Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Cabot Oil & Gas (NYSE:COG)

Q1 2011 Earnings Call

April 28, 2011 9:30 am ET

Executives

James Reid - Vice President and Manager of South Region

Steven Lindeman - Vice President of Engineering & Technology

Jeffrey Hutton - Vice President of Marketing

Dan Dinges - Chairman, Chief Executive Officer, President and Member of Executive Committee

Analysts

Daniel Morrison - Global Hunter Securities, LLC

Michael Hall

Brian Singer - Goldman Sachs Group Inc.

Raymond Deacon - Pritchard Capital Partners, LLC

Eric Hagen - Lazard Capital Markets LLC

Amir Arif - Stifel, Nicolaus & Co., Inc.

Gil Yang - BofA Merrill Lynch

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Ronny Eisemann - JP Morgan Chase & Co

Operator

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 & Gas First Quarter 2011 Conference Call. [Operator Instructions] I would now like to turn the conference over to Dan Dinges, Chairman and President and CEO.

Dan Dinges

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, our VP of Engineering and Technology, with me today. As you're aware, the boilerplate language that's in our forward-looking statements included in the press release will apply to my comments today.

We have several items to cover, and I'll also expand on the press releases that were issued last night. I'll briefly cover the first quarter financial results and a discussion of our operations and further plans for 2011. And at the end, we'll leave ample time for Q&A.

Cabot did report its financial results 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 3 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 guidance 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 hookup 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 would be dependent upon the timing of these 2 items. And again, that's 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 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 deliverability that we've seen from our completions has not changed, and we continue to add to the backlog of completions for future productivity.

Okay. As part of our marketing effort, our costs associated with the required firm transportation arrangements and our gathering fee have grown. And as such, we are now reflected on separate line items. Previously, these costs were an offset to realized prices. The impact of this change to historical comparisons is 0, 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 costs guidance.

Now let's move to operations for 2011. Our plans remain unchanged from our original budget. We're 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 did take 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 5 basis only hedges, and 5 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 2-well pad site that has been in line for 3 months and is currently producing 36 million cubic foot a day, in addition to our first 6-well pad site that is producing at a curtailed rate of 51 million cubic foot per day. We would expect the 6-well pad site to be able to produce around 70 million to 80 million cubic foot uncurtailed.

On the completion side, we have just finished frac-ing a 5-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're well on our way to finalize 26 stages in this completion. Cabot continues to run 5 rigs in the Marcellus and has a total of 560 stages being completed or cleaned up, waiting on pipeline or waiting to be completed. Our dedicated frac crew has been very effective, averaging 3 completions 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 a total of 7 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 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. And 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's most visible, the Heath, we have a completion crew scheduled for late May. This well is designed for an 8-stage frac, and we'll report the results when we get these results available. We do have several other items or several other initiatives going on, which we will also report on in a timely fashion in the appropriate time. We have been asked about our future plans in the Heath and right now, we're just currently focused on the completion of this particular well.

Now let's move south into the Eagle Ford area and our Buckhorn area. The company has successfully completed 3 recent Eagle Ford wells. Each well is a 100% Cabot well and they're located in Frio County. The wells flowed at a 24-hour rate of 558 barrels per day equivalent, 400 -- excuse me, that's 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. But nevertheless, it's early in the completion techniques in this area and we certainly like the results we've 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 3 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 our activity in East Texas and our Haynesville joint ventures, Cabot has finalized 2 agreements that would 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 at similar levels and with the acreage held by the initial well 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 nonoperated units, both producing and nonproducing, with 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 in the 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's operational program remains fairly simple, spending $350 million in the best area industry has discovered in the Marcellus, that will deliver us significant returns with stellar reserve and production growth. Additionally, we'll allocate the remainder of our capital, $250 million, to the oil window at 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 rate of returns to many oil projects plus a great rate of return project in the South region. Additionally, we had several other oil initiatives that we are moving on.

Melissa, with that quick overview, I'll stop here and answer any questions the group might have.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

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

Dan Dinges

Yes. We have, of course, the 5 rigs 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're flowing back the load water right now and cleaning those up or we're waiting on the pipeline or we're waiting for the frac crew to move from the current pad site it's on to another pad site.

Brian Singer - Goldman Sachs Group Inc.

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

Dan Dinges

Yes. That is included in the 560.

Brian Singer - Goldman Sachs Group Inc.

It's included. Okay.

Dan Dinges

But we are currently, of course, drilling wells right now that we're may be at TD, we haven't run pipe on yet, that would add to that count.

Brian Singer - Goldman Sachs Group Inc.

Got it. And then as you think about 2012, can you talk about your activity and availability in getting additional -- securing additionally firm transport 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?

Dan Dinges

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

Jeffrey Hutton

Great. Brian, to begin with, in 2012, we're poised to expand out of our core area to the North with the Laser Pipeline project. We've got a compressor site up there already and construction is underway on that pipeline. We have say about 150,000 a day of take-away going north to Millennium, and that will be a 2012 kind of timing. Also in 2012, we're expecting an expansion of the Williams Springville line going to Transco. I think that's scheduled for approximately midyear of 2012, where we'll 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'll be drilling some additional wells there for 2012.

Brian Singer - Goldman Sachs Group Inc.

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

Dan Dinges

Well, obviously, we work closely with the DEP and we're current with all of the projects that are going on up there and 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're all aware of, have been along the lines of a severance tax. And Corbett's made clear that he is not in favor of a severance tax. There's 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 anybody's guess at this stage. More on the regulatory side, they recently announced -- Mike Krancer, the Secretary of the DEP, recently announced the -- where we do not -- they do not want any produced water to be taken to the public disposal sites anymore. 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's non-effect on Cabot. I think with the decision made, I think the majority of the industry will be recycling their produced water, so I don't think that's 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 controlling hydraulic fractioning, 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 the groundwater commission's website, 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. But 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're doing all we can right now to mitigate any potential risk. 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 a 0 potential for upsets. I think we do our fair share and we spend millions and millions of dollars to mitigate any risk. But 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 a 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.

Operator

Your next question comes from Michael Hall of Wells Fargo.

Michael Hall

Just if you could kind of help me understand how you worked down the backlog? Like you said, you got 560-some-odd stages waiting on something. As of last count, I think it was 450 waiting on completion. You'll generate another -- if you're drilling 51-some-odd wells, you'll generate another 760-plus stages that need to be completed. So with one frac crew doing 3 stages per day and, like you said, 20 pumping days per month, I'm having trouble seeing how that crew is enough to work down that backlog in any meaningful way. And just curious on your thoughts on adding another crew? And what time that might come under consideration and how you're thinking about that?

Dan Dinges

That's a fair question, Mike, and I appreciate it. We have -- in fact, we had 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 6-stage -- I mean 6-well pad, we have that particular pad 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 buildout, which we're getting very, very close to on the Lathrop station dehy [dehydration] and additional pipelines, and Williams, we know, is working diligently to get that pipeline put into the South, we do anticipate that we'll be able to add another frac crew. It'll probably be towards the end of '11 or the beginning of '12 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.

Michael Hall

Okay. Great. That's helpful. It makes sense. And then I guess one more. You got a lot of pipelines being built out in the region. Obviously, you've got a lot of your own capacity coming on. Are there any permitting issues or anything along those lines we ought to keep in mind as it relates to any of these buildouts?

Dan Dinges

I'll let Jeff Hutton answer that, Mike.

Jeffrey Hutton

Mike, I'll 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, kind of the same time period. Obviously, the interstate pipelines have imminent domain and they -- these are all PERC [ph] -approved projects. And so we have no issues surrounding those projects in terms of being built. Obviously, Millennium has an open season. They'll be expanding that pipeline, kind of the same set of circumstances with them. Transco has got a project on the book, and again, same story. Then you get into kind of the midstream projects that do have permitting and regulatory issues that are not federally regulated. So far, I will knock on wood here, Laser Pipeline got their New York permits and PA permits. Williams has a number of their permits. I think they're 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 that we're operating in. So, so far, so good.

Michael Hall

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

Jeffrey Hutton

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's going to operate in the 600-pound range, which means it will have free flow capabilities up there, we think, for quite a while. So it shouldn't be compressor limited. And that's, again, kind of a third quarter timing on that. They'll have -- they should have everything ready to go, and of course we'll be ready to go. And then in the eastern part of our block, at the Lennoxville area, we've planned -- we already have our 12-inch tap there at Tennessee and a compressor site. Again, we were able to free flow quite a bit of gas in the Tennessee without compression prior to building Lathrop. And so we intend to do the same thing, although there is already compressors ordered and the site is there, and right away is acquired. So I would say that's kind of 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.

Operator

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

Gil Yang - BofA Merrill Lynch

You mentioned the -- 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?

Dan Dinges

It was a culmination of the true-up from the year-end reserves that all kind of 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 this same question last night. It is the better well performance that we reported back in February. And it's also, if you think about our Marcellus gas, it's got a UOP [ph] rate of less than $1 from a DD&A perspective, and it is a growing component of the blended rate. In other words, that accounts for 2/3 to 3/4 of our production base. So that's the dynamic that is driving the DD&A rate down.

Gil Yang - BofA Merrill Lynch

Okay. So it's not a since-year-end change, it's just that you trued it up to what you reported for the year end.

Dan Dinges

Right.

Gil Yang - BofA Merrill Lynch

Okay. The pads, what's the expectation for the well results on the pads versus the individual expectations that you had today?

Dan Dinges

Well, there's really no difference in our expectations if we drilled a 6-well pad site versus a 1-well site. The efficiencies come in 2 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 we 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 frac-ing with the wells on the multi-well site.

Gil Yang - BofA Merrill Lynch

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

Dan Dinges

What, do you mean interference in the form of, do we see a frac -- when we're pumping in one, do we see it in the other well?

Gil Yang - BofA Merrill Lynch

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

Dan Dinges

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 unique gas. Once we start down spacing, we'll be able to answer that better on exactly what the appropriate spacing is going to be for the most efficient drainage.

Gil Yang - BofA Merrill Lynch

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?

Dan Dinges

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

Gil Yang - BofA Merrill Lynch

Okay. And just to follow-up on Brian's question. How much deliverability is behind -- is held back in those wells that are being restricted today?

Dan Dinges

Well, on that -- on just the one well, I mean, on the 6-well pad site, we think there is an incremental 20 million to 30 million a day just on that 6-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 exact volumes if we would draw all those wells down, say, to the suction pressure. But it's some volumes, I just don't have exact number.

Gil Yang - BofA Merrill Lynch

Okay. And when the pipelines are all set up and ready to go in terms of the third quarter, how much will that -- will that deliverability still be there for that -- for example, for that 6-well pad? Will it still be 20 million to 30 million or will that deliverability have disappeared by then because of well decline?

Dan Dinges

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

Operator

Your next question comes from Amir Arif of Stifel.

Amir Arif - Stifel, Nicolaus & Co., Inc.

Just a follow-up to Gil's question. Just in terms of going forward, how are you guys thinking of the optimal development, if there wasn't any restriction on capital -- on take-away constraints? Is it a 6-well pad site or are you thinking smaller developments just given the field-level constraints with building the pads?

Dan Dinges

Well, I think -- we've just now gotten to our 6-well pad site. I think that's a very efficient pad site. We might be looking in the future at an 8-well pad site. But we have not made that determination yet. But we certainly think the 6-well pad site's a very efficient site.

Amir Arif - Stifel, Nicolaus & Co., Inc.

And then if there wasn't the take-away capacity, I mean, I'm just thinking would you rather have it constrained 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?

Dan Dinges

Well, that's 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, then we're 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 effort and what our expectations would be out into the future, I think it's safe to say that we're going to have a fairly significant free cash flow program moving forward up there in the Marcellus. And so we'll utilize, prudently utilize that free cash that we'll generate. And if we can monetize it up here and make the returns that we're seeing, then we'll do that.

Amir Arif - Stifel, Nicolaus & Co., Inc.

Okay. And then in terms of your exit rate from Marcellus. I think you mentioned in your release 320 gross. Do you know what that is on a net basis?

Dan Dinges

About 280.

Jeffrey Hutton

279.

Amir Arif - Stifel, Nicolaus & Co., Inc.

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

Dan Dinges

I'll let Matt Reid, our VP and Regional Manager, take that one.

James Reid

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 and it will be called our Presidio area.

Operator

Your next question comes from Ray Deacon of Prichard Capital.

Raymond Deacon - Pritchard Capital Partners, LLC

Matt, I was wondering if I could follow-up with a question. What's your current thinking on EURs in the Eagle Ford?

James Reid

We've got a wide range, it depends on lateral lengths. But our EUR's roughly 375,000 to 600,000 barrels equivalent.

Raymond Deacon - Pritchard Capital Partners, LLC

Okay. Got you. Great. And how much of that is liquids versus gas would you guess?

James Reid

Majority of it's liquids, vast majority. I'm not going to do the percentages for you. But very small percentage of it's gas. I would say 85% of it's liquids.

Raymond Deacon - Pritchard Capital Partners, LLC

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

Dan Dinges

Well, 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 components of a completed well cost, but we would expect our costs to remain fairly flat.

Raymond Deacon - Pritchard Capital Partners, LLC

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

Dan Dinges

I haven't seen any new numbers out of the Heath, but I would expect now with the spring coming that you're 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'll continue to be focused on the lower Marcellus right now. But I will say that our 1 Purcell well that we have there up there has done extremely well, and it is a -- the EUR of that well is 8 to 10 B, so we've been very pleased with that particular Purcell completion.

Operator

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

Eric Hagen - Lazard Capital Markets LLC

Dan, just thought I'd follow-up on the questions from Amir about possible development mode. In terms of lateral lengths, it seems like you've been experimenting with various lengths. Have you -- what is the range and do you think you've decided on an optimal length at this point?

Dan Dinges

Are you talking about in the Marcellus or in the...

Eric Hagen - Lazard Capital Markets LLC

Yes, in the Marcellus.

Dan Dinges

Yes, it's still a little bit early, Eric. There's a couple of items. One, we're averaging, probably -- I want to say our 2011 program was kind of budgeted on something like a 3,600, 3,700-foot lateral with 14 to 16 stages or something of that nature. The well we are currently completing right now, this 6,100-foot usable lateral and 26 stages was a pretty good step above what we have been doing. And so we're going to take a look at that once we start producing that. And we won't be able to produce that until we get some of these infrastructure items taken care of. But I would say that another well -- definitely, another component to the length of the laterals is going to be a -- conditioned upon the geographics and the lease configuration and surface area, because there's areas that there's still some folks that have held out. So there's not forced pooling or joint pooling in the Pennsylvania area. And we have to restrict some of the distances or unit configurations because some folks just do not want to enjoy this domestic, clean energy source, natural gas.

Eric Hagen - Lazard Capital Markets LLC

And one quick follow-up on that was you have about, I think, 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?

Dan Dinges

Well, as a rule of thumb, I think you could probably back into it a little bit. Just for example, our 6-well pad site, we're producing 51 million a day. It has the upper 70s in the number of frac stages in that particular pad site. We're thinking that deliverability from that pad site would be 70 million, 80 million cubic foot a day and that would be inclusive of a 30-day average.

Operator

Your next question comes from Ronny Eisemann of JPMorgan.

Ronny Eisemann - JP Morgan Chase & Co

Just a couple of quick 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?

Dan Dinges

Well, we have -- right now, Ronny, 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 towards the latter part of the third quarter. So we hedge a little bit on exactly what are 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 when you look at the year end, I don't know, we'll be between -- this is a swag, of 410 million to 450 million cubic foot a day gross, something like that.

Ronny Eisemann - JP Morgan Chase & Co

So after the Springville line comes on, you won't be infrastructure-constrained?

Dan Dinges

At that point in time, we'll be -- I think we'll be almost heads up, less and except with the frac crews. And that's what my comment was on adding additional frac crew when we see more clarity on that happening. That happening, being the Springville line commissioning. But we do anticipate as rapidly as we physically can to frac additional wells and get them turned in line.

Ronny Eisemann - JP Morgan Chase & Co

And then last question, the closed loop system that you're utilizing, what is the impact on costs?

Dan Dinges

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

Ronny Eisemann - JP Morgan Chase & Co

For the frac fluids, yes.

Dan Dinges

Well, frac fluid is just not a -- it's 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's very little incremental costs attached to the recycling aspect of it. But we do also have closed loop systems on our -- all five of our drilling rigs, for the drill cuttings and whatnot. That's a closed loop system, and it's $60,000 incremental costs or something for those closed loop systems per rig.

Operator

[Operator Instructions] Your next question comes from Dan Morrison, Global Hunter.

Daniel Morrison - Global Hunter Securities, LLC

Real quick, have you all seen in any of your legacy acreage positions, especially in the Mid-Continent, any kind of emerging plays coming in your direction? Or anything worth talking about at this point?

Dan Dinges

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. And there is the Atoka, there's the Marmaton, there's the -- there's a handful of new plays that people are looking at to utilize the horizontal technology to produce. And yes, we are looking at those areas and we do have a little bit of activity in regard to that.

Ronny Eisemann - JP Morgan Chase & Co

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

Dan Dinges

We'll probably at the end of the -- on our second quarter call, we'll probably mention a couple of things that we're doing up there.

Operator

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

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Now that you guys have some more run time on especially some of the more recent wells, can you update us on your 2pk's [ph] for EURs per well in the Marcellus?

Dan Dinges

Well, we haven't -- Brian, we haven't seen anything that would be [indiscernible] with -- different than what our 2010 program yielded. And that was a 10 Bs per well. So as far as coming out 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.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

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

Dan Dinges

Well, I don't -- we've got -- Steve Lindeman's kind of shuffling over there to look at it.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

While he's looking on that, just a clarification. On the Marcellus production for the first quarter, what was the average net production for the quarter?

Dan Dinges

The average net per quarter -- what area, Brian?

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

Just Marcellus only.

Dan Dinges

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

Steven Lindeman

Brian, just the numbers off of our type 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.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

That's really helpful. In the Eagle Ford, last question I have, if you -- unless you guys have the actual net Marcellus numbers. But on the Eagle Ford...

Steven Lindeman

12 Bcf in the first quarter.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

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? Just what is your sense there?

Jeffrey Hutton

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

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc.

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

Jeffrey Hutton

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

Operator

At this time, there are no further questions.

Dan Dinges

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. But 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's 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. But at this stage, with basically a flat budget, $600 million, we're 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 maybe some new items to talk about. Thank you very much.

Operator

Thank you for participating in today's conference. You may now disconnect.

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Cabot Oil & Gas' CEO Discusses Q1 2011 Results - Earnings Call Transcript
This Transcript
All Transcripts