Good morning ladies and gentlemen. Thank you for standing by. Welcome to the Copano Energy's first quarter earnings conference call. During today’s presentation all parties will be in listen-only mode. Following the presentation the conference will be open for question. (Operator Instructions) This conference is being recorded today Friday May 7th 2010. I would now like to turn the conference to Mr. Dough Lawing, Executive Vice President and General Counsel, please go ahead sir.
Thank you and good morning. We appreciate you joining us for Capano Energy's conference call to review financial and operating results for the first quarter of 2010. If you would like to be on our email distribution list to receive future news releases, please call our Investor firm DRG&E. Their number is 713-529-6600. A replay of this call will available later this morning. Access details are provided in the news release. please note that information recorded on this call speaks only as of today May 7th 2010. Therefore time-sensitive information may no longer be accurate as of the date of any replay. Our discussion today will include forward-looking statements that are based on management’s belief as well as in certain assumptions based on the experience and perception of the historical trends, current conditions and expected future developments.
Although the company believes that the expectations reflected in such forward-looking statements are reasonable, actual results may vary materially. Actual results are subject to a number of risks and uncertainties which are discussed in the company’s annual and quarterly reports filed with the Securities and Exchange Commission. Please note on this call, we will use the terms gross margin, EBITDA, adjusted EBITDA and total distributable cash flow. These are non GAAP financial measures and we have provided reconciliations to comparable GAAP measures in our news release. In addition the reconciliation of adjusted EBITDA to net income for our operating segments can be found in the Investor Relations page of Copano's website under events.
Bruce Northcutt, Copano’s President and Chief Executive Officer will begin today’s call by reviewing operating highlights for the first quarter of 2010, our outlook for the second quarter and the progress of our growth initiatives. Carl Luna, our Senior Vice President and Chief Financial Officer will then provide details on our financial results.
Bruce will then ramp up our formal presentations and then, we’ll take your questions. With that, I will now turn the call over to Bruce.
Thanks Dough and good morning everyone. I'm pleased with the progress we’re making on our various growth initiatives. Over the last several quarters, we’ve invested in expansion projects in areas that are seeing oil and rich gas directed drilling activities specifically the Barnett Shale Combo Play located in North Texas and the Eagle Ford Shale Play located in South Texas. And we’re now beginning to see volume increases in those areas. These projects and others that we are currently working on will have rates of return in excess of our cost of capital and will create additional value for Copano and its unitholders as they come online.
Our distribution coverage ratio fell to 81% for the first quarter. This is temporary and reflects the equity we issued in March to fund our growth plans, the conversion of our Class D unit as well as the planned six day shutdown of our Houston Central Plant which was necessary to complete the work acquired to start our fractionation facilities.
We expect coverage to significantly improve during 2010 given our growth outlook particularly the opportunities in Texas. Before discussing these opportunities and the progress we are making in further detail, let me quickly review the operating highlights for each of our business segments. In Oklahoma, our service throughput averaged 248,784 MMBtu per day for the first quarter of 2010, which was down 8% versus a year ago and flat from the prior quarter. We expect second quarter volumes to be slightly up versus the first quarter of 2010.
NGL production in Oklahoma in the first quarter averaged 15,334 barrels per day, which was flat versus a year ago and down about 5% from the fourth quarter. Although service throughput volumes were flat compared to the fourth quarter of 2009, plant inlet volumes were down 5% in part due to freeze-offs. We anticipate an increase in NGL production for the second quarter. Gross margin for the Oklahoma operating segment was $24.3 million for the first quarter which is an increase of 70% from a year ago and a decrease of 9% versus the fourth quarter of 2009.
The year-over-year increase was due to an 84% increase in NGL prices and a 55% increase in natural gas prices. Segment gross margin decreased compared to the fourth quarter due to lower NGL volumes primarily as a result of freeze-offs and also due to a partial outage of a third-party downstream NGL pipeline. Despite anticipated volume growth we expect the second quarter gross margin to be lower than the first quarter primarily due to a decrease in commodity prices.
14 rigs we’re drilling in our service areas in Oklahoma in the first quarter, nine were working in rich gas areas and five were working in the Woodford Shale. In addition we placed our 10 million cubic foot a day Burbank processing plant service in mid-April. The plant inlet has averaged about 4 million a day since first start up and we expect drilling behind the plant to continue.
Moving on to our Texas operating segment. service throughput volumes averaged 5,82,958 MMBtu per day for the first quarter of 2010 which was down about 10% compared to a year ago but up 1% versus the fourth quarter. During the quarter we had volume increases on our upper Gulf Coast, Karnes and Live Oak gathering systems. Our upper Gulf Coast system volume increases were attributable to a new interconnect that went into service during the fourth quarter.
While volume increases on Karnes and Live Oak were primarily a result of Eagle Ford Shale well connects. We expect further volume increases in the second quarter from additional Eagle Ford wells as they are connected to our systems. I will discuss our activity in that play in more detail in just a moment. Texas NGL production averaged 15,339 barrels per day in the first quarter which was down 9% versus a year ago and down 16% from the fourth quarter. The lower NGL production resulted from lower plant inlet volumes from third party pipeline.
And our Central Gulf Coast gathering system as well as the Houston Central plant Shutdown we mentioned earlier. In the fourth quarter of 2009 we processed and averaged 13 million cubic feet a day at our Lake Charles processing plant and recovered 1,134 barrels a day as opposed to the first quarter when the plant did not run. With the startup of our fractionation facilities, we began delivering purity propane to market during the second half of April and purity ethane deliveries began in early May. Gross margin for Texas was $27.2 million for the first quarter, up 32% from a year ago and down 17% from the fourth quarter. The year-over-year increase was primarily as a result of Mt. Belvieu NGL prices increasing by 85%. But sequentially our first quarter margin declined due to the temporary shutdown of our Houston Central Plant and also due to a reduction of lower margin volumes from a third party pipeline. We anticipate second quarter gross margin to be higher due to additional revenue from our fractionation facilities and an increase in volumes from the Eagle Ford Shale and the Barnett Shale Combo Play.
Looking quickly at the Rocky segment, on a combined basis throughput volumes for Bighorn and Fort Union averaged 931,319 MMBtu per day in the first quarter which was down 7.4% from a year ago and down 3.5% from the fourth quarter. Both systems were impacted by declining volumes, but Fort Union was also impacted by downstream maintenance on Wyoming Interstate. Our Rocky Mountains operating segment contributed $7.7 million to adjusted EBITDA for the first quarter. For 2010, we continue to expect adjusted EBITDA to be relatively flat compared to 2009. Although CIG pipeline process averaged $5.14 per MMBtu during the first quarter, they decreased to under $4 per MMBtu for April and May which based on producer feedback is not currently sufficient to spur a significant new drilling.
Looking at our expectations for the second quarter from a pricing standpoint, both natural gas and NGO prices are off their January highs in the Mid-Continent and the Gulf Coast. We also saw the spread between Mt. Belvieu and Conway NGL prices widened again in the second quarter from $0.07 per gallon average for the first quarter to $0.11 per gallon for April. Reports indicate that several Midwest steam crackers are down for turnaround and Conway product normally sent to the Midwest is constrained by pipeline capacities to the Gulf Coast.
Current forward pricing for NGLs indicates the market’s expectations that the bases will tighten during the summer as these steam crackers resume using normal operations. Operationally we have several initiatives underway that will add to the top and bottom lines before the end of this year. We currently projected that 50 million cubic feet a day of compression capacity were adding at our Saint Jo processing plant located in North Texas will be in service by early fourth quarter, two months ahead of schedule. The timing of this expansion is key to our volume growth expectations in this area. During the quarter, we gathered an average of 21 million cubic feet a day in this area.
In April we averaged approximately 37 million cubic feet a day as we began to see increased volumes from our largest producer who currently has nine rigs drilling in this area. Current spot volumes are averaging about 38 million cubic feet a day and we expect the growth to continue as the same producer expects to add three additional rigs to this area this year and possibly an additional four rigs next year. Based on producer projections we expect to be at 50 million cubic feet a day by September of this year and a 100 million cubic feet a day by early 2011.
We now expect our North Texas assets to contribute $30 million to $35 million in fee-based cash flow on an annualized basis by the end of 2010 and growing in 2011 which is a $5 million higher than our previous estimate. And we continue to be very encouraged by the opportunities we see in the Eagle Ford shale. Like the Barnett Shale Combo Play, the rig count continues to grow as more and more producers are focusing their drilling on oil and rich gas areas. To-date we have connected six Eagle Ford shale wells with the combined IP rate of about 40 million cubic feet a day with significant associated condensate.
Several of these wells are connected to our certainly announced DeWitt-Karnes Header which we continue to build out. This header will consist of 38 miles of 24 inch pipelines stretching through the heart of this condensate window of the Eagle Ford Shale and DeWitt and Karnes counties. We are building this in sections as drilling dictates and expect completion of the line by August 1. This project will substantially increase our capability to bring rich gas to our Houston Central Complex for processing and fractionation giving our producers needed access to downstream natural gas in NGL markets. In an area south to DeWitt-Karnes, we just executed a 35,000 acre long-term dedication with the major producer of Eagle Ford Shale gas behind our Live Oak gas gathering system. The gas we gather from this area will be delivered to the Kinder Morgan System and re-delivered to Houston Central for processing and fractionation.
In addition, we are close to finalizing our joint venture agreements with Kinder Morgan for the western portion of the Eagle Ford Shale. Once executed, the joint venture members will be in a better position to provide much needed access to gathering, transportation, processing, fractionation and downstream markets for both natural gas and NGL products.
While our negotiations have continued longer than anticipated, both companies with commercial themes have been busy continuing to pursue producers in this area. As I’ve said in the past, the startup of our fractionator, The Houston Central plant are the key ingredient of our strategy for pursuing initiatives in the Eagle Ford Shale. This project brings online 22,000 barrel a day of fractionation capacity at a time when fractionation capacity remains scarce. Our fractionation capacity will be an important growth driver for Copano’s operations in South Texas, allowing us to move away from paying others to transport and fractionate NGLs to being paid to provide this services directly.
This project cost approximately $17 million and we continue to expect it to generate about $8 million to $10 million annually in fee-based cash flow, at current throughput volume. We are currently evaluating a possible expansion of this facility or additional access to third-party fractionation as NGL production gross. Next I will ask Carl to review our financial results.
Thanks Bruce. I will review the first quarter financial results as well as our outlook for the remainder of 2010 and then update you on our hedging activity to current liquidity position and our capital expenditure plan. As we reported yesterday afternoon, we had a net loss of $1.3 million or $0.02 per unit on a diluted basis for the first quarter which compares with net income of $5.9 million or $0.10 per unit on a dilutive basis for the first quarter of 2009. As further detailed in our press release, the primary drivers of the decrease in net income versus the first quarter of 2009 included a decrease of $3.9 million in gain related to the repurchase and retirement of senior notes and $2.1 million increase in depreciation and amortization expense related to our expanded North Texas operations and the retirement of the certain assets in Oklahoma. Adjusted EBITDA for the first quarter declined 12% from the year ago to $35.7 million for the first quarter of 2010.
non cash charges incurred during the quarter that were not added back in determining adjusted EBITDA include amortization expense of $8 million related to the option component of our risk management portfolio. Total segment gross margin was $51.1 million for the first quarter which is down about $650,000 from a year ago. Bruce already covered our three operating segment gross margin in details. So I now will review gross margin for corporate and other which reflect the results of our hedging program. First I think it's important to point out that during the first quarter of 2010 gross margin from our operating segment was up $16.8 million from a year ago, while other corporate and other gross margin was down $17.5 million over the same period reflecting an improved commodity price environment and less reliant on our hedging program to support our segment gross margin. Specifically, our corporate and other segment produced a loss of $1.4 million in the first quarter of 2010 versus a gain of $16.1 million for the first quarter a year ago.
The $1.4 million loss includes $8 million of non cash amortization expense previously mentioned. $400,000 of unrealized mark-to-market losses and offset by $7 million of cash settlements received during the quarter. Revenue for the first quarter increased 33% versus a year ago to $266.7 million. This increase reflects the impact of higher revenue from our operating segment partly offset by lower revenue from our hedging portfolio both due to increased commodity prices. Total distributable cash flow was $30.9 million for the first quarter of 2010 versus $35.1 million a year ago. If you exclude the effect of the $3.9 million gain on the retirement of debt in the first quarter of 2009, distributable cash flow would have been roughly flat year-over-year.
As Bruce mentioned distribution coverage was below a 100% for the first quarter. This was expected and we anticipate coverage to improve significantly during the balance of the year. It’s worth noting that since our IPO in 2004 Copano has generated total distributable cash flow coverage in excess of 150%. That being said we remain committed to growing our business, our distributable cash flow per unit and our distribution coverage while at the same time maintaining the strength of our liquidity and balance sheet.
As we continue to execute on our business strategy you will see higher and more stable distribution coverage which we expect to lead to further distribution increases. Now to our expenses. G&A expense was $10.5 million for the quarter, down 1.7% from a year ago. We continue to expect full year 2010 G&A to be in the $40 million to $43 million range. Operations and maintenance expense was $12.1 million for the first quarter, down 4.5% from a year ago. We are reviving our O&M guidance for the full year 2010. We now expect O&M expense for the year to be in the $52 million to $55 million range. This is down from our previous expected range of $54 million to $58 million. Interest expenses was $14.9 million for the first quarter and essentially flat compared to the first quarter last year.
Given our lower debt level of after paying down a revolver with the proceeds from our March equity offering, we now expect interest expense to be in the range of $60 to 62 million for the full year, excluding any unrealized gains and losses on interest rate swaps. This is a slight decrease from our previous stated range of $61 to 64 million. In terms of our hedging activities, our hedge portfolio contributed $7 million in cash settlements during the first quarter of 2010. Although significantly less than we realized on our hedges in the first quarter last, this decline is offset by increased revenue from our operating segments as NGL and crude practice have improved. Our 2010 hedge positions have not changed from our last call and are detailed in our public filings with the SEC. We continue to expect a non-cash amortization expense related to the option component of our existing hedge portfolio to be in the range of $32 million to $34 million for the full year 2010. So far, this year we have added ethane inputs for calendar year 2011 with a cost of approximately $700,000 and ethane, propane, isobutane, normal butane and WTI puts for calendar year 2012 with a net cost of approximately $10.1 million.
We will continue to add to our 2012 portfolio as market opportunities arrived. Our first quarter 10-Q will provide more detail on our hedging portfolio. Turning to liquidity in the balance sheet. in March 2010, we issued 7,446,250 common units at a offering price of $23.10 per unit. We used the net proceeds from the offering to repay a portion of our outstanding borrowings on our revolver and plan to use our additional borrowing capacity to fund our near-term growth capital projects.
At March 31st, we had $54.1 million of cash on our balance sheet, after the paydown of our revolver, we had $135 million borrowed under our $550 million credit facility at quarter end. Due to our debt covenant limitations we currently have available borrowing capacity of $247 million, when combined with our cash balance this gives us total liquidity in excess of $300 million. At March 31st, 2010 our ratio of total debt to trailing 12 months EBITDA as defined in our bank agreement was approximately 3.7 times versus a maximum covenant level of five times. Our interest coverage ratio for the same period was 3.5 times compared to a minimum covenant level of 2.5 times.
Finally turning to capital expenditures; expansion capital expenditures for the first quarter of 2010 totaled $20.4 million, the majority of this spending was related to the construction of gathering lines upstream of our Saint Jo plant in North Texas, right away acquisition and construction of the DeWitt-Karnes Header in South Texas and the completion and startup of our fractionation facilities at our Houston Central complex.
For now our board approved expansion capital budget remains at a $130 million and we continue to expect this capital to be invested at approximately five times cash flow multiple. However capital spending particularly in Texas has been brisk so far this year and the number of new opportunities we are seeing has increased since year end. I anticipate that our expansion capital plans will grow as we begin to execute on these new opportunities. Bruce and I will continue to update you on new developments.
The full year 2010, we continue to expect maintenance CapEx to be in the range of $10 million to $12 million. Additional details on our financials, including financial tables maybe found in our press release we issued yesterday. Now I will turn the call back over to Bruce.
Thank you, Carl. As I covered with you last quarter a key tenet of our strategy will be to continue to execute on organic growth opportunities around our existing operating areas. At the same time we will continue to extract additional value from our existing assets as demonstrated by the startup of our fractionator at Houston central. There are several exciting initiatives that we are currently evaluated. These include projects such as professing expansions, fractionation expansion, organic pipeline projects as well as acquisition opportunities. Several of these projects are associated with development in Eagle Ford Shale in combination with our Houston Central Complex, but also include opportunities in the Barnett Shale Combo Play and in Oklahoma.
Before we take your questions I wanted to quickly introduce and welcome Jim Wade who joined us as President and Chief Operating Officer of the Texas operating segment and at early April. Jim has significant experience in business development, gas and NGL supply and marketing. And we want to welcome him, and one additional management change worth noting John Raber who many of you know was President and Chief Operating Officer of our Rocky Mountains Subsidiaries has transitioned into a new role working with other senior officers on corporate strategy and development.
As a result Sharon Robinson, our current President, Chief Operating Officer of our Oklahoma segment will assume John’s responsibilities for the Rockies. We continue to conduct a search for Vice President of Corporate Development as well. This concludes our formal presentation. Operator will you please open the call for questions.
(Operator Instructions). And our first question is from the line of Michael Bloom with Wells Fargo.
Michael Bloom - Wells Fargo
You talked that you're evaluating acquisitions. Can you give us a little more detail in terms of these smaller sized deals, bigger ones or these bolt-ons to your current operations, just a little more flavor?
Actually I would have to say that more recently we are seeing, I wouldn’t call it a flurry, but we seeing several more opportunities that have come on the radar. Some of them are in the vicinity of assets where we currently operate. There would be slight step-outs from where we are but there are a couple that would be in new areas that we currently are not operating.
Michael Bloom - Wells Fargo
Maybe just also can you talk about where multiples are?
Not really, not at this time. I mean we have seen a couple of deals out there that had extremely high multiples. I think it depends on the asset. Obviously the smaller ones we would think that the multiples would be much lower in historically.
Michael Bloom - Wells Fargo
My second question was just around the Rockies. I think you said that, based on the prices, producers are not going to ramp up drilling there so I interpret that to mean that volumes could continue to decline and is that correct and then I think you also said that you thought EBITDA could be flat so just trying to reconcile all that.
At least behind Fort Union there should be pickup in drilling for annual drilling quotas up in that area from some of the larger producers there. Behind Big Horn we have seen a little bit of M&A activity between E&P companies behind there. Usually that’s a signal that’s some thing is likely to occur but keep in mind also that we have got some wells that have been drilled up there but not de-watered. I guess my point in my comments are, I just don’t see a significant increase in drilling up there right now. Also, Michael I want to go back to your last comment with respect to the acquisition. Beyond acquisitions there is also a fair amount of organic opportunities and those also exist around our existing assets but in new areas as well. So, I just wanted to recap that.
Thank you and your next question is from the line of John Edward with Morgan, Keegan.
John Edward - Morgan, Keegan
You mentioned that you've put puts on costing $10 million I guess for 2012 and about what percentage are you hedged now?
Depending on the product John in certain products it's about 20% for 12 and in other products it kind of ramps up to 50%. So it's kind of I haven’t done the weighted average of this because I don’t look at it in total, I look at it by products, so it's 20% to 50%, the higher percentages on the heavier products because those prices have been at higher levels here recently.
John Edward - Morgan, Keegan
And where do you stand now for 2011?
For 2011 it hasn’t changed much since our last call and it's in that kind of 60% to 80% range depending on the product.
John Edward - Morgan, Keegan
All right and then you mentioned your G&A and O&M guidance are coming down and what's driving that?
Cost cutting measures, as a matter a year and half ago we had several meetings to discuss how do we continue to drive down O&M and G&A costs and our team has done a phenomenal job doing that without risking things like safety, that’s one that’s been paramount too as we didn’t want to cut back there. So I attribute that to our great employees who are doing a good job of keeping cost down.
We didn’t revise our guidance on G&A downwards just on O&M.
John Edward - Morgan, Keegan
Just on the CapEx I missed what you were saying. I think you said 130 for the year on growth CapEx. Is that still right?
That’s what our Board approved plans are – at this point and I said that’s still the case but we’re seeing activity and it’s highly likely that will increase like somewhat many of the things that Bruce was talking about or had talked about.
Thank you. And our next question is from the line of David Fleischer with Chickasaw Capital Management.
David Fleischer - Chickasaw Capital Management
I like the math, loved working the math on the returns of this fractionation capacity addition here and you mentioned that you were looking at further expansions of that or of the capacity. Can you tell me what the timeframe for that might be is the first question? And then could you secondly, give us updates on what the volumetric commitments might be now at Karnes DeWitt?
Sure. With respect to the first part of your question which was the timing of maybe the fractionation expansion. Obviously, it will be producer drive. Right now David, last time I looked we got maybe just shy 60 rigs running in the Eagle Ford Shale, projections that I have seen lately they think that it may go by this time next year upto about to 100 rigs running in the play. All of that gas and liquid has got to find the home obviously and with fractionation capacity at a premium. We do have spare capacity right now, upon the start of the fractionator.
So that will be the first to fill first, but we are probably more at 14 months lead time if we kicked off the actual expansion in order to get in place so that would be the lead time that we would need before we would need to meet the producers expectations. Having said that a fair number of producers that we are talking to not just at Copano or behind, some of wholly owned systems like the DeWitt-Karnes Header, but also behind the joint venture that we are working with Kinder Morgan on.
A lot of it will depend on when they make those commitments, but I will tell you this there's been some recent announcements of large deals that are taking up the additional capacity that's being added for fractionation at Mt. Belvieu the two major expansions going on there. And in my view a lot of the producers who have significant drilling schedules ahead of them, those of things that they are needing to take into consideration now and so it will depend on those producer commitments. And with respect to volumes on the DeWitt-Karnes Header, we have connected I believe now three wells to the Header itself. These are one off wells, there are a fair number of producers who are building larger central delivery points and we are trying to be in close proximity to those parties and when we get larger deal done with them.
David Fleischer - Chickasaw Capital Management
You talked about $130 million of approved CapEx projects, and these internal projects have some very nice returns we know so, adding to those is quite helpful. What range it might there be, if you're willing to speculate with us, as to where CapEx might end up this year? Could you add $20 million to that number? And, more importantly perhaps, what range might we be looking at for next year? Do you have any early guidance there as to a broad range for CapEx for next year from internal projects only?
It again it depends on producer activity. There is a flurry of activity out there amongst producers looking for processing and fractionation and market access for their NGLs and it will be driven off of that David. Having said that, there can be -- there will be lots of small projects that maybe in the size that you are talking. But there could be projects that are bigger than that. But it's almost too early to speculate. We are starting to formulate those ideas now in discussions with some of the producers who are looking at bigger deals and hopefully we get something done with somebody. We will give you more guidance on that.
Thank you, and our next question is from the line of Lenny Brecken with Brecken Capital.
Lenny Brecken - Brecken Capital
I don't know if someone asked this question but you keep on referring to the coverage substantially improving. Can you be a little more specific on whether the next quarter it will be over one? Or what the timing it would be over one?
Our thoughts are by towards the end of this year we could be back in the areas we are traditionally we feel comfortable having our coverage well. The biggest driver is that, we raise the guidance on North Texas and we've said this every call. I think in the recent history that North Texas is the driver for 2010 distributable cash flow and as we continue to see those volumes ramped and the activity going on there, that plan as we said on our comments earlier is going to be expanded two months earlier. So therefore, we revise our guidance up so that on a run rate basis at the end of the year, that will be in a $30 million to $35 million range. That’s more than double what’s its doing now. So I mean, that’s second half of 2010 versus the first half of 2010 I guess is the short answer.
Lenny Brecken - Brecken Capital
You've been pretty consistent about North Texas and it looks like it's coming in as you planned. Can you just give us more specific updates and why there hasn't been any announcements on the Eagle Ford side? Is that because you have to finalize things with Kinder Morgan first?
I talked to a lot of producers out there and I think as long there is any spare capacity available on anybody, those will the first deals that, in some cases they are one-off deals. They are either going to be singles or doubles, they’re not going to be the big dedications and things like that. Obviously, there’s a couple of large competitors out there. Now, when you step beyond that and you start looking beyond those single and doubles, the likelihood of bigger deals goes up because people if they truly intend to drill up these acreage that they believe and there’s some significant positions that the producers have taken down as many of you probably read. They are going to need an outlook for both their gas and the NGLs, but not just for processing as we said before, they need access to fractionation. I think that’s what speaks of our project, that we have that capacity available.
Lenny Brecken - Brecken Capital
Okay one follow-up question, guys, if you look at the broad picture it seems like Asia via exports is sopping up a lot of the petrochemical demand and I am just wondering do you have any fear that things slow down across the globe and then we are in a situation where we're in oversupply at any point? I am talking about the industry. I'm not talking about just you, I mean your situation is specific to you obviously, but just a macroview picture. I know NGL inventory is very low, so I don't know if that sticks in your mind as a risk factor?
Well a couple of points there. First of all, there is a significant domestic utilization of NGLs, in particular ethane and propane. I think we are currently an exporter of propane. So what would the effect be on the overall international market. I think we could drive down prices internationally. I don’t know that then we become a gigantic importer of those products as opposed to producing it, state side. With respect to the NGLs in particular and we certainly are watching this, how do we handle this gigantic influx of NGLs as people become more directed towards that and that’s one thing that we watch pretty closely here, we pay particular attention to it and the big levelizer in that whole process is if those prices get to soft then you go into ethane rejection and it's a big stabilizer of prices. The last time we saw I think 2004, 2005 other than just sporadic periods when we saw ethane rejection occur. We don’t see that in the foreseeable, in the near term or mid term. But we do watch it closely.
Thank you and our next question is a follow up question from the line of Michael Bloom.
Michael Bloom - Wells Fargo
Just two quick ones, just in response to one of your comments, what is that coverage ratio again? Can you just remind us kind of your long-term coverage ratio that you're comfortable in?
Personally we'd like to see it in that 1.2 to 1.3 type range. That is where we feel comfortable.
Michael Bloom - Wells Fargo
Second question, in terms of hedges what's your thought now in terms of lengthening the hedge book, so to speak, adding hedges in outer years to store up future cash flows?
That is 2012. We are actually now starting to look at indications on those. I think as we get into the balance of year, as we are now we are focused on 2012. As we get into kind of the second half of the year we will start probably spending more time and money in 2013. We start to do it about late this year when we try to be couple of years ahead.
(Operator Instructions) And we have another follow up question from the line of John Edwards.
John Edward - Morgan Keegan
Just following up, you talked about the North Texas guidance, I guess, at 35. What's your guidance now for the Texas segment overall, I think you mentioned North Texas you were raising it?
We haven’t really done that in the past John. When we have a clear line of sight to certain parts of our business like in north Texas. That’s where we will step back and give guidance, but Texas we haven’t and the key to that John is this because the Saint Jo plant and the contracts behind that asset are fee-based. It’s a lot easier to be able to just look at volume times that rate, whereas when you talk about the rest of Texas it is you know their processing margins in economics. So when you start giving guidance, you are predicting a processing margin and commodity price environment.
John Edward - Morgan Keegan
Okay what was the contribution up from North Texas this quarter?
It was about $2 million to 3 million in gross margin.
The other thing John I think is follow on with respect to Texas in general. There are a lot a initiatives going on in south Texas and quite frankly right now that, we have a feel for where it is headed, but it's like hitting moving target right now because of the opportunities that are out there.
John Edward - Morgan Keegan
Carl you mentioned there was a one-off item of $3 million on your calculation of distributable cash flow, so that I think you came in at 22.9; you think you would have been more like 25.9. What was that item?
It wasn’t 22 or 25. The distributable cash flow was 30.9 for the quarter. In the first quarter of 2009 we had a gain on the repurchase of senior notes of $3.9 million or $4 million. So, that was embedded in distributable cash flow in the first quarter of '09 which was about $35 million. So, if you were to just back out the gain of four, you end up at 31 versus 30.9 that's what is kind of my point. So in terms of Bcf generated by our assets it was relatively flat quarter-over-quarter.
The other thing to point out is if you go back and look historically our first quarter has been our lowest quarter of all four quarters and its just one of those things where you have weather issues, volumes typically are impacted during that period of time and our expenses tend to be a little bit higher if you go back and look at kind of what our assets generates, that’s the other thing we got to keep in mind.
Thank you. And no further questions at this time. I would now like to turn the call back over to management for any closing statements.
We appreciate for joining us this week for this call and we look forward to the next quarter's call. With a number of opportunities out there we hope to provide more information as we go. Thank you.
Ladies and gentlemen, that does conclude the Copano Energy’s first quarter earnings conference call. If you would like to listen to our replay of today’s conference, the details were included in the press release. ACT would like to thank you for your participation, you may disconnect.
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