throughput increase to 812,000 MMbtu per day in the first quarter of 2009, compared to 732,000 MMbtu per day in the first quarter of 2008. Our adjusted segment margin decreased to $12 million in the first quarter of 2009, compared to last years adjusted segment margin of $13 million. This is primarily due to the contribution of rigs to the Haynesville Joint Venture in the middle of March.

The second chart which is the combined transportation segment, accounts for 100% contribution from rigs for the entire quarter. The adjusted segment margin on this basis increased by 3% comparing the two quarters; $13.6 million versus $13.3 million. Our adjusted segment margin per MMbtu decreased slightly from $0.20 to $0.19 from quarter-to-quarter, which is primarily due to additional volume slowing under our Union Power FT agreement, which had no impact on our margins.

Page 17, we have an update on our contract compression segment. Our segment margin was $23 million in the first quarter of last year versus a segment margin of $37 million this year. This is primarily attributable to the 174,000 horsepower increase in revenue generating horsepower, which is as Byron mentioned, a 28% increase. This was also enhanced by the exclusion of 15 days of activity in 2008 due to the timing of CDM acquisition.

CDM has experienced slower than anticipated growth in revenue generating horsepower so far this year. We have responded to this development by aggressively managing cost. The net impact of the current environment and our response to it, has allowed us to meet our first quarter expectations for our contract compression segment. We continue to actively monitor the market and we see the current environment as an opportunity to continue to differentiate ourselves from our competitors.

I like to give you an update on our liquidity next. The total amount available to Regency under our credit facility as of the end March was $102 million. In addition to that, we have entered into an operating lease facility with Caterpillar Financial Services, which allows us to fund up to $75 million of our compression capital spending, under 10 year leases which have early buyout options in years five and seven, with an approximate cost of 8% to 8.5%.

In total, we now have budgeted $107 million of capital to be spent in 2009, which approximately $45 million has been incurred through the end of the quarter, leaving about $62 million remaining. We expect to fund approximately $40 million of our compression needs on this facility in 2009. The remaining $22 million, plus approximately $10 million of incurred, but not yet paid capital expenditures will be funded under our revolver.

This leaves us with sufficient liquidity to meet all of our growth capital plans for 2009 without having to access the capital markets. Any capital markets activity would be completed in order to further strengthen our financial position or to finance currently unidentified attractive growth projects.

Before moving onto my discussion with commodity price risk management, I want to spend a couple of minutes discussing our current and expected distributions in the context of our current end forecasts, as well as historical financial results.

Regency achieved a 1.1 time distribution coverage ratio in the first quarter of this quarter. Assuming a flat distribution in 2009 as we have previously shared with you, our coverage ratio will likely dip below 1.0 times for full-year 2009, returning to greater than 1.0 times once the Haynesville expansion project comes online.

We have stressed since our initial public offering over three years ago, that distribution determinations are made based on our cash available for distribution and the perceived sustainability of distribution levels over an extended period.

Since our first distribution for Q1 2006, our cash available for distribution has provided a cumulative coverage ratio of nearly 1.2 times for all distributions. After factoring in the expected financing costs associated with the JV structure for the balance of this year, we expect to enter 2010 with a cumulative distribution coverage ratio of 1.1 times.

On page 18, we have some details on our commodity prices risk management; our quarterly NGL equity position in barrels per day compared to our hedge position. For 2009 we have hedged 97% of our NGL equity production due to product specific swaps. In 2010 we’ve hedged approximately 70% of our non-ethane equity exposure. We have not yet hedged any of our expected ethane equity production, leaving us with an overall 2010 NGL hedge of 36% of our equity production.

For 2009 and 2010, we have hedged approximately 75% of our condensate equity production to WTI crude swaps and finally we have hedged approximately 70% of our natural gas exposure.

We anticipate entering into additional hedges to hedge approximately 75% of our total equity exposure across all products in 2010 and 50% in 2011. Our risk management committee has determined that we will be rolling hedges in quarterly versus annually to help produce our overall risks, moving away from large annual volume trades, which would reduce the risk and moving the market negatively against us.

On page 19, we have a sensitivity cart to our commodity prices. We do have link in natural gas due to a concerted effort to minimize keep-whole exposure. At many of our processing facilities, we have the ability to reject some level of ethane, which will minimize downward DCF impact in negative frac spread environments.

A $10 per barrel movement in crude, along with the same percentage change in NGL pricing, will result in a $0.1 million change in Regency’s full year available cash. A $1 per MMBtu movement in natural gas pricing, will results in a $1 million change in our full year cash available for distribution.

Sulfur prices, as I mentioned before are difficult to hedge financially and economically. We have assumed $30 per long-ton for our 2009 forecast. A $10 movement in sulfur prices results in a $0.4 million change in segment margin.

With that, I’d like to open it up to Q-and-A.

Question-and-Answer Session


(Operator Instructions) Our first question comes from Lenny Brecken - Brecken Capital

Lenny Brecken - Brecken Capital

If you look at holding your volumes static, the pricing environment pretty much static, I’m trying to get a sense of what future upside there is on the EBITDA line as we move into 2010 or 2011, so that the distribution can actually grow?

When I look at the Haynesville opportunity, yes it’s going to enhance your cash flow, but it looks like it’s going to just cover, give you a buffer on EBITDA line for maintenance CapEx and here and there it’s not really going to allow you to grow your distribution.

So, can you give us just a snapshot into your expectations for what up side there is on the EBITDA line going into 2010, 2011 so that we can get some comfort that you can actually growth the distribution? Thank you.

Stephen Arata

Certainly, I’ll address part of that and I think Byron will add in at the end. With respect to the Haynesville project, we actually expected to significantly enhance our EBITDA and potentially allow us to increase our distributions.

We have assumed a very conservative ramp up of volumes next year and one of the keys to that project as Byron mentioned during his discussion was that, it does position us well for further expansions beyond just the initial project and particularly if those are funded at the joint venture through the issuance of debt that will reduce our overall cost of capital and allow us to increase our distributions going forward.

Byron Kelley

Yes, one thing I would add to as we were taking about Haynesville is that I mentioned two events related to Petrohawk and Exco increasing their drilling activity. So that, as we look at the ramp up of volumes, I think there’s a good opportunity that even with the ramp up that we’ve got in our model, it is accretive, but I think there is an opportunity here that those volumes are going to ramp up much quicker with the activity that we are seeing.

So, I think that Stephen mentioned that there’s a number of expansion that are being looked at and that all of those are long term expansion. Some of those can be done potentially; one of those can actually be done by the end time the project is placed in service, which will add incremental revenues and margins for us out of that business.

South Texas, Eagle Ford Shale, I’ve touched on that. It’s presenting some tremendous opportunities. We are adding wells down there. We are going to see increased volumes coming out of that area and opportunities there to enhance our margins around that whole South Texas system.

Loaded for expansions; as I mentioned that system is for the Nexus system. There is some tremendous opportunity to do some growth there as well and so we’ve got opportunities in front of us, that do present chance to add incremental revenues to the system. What I would tell you is we talk a lot about the impact of these rigs down and the declines, but those are in our forecast for this year and so if you get a little bit of help on pricing and I think we are beginning to see that, I think there is a good chance that next year can be a pretty good turnaround year.

Lenny Brecken - Brecken Capital

Okay and there is no doubt it’s going to be a pretty good turnaround year in terms of EBITDA, but it would be help full if you can outline all these upside opportunities and maybe give a range of contribution EBITDA, so that we can give a sense of what upside there is in the distribution in the years to come.

I not asking you to make specific projections, but for example on the Haynesville, I think it could potentially if you build that out to your volume expectations, at least the first stage, I think it could add upwards of $40 million in the EBITDA line if I recall and I understand you can get upside if you go to Phase II. So just that kind of think would really help me as an investor down the road, to assist the distribution. Thank you.

Stephen Arata

Just to follow-up, we’ll keep that in mind. To the extent we can share, we will. Obviously some of these things are somewhat competitive sensitive and so there are some things that we are working on, we are really not ready for the lot of details out there about.


Your next question comes from Xin Liu - J.P. Morgan.

Xin Liu - J.P. Morgan

A question in your compression segment; you talked about volume target, can you talk about on the pricing side, what you see and what’s baked in your forecast?

Byron Kelley

I’ll talk about just in sort of general market dynamics. I would say that every segment of every business today is under pricing pressure, whether it’s the compression or not, but the compression sectors obviously has customers on the other hand, just like we are looking for people to reduce prices, they are looking as a customer for us to reduce prices.

One of the things that we’ve been successful in, is working with our customers to make sure they understand the way our model works and that the higher runtimes that we provide customers create value for them. To-date we’ve been pretty successful in maintaining our rates in our compression business.

We did have a little down turn in those rates related to the CPI adjustment that we do annually, tied to the economy, but we continue to try to work with our customers to find multiple solutions around your contracts related to change that compression a ways to help them perhaps save some money about refiguring their system configuration and have been pretty subtle in using that as a way to minimize the impact of pricing pressures.

Xin Liu - J.P. Morgan

Another question regarding the Eagle Ford, do you receive any Eagle Ford volumes in your fashion plant right now and what do you feel is the best quality in that region?

Byron Kelley

No, not in the fashion plant now, but this is what we got.

Xin Liu - J.P. Morgan

Can you comment in generally, what kind of results you’ve seen from private producers? I know you put out the result from the public companies, in that region?

Byron Kelley

Well right now, the impact on our system has been through a public company. It’s been quite successful and this is sort of sweat rich gas that we’re seeing down there. So it’s not going to Fashing plant.

The information that we have from a few other producers in the region, is that their programs are picking up and becoming more active. They are not putting out a lot of public information, but I would say in addition to what we’ve seen from Petrohawk, who has been a big customer of ours, both in compression and on the gathering business and certainly all the way up in Haynesville; is also the biggest customer that we see coming to us out off the Eagle Ford Shale.

Their stuff is, by the addition to them some of the smaller producers are drilling some wells and I would expect that in addition to what we’re going to see out of Petrohawk, that you’re likely to see another well to come on this quarter and next quarter.


Our next question comes from John Edwards - Morgan, Keegan.

John Edwards - Morgan, Keegan

Can you give a little more color on, okay you have some price decreases, is that what was causing the decrease Q-over-Q; I mean from the fourth quarter in compression, because you did have more compression deployed. So, if you could just give a little more color on that. It’s kind of a follow up to Xin’s question on going forward there?

Stephen Arata

I’m sure I understand your question John. Can you repeat that please?

John Edwards - Morgan, Keegan

The compression results, they were down from the fourth quarter. Was that from pricing or was there something else?

Stephen Arata

I am not sure what numbers you’re referring to. We had 11,000 more horsepower deployed and we had 14,000 of adjusted segment margin.

John Edwards - Morgan, Keegan

Yes, but I think in the forth quarter it went through about $40 million. I understand year-over-year you’re up $14,000 million

Stephen Arata

Yes, I think what that’s referring to as Byron mentioned, we had some PPI adjustments on some of our contracts that reduced our revenue. We have an annual contract. This is the first year that’s ever been a negative adjustment, and that flowed through, but as I would mention, the costs have gone down even greater than our margins have gone down. So, we have actually increased our net contribution to the company from the business.

John Edwards - Morgan, Keegan

So, what was the contribution from the negative pricing adjustments?

Stephen Arata

I believe about $2 million on an annualized basis.

John Edwards - Morgan, Keegan

Then if there was only that, my understanding is you’re about $37 million and same amounts as this quarter, but you’re about $40 million in the quarter, so that’s down three, two of which was from the indexing, but you had more compression deployed. Was there something that contributed to the decline there?

Byron Kelley

I think it primarily had to do with some inter segment elimination items John. I’ll be happy to go through this in more detail, if you’d like.

Stephen Arata

I’ll just mention one thing. As we look at the impact of the CPI adjustments, there is some other things that we think through our cost management program are going to be offsets to those going forward; plus the way we buy the Louville parking is one of our compression with one of our big expenses. Those don’t follow WTS so of speak. There’s a time lag and so we’re going to get some benefits from lower cost payer, as we through the next six months as well.


Your next question comes from Helen Rue - Barclays Capital.

Helen Rue - Barclays Capital

First question is related to your O&M expense and G&A. It was up year-over-year and on quarter-over-quarter basis O&M was flat. G&A was up and I think you said it’s because of addition of compression assets.

Just going forward, I would like to share your expectation, whether there’s some room for these expenses to go down given the commodity price. I don’t know how much of O&M cost would be tied to that, but if you could provide some outlook there, I would appreciate it.

Stephen Arata

First of all obviously, when you added much horsepower as we did last year, that there is about $8 million of normal what you would call G&A and O&M, that’s just as a normal increase, just from adding the horsepower, if you take our traditional margin.

Obviously in this environment, CM has been very focused on cost management; has actually reduced the number of employees that they’ve got, recognizing that their growth rate is not going to be strong this year as we’ve seen in the last few years. So, they’ve made a lot of changes around cost management.

Those costs are coming down. We had lower than budgeted; we beat budget in the first quarter related to those costs and we’re expecting to hold onto those types of levels going throughout the rest of the year, in terms of those reduction managements.

Helen Rue - Barclays Capital

So, is the current quarter’s expense a good run rate to use going forward or…?

Byron Kelley

Yes, we are working to hold onto that run rate that’s right in terms of our G&A expenses.

Helen Rue - Barclays Capital

Another question is on your Caterpillar operating lease facility, I guess the size is 75 and you’re planning to use 40 of that. I guess the remaining 35, is that something you could use next year, right?

Stephen Arata

Well, the current agreement allows us up to use to end of this year. We have already been in discussion with Caterpillar to extend that into next year. We haven’t come to an agreement yet, but we would hope that that would be the case.


Your next question comes from Noah Lerner - Hartz Capital.

Noah Lerner - Hartz Capital

Byron I was just wondering if you could give a little more color. You talked about the 2 billion volumes that are expected at the Haynesville in the next year or two. I’m just wondering what you think are the risk of any possible cannibalization on the other basins you are operating; whether it’s East Texas or even South Texas, now the Eagle Ford starting to come online or other North Louisiana assets.

Do you think it’s going to be a case of taking your competitor to get to pull? Where do you think demand will pick up that will increase the desire for natural gas above and beyond what you think the replacement for depletion will be?

Byron Kelley

I would say that I’m not sure there is a cannibalization right now. When you look at the number of rigs that aren’t running, there are plenty of rigs available to drill not only in the Haynesville and Eagle Ford Shale, but also to do some drilling in these other areas.

I think right now what you’ve seen is economics has driven rigs to the Haynesville area and those same economics or close to those economics have driven rigs to the Eagle Ford Shale area, but if we can get some benefit implies and I’m an optimist, so I would like to think, we’re seen a little hope right now with the change we’ve recently seen in top prices.

I will move back up; so there’s plenty of rigs to come back in the market. If pricing is there to encourage people to drill back in places like [Inaudible] or back in some of the other regions. So its price driven at this point and there’s plenty of rigs to go around.

The one thing that I think we made to keep in mind as we look at supply demand balance, people have tend to focus on the fact that in this recession we’ve seen a reduction, some conservation and then certainly a reduction in industrial usage of natural gas.

If we can get a little change in the economy, that’s coming back, it’s not going to rebound immediately, it will start coming back, but the other side of the equation, we don’t hear as much about. What is the impact of reducing our rig count in the United States and have? We think the impact over a twelve month period is probably going to be a loss of deliverability of 10 billion cubic feet to 12 billion cubic feet a day.

While if you look at how much deliverability has been, basically just in time deliverability over last five years, that number has continued to increase and so when you pull a rig well, you get some pretty quick declines and so with that piece in the equation, we’re fairly comfortable that we’re going to see some strengthening in prices.

I’m not taking $11 and $12 prices, but I’ll think to see, annual average prices in the $6 to $7 range for next year, for the full year is not out of the question and I think that you will see some pickup. We won’t go back to 1700 rigs, but I have certainly things that you could see a chance to get us picking up another 200 to 300 rigs and a lot of those will come back in regions that we have assets in.


Your next question comes from [Bob Martin].

Bob Martin – Unidentified Company

I want to ask a question that a lot of the MLPs are kind of reluctant to answer, so I’ll understand if you are too, but how do you stand on your debt metrics like interest coverage ratios or debt-to-EBITDA ratios, compared to your requirement in your debt covenants and I would like the actual numbers for Q1 ’09, along with your projections for full year 2009?

Stephen Arata

This is Stephen Arata. Our EBITDA compliance calculations, we are well within our metrics. Our maximum debt-to-EBITDA ratio is 5.25 times per our credit agreements and we are approximately 4.2 times in that credit agreement. Our EBITDA to interest ratio, the covenant ratio is 2.75, that’s the minimum ratio and we are around again 4.2 times. So, we have significant headroom on both of those measures.

Currently, we expect those measures to get a little bit tighter during the year as we continue to work through the Haynesville construction project. I can’t really give you a specific forecast for the balance of the year, but we expect to remain well within our compliance ratios at any point on the range of our guidance we’ve given the street, 220 to 240 of adjusted EBITDA.

So, we feel really good about that, we work very well with our bank group and we get our amendment over the winter to get the Haynesville joint venture done and we are not particularly concerned about our compliance ratios from our debt group.


Your next question comes from Lenny Brecken - Brecken Capital.

Lenny Brecken - Brecken Capital

Just that it’s sort of a disconnect with the rig count going down, production sort of lagging. Industry wide, when do you see the actual projection pullback and I understand you anticipated that impact in your business. I understand what you forecast that in declines, but is the full impact felt industry wide yet or when do you think that production versus rig count relationship is going to be fully reflective?

Byron Kelley

I will give you an opinion on that, not necessarily fully scientific. I think there are a couple of things that are tempered seeing that decline. We’ve seen some declines, we’ve forecasted declines. I think other people have seen declines on their system, but it’s not really showing up per say in the spot demand balance, between a couple of thing tempered there.

There was in my understanding, a pretty good inventory of wells that had been drilled last year that we’re getting connected earlier this year in the Barnett Shale. So, you had a sort of a backlog, a new connection; that even after drilling rigs would pullout of that area and move to the Haynesville area, if you still had a backlog of connections, that brought additional supply on through the first quarter, and so that was a tempering factor in what’s being going on as well.

Then the other tempering factor is the demand side of the equation and certainly we know with the economy going down. So those two factors together are part of the reasons why I don’t think we’ve seen this work through yet. My view is, I think we’ll start seeing this as we work through the year and that we’ll see some of this start showing up perhaps in the winter months when demand picks up for the winter next year.

Lenny Brecken - Brecken Capital

So, should production hold more than upper single digits and low teens type of thing? Listed companies like yours, a lot of companies are expecting a drop in that range, but the rig count is obviously much greater than that and I’m wondering, is this still risk to management’s forecast, including your own for volume declines; I’m just trying to asses that.

Byron Kelley

Well I mean, I think as an industry, yes. I think we’ve seen some tempering of rig count. The plan we had a couple of weeks there, we have stayed basically flat, then a few more rigs came off. Part of that had two weeks basically flat, but I think its price related and if we can get a little price, we’re going to see rigs comeback.

What we do, when we look at our system in specific, it’s going area-by-area and look at who is doing what and we have obviously the bigger names that are drilling in the Haynesville Shale standout, but we’ve got smaller producers that we’re in contact with, that to the extent they do have prospects and they want to drill and once they’re able to raise capital, even at today’s prices we’re sending them back and drilling some areas; the capital markets are getting better and we’re seeing people get better access to capital.

So, part of this is price driven, part of it is capital driven; that independent produce needs to keep drilling and they’ve got some prospects at today’s prices that they can drill at, but what we do is go back very specific to our regions to come up with our forecast. Could it worse? Yes, things can always get worse.

We think we’re at a point where we’re seeing some positive signs, a little bit stronger gas prices and the capital market open. We think that we’re going to be able to hold onto our forecast and then beginning at the end of this year and early next year, we’re going to see some more active drilling programs back in the year.

Lenny Brecken - Brecken Capital

It seems to me that when demand picks up in the winter season, that’s when the markets going to correct, because it’s not going to be as much added. Is that basically the bet?

Byron Kelley

Absolutely, it’s not just a bet. You got two factors going on there. You got the decline in usage that is offsetting sort of the decline in deliverability sort of speaks, plus that little inventory you had to work off.

When you get into a more active period, where markets are picking up and especially lets just assume the economy starts back up instead of going down, it gets flat to slight growth, that can turn into a lot of gas and that deliverability or lack of ability is certainly going to show up in that period time, because it’s real. The gas just, if you’re not drilling it’s not there.


At this time we are showing no further questions available. Ms. Ming, you may proceed.

Shannon Ming

Thank you for joining our call today. If you have any additional questions feel free to give me a call.


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

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