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Executives

Doug Lawing – EVP, General Counsel and Secretary

Bruce Northcutt – President and CEO

Carl Luna – SVP and CFO

Analysts

TJ Schultz – RBC Capital Markets

Michael Blum – Wells Fargo

Helen Ryoo – Barclays Capital

Selman Akyol – Stifel Nicolaus

Becca Followill – US Capital Advisors

Copano Energy, L.L.C. (CPNO) Q2 2012 Earnings Call August 9, 2012 10:00 AM ET

Operator

Ladies and gentlemen, thank you for standing by and welcome to the Copano Energy’s Second Quarter Earnings Conference Call. During today’s presentation, all participants will be in a listen-only mode. Following the presentation, the conference will be opened for your questions and instructions will be given at that time. Today’s conference is being recorded, August 9, 2012.

I would now like to turn the conference over to Doug Lawing, General Counsel. Please go ahead.

Doug Lawing

Good morning and thank you for joining us today for Copano’s conference call to review financial and operating results for the second quarter of 2012. Before we begin, I have a few housekeeping items. If you’d like to be on our email distribution list to receive future news releases, please call our Investor Relations firm DRG&E, their number is 713-529-6600. A replay of the call will be available later this morning. Information on how to access the replay is provided in the news release.

Please note that information reported on this call speaks only as of today, August 9, 2012. 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 on certain assumptions based on its experience and perception of historical trends, current conditions and expected future development. Actual results are subject to a number of risks and uncertainties and may vary materially from the forward-looking statement including guidance discussed on today’s call.

These risks are discussed in our annual and quarterly reports filed with SEC. Please note, that 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’ve provided reconciliations to comparable GAAP measures in our news release. In addition, a reconciliation of adjusted EBITDA to net income for our operating segments can be found in the Investor Relations page of our website under events.

With that, I’ll turn the call over to Bruce Northcutt, our President and CEO.

Bruce Northcutt

Thank you, Doug, and good morning to everyone on the call. I’d like to begin this morning with a high level review of the second quarter followed by an update on our Eagle Ford Shale strategy, including the expansion projects that are currently underway. I’ll then turn it over to Carl to review our financial results for the quarter and to discuss the 2013 guidance included in our earnings release. Following Carl’s comment, I’ll introduce two new executives who joined Copano this past month and we’ll take your questions at the end.

In the second quarter, total distributable cash flow increased $6.2 million or 19% from the first quarter of 2012 to $39.5 million. This increase is primarily due to Texas segment gross margin improving by $3.8 million, driven by better performance at our Houston Central complex. With the modifications we completed in mid-April, the new cryo (inaudible) has been exceeding our original performance expectations, and for the quarter, our overall actual recovery rates at Houston Central including our lean oil plants were better than contractual rates.

In addition to better overall performance at Houston Central, total volumes from the Eagle Ford Shale increased 62,000 MMBtu per day or 14% from the first quarter of 2012. Increased rich gas volumes and the cryogenic modifications completed at Houston Central in April increased NGL production by over 12,400 barrels per day or 56% from the first quarter.

We continue to make good progress on our Eagle Ford Shale strategy and our current slated expansion projects are a key driver in the growth reflected in our 2013 guidance numbers. As I’ve said before, given the Eagle Ford’s reservoir size, gas quality and proximity to both natural gas and NGL market, we believe it is one of the best shale plays in the U.S. Due to the Eagle Ford’s reservoir characteristics and strong producer economics, we have continued to see little impact on rig count in the play even in the current pricing environment.

As an early mover, in the Eagle Ford, we have established a strong presence. Projects we’ve already placed in service as well as those in progress are supported by long-term contracts with some of the largest producers in the play. These contracts have greatly reduced our sensitivity to commodity price fluctuations by increasing our fee-based contract mix. Producer demand for additional Midstream services in the Eagle Ford remains strong and we continue to evaluate additional capital projects. While we worked hard to reduce our sensitivity to commodity prices, they remain in our overall company performance.

During the second quarter liquids prices fell significantly from first quarter averages with the largest decline in ethane and propane. Warmer than normal temperature this past winter led to higher than normal propane storage levels. As a result, propane has been competing directly with ethane as a cracker feedstock. In addition, ethane storage levels and prices were impacted by downtime at multiple crackers and fractionation facilities during the second quarter and early third quarters of 2012.

The combination of these factors drove ethane and propane prices lower. While we believe NGL prices may improve slightly during the second half of the year, we do not expect prices will return to the levels we saw at the beginning of 2012. The basis differential between Mont Belvieu and Conway for NGLs remains wide, which has resulted in ethane rejection at some of our plants in Oklahoma. We believe this wide basis differential will continue for the balance of 2012 and will not improve significantly until new third party NGL takeaway capacity is brought online in late 2003.

While lower natural gas and NGL prices have impacted our percentage of proceeds contracts in our Oklahoma business segment, we’ve made significant progress transitioning our overall contract mix for the more fee-based contracts as a result of our strategy in Texas. During the second quarter, 62% of our total gross margin was fee-based compared to 45% in the second quarter a year ago.

Now, I’d like to update you on our current expansion projects. Construction on the first 400 million cubic foot a day cryogenic expansion at the Houston Central complex is progressing well, and as previously discussed, we expect the first quarter 2013 in-service date. We are working hard to complete the project ahead of schedule, which will require acceleration of some capital expenditures into the fourth quarter of 2012. Additionally, Formosa’s fractionation expansion (inaudible) facility is underway and is scheduled to come online in the second quarter of 2013.

We will have 37,500 barrels per day of fractionation capacity at Formosa’s expanded facility when it is complete. An EPA permit application has been submitted for our second 400 million cubic foot a day cyrogenic expansion in Houston Central which we announced during our last call. Based on a one-year permitting process timeline and the time required to construct the second cryo, we currently anticipate a mid-2014 start up.

In order to meet our expected in-service date we will begin incurring capital expenditures for long lead items in 2012. This newest cryo expansion is supported by long-term fee-based capacity commitments with major producers and will give us a total Bcf a day of cryogenic processing capacity at Houston Central. Construction of the Southwest extension of our DK Pipeline announced in early February is now underway.

(Inaudible) is being acquired and pipe is being delivered to the location and we expect the second quarter of 2013 in-service date. Finally, we’re making good progress on the Double Eagle pipeline, our 50/50 joint venture with Magellan Midstream Partners, which will provide 100,000 barrels a day of condensate and crude oil gathering from Eagle Ford Shale for delivery to Magellan’s terminal on the Corpus Christi ship channel.

All necessary permits have been secured and construction is underway on the pipeline connecting the Three Rivers Terminal to the Magellan Terminal at Corpus Christi. Construction of the Three Rivers Storage and Truck Terminal is also in progress. We expect to be able to flow volumes from Three Rivers to Corpus Christi by the end of this year and the extension into Orange County to be completed shortly thereafter. We anticipate further extension to Gardendale and the (inaudible) will be completed late in the second quarter of 2013 providing access to additional production areas in Southern Eagle Ford.

In Oklahoma we have commenced construction of a pipeline connecting our Osage and Stroud systems in order to deliver rich Mississippi Lime gas gathered on Osage to the same processing plant where we can provide processing and nitrogen rejection services. We expect this project to be complete in the first quarter of next year. We are currently approaching roughly 50,000 acres in dedications from multiple producers in the Mississippi Lime.

Before I turn the call over to Carl, I’d like to discuss our decision to provide expanded 2013 guidance in our second quarter earnings release. Our practice has been to provide quarterly gross margin trends, annual expense and CapEx projections, and for the last several quarters, we provided expected incremental distributable cash flow from our 2011 capital expenditures. Given the complex structure of our contracts and the rapid growth in capital spending and volumes related to our Eagle Ford strategy, we understand that many analysts and investors have had difficulty forecasting the longer term impact of this strategy, our adjusted EBITDA, total DCF and distribution growth.

As a result, Wall Street analysts’ estimates have varied widely which has led to a misalignment between analysts and management’s expectations for our longer-term growth prospects. In an effort to better communicate our expectations, we decided to begin providing guidance ranges for annual adjusted EBITDA, total DCF, distribution growth and our contract mix, while continuing to provide updates on our quarterly gross margin trends. We plan to update this guidance on our earnings call, but only if our revised expectations fall out apart our guidance ranges. Now, I’ll ask Carl to review our second quarter financial and operating results as well as our 2013 guidance in more detail.

Carl Luna

Thanks, Bruce, and good morning to everyone on the call. As Bruce mentioned, total distributable cash flow for the second quarter was $39.5 million, which was up 19% compared to the first quarter and up 5% versus the second quarter a year ago. The improvement in total distributable cash flow resulted in 93% covered to our second quarter distribution compared to 79% covered for the first quarter of this year.

Now looking at our operating highlights by segment. In Texas, second quarter segment gross margin increased approximately 8% from the first quarter, an increase of about 6% from the year ago to $49.1 million. The improvement over the first quarter was primarily a result of better performance at our Houston Central complex and increased volumes from the Eagle Ford Shale play. This increase in gross margin during the second quarter is in line with the guidance provided in our first quarter earnings call.

Second quarter service throughput volumes in Texas decreased 2% over the first quarter, but increased almost 40% versus the second quarter last year to 925,000 MMBtu per day. Although service throughput volumes decreased slightly over the first quarter, growing rich Eagle Ford Shale volumes received at our Houston Central plant displayed nearly all third-party lean volumes delivered by Kinder Morgan during the second quarter. Total gas volumes from the Eagle Ford Shale averaged 490,000 MMBtu per day in the second quarter, with is up 14% from the first quarter, and up 277% compared to the second quarter a year ago. Of these volumes, 237,000 MMBtu per day were gathered on our wholly owned systems and 253,000 MMBtu per day were gathered on our joint-venture pipeline.

Based on these volumes gathered on our wholly-owned systems in the second quarter, deficiency fee on committed volumes not delivered by producers were minimum. Remember, Eagle Ford gathering is unconsolidated and substantially all of the deficiency fees payables to JV for 2012 will be reflected in our total distributable cash flow in the first quarter of 2013.

Gathered volumes on our Saint Jo system remains strong averaging 123,000 MMBtu per day during the second quarter. Inlet volumes to our Saint Jo plant are at capacity averaging 109,000 MMBtu per day for the second quarter, an increase of 7% compared to the first quarter and an increase of 71% from the second quarter of last year.

Our Lake Charles processing plant which we restarted late last year ran consistently throughout the second quarter. Volumes at the plant averaged 163,000 MMBtu per day during the quarter, an increase of 22% compared to the first quarter. Second quarter Texas segment NGL production averaged over 50,000 barrels per day, an increase of 42% compared to the first quarter of this year and 86% versus the second quarter of last year. Second quarter Eagle Ford gathering NGL production process at third party plants averaged over 10,000 barrels per day, an increase of 4% compared to the first quarter of this year.

Looking ahead to the third quarter for Texas. We are seeing continued increases in Eagle Ford Shale volumes as producers ramp up production of rich gas in the third quarter. However, due to lower NGL price – prices and lower volumes processed at our Lakes Charles plant, we currently expect Texas segment gross margin for the third quarter to be slightly lower than the second quarter.

Moving to Oklahoma. Gross margin decreased by 17% from the first quarter and 30% versus the second quarter a year ago to $20.2 million. The decrease for both periods was driven by lower midcontinent natural gas prices and NGL prices. Oklahoma, service throughput volumes increased slightly compared to the first quarter and 14% from the second quarter a year ago to 325,000 MMBtu per day. The volume growth was driven by lean gas production in the Woodford Shale. NGL production of over 17,000 barrels per day was roughly flat compared to the first quarter and the second quarter a year ago.

Looking ahead to the third quarter in Oklahoma. In the Woodford Shale we expect to see modest volume decreases as a result of normal well decline and a lack of drilling in the area due to the current natural gas pricing environment. We expect volumes to grow in the Mississippi Lime as producers continue to focus on rich gas plays. The volume growth in Oklahoma should be offset by lower commodity prices during the third quarter resulting in segment gross margin that is slightly down compared to the second quarter.

Touching briefly on the Rockies. Second quarter adjusted EBITDA for the Rockies including Bighorn and Fort Union was $7.2 million compared to $3.8 million for the first quarter and $6.9 million for the second quarter of last year. The increase from the first quarter was due to higher distributions from Fort Union reflecting its precede of annual treating deficiency fees. Because annual treating fees are only received in the second quarter, adjusted EBITDA for the Rockies is estimated to be approximately $3 million lower in the third quarter compared to the second quarter.

Now, turning to corporate and other. Second quarter gross margin was a gain of $3.4 million compared to a loss of $5.1 million for the first quarter, and a loss of $10.3 million in the second quarter a year ago. The gain was primarily due to net cash settlements received on higher unrealized gains on derivatives partially offset by non-cash amortization expense.

We received net cash settlements on our commodity hedges of $3.5 million in the second quarter compared to $500,000 in the first quarter and payments of $2.7 million for the second quarter a year ago. Based on the current commodity price environment, we expect cash settlements from our hedges in third quarter to be higher by approximately $2 million.

Now, moving to the expense items for the second quarter. G&A expense was $10.3 million, which was down 30% from the first quarter, and 13% from the second quarter a year ago. The decrease from the first quarter was primarily due to higher compensation expenses in the first quarter associated with closing our Denver office, a reduction in non-cash deferred equity compensation expense and a collection of the receivable previously written off. The year-over-year decrease in G&A was primarily due to the reduction in non-cash deferred equity compensation expense and a collection of the receivable.

Operating and maintenance expense was $18.3 million which was down slightly from the first quarter and up about 16% from the second quarter a year ago. The year-over-year increase in O&M expense is primarily due to increased expenses for our expanded assets in the Eagle Ford Shale and the North Barnett Shale combo plays. Interest expense was $14.6 million, which is up slightly from the first quarter and up 28% from a year ago. The year-over-year increase was primarily due to higher indebtedness outstanding.

Turning to CapEx and liquidity. During the second quarter, we spent a total of $130 million in expansion capital, including $115 million on wholly owned projects and $15 million on joint venture projects. We also spent approximately $4 million in maintenance capital during the quarter. We now expect to spend $400 million to $430 million for wholly -owned and JV expansion projects for the full year 2012 – an increase of $25 million to $55 million over our previous guidance. This increase is primarily due to accelerating capital expenditures for the initial 400 million cubic foot per day cryoexpansion and purchase of the only items required to accommodate our second 400 million cubic feet per day cryoexpansion. For the second half of 2012, we expect to spend between $200 million and $230 million for wholly owned and JV expansion projects.

As of June 30, we had $245 million borrowed on our revolving credit facility and including our cash we had over $284 million of total available liquidity.

Finally, I’d like to highlight some of the items in our 2013 guidance. Last night, we announced our 2013 guidance in detail in our earnings release. While I won’t go to each item of guidance, I want to highlight a few key items. For 2013, we expect adjusted EBITDA to be in the range of $300 million to $330 million and total distributable cash flow to be in the range of $220 million to $240 million.

We also expect that we will be able to grow our quarterly distribution between 7% and 9% on an annualized basis and maintain quarterly distribution coverage between 100% and 115%. This guidance is derived from our internal planning models and is based on a number of assumptions made by management, including forward commodity prices, consistent operations at third party facilities and timely completion of expansions at third party facilities that impact Copano’s operations, producer volumes and treatment of our preferred units.

Please refer to our earnings release for greater detail on these and other key assumptions. We will update this guidance on our earnings call if material changes occur. This guidance replaces any past guidance we have provided as it relates to 2013. We will continue to refine our thinking around issuing guidance and may, from time to time, elect to disclose additional information that might be helpful to analysts and investors in assessing our long-term growth prospects.

With that, I’ll turn the call back over to Bruce.

Bruce Northcutt

Thank you, Carl. Before we go to your questions, I’d like to introduce two new members of our Executive Team. In mid-July we announced that Bryan Neskora had joined Copano as Chief Operating Officer and Susan Ortenstone had joined as Chief Administrative Officer. Bryan comes to Copano with over 20 years of pipeline experience in a variety of areas and he most recently served as Senior Vice President of operations at El Paso Corporation. He is also serving various other roles, managing areas such as business development, commercial operations, marketing and regulatory affairs.

Sue joins Copano with more than 30 years’ experience in various functional areas of business segments within the energy industry. Most recently, she served as Executive Vice President and Chief Administrative Officer for El Paso Corporation. Let me just say, I’ve known both Bryan and Sue for many years and each one brings a breadth of experience and leadership to our organization and they’re going to be a tremendous addition to Copano’s executive management team.

In closing, Copano has a strong asset base and is well positioned in several active plays with significant long-term producer commitments and a number of projects either underway or in development that will benefit us, our producers and our investors for years to come. We have many projects in service and many more coming online during the first half of 2013 that we expect will dramatically improve distributable cash flow for our unitholders.

I’d also like to recognize and thank the Copano employees across our entire operations for the hard work and contributions they had made this quarter and especially with managing our significant expansion program. Now, operator, we’re ready for your questions.

Question-and-Answer Session

Operator

(Operator Instructions) And our first question comes from the line of TJ Schultz with RBC Capital Markets. Please go ahead.

TJ Schultz – RBC Capital Markets

Hey guys, good morning.

Bruce Northcutt

Good morning TJ

TJ Schultz – RBC Capital Markets

Good quarter and I appreciate the guidance very, very helpful. I guess I’ll just focus on that, for your guidance for 2013. If you could just, maybe, comment on your commodity assumptions there? I guess the NGL to crude ratio seems fairly conservative. So maybe just comment on your thoughts on NGLs in the 2013.

Bruce Northcutt

Okay. TJ I’ll now let Carl pick up anything I miss here. If you take a look at our NGL functions, they are probably a little lower than what some people would expect, we use third party service, for forward pricing and that comes out little bit more conservative, then maybe some other people’s expectations in the market. Carl, you want to add anything,

Carl Luna

Yeah, I mean, if you look at what other folks typically do TJ and I know you – you know this. They will use a crude to – a NGL to crude ratio. The numbers we’re using are really from market makers, where essentially, we could hedge our business. So they are going to be a little bit lower, generally speaking, because of that than if you are just to use simple math or other ratios. So it’s something that – how we mark our (inaudible) and so it’s probably more conservative than most. We feel comfortable that we have pretty good base exports.

TJ Schultz – RBC Capital Markets

Okay, great. I guess just kind of follow-up on the guidance, just so I am clear on the preferred units. Does your coverage assumption in 2013 exclude the preferred, even though you kind of mentioned that you’ll pay those in cash in the third and fourth quarters, and then maybe your view on, when those would convert to com, and is it really just a view on coverage post conversion?

Carl Luna

Yeah, I mean it’s about $10 million a quarter, if you were to pay the distributions in cash. And so what – the coverage is really the coverage on the common units. So you take – you take our total DCF guidance, subtract the, I guess, the assumption of $10 million per quarter for two quarters and then that would get you kind of the DCF to common unit and that’s what our coverage assumption is based on.

In terms of kind of why we assume that. I mean, really it’s – the key driver to that is the $37.77 unit price, strike price on that and so just sitting here at south of $30, it’s hard for us to make an assumption if we think that will convert. So we think we made a more conservative assumption and then look – we have the option to pay it in cash and we’ll choose to do that. And then as soon as we are able to convert it, in our unit price trades above that level, then we will obviously seek to do that.

So from 2013 we just assume that wouldn’t happen.

TJ Schultz – RBC Capital Markets

Got it. Thanks. I’ll get back in queue. Thanks.

Bruce Northcutt

Okay.

Operator

Thank you. Our next question comes from the line of Michael Blum with Wells Fargo. Please go ahead.

Michael Blum – Wells Fargo

Thanks. Good morning guys.

Bruce Northcutt

Good morning. How are you, Mike?

Michael Blum – Wells Fargo

Good. A couple of questions on the guidance. One, just a point of clarification, the 79% growth that’s looking at Q4 2013 declared over Q4 2012 declared in terms of the annual growth rate.

Bruce Northcutt

That’s right.

Michael Blum – Wells Fargo

Okay. And then the other question I had, which – related to the guidance, I guess is, what – how should we think about what’s your non-cash amortization expense or what premium is it going to look like next year. And just to clarify your DCF excludes that, correct?

Bruce Northcutt

Our DCF, I guess it excludes, I mean, we’re adding back the amortization.

Michael Blum – Wells Fargo

Okay.

Carl Luna

In fact for 2012 it looks $20 million and for 2013 it’ll be slightly less than that. We haven’t hedged this much for 2013 as we did in 2012. And really that’s most ironic.

Michael Blum – Wells Fargo

Okay, got it. All right Thank you.

Operator

Thank you. Our next question comes from the line of Helen Ryoo of Barclays Capital. Please go ahead.

Helen Ryoo – Barclays Capital

Good Morning. Just a question about your CapEx guidance from 50 to 300. Could you provide a breakdown of that spending? And also, does that include some projects that has not been announced yet?

Carl Luna

Well, first of all, I think let’s take you through – Helen, what, I think we had guidance earlier in the year of about $400 million and that brought back to the 375. And okay, Helen, your question’s more directed towards 2013?

Helen Ryoo – Barclays Capital

Yes. Yes, sorry.

Bruce Northcutt

Okay. In 2013, I don’t think we have given that a break, given a breakdown on each individual project. But most of the spending will be obviously, what will be finishing up at the beginning of 2013 on the costs, on the $400 million at cryo at the first one. We’ll also have some additional ongoing cost associated with the second $400 million at cryo. Most of that won’t come into the back half of the year after we receive a permitting from the EPA. We’ll also spending money on the double Eagle pipeline and as well as the Southwest Extension of the decay pipeline. That’s where the majority of the spending will come from

Helen Ryoo – Barclays Capital

Okay. So if you – so this is just based on the projects, you’ve already announced?

Bruce Northcutt

That is correct and nothing that has not been announced yet.

Helen Ryoo – Barclays Capital

Okay, and you talked about some acceleration of CapEx related to these cryo plans. I guess the total cost has not changed. It’s just the timing here given the spend a little bit earlier and then lower, smaller later on. Is that the right way to think about it?

Bruce Northcutt

Yeah there is actually a – couple of drivers to the CapEx spending for the back half of 2012. First would be, of that roughly $40 million to $50 million increase about $25 million of that is associated with items that we are going to go ahead and do now in preparation to be able to manage the second 400 million a day cryo. We would have had it done, we would not have had to have done these and that’s primarily providing flexibility in order for us to be able to run gas through either plant independently of one another. So that’s the line shared that spend in 2012, and then there is a little bit of money in there. Obviously for the long lead items, the things like turbines and towers for the new plant, that when we submit the purchase order, we’ll have to pay a small amount, but to get the purchase order loaded in. So, but that’s the vast majority of it. And, I guess a little bit of it is, what would be costs associated with the, South West UK pipeline and that’s the pipeline cost itself.

We expedite that the reason that is cases because we’re going to be sharing the right of way between and Double Eagle and we want to go ahead and have pipe both of those in those rounds.

Helen Ryoo – Barclays Capital

All right, that’s very helpful. Thank you very much.

Operator

Thank you. Our next question comes from the line of Selman Akyol with Stifel Nicolaus. Please go ahead.

Selman Akyol – Stifel Nicolaus

Thank You. We also appreciate the guidance going in 2013. Just a quick question on your G&A numbers, given that you have recoverable, under I guess receivable and then you also had the closing of Denver office. Can you give us little more color in terms of what might be a good run rate going into the back half of the year?

Carl Luna

We gave guidance, I guess earlier in the first quarter, on our first quarter call, I guess that was our year end call for the year on what we thought G&A expense was, and that we haven’t changed that guidance, so we still feel like we’re probably in the range of $45 million to $55 million. I’m sorry, that’s the wrong years. Yeah, $50 to $60 million for G&A for 2012.

Selman Akyol – Stifel Nicolaus

Okay, thanks.

Carl Luna

So our guidance hasn’t changed.

Selman Akyol – Stifel Nicolaus

All right.

Operator

Thank you. Our next question comes from the line of back Becca Followill with US Capital Advisors. Please go ahead.

Becca Followill – US Capital Advisors

Good morning, guys. And, two of your in the room. Congratulations. On – Pearsall, we have been hearing increased activity there and guys talking about that might have been a lot of potential where your assets position relative to that. And you guys have any opportunities, maybe for some of that additional infrastructure to serve at the Pearsall.

Bruce Northcutt

Thanks Becca, for those of you who don’t know, Pearsall actually that lies kind of along the same line, as the Eagle Ford trend but shifted a little bit more towards the North and the West from our trend. We kind of run them – I think South East corner of that trend, we kind of traverse that same area. There have been some pretty big wells made there from our understanding, some of these wells has been $5 million a day and significant amount of rich gas. Certainly we would hope to gather some of that into the decay, but right now, quite honestly, we have got, quite a bit contracted, just from Eagle Ford shale producers though. I think, as with all good projects, you hope that you have following opportunities as result of having spent a capital and having those assets and then grown. I think we will ultimately capture some.

One thing I have Becca with respect to that play, which you know we would want to be cognitive, in some areas there’s been a fair amount of H2S associated with that trend and we probably, we either need to develop a strategy around handling H2S or we want to avoid it.

Becca Followill – US Capital Advisors

Okay, thank you. And then on the line if you guys are doing with Magellan. We’ve heard some discussion as perhaps too much crude on can to take of half of this is being built and planned diluted to that earlier this week in there conference call. I know you have a couple of contracts there, major contracts that anchored the pipeline, but what percent of the total pipeline to those two contracts anchor?

Bruce Northcutt

They currently, 50% of capacity the pipeline to begin with. A couple things, and I did hear some of the comments made by I believe it is this playing some enterprise and other they announced their combined project down there. One of the things that we’ve done, which is a little bit different strategy than most as we’ve really concentrated on the condensate window.

So there’s a fair number of people who are targeting just that 55 degree to 65 degree API condensate and that’s kind of accrual our strategy as it lies and so we contracted under shipper pay contracts for the full-term you tenure period with those with the two producers that make up the biggest, the vast majority of that. I think there is a fair amount of work that we’re doing right now commercially around the development of the Double Eagle pipeline and some of it’s not ready for prime time yet, but some of those strategies would get some people from new alternatives we hope, and if they come to fruition we think we won’t have any problem gaining more producers supported project.

Carl Luna

And Becca, on that project we have said it in a prior call, and just those 50,000 barrels that are contracted, we generate north of 20% rate of return on the project. So if we don’t sign another contract we still achieve what we consider a pretty good rate of return on the capital.

Becca Followill – US Capital Advisors

Great, thanks guys.

Bruce Northcutt

Thanks Becca.

Operator

Thank you, (Operator Instruction). And our next question comes from the line of TJ Schultz with RBC Capital Markets. Please go ahead.

TJ Schultz – RBC Capital Markets

Hey, I just there is I guess in the press release. I don’t want to read too much into it, you made comment that you have begun the focus on new kind of long-term growth opportunities and just if you could comment, if this kind of relates to investment in and around your established footprints or are you guys looking at other areas as well?

Bruce Northcutt

It’s both TJ – we do have some follow-on opportunities around the Eagle Ford, and again we’re stepping through all of the requirements and negotiations that need to be done in the front end of doing – anything more there. We certainly want to make sure that we have adequate capacity both for gas and for NGL Capacity, associated with any follow on top opportunities and some of those are around establishing some additional capacity.

Then as far as other projects that are outside the area, there’s really I would say, really three primary areas and all those are now, what I would say, working significantly with our existing infrastructure. They’ve been in progress for some time. Obviously competition is fierce as you’ve seen a lot of other people, that is – typically not been in gathering and processing. They kind of enter the space. We still think we have a competitive advantage because we’ve been doing it for a long. We’re trying to use those relationships in order to land some key customers that it would take to be able announce these projects. Not ready yet to talk more in detail about almost the outcome, how they progress as time goes on.

TJ Schultz – RBC Capital Markets

Hey Okay, thanks. And then in the Mississippi Lime, you mentioned 2000 acres of dedication. Can you just comment on how this has increased more recently and if you’re still looking at adding acreage dedications here?

Bruce Northcutt

Yes, we are, as we described them in the last calls, we’re actually on the eastern side of the new highway, where the wells are not the big (inaudible) burners like you’ll see on the Western side (inaudible). But I would say this, we’ve more recently, one particular producer, we thought them extremely encouraging results. Historically, we probably would be probably staying well, on the average.

I would say, somewhere around the 250 Mcf a day, which is relatively small, making 200, 300 barrels a day. This producer IP Well roughly just shy of 2 million cubic feet per day and about 500 barrels a day of crude. So, I think part– of part of our success will be we’ll rely on the success of the producers and physically as they stand in this place and do – and learn kind of the trick to the particular formation as to how they need to stimulate it and completed, they make better wells.

And then, hopefully we do well. I will say this regardless of what the volume is, the gas that we’re seeing is probably six to eight GTM gas and so it does need a fair amount of midstream services and so that’s the focus that will have on the players is gathering rich gas and finding a home for it and also said in areas in which we which we operate we also in some place that see some pretty high match in services and so, that’s kind of key for connecting our outside system, the payment system.

As you remember, the (inaudible) plant we have oxygen rejection unit facility and that allows us to manage the nitrogen organs into play, so we can develop our, it’s already developed. I think we have a pretty well develop strategy with respect Mississippi Line. It’s just that we need to understand how much infrastructure we’ll need. What we don’t want to do is go out there and over build capacity. And right now we’re kind of waiting on producers to understand what they plan- what they think they see on the eastern side of the new model.

TJ Schultz – RBC Capital Markets

Great, thanks.

Bruce Northcutt

Thank you TJ

Operator

Thank you. And I’m showing no further questions in the queue at this time, I’d like to turn the call back to management for any closing remarks.

Bruce Northcutt

Thanks everybody for joining us on the call today and we look forward to catching up with you in November as well. Thank you.

Operator

Ladies and gentlemen. And they too many of you like to listen to a replay of today’s conference, you may find the information for the replay in yesterday’s earnings being and I could think of it at the time for joining today’s conference. This concludes that call for today. Thank you.

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