Regency Energy Partners LP (RGNC) Q4 2009 Earnings Call Transcript March 1, 2010 11:00 AM ET
Shannon Ming – VP, IR and Corporate Finance Support
Byron Kelley – Chairman, President and CEO
Stephen Arata – EVP and CFO
Michael Broom – Wells Fargo
Lenny Brecken – Brecken Capital
Scott Fogelman – Morgan Keegan
Good day ladies and gentlemen and welcome to the Q4 2009 Regency Energy Partners LP earnings conference call. My name is Sallie and I will be your conference operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Ms. Shannon Ming, Vice President of Investor Relations and Corporate Finance Support. Please proceed, ma'am.
Good morning, everyone. Welcome to our fourth 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 press release and slides that we will use today are available on our Web site at www.regencyenergy.com. The first slide is a presentation, describes our use of forward-looking statements and lists some of the risk factors that may affect actual results. Please carefully read this slide. Also included in the presentation today are various non-GAAP measures that have been reconciled back to GAAP or generally accepted accounting principles. These schedules are at the end of the presentation starting on slide 27.
With that, I will turn the call over to Byron Kelley.
Well, thank you, Shannon. Let me say good morning to everybody and welcome you to the call. We appreciate you joining us. It's always our pleasure to have a chance to share with you information related to our performance as well as share with you thoughts about the market in general.
Before we get into the presentation, I would like just to say a brief word about Regency's 2010 Annual Investor Day. The date for this meeting is March 30. It will be held in Dallas. The invitation is available on our website and you will also on that site find details about how RSVP for this event. So please mark your calendars and plan to attend and we look forward to seeing you here in Dallas on March 30.
I'd like you to turn to slide four, the presentation. 2009 was a busy year for Regency. It was driven by several capital raising transactions. It was driven by the exciting activity around our organic growth and by continued progress towards our long-term objective of achieving investment grade metrics.
To put in perspective, I think these many accomplishments that we had had in 2009, I believe it is important to look back and remember the state of the world in January of 2009. Capital markets were in turmoil. Producers were significantly decreasing their drilling programs. Commodity prices were falling and in spite of our assurances, they remain uncertain in the market related to the financing of our Haynesville expansion project and uncertainty in the market regarding our ability to retain our customer base for that project during that period.
So how did all of this unfold over the year? Well, by March of last year, concerns about rigs pipeline project were a non-issue. The joint venture was in place allowing us to raise 650 million in equity capital. Our customers had signed up for over 80% of the capacity of the expansion project and construction was ready to begin.
And just a few months later, we announced an extension of that base project along with an update that, that extension as well as the original expansion were fully subscribed. And subsequent to closing the join venture, we had a successful bond offering at the partnership level in May raising $250 million. We did a preferred equity offering for $80 million in September and another equity offering in December for $230 million of common units.
As I told, we raised $1.2 billion of capital over the course of the year. Drilling activity along with the commodity prices did continue to climb through the third quarter of 2009 and we did see some volume decreases in several regions. But we responded, our team responded aggressively and pursued new Eagle Ford Shale volumes in South Texas, netting a 30% increase in South Texas volumes for the year.
We increased efficiency of our Waha plant in West Texas and identified and pursued several new packages of gas. From 2008 to 2009, we saw a net increase in volumes in West Texas of about 4,000 MMbtu per day or 4%. We did have continued low sulfur prices in 2009, somewhat below what we had expected for the year. There was no rebound in East Texas from a drilling standpoint and low commodity prices in general did not support drilling activity in North Louisiana outside of Haynesville.
Summed up, we were able to maintain gathering and processing volumes basically flat for the year but we did see lower transportation volumes due to low drilling activity in the Terryville field. The impact of lower drilling activity on domestic compression business did proof to be a real threat to the interests in 2009.
Over the course of the year, the industry saw installed horsepower decline somewhere between 12% and 15% on average. So how did Regency’s contract in compression business fare in this environment? While we did have pricing pressures for new contracts that we negotiated; however, these pressures were mitigated as much as possible as David Marrs and his team worked tirelessly to ensure that our customers remembered the value proposition of our high runtime operating model.
His team also began earlier in the year to diligently manage CDM’s internal cost structure. Regional alignment in our contract compression segment allowed to us move strategically -- to more strategically allocate our labor force and then a strong focus on expense management allowed us to support growth in margin. As a result, CDMs revenue generating horsepower was down only 3% in 2009 compared to an industry that saw a 12% to 15% decline.
And we had an increase in EBITDA margins from 45% in 2008 to over 50% in 2009. But even while we were managing this cost, one thing to remember is that no time did we fail to deliver on our high levels of service. So in a year that stress tested service levels in the industry, our business delivered our 98% run time guarantee and we provided our customers better bottomline results.
With more producers understanding our high run time value proposition, our market share has continued to increase and we believe our model will -- may well be the model of choice among many producers and gatherers with growing needs in 2010. So despite the many challenges facing up in 2009, I'm very pleased and believe we had a very good year.
You can see the checklist on slide four which details our major accomplishments for the year. Looking at these, 101 we achieved our adjusted EBITDA guidance range in rating $205 million in adjusted EBITDA with four solid quarters of operating performance for the full year. After getting the joint venture in place, we still need to do execute on a very large capital project.
In January of this year, we announced the completion of the construction on the Haynesville expansion project including the Red River Lateral extension. The project came in underbudget and was the first major pipeline expansion to come online in the prolific Haynesville shale in North Louisiana. In aggregate, these expansions added 1.2 billion per day of capacity to rigs bringing the totals pipeline capacity to approximately 2.1 billion cubic feet per day.
Thirdly, we executed on our growth strategy, completed over $705 million of growth projects in 2009 including the Haynesville joint venture. As I mentioned earlier, we raised -- successfully raised over $1.2 billion in capital to prudently fund our organic growth products.
We strengthen our balance sheet, lowering our debt-to-EBITDA ratio and we improved liquidity by lowering revolver balance from $769 million at year end 2008 to $420 million at year end 2009. We managed commodity exposure limiting our exposure to market volatility and producing stable cash flows.
We increased our adjusted segment margin from our fee-based business to 71% for full year. We instituted comprehensive quarterly rolling hedge program to further limit exposure to commodity price fluctuations and to reduce year-to-year swing impacts from our hedging program. And then of importance to everyone, we maintained our quarterly distributions for the distribution of $0.04 to $0.045 per common unit for each of the four quarters for total of $1.78 per common unit for the full year.
I'd like to now to touch on some highlights related to our Haynesville Shale expansions and invite you to turn to slide five. This initial well reserve from Haynesville became public in early 2008. Drilling activity has continued to increase due to the low-production costs roll rather relative to other producing basins in North America.
There are currently over 3 million acres leased in Haynesville Shale and quarterly cash rates in Haynesville average 14.1 million cubic feet equivalent per day for the fourth quarter of 2009, up 16% from 12.2 million cubic feet equivalent per day average for the third quarter 2009 and up 26% year over year.
Today, we are moving with our Haynesville project in line, incremental volumes of approximately 400 million btu per day. To date, we have spent or committed to spend $787 million of growth capital in this place, $700 million which was related to the pipeline expansions.
In addition, to the expansion, we announced in September, two expansions to our Logansport Gathering System in North Louisiana, further growing Regency's position in one of the country's lowest cost producing basis. A Logansport phase I and phase II expansions will expand our gathering, treating and interconnect facilities to provide additional high value take away options for our customers in North Louisiana.
Basically, there's $87 million of capital for those two projects. We expect the expansion of phase I to be in service in the second quarter with phase II being completed around mid year and then we will start beginning to see volumes ramp up over time. We are well-positioned in the Haynesville Shale based on our presence to continue to expand as this market continues to grow.
We also believe that the presence to the Bossier Shale enhances the economics of Haynesville play and creates potential for additional producer returns based on the projected increase in reserves in the area. As producers began to focus on this opportunity in the next few years, we believe it will create further opportunities for to us expand our asset base.
Moving to slide seven, I'd like to touch on some of the fundamentals around the industry. We first address some of the drilling activity. With depressed energy prices in '09 compared to '08, the rig count for U.S. drilling declined from 2,160 rigs at the end of 2008 to a low of 932 rigs at the end of the second quarter. And then we began to see some rebound in this in the third and fourth quarter.
During the fourth quarter, total U.S. land rig counts increased approximately 17% quarter over quarter ending the year at 1,188 rigs. Perhaps even a more positive indicator for Regency is that the land rig count in the areas in which Regency operates increased for the second consecutive quarter by approximately 18% from 756 rigs at the end of the third quarter to 889 rigs at the end of the fourth quarter.
Also, the historically high crude to gas ratio has increased the relative attractiveness of rich gas plays which have a higher ore component including those in South Texas and West Texas and we are seeing benefit from that change. In the regions, where we operate our gathering assets, rigs increased quarter-over-quarter in West Texas by 53 rigs, North Louisiana East Texas by 26, mid continent by 25 up, all of these are up numbers by the way. Applachian, up 22, Barnett Shale, plus four and South Texas, plus six – seven, excuse me.
In early 2010, indicators point to continued increase in rig counts. And this is really important for us if you look at the counties in which we operate. And for the counties in which we operate, so far this year we have seen a rig count increase of about 31 rigs. We expect total U.S. rig count to level out during this year somewhere between 14, 15 and maybe up to 1500 at the end of the year.
Looking at the more fundamentals on page eight, natural gas finished the year on a high note with cash prices closing at $5.81 just shy of the 2009 high of $6.07 which was set in the 1st week of January and obviously, we know we saw sub $3 prices in the interim. So it did end on a high note. NGL prices outperformed both natural gas and crude for the fourth quarter.
With ethane leading the way with quarter over quarter gain of 40%, with NGLs up between 10% to 16% and ethane at 40% compared to crudes 11% gain, the NGL to crude ratios have now trended back in line with historical levels. The current forward curves for natural gas and crude oil pricing suggest that natural gas will average $5.18 per MMBtu for 2009 -- 2010 and crude should average approximately $79 per barrel for the full year.
I'd like to go back to talk about our businesses and a little bit on our quarter to quarter performance on page -- slide 10. When you look at the numbers, Regency demonstrated consistent financial performance across all four quarters of 2009. Comparing the third quarter of 2009 to the fourth quarter of 2009, our adjusted EBITDA increased slightly from $49 million to $51 million in the fourth quarter.
This increase was principally driven by lower expenses and by Regency's purchase of the additional 5% ownership in the Haynesville joint venture which was completed in September of 2009. Those positives were partially offset by the lower foreign volumes on rigs as I mentioned earlier from the Fayetteville region.
For the full year 2009, we generated $420 million of combined adjusted total segment margin with each of Regency's three businesses contributing steadily over the course of the year. Combined adjusted total segment margin remained flat on 104 million comparing third quarter to fourth quarter.
Additionally, EBITDA and adjusted EBITDA details are outlined in the appendix on slides 27 and 29 and I'll invite to you review those numbers as well. And if you have questions, we can address that during the question-and-answer session. A quick note about our expectations for 2010 and first, we'll provide full guidance at our Investor Day at the end of the month.
But our results in the seconds half of 2009 are generally indicative of what we view as current base EBITDA run rate after factoring in volume declines, commodity prices and hedging impacts. The base EBITDA run rate excludes contributions from growth capital projects, most notably the recent completed rig expansion in the Logansport Gathering projects and then given the estimated construction time associated with these gathering projects in the late January and service day for rigs expansion, we expect normally a partial year contribution from those capital projects.
Moving to slide 11, a little bit about our fee-based portfolio, in 2009, Regency continued to focus on increasing our fee-based assets and our adjusted segment margin derived from fees increased to approximately 71% for the full year 2009. This compares to 64% and 42% for 2008 and 2007 respectively. And as you can see that's, that is really good progress in and continual progress when you begin at 2007 in 42% and you finish 2009 at 71% fee based. And so in 2009, only 2% of our adjusted segment margin was subject to commodity price fluctuations.
Looking forward to 2010, we estimate approximately 5% of the margins will be subject to commodity price fluctuations but we also believe that approximately 74% of our adjusted EBITDA margin in 2010 will be attributable to fee-based business. So moving from 42 in '07 to a projected 74% in 2010, our long-term objective is to move this --continue to move this number up so that we are at 80% of adjusted segment margin derived from fee-based businesses.
Moving to slide 12, a little discussion around our transportation segment. Our combined transportation segment margin accounts for 100% contribution from rigs for the entire quarter. And a combined transportation segment margins and volumes were down on rigs over the course of 2009 due to reduced levels of Cotton Valley drilling and compressed basis differential between East Texas and North Louisiana.
Comparing fourth quarter 2009 to third quarter 2009, our combined transportation segment margin increased to $12 million from $14 million for Q3, 2009. The total throughput decreased from 736,000 of MMBtu in the third quarter to 640,000 in the fourth quarter of 2009.
Adjusted segment margin for MMBtu though, the margin increased by 5% from $0.20 to $0.21 in Q4 and, of course, the throughput has already begun moving up significantly with the completion of the expansion projects with current volumes on the rig system now running over 1 billion cubic feet per day.
Moving on to slide 13, in our gathering and processing segment, our segment margin and volumes remain relatively flat and relatively stable over the course of 2009 despite the very difficult commodity environment we were dealing with. When comparing third quarter to fourth quarter, gathering processing throughputs increased though quarter to quarter with total throughput moving from 982,000 in the third quarter for a little over 1 million or 1 billion cubic feet in the fourth quarter.
Quarter over quarter in 2009, we've seen volumes increase principally due to the Haynesville drilling, which increased volumes in our Logansport gathering system and helped offset some of the declines pouring into our gathering in the Terryville field in North Louisiana.
The ability to take on additional packages in Waha plant also was beneficial as well as coupled with increased activity in Eagle Ford Shale drilling in South Texas. NGL production increased 13.5% quarter over quarter to 25,000 barrels a day in Q4 from 22,000 barrels in Q3 2009.
And this increase was primarily the result of power volumes, rich gas and Eagle Ford Shell and some of the increased volumes we saw in West Texas. The adjusted segment margin for MMBtu decreased quarter to quarter from $0.61 to $0.59 in Q4 2009. This decrease was primarily driven by lower margins on the new packages that we added at Eagle Ford Shale and on Haynesville Shale compared to some longer term contracts that were previously in place.
With the slight volume increase and the slight margin decrease, our adjusted segment margin for the third and fourth quarters basically remained flat at $55 million. One of the things that we have tried to do as we've gone through this year and has been a high focus on volumes is to give you input on a region-by-region basis, so I'd like to do that now and we will move to North Louisiana.
Volumes decreased 6% during the fourth quarter at our Dubach facility driven by, as I mentioned earlier, the decrease in drilling in Terryville fields. Those volumes peaked in Q3 2008 but as producers began ramping up their Haynesville drilling activity, they moved rigs from Terryville fields to Haynesville. The lower than expected volumes were partially offset by higher NGL recoveries at the Dubach plant as well as lower fuel usage.
The Logansport system has continued to do fill up and right now, it is running at full capacity and as you know, we have two construction projects underway, the phase I and phase II projects that ad capacity but that system is now running full in North Louisiana.
For 2010, we are forecasting a 7% increase in volumes for North Louisiana compared to 2009. West Texas region, and this region quarter over quarter, we saw an increase in volumes by 43% from the third quarter of 2009 to the fourth quarter of 2009. I would remind you we were down in the third quarter for some extensive maintenance and foreign upgrade on our Waha plant. But with that upgrade in place, not only did we replace the volumes related to being down for maintenance but we added additional volumes because we had additional capacity.
Favorable ethylene spreads have also made it economical to begin processing of approximately 10 million per day of optional additional keep-whole gas from an interconnected pipeline in the area. Our business development team and regional services teams have continued to pursue opportunities for new supply and we are in the process of securing new gas packages which more than -- which should more than offset the traditional field declines. Overall for West Texas, we are forecasting a 10% increase in volumes for 2010.
Mid-continent area and these comments are going to be excluding FrontStreet, you may remember that our contract with FrontStreet is not volume dependent and so excluding FrontStreet, I'd like to talk about volumes that do impact revenues. And so excluding FrontStreet we would end up approximately 2.5% from the third quarter to the fourth quarter. We have not ceiling a lot of drilling activity here, certainly not enough to offset volume declines.
But although volumes were down slightly, our recoveries have also been above plan and financially these assets actually performed better than expected for the full year 2009. All in all, excluding FrontStreet, we are forecasting the volume decline in the mid-continent area of about 14% for 2010.
Quarter-over-quarter, in the east region, our volumes declined by 6%. Sulfur pricing improved from third quarter to fourth quarter but still had a negative impact on margins against budget. You may remember a year ago, we had -- saw anomaly in the market where we saw sulfur prices well over $650 a long ton. We've seen sulfur prices this year since we have a net impact to a net negative impact to us but the good news is as we stand and that was true in the fourth quarter as well.
The margins were -- the sulfur prices were below what we had forecasted. But as we sit here today, we are pleased to announce the sulfur price is now trading at $80 a long ton which is a positive net to us of about $30 a ton and those prices are more in line with historical levels of sulfur so we are glad to see that recovery.
All in all, for the east region we are forecasting a decline in East Texas volumes for 2010 of about 12%. Moving to South Texas is like Haynesville and West Texas is another area of good news. Volumes around our South Texas gathering and treating system continued to ramp up with the continued drilling of the Eagle Ford shell play while traditional areas continue to see very little activity.
We did add new five new Eagle Ford wells to our system in the fourth quarter of 2009 and we expect a significant increase in drilling activity going forward. For the year in South Texas, even though traditional areas are declining with the activity in the Eagle Ford Shell, we are overall forecasting a net 67% increase in our 2010 volumes in South Texas compared to 2009.
So summing up, all of our regions, when you look at the total G&P [ph] volumes for the year, we believe it will be up approximately 10% compared to 2009. I'd like to now move to our contract compression segment.
On slide 14 and give you an update on that business. In a world of low production levels reduced demands for compression, increased prices and increased pressures on pricing, I really believe in that ugly word, our 2009 performance really demonstrated the strength of our business relationships and of our business models that focuses on enhancing customers’ bottomline.
Despite a 46% decline in U.S. onshore gas rig count since October of 2008, Regency's overall generating horsepower has remained relatively flat over the same period. Quarter over quarter, revenue generating horsepower from the third quarter to the fourth quarter actually increased from 743,000 to 753,000.
Our segment margin quarter-over-quarter remained flat at $43 million for both third quarter and fourth quarter. And quarter-over-quarter, our average horsepower revenue – our average horsepower per revenue generated compression unit increased from 836 in the third quarter to 849 in the fourth quarter of 2009 and this is a ratio that remains significantly higher than our peers in the contract compression business.
The management team at CDM worked diligently to the maintain margins through aggressive cost management practice and it realized significant savings in the number of areas. Commodity driven price release on lube oil and fuel have resulted in savings throughout the year of approximately $2.1 million.
Operating less horsepower than we had budgeted resulted in expense savings of $8.8 million and this is the key as where we had aggressive expense management resulted in additional savings of $7.7 million. What I'd like to point out that even with those aggressive cost management efforts which reduced expenses, Regency's contract compression business maintained approximately 99% plus runtime average for the year. That's an important indicator of us maintaining our service to our customers and helping them create value for themselves.
And lastly, I'm pleased to note that in January, we placed in operation our first units in the Marcellus Shale. Initial unit placement was for approximately 2700-horsepower and these units are in operation as we speak. We have another 4,000 horsepower that's under contract that is scheduled to be in service in May and beyond those two, we signed letters of intent for an additional 6200 horsepower. And one step further, we have quotes out for several large packages totaling approximately 30,000 horsepower.
And when we looked to the future, we are in discussion with potential customer for multiples of those numbers and we believe this market represents an attractive growth opportunity for Regency over the next few years. And beyond Marcellus, we are also evaluating opportunity to capture compression growth in Eagle Ford Shale, Terryville shale and several other drilling areas, where we have identified some very niche opportunities.
So wrapping that up, we are pleased with our performance for the year and with the way that our business has reacted to a market that had some very ugly dynamics at the beginning of the year. We think, we believe our teams have reacted very favorably and very aggressively to the addressing those issues and I'll just take this time to say thanks for all of our team for the great work they did in 2009.
With that, I'm going to turn this over to Stephen and will he move through some of the financial sections.
Thanks, Byron. Turn to page 16, we show our consolidated operating results on a quarterly basis for 2009. For the three months ended December 31, we had a net loss of $3 million which compared to a net loss of $11 million for the third quarter of 2009. The decrease in the fourth quarter in our net income loss was primarily due to the assets of the non-cash value change of approximately $14 million in the third quarter which was associated with long-term derivatives embedded within our convertible, redeemable preferred units which we issued in September.
We continue to see excellent results in the area of cost control during the year with our combined O&M and G&A costs down over 2% from Q3 to Q4 and down a full 8% from the fourth quarter of 2008.
Turning to page 17, we show some commodity price risk management information. In 2009, as we've told you before, we’ve instituted a quarterly rolling hedge program as a way to continuing to minimize our exposure to commodity prices and to stabilize our cash flows.
In the fourth quarter, we executed the balance of our 2010 hedges which leaves us for full year 2010 hedged at 80% of our NGL equity links and 84% for our condensate equity links and at 85% for our natural gas linked and all of those are executed through product specific swaps.
On page 18, we have some additional information on our 2010 and ‘11 hedging program. We currently hedged 34% of our NGL links in 2011, 42% of condensate and 27% of natural gas. We expect to execute additional hedges to the balance of the first quarter of this year to bring our 2011 total hedge percentages by the end of this quarter to approximately 55% for both NGLs and condensate.
Over the balance of this year, we anticipate entering into additional hedges to hedge approximately 85% of NGL and condensate exposure and 75% of natural gas exposure for 2011. We will also begun our 2012 hedging by the middle of this year. On page 19, we have some sensitivity information on commodity prices.
As we've noted before we have, we do have links in natural gas. We do a conservative effort to minimize our keep-whole contracts as well as the contractual gasolines that we have from our percentage of proceeds contract. The table shows the $10 per barrel movement in crude along with the same percentage change in NGL pricing will result in a 2.5 million change in our full year distributable cash.
One dollar per MMBtu movement in natural gas pricing will result in a half million dollars change in our full year distributable cash. On page 20, we provided a liquidity update. 2009 as Byron has mentioned, we successfully executed our growth strategy to opportunistically accessing the capital markets to prudently fund our accretive growth projects using both debt and equity.
At year end 2009, the total availability under our revolving credit facility was $453 million. For full year '09, we strengthened our balance sheet by raising over $1.2 billion of capital including our fourth quarter equity issuance. On December 2, we successfully priced an upsized public offering, it is just over 12 million common units which included our overallotment option at $19.12 raising total gross proceeds of $230 million.
Byron also mentioned our fourth quarter '09 distribution was in line with our expectations of $44.5 per unit or $1.78 per common unit for the full year. In the fourth quarter, we generated $28 million in cash available for distribution representing a coverage ratio of 0.65 times. For the full year 2009, our coverage ratio was 0.87 times and I would note that for the full year '09, excluding the units we issued in December, our common -- sorry, our coverage ratio would have been 0.90 times for the full year.
As discussed over the past couple of quarters, we have anticipated a drop below one times coverage during the construction of our Haynesville expansion project and as volume ramped up on rigs during the course of this year, we anticipate our coverage ratio will increase substantially. As a reminder, our distribution is set quarterly by our board and is driven by the long-term sustainability of the business as well as the available cash flows.
In 2009, we expanded our business to approximately $150 million of organic growth projects. Excluding the original Haynesville expansion project which was funded by our partners and accounting for only Regency's pro rata portion of spending related to the Red River Lateral expansion of the Haynesville joint venture. Specifically, we spent $87 million on fabrication of new compression packages for our contract compression segment.
We spent $49 million on the gathering processing segment, primarily in North Louisiana and South Texas and we spent $14 million on the transport segment related to our share of expenditures for the Haynesville joint venture related to the Red River Lateral. I'll also note that we let our Caterpillar operating lease facility expire at the end of 2009.
It has provided the liquidity cushion during the past year but with our demonstrated access to the capital markets in 2009 and no need to purchase additional compression during 2010, we did not extend that facility.
On page 21, we show our capital spending plans for 2010. Our anticipated 2010 organic growth capital expenditures of $167 million, include $137 million related to gathering and processing, of which $77 million relates to previously approved Haynesville projects in our gathering and processing and transport segments, $14 million related to contract compression, $8 million related to corporate and others and then $8 million related to the Haynesville joint venture which represents our 43% proportionate share.
Given the current capital structure at the joint venture, we do anticipate that any significant growth in the joint venture will likely be funded through debt at the joint venture. We believe our balance sheet is strong and that we are well-positioned to meet all of our growth capital plans for 2010 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 and identify the attractive growth projects. With that, I would like to open it up for Q&A.
(Operator Instructions) Your first question comes from the line of Michael Broom with Wells Fargo. Please proceed.
Michael Broom – Wells Fargo
Thanks, good morning.
Good morning, Mike.
Good morning, Mike.
Michael Broom – Wells Fargo
Just a couple of questions around the growth CapEx, I think, Byron, you mentioned that you thought you’d see more future opportunities, more opportunities in the Haynesville. Do you think those would be more in the gathering side and outside the JV or do you think the expansion of the pipeline is possible within the JV or both?
Well, actually we both quite frankly, the JV is interested in expansion and we have some discussion underway that could lead to another expansion on that pipe. That is something that we’ll probably know quite a bit more about over the course of the next two months. But so the JV is looking to expand, then outside the JV there's still part of that it needs to be done in the treating and gathering side of the business in Haynesville. And then one of the things, we will not talk about much about Haynesville though if you look out a few years, they are going to start having some needs for compression as well. And so we are pursuing all of those avenues from both sides of the business.
Michael Broom – Wells Fargo
Okay. And then just a followup on that, is there any way to quantify in dollar terms what you think the gathering side or pipe side should mean an incremental dollars spend and then what do you think is the likelihood in 2009 that you do in fact increase your capital budget to the year as you identify projects. Thanks.
Actually I will really defer any discussion related to capital beyond 2010 until the meeting on the 30th where we will talk a little bit more about the future. So -- but I'll tell you there are sizable opportunities out there and we are doing -- pursuing those and we will certainly anticipate spending, having an opportunity to spend some sizeable amount of capital post 2010. We will talk more about that on March 30.
Michael Broom – Wells Fargo
Okay. Thank you.
(Operator Instructions). Your next question come from the line of Lenny Brecken. Please proceed.
Lenny Brecken – Brecken Capital
Hi, guys. Can I ask a question about the coverage ratio since we are starting at pretty much a low point as you pointed out during your discussion. When do you think that coverage ratio will be reaching one? Is it this quarter or next quarter?
Thanks, Lenny, this is Stephen. I think the 0.65, we didn't give the specific number but in the fourth quarter around what it would have been without the equity issuance, I would note that because we issued it in December, we ended up having to pay distributions and interest on the debt that we paid off from pretty much the full quarter. That number would have been closer to 0.8 for the fourth quarter if we had adjusted for those items.
The pipeline obviously started flowing and we started billing our customers for the reservation charges on the expansion starting February 1. So we are not going to have a full contribution during the first quarter. So, I would not expect it to be above one in the first quarter but we expect sometime shortly after the first quarter for it to be above one.
Lenny Brecken – Brecken Capital
Okay. Just one last question. On the natural gas prices, where do you think the cost basis in the Haynesville area is in terms of a minimum amount of price that natural gas has reached its effect volumes?
It's hard to tell because each producer has a little different situation. We do know that with the possible exception of the Marcellus, it is the lowest of any basin in the U.S. and various producers have put it at $4 and some have put it lower than that. But I would really defer to the producers but we clearly think that last year, it demonstrated low prices, have not had rigs for moving to that area and we continue to see our producers adding rig count for 2010.
Lenny Brecken – Brecken Capital
One last question, in terms to the switch to natural gas, I started to notice that that has started. Can you just describe that how you see that as affecting demand for natural gas or price?
Can you repeat the question, Lenny? I'm not sure I caught it.
Lenny Brecken – Brecken Capital
Sure. It's relating to the switch from for utilities actually from other energy sources to natural gas. I started to see that show up in the numbers in terms of the overall industry. Can you just describe how you see that playing a role in demand for natural gas and or price.
Well, I think during 2009 we clearly saw some cold gas switching primarily because gas was so inexpensive but we saw it drop below $3. I think we continue to see a long-term trend of incremental capacity being provided by gas but I think in all likelihood 2010, we’ll see a reduction in electricity generation from gas given that -- if the forward curve stays where they are, you don't see as much coal to gas switching this year.
Lenny Brecken – Brecken Capital
Okay. Thank you.
(Operator Instructions) Your next question comes from the line of Scott Fogelman with Morgan Keegan. Please proceed
Scott Fogelman – Morgan Keegan
Hi, guys. Just a couple quick questions. Have you given any EBITDA guidance for 2010?
No, we haven't. We'll do that at our March 30 meeting.
Scott Fogelman – Morgan Keegan
Okay. Regarding compression, just if you could expand on when you have contracts, are they generally for a year, two years, three years in the compression segment? How does that break down?
Most of our contracts are three to five years and obviously since the billing, they are not all in one year so you got a roll off to each year of a certain portion of the contracts that you have to renegotiate and replace contractually in the portion of portfolio but on average three to five years.
The group has been actually quite good in managing to rollover their contracts. We have got an excellent customer retainage history and overall this business has really been growing quite significantly. If you look at the market from 2004 through 2009, the market add about 1.2 million of horsepower in the lease and compression services and out of that we added 7,574,000, about 45% of the growth, we captured since in the last five years of this market.
We've gone from about 3.7% of the market to a little bit under 7% of the U.S. domestic market.
Scott Fogelman – Morgan Keegan
Okay. When you have to re-up [ph] your customers what sort of concessions are you making if any.
Last year there was tremendous pressure on everybody in the industry for some pricing concessions and we didn't escape fully on that. But our indications from what we've seen is the concessions we made were substantially less than what was made in the rest of the industry. A lot of that driven by as I mentioned earlier in my comments our run time models is that nobody delivers kind of runtime we do and so we are able to use that and our customers understand the value of that run time. So we didn't escape 100% on pressures. We offset that really with some reduced reduction in costs and our margins for the year were actually stronger than they were the year before.
Scott Fogelman – Morgan Keegan
Okay. Appreciate it.
There are no more questions at this time. Ms. Ming, you may proceed.
Thank you for taking the time to join us today. We look forward to seeing everyone at the Investor Day on March 30 at the Crescent Hotel in Dallas. If you have any additional questions, please feel free to give me a call. Thank you.
Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect and have a great day.
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