Coterra Energy Inc (CTRA) 2011 Q1 法說會逐字稿

Good morning. My name is Melissa and I will be your conference operator today. At this time I would like to welcome everyone to the Cabot Oil and Gas First Quarter 2011 conference call. ( Operator Instructions ) Thank you. I would now like to turn the conference over to Dan Dinges, Chairman and President, CEO. Please go ahead.

Thank you, Melissa. I appreciate everybody joining for this conference call. I have Scott Schroeder, our CFO; Jeff Hutton, VP of Marketing; Matt Reid, VP and Regional Manager in the south; and Steve Lindeman, VP of Engineering and Technology, with me today. As you are aware, the language in our Forward-looking statement will apply to my comments today. We have several items to cover, and I will also expand on the Press Releases that were issued last night, briefly cover the first quarter financial results, and a discussion of operations and further plans for 2011, and, at the end, we will leave ample time for Q &A. Cabot did report financial reports for the first quarter with clean earnings of just over $20 million and with discretionary cash flow of about $109 million. This quarter continued the same trend of lower natural gas price realizations, offset by robust production growth.

Throughout the remainder of 2011, I would expect to see similar commodity pricing, and also a continued increase in our production profile. In terms of production, the company posted a 41% production growth rate between comparable first quarters. 37.7 BCF was the highest quarterly production total the company has ever reported. Along with this production achievement is the fact that last week we surpassed 100 BCF cumulative production level for the Marcellus shale in Pennsylvania, and we did this in just under three years. At our current production rate, the next 100 BCF of production will be achieved within less than a year.

Looking ahead to guidance, last night, we posted new full year 2011 expectations, increasing the overall growth rate to 34% to 42%. Effectively, the midpoint is now 5% higher than before. The low end of the guidance is based on the current production levels. The high end of the guidance is tempered by our best guess of timing of the commissioning of the additional dehydration units, which we are currently installing, and the hook up of additional gathering lines to the Lathrop Compressor Station. With the dehydration and additional gathering lines, we think we can move an additional 50 million to 70 million cubic foot of gas to the market. Any upside to our second-quarter guidance will be dependent upon the timing of these two items. And, again, that is upside to the second-quarter guidance.

You will note as we move to the third and fourth quarters, we are increasing our guidance as we anticipate the commissioning of the Williams Springville line from Lathrop to the Transco Interstate line, which is 30 miles south. To summarize, I understand there remains a lot of near-term noise and some uncertainty on the timing of infrastructure. However, each day we get a little bit more clarity on these items. By the end of the second quarter, Lathrop should be fully commissioned, with the piping and dehydration installation. At this point in time, we will be waiting on the Springville pipeline.

Again, the infrastructure capacity, this is not production, but the infrastructure capacity at Lathrop and Teel at the end of the second quarter will be 550 million cubic foot of capacity. Following the Springville commissioning, we will begin producing into of this available capacity, and our guidance reflects what we think might be a conservative look at the expectations as we fill up this capacity in the third and fourth quarters. I think most importantly is the fact that our well performance and the deliver ability that we have seen from our completion has not changed and we continue to add to the backlog of completions for future productivity.

Okay. As part of our marketing effort, our cost associated with the required firm transportation arrangements, and our gathering fees have grown, and as such are now reflected on separate line items. Previously, these calls were an offset to realized prices. The impact of this change to historical comparisons is zero, as realized prices are slightly higher to completely offset the new expense category. For the first time, we have posted guidance for the transportation line which captures all of these arrangements company wide. This addition, together with some reductions in DD&A, financing, operating costs and in addition to a slight increase in G&A, excluding the pension, termination and stock compensation, are the changes that were reflected and posted to our cost guidance.

Now let's move to operations for 2011. Our plans remains unchanged from our original budget. We are holding firm to a $600 million capital program that has $350 million directed towards the north region for our Marcellus, and $250 million in the south region for the Eagle Ford oil initiative. I would note that the first quarter disclosure for capital investments on the cash flow statement included over $30 million of 2010 carryover that was paid in 2011.

Now, let's take a look at our hedging. Cabot took advantage of a short window of opportunity with natural gas price strength during the first part of the quarter to add hedges in 2012 and 2013. This effort now has the company with 21 contracts for 2012 production, excluding the five basis-only hedges and five contracts we placed for 2013 production. The hedge slide that we have on our website will illustrate all of this.

Moving to the north region, and a little bit of detail, some of this might be a little redundant. But, we do continue to establish new milestones in the Marcellus. During the first quarter, we had a new production record of 320 million gross per day, predominantly from 57 horizontal wells. Cabot continues to have excellent results as demonstrated by a two-well pad site that has been in line for three months and is currently producing 36 million cubic foot a day, in addition to our fit first six-well pad site that is producing at a curtailed rate of 51 million cubic foot per day. We would expect the six-well pad site to be able to produce around 70 million to 80 million cubic foot un-curtailed.

On a completion side, we have just finished fracking a five-well pad site that is currently cleaning up. Also, we are in the process of completing our longest lateral to date, which was a total usable lateral length of over 6,000 feet, and we are well on our way to finalize 26 stages of-- in this completion. Cabot continues to run five rigs in the Marcellus, and has a total of 560 stages being completed or cleaned up, waiting on pipeline or waiting to be completed. A dedicated frack crew has been very effective, averaging three completion stages per pumping day during March. And, we generally average about 20 pumping days per month.

At the Lathrop compressor station, which Williams now owns, there are total of seven compressors running, giving us a current capacity of 225 million cubic foot per day at the Lathrop station. Once the additional dehydration units which I've talked about are installed, along with additional piping, the capacity at the station will increase to 450 million to date-- per day. And, the Teel station will have another 100 million a day to get us to that 550 million I previously mentioned. Again, actually flowing capacity will be tied to the Interstate take-away capacity, and the completion of the Williams line to the South. That completion and commissioning of that Springville line down to Transco is anticipated for the third quarter.

In terms of other initiatives, we have several initiatives going on. In regard to the one that is most visible, the Heath, we have a completion crew scheduled for late May. This well is designed for an eight-stage track and we will report the results when we get these results available. We do have several others items or several other initiatives going on, which we will also report on in a timely fashion and the appropriate time. We have been asked about our future plans in the Heath and right now we are just currently focused on the completion of this particular well.

Now, let's move south into Eagle Ford area. In our Buckhorn area, the company successfully completed three recent Eagle Ford Wells. Each well is 100% Cabot well, and they are located in Frio County. The wells flowed at a 24-hour rate of 558 barrels per day, equivalent to 400-- excuse me, that is 958 barrels of oil per day, equivalent 460 barrels of oil per day equivalent, and 345 barrels a day equivalent. The 345 barrels per day was a well that we got a little bit out of zone in. Nevertheless, it is early in the completion techniques in this area, and we certainly like the results we have seen so far. Three additional Wells have been drilled and cased in the Buckhorn area, and they will be completed in May and June. Additionally, there are three wells that have been drilled in our 18,000 plus acre AMI with EOG. Cabot intends to drill, or participate, in 25 to 30 net Eagle Ford oil wells in 2011.

In regard to activity in East Texas and our Haynesville joint ventures, Cabot is finalized to agreements that will allow us to maintain a large percentage of our Haynesville acreage with no capital investment. These agreements will provide Cabot with a carried interest in the initial well covering 24 units. If commodity prices remain similar levels and with the acreage held by the initial wells in each unit, no subsequent drilling would occur in these units for a period of time. An additional agreement that Cabot has been working on is to sell a minority interest in some non-operated units, both producing and non-producing, with a net production to Cabot of approximately 4 million cubic foot per day. And, that is executed and moving towards close.

Combined, these agreements will allow Cabot to maintain approximately 22,000 net acres of its original 33,000 net acres into play, within the original lease terms, at no incremental cost to us, for 2011 and 2012. This was our plan going into these joint ventures. Two participation agreements as I mentioned are complete and operated, and the sales transaction is expected to close in early May. And, as we said, cash proceeds are expected to be in the range of $50 million to $55 million, subject to final adjustment.

In closing, Cabot operational program remains fairly simple, spending $350 million in the best area the industry has discovered in the Marcellus. That will deliver us significant returns with stellar reserve and production growth. Additionally, we will allocate the remainder of our capital, $250 million, to the oil window in the Eagle Ford, which will increase our oil reserves and our production year-over-year. So we have the best rate-of-return gas project in North America, which includes comparing the rate of returns to many oil projects, plus a great rate-of-return project in the south region. Additionally, we have several other oil initiatives that we are moving on. With that quick overview, I will stop here and answer any questions the group might have.

Thank you. (Operator Instructions)

Your first question comes from Brian Singer of Goldman Sachs.

Thank you. Good morning.

Hello, Brian.

A couple questions. First, could you just refresh us on your backlog of uncompleted wells and wells that are completed and not yet tied in, in the Marcellus?

Yes. We have of course the 5 rigs that are currently running on 5 different pad sites. And, those particular wells, or those rigs, on some of those pad sites, we have 500-- combined, we have 560 stages of-- frac stages that have pipe run. And either we are flowing back the load water right now and cleaning those up or we are waiting on the pipeline, or we are waiting for the frac crew to move from a current pad site it is on to another pad site.

Got it. And, I'm sorry, was there a backlog as well, and maybe I missed that, of wells that have been drilled but have not yet been completed?

That is included in the 560.

It is included okay.

But, we are currently, of course, drilling wells right now, that were maybe at TD that we have not run pipe on yet that will add to the count.

Got it. And, then as you think about 2012, can you talk about your activity and availability in getting additional-- securing additional firm transports and compression capacity? Are you seeing-- how active are you there? Are you seeing any changes in terms, and are you seeing any changes in the tightness in the market?

Yes. Jeff Hutton has been about 24/7 working on this project to make sure that we are going to be able to monetize our investment up there, and he has done a super job in positioning us, I think ahead of the curve, for our take away, and I will let him answer some of that.

Great, Brian. To begin, in 2012, we are poised to expand out of our core area to the north with the Laser Pipeline project. We have got a compressor site up there already, and construction is under way on that pipeline. We have-- let's see, about 150,000 a day of take away on north to Millennium, and that will be a 2012 timing. Also in 2012, we are expecting an expansion of the Williams Springville line on the Transco. I think that is scheduled for approximately mid year of 2012, but we will be getting some additional capacity on South Transco. The third project in 2012 will be to the east of our core area at Lennoxville. We have a compressor site there planned, we have right-of-way, and we will be drilling some additional wells there for 2012.

Great. Thank you. And, lastly, with the Marcellus increasingly in the news, can you just talk about any changes you are expecting, or anything you are doing differently from a regulatory perspective? And, do you anticipate any additional costs, compliance costs, from the environmental side?

Well, obviously we work closely with the DEP, and we are current with all of the projects that are going on up there, any initiatives and conversations. Governor Corbett's commission is studying the Marcellus and looking at the entire space, and trying to balance the environmental aspects, along with the tremendous upside potential in the form of jobs and revenue generated by the Marcellus for the state. The conversations, which we are all aware of, have been along the lines of a severance tax, and Corbett has made clear that he is not in favor of a severance tax. There has been discussion on an impact fee, which would be a fee generated, whether it is based on a pad site or your well permitting, or volumes is yet to be determined. But that impact fee would be for the benefit of the local communities where the activity is taking place, and whether or not that holds true and how the final form of that is, is anybody's guess at this stage.

More on the regulatory side, they recently announced-- Mike Krancer, the secretary of DEP, recently announced where we do not-- they do not want any produced water to be taken to the public disposal sites any more, and we fully support that. We don't have any problems with that. For a long, long time, we have been recycling 100% of our frac water, and we are not taking any of our produced frac fluids to any of these sites. So, it is a non-effect on Cabot. I think with the decision made, I think the majority of industry will be recycling their produced water, so I don't think that is going to have an effect.

As far as any incremental regulations, certainly the EPA is going to continue to try and get involved in our business. They feel like the-- controlling hydraulic fracturing, as an example, should be an EPA item. We are fully convinced and supportive that the states can control their regulations much, much better than a federal oversight body could. And, with our full disclosure now of frac fluids and chemicals on our-- on the groundwater commission's web site, fracfocus.org, I think the clarity and concern about what we put in frac fluids is also a benefit to the community and the politicians.

Aside from that, and again looking at what industry is doing up there, I think every one of us are trying to employ the best available technology. Using premium thread connections is one area that we are employing. And, we think it is a benefit to the community and to the environment, and we are doing all we can right now to mitigate any potential risks. I think it is and should be stated, and maybe we should be a little bit more vocal as an industry to state that, there's no large-scale industry, like the manufacturing industry or the extraction industry, or many other types of industries out there, that has zero potential for upsets.

I think we do our fair share, and we spend millions and millions of dollars to mitigate any risks. I think it has to be understood by all that in order to have our energy source and in order to have cars to drive and be able to flip the switch and turn on the lights, that there is a lot of work behind the scenes to be able to get there. And, there is inherent risk with every type of industry out there.

Thank you. I appreciate it, thanks much.

That was a little long-winded, Brian. (laughter) I will get off my platform.

Your next question comes from Michael Hall of Wells Fargo.

Thank you. Good morning and congrats on the solid quarter.

Thank you, Mike.

If you could help me understand how you work down the backlog. Like you said, you've got 560 some-odd stages waiting on something. As of last count, I think it was 450 waiting on completion. You will generate another-- if you are drilling 51 some-odd wells, you will generate another 760-plus stages that need to be completed. So, with one frac crew doing three stages per day, and like you said, 20 pumping days per month, I am having trouble seeing how that crew is enough to work down that backlog in any meaningful way. Just curious on your thoughts on adding another crew, and what time that might come under consideration, and how you are thinking about that.

Fair question, Mike, and I appreciate it. We have, in fact, we have moved on a spot crew out there. We moved a second crew in to pick up a location that had a couple of wells on it recently. What we are doing is balancing our capital commitment at this stage, along with our ability to monetize our gas. Right now, we have volumes that are currently producing, that are restricted. As I mentioned in the six-stage-- I mean a six well pad, we have that particular pad's site restricted and curtailed right now. Some of our other wells are also not being pulled as hard as they possibly could.

We do anticipate, though, with the infrastructure build out, which we are getting very, very close to on the Lathrop station, Dehigh and additional pipelines. And, Williams, we know, is working diligently to get that pipeline put in to the south. We do anticipate that we will be able to add another frac crew, it will probably be towards the end of 2011 or the beginning of 2012, and look at picking up some of these-- picking up the pace, if you will, on some of the wells that are in the queue. So, it is in our plan to have more than one frac crew out there.

Okay, great. That's helpful and makes sense. I guess one more. You have a lot of pipelines being built out in the region, obviously you have a lot of your own capacity coming on. Are there any permitting issues or anything along those lines that we ought to keep in mind, as it relates to any of these build outs?

I will let Jeff Hutton answer that, Mike.

All right, thanks.

Yes, Mike, I will take the easy one first. On the interstate pipeline build outs, Tennessee, of course, has an expansion that's occurring this summer. They have a second expansion for next year. At the same time period, obviously Interstate Pipelines have eminent domain, and these are all PERC-approved projects. So, we have no issues surrounding those projects in terms of being built. Also, Millennium has an open season, they will be expending that pipeline, kind of the same set of circumstances with them. Transco has a project on the book, and again the same story.

Then you get into the midstream projects that do have permitting and regulatory issues that are not federally regulated. So far, I'll knock on wood here, Laser Pipelines has their New York permits and PA permits. Williams has a number of permits, I think they are just waiting on one more to get started. In terms of the gathering lines, a number of those permits have been issued, at least in the area we are operating in. So far so good.

Okay. I guess one more, if I may. You've got field level compression and gathering capacity at the end of the year, about 550 million a day, as I understand it, and you have plans to build that out further. Can you give any color on the timeline of those additional build outs at the field level in 2012, and how you bring the field capacity up towards that 1.2 BCF a day 2012 exit you talked about for the pipeline take away capacity?

Sure. The Laser, again, 150,000 a day with some additional capacity being negotiated. That pipeline is going to operate at fairly low pressure in this part of the Marcellus. So, it is going to operate in the 600-pound range, which means we will have free-flow capabilities up there, we think, for quite a while. So, it shouldn't be compressor limited. And, that is, again, a third quarter timing on that. They should have everything ready to go and of course we will be ready to go.

And, then in the eastern part of our block, at the Lennoxville area, we've planned-- we already have a 12-inch tap there in Tennessee and a compressor site. Again, we were able to free flow quite a bit of gas into Tennessee without compression prior to building Lathrop. So, we intend to do the same thing, although there's already compressors ordered and the site is there and right-of-way is acquired. I would say that is an end of the year, first quarter 2012 timing. And, then the of course Springville line is due to be in place third quarter this year, and the first expansion is April/May of 2012 with a second expansion planned for May of 2013.

Okay. That's helpful. Thanks very much. Congrats again.

Thanks.

The next question comes from Gil Yang from Bank of America.

Good morning. You mentioned that you had DD&A reductions in the quarter. Can you comment on, was that from better well performance, or lower capital costs expected going forward?

It was a combination of the true up from the year-end reserves that all flow through in the first quarter. When we put initial guidance out, we anticipated the decline, but we wanted to have more certainty. I got asked the same question last night. It is the better well performance that we reported back in February. And it is also-- if you think about a our Marcellus gas, it has a ULP rate of less than $1 from the DD&A perspective, and it is a growing component of the blended rate. In other words, that accounts of two thirds to three quarters of our production base. So, that is the dynamic that is driving the DD&A rate down.

Okay, so it is not a since year-end change that you trued it up to what you reported for the year end?

Right.

Okay. For the pads, what is the expectation for the wells for the pads versus the individual expectations that you have today?

Well, there's really no difference our expectations if we drilled a six-well pad site versus one-well site. The efficiencies come in in two ways, I guess. One is the limited number of rig moves and the timing of just getting over a few feet to the next well. And, while do think we do get some incremental gain. It is not-- it's hard to measure tangibly, but we do think we get some incremental gain by doing our simultaneous fracking with the wells on the multi-well site.

So, any interference is offset by the synergies of the simul-frac?

What do you mean? Interference in the form of do we see a frac when we are pumping in one, do we see it in the other well?

No, I just more meant the drainage volumes are overlapping, so you are not getting the full UR for each well, because they're overlapping a little bit.

Well, right now, we think our spacing is all accretive. We don't think our spacing right now is an acceleration process. We think the spacing is each well capturing a unique gas. Once we start down spacing, we will be able to answer that better on exactly what the appropriate spacing is going to be for the most efficient drainage.

So, what is the current-- for the pads, what is the current spacing, and what do you think it might go to before you start seeing that interference?

Right now our spacing on the pad site is about 1,000 feet. Do we think it can go down to 600 or 700 feet? We are going to take a look at that.

Okay. And, just a follow up on Brian's question, how much deliverability is behind-- is held back on those wells being restricted today?

Well, just the one well-- I mean on the six-well pad site, we think there is an incremental 20 million to 30 million a day just on the six-well pad site. Some of the other wells that we are holding back, and we have flow tubing pressure is greater than 1,000 pounds right now on some of our other wells. I don't have the exact volumes if we would draw all those wells down, say to the suction pressure, it is some volumes, I just don't have the exact number.

Okay, and when the pipelines are all set up and ready to go in terms of third quarter, how much will that deliverability still be there? For that-- for example, for the six-well pad, will it still be that 20 million to 30 million, or will that deliverability have disappeared by then because of the well decline?

Well, certainly, every well has decline. We have not seen exactly what these particular wells will do, because they have not been producing that long. I would expect, and anticipate, if they stay on the trend line of some of our other wells, that we will have excess capacity on that well site above the 51 million today that we are producing, to flow into that new system at that particular time.

Okay. Great. Thanks a lot.

Thank you.

The next question comes from Amir are off of see full.

Thank you. Good morning, guys.

Good morning.

Just a follow-up to Gil's question, in terms of going forward, how are you thinking of the optimal development if there wasn't any restrictions on capital-- on take-away constraints? Is it a six-well pad site or are you thinking smaller developments, just given the sea-level constraints with building the pads?

Well, I think we have just now gotten to our six-well pad site. I think that is very efficient pad site. We might be looking in the future at an eight-well pad site. We have not made that determination yet, but we certainly think a six-well pad site is a very efficient site.

Okay. And, then if there wasn't the take away capacity, I am just thinking, would you rather have a constraint and just flow at a stable rate longer? Or would you rather put in more capital to have them be flowing at a higher initial rate?

Well, you know that is a balancing act. We would like to be able to monetize every dollar as soon as we put it in the ground. If we see that we will be able to do that with our future growth, and we are going to spend the money to be able to deliver the volumes into the pipeline and do that. I think it's safe to say, in looking at the-- if you take our marketing efforts and what our expectations would be out into the future, I think it is safe to say that we are going to have a fairly significant free cash flow program moving forward up here in the Marcellus. So, we will utilize, prudently utilize that free cash the we will generate. And if we can monetize it up here and make the returns that we are seeing, then we will do that.

Okay. And, then in terms of your active rate for Marcellus, I think you mentioned in your release, 320 MCMF gross, do you know what that is in the net basis?

About 280 MCMF.

279 MCMF.

280 MCMF, okay.

Okay. And, finally, just on the Eagle Ford, of the 25 wells you are going to drill there, are they all going to be in the Buckhorn area or are you also testing the Powderhorn?

I will let Matt Ried, our VP and Regional Manager take that one.

Amir, the majority will be in the Buckhorn area. There will be no wells in Powderhorn this year, and the remainder of the wells will be in our joint venture with our partner over in what will be called our Presidio area.

That is all for me thanks.

Thank you.

Your next question comes from Ray Deacon of Pritchard Capital.

Yes, Hello. Matt, I was wondering if I could follow up with a question. What is your current thinking on EURs in the Eagle Ford.

Well, we have a wide range, it depends on lateral links, but EUR is roughly 375,000 to 600,000 barrels equivalent.

Okay. Got you, great. And, how much is that liquids versus gas, would you guess?

Well, the majority of it is liquids, the vast majority. I am not going to do the percentages for you, but a very small percent of it is gas. Not even-- 85% of it is liquids.

Got it. Great. And, I just had a follow-up on the cost side. I guess, do you have any sort of number for completion cost trends in the Marcellus, quarter over quarter? I've heard some companies talking about maybe 10% or something. I was wondering how much of that you have locked in?

We have it locked in, Ray. We have our drilling equipment and our frac crew locked in on an annual contract. So, we would expect-- and those obviously are the largest component of a completed well cost, but we would expect our cost to be to remain fairly flat.

Okay. Great. And, then just any updates on any plans to further test the Purcell line, are there-- I have not seen any results out of the Heath yet, but are you aware of any other operators that have any success there?

I have not any new numbers out of the Heath, but I would expect now with the spring coming that you are going to see some additional operations up there. And, as far as the Purcell is concerned, we are still focused on the lower Marcellus and we will continue to be focused on the lower Marcellus right now. But, I will say that our one Purcell well that we have up there has done extremely well, and it is a-- the EUR of that well is 8 to 10 days. We have been very pleased with that particular Purcell completion.

Got it, great. Thank you very much.

The next question comes from Eric Hagen of Lazard Capital Markets.

Good morning, Dan. I just want to follow up on the questions from Amir about development mode. In terms of Eagle Ford, it seems you have been experimenting with links. What is the link that you have decided on the optimal months at this point?

Are you talking about in the Marcellus, or the--

Yes, the Marcellus.

Yes, it's still a little bit early, Eric. There's a couple of items. One; we are averaging probably, I want to say our 2011 program was budgeted on something like 3,600, 3,700-foot lateral with 14 to 16 stages or something of that nature. The well we are currently completing right now, the 6,100-foot usable lateral in 26 stages was a pretty good step above what we have been doing. So, we are going to take a look at that once we start producing that, and we will not be able to produce that until we get some of these infrastructures items taken care of.

I would say definitely another component to the length of the laterals is going to be a condition upon the geographics, and the lease configuration and surface area, because there are areas that there are still some folks that have held out. So, there's not force pooling or joint pooling in the Pennsylvania area. And, we have to restrict some of the distances or unit configurations, because some folks do not want to enjoy this domestic clean energy source, natural gas.

Thanks. And, then one quick follow-up on that, you have about 550 or 560 stages being completed, and maybe trying to get at the deliverability from that another way. Do you have any broad estimate or conservative estimate of what each stage will add in terms of production, maybe over a 30- or 90-day period?

Well, as a rule of thumb, I think you could probably back into it a little bit. For example, our six-well pad site, we are producing 51 million a day. It has the upper 70 millions in the number of frac stages, in that particular pad site, we are thinking that deliverability from that pad site would be 70 million or 80 million cubic foot a day, and that would be inclusive of 30 day average.

Okay, great. That is very helpful. Thank you.

Your next question comes from Rodney Eastman of JP Morgan.

Good morning. Just a couple of questions; once the Springville line is in place, how long do you think it will take Cabot to achieve approximately 550 million cubic feet of production?

Well, we have-- right now, Rodney, when you look at our guidance for third and fourth quarter, the Springville line is scheduled sometime during the third quarter and it would probably be toward the latter part of the third quarter. So, we hedge a little bit on exactly what our exit volumes are going to be for 2011, but we do have some backlog. We are doing, running dual tracks here with pipelines, with completions of wells, with configurations on the free flow areas that Jeff had talked about earlier, at Lathrop and over at our Lennoxville facility. So, you know, when you look at the year end, I don't know, we will be between-- this is a swag-- 410 million to 450 million cubic foot a day gross, something like that.

So, after the Springville line comes on, you will not be infrastructure constrained?

At that point in time, we will be almost heads up, less than, except with the frac crews, and that is what my comment was on adding additional frac crew. When we see more clarity on that happening, being the Springville line commissioning, then we do anticipate as rapidly as we physically can to frac additional wells and get them turned in line.

Great. And, then last question; the closed loop system that you are utilizing, what is the impact on cost?

Are you talking about for drilling or are you talking about for the flow back of frac fluids?

For the frac fluids, yes.

Well, the frac fluids, is just not a-- it is kind of an offset, because the water we flow back and we recycle, saves us X amount of water, however much water it is, from having to truck it in to our next frac stage. So, there is very little incremental cost attached to the recycling aspect of it, but we do also have closed loop systems on all five of our drilling rigs for the drill cuttings and what not. That is a closed loop system, and it is about $60,000 incremental cost or something for those closed loop systems per rig.

Okay. Great. That is all I had.

Thanks, Rodney.

(Operator Instructions )

Your next question comes from Dan Morrison at Global Hunter.

Hello. Real quick, have you all seen any your legacy acreage positions, especially in the mid continent, any of the emerging plays coming your direction? Or anything worth talking about at this point?

Well, we have. We have a great position up there, and as you mentioned, Dan, a legacy position up there in the mid continent area. There is the Atoka, the Marmonton, there's a handful of new plays that people are looking at to utilize the horizontal technology to produce. Yes, we are looking at those areas, and we do have a little bit of activity in regard to that.

Okay. Any timing on when you think you might have something worth talking about?

Well, probably at the end of our second-quarter call, we will probably mention a couple of things that we are doing up there.

Great. Thanks.

Your next question comes from Brian Lively, Tudor, Pickering & Holt.

Good morning. Now that you guys had some more run time, on especially some of the more recent wells, can you update us on your 2PKs for EURs per well in the Marcellus?

Well, we haven't-- Brian, we haven't seen anything that we'd be popped with different that what our 2010 program yielded, and that was 10Bs per well. So, as far as coming up with any update or change in that number, we have not scrubbed this early in 2011. We have not changed our position on that yet.

Okay. Well, thinking about that 2010 program, do you have handy, maybe the average 6-month and 12-month cumulative on a per well basis?

Well, I don't-- Steve Lindeman is kind of shuffling over there to look at it.

While he is looking on that, just a clarification; on the Marcellus production for the first quarter, what was the average net production for the quarter?

The average net per quarter? What area, Brian?

Just Marcellus only.

Let's get that specific number and let Steve Lindeman answer your other question, Brian, thanks.

Brian, just some numbers off of our tight curve. From a 90 day perspective, we would anticipate just short of a BCF of recovery. For the first year, about a little over 2 BCF and by the end of the third year, 3 BCF.

Okay. That is really helpful. In the Eagle Ford, last question I have, unless you have the actual net Marcellus numbers, but on the Eagle Ford -- .

20 BCF in the first quarter.

Okay. On the Eagle Ford, the variability of results, what are you guys seeing in terms of why such a big variability? Is this driven by depth location, or is it completion oriented? What is your sense there?

Well, it's several different issues. Depth obviously is a factor, but we are still early on in our program, and we are tweaking a recipe for our stimulation treatments. I think we are getting very close. The last we drilled, it IP'd at the 958 number that Dan mentioned earlier. The low number, as Dan mentioned also, I think in that particular well, we are basically out of the interval we wanted to be in, out of the zone. So, I would discount that well as an issue with the treatment, but we are tweaking our treatment and I think we're we are pretty close to getting that where we want it.

Okay. And, then what are you guys seeing in terms of total completed cost right now for Eagle Ford?

It depends. Again, it depends on where you are and it depends on lateral lengths. I would say it is somewhere between the $7 million and $8.5 million number.

Okay. Appreciate it.

At this time there are no further questions.

Okay. I appreciate everybody joining us. And, as you can see, we still have some near-term installations in our Marcellus. We do anticipate the ramp up to start towards the end of the third quarter with the Springville line. You can see with the tripling of our production since the first quarter of last year up there, that our operation is going extremely well and we have a significant amount of wells in the queue to be able to fill this infrastructure capacity once it is commissioned.

We were happy to get a little bit of cash in from the Haynesville JVs and certainly, we plan on probably utilizing that in some form or fashion this year. At this stage, with basically a flat budget, $600 million, we are still anticipating growing this company, production and reserves, in a significant manner. And, we look forward to our third quarter-- our second quarter release. We think we will have some additional clarity and some, maybe some new items to talk about. Thank you very much.

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