Coterra Energy - Earnings Call - Q1 2011
April 28, 2011
Transcript
Speaker 4
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 Coterra Energy First Quarter 2011 Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, then the number one on your telephone keypad. If you would like to withdraw your question, press the pound key. Thank you. I would now like to turn the conference over to Dan Dinges, Chairman, President, and CEO. Please go ahead.
Speaker 1
Thank you, Melissa, and 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, including 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. At the end, we'll leave ample time for Q&A. Coterra Energy 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. The 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 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 to 70 million cubic feet of gas to the market. Any upside to our second quarter guidance would be dependent upon the timing of these two items. 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 pipeline 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 Teal at the end of the second quarter will be 550 million cubic feet 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 fees 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 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 remain 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 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. Coterra Energy 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 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. Coterra Energy 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 first six-well pad site that is producing at a curtailed rate of 51 million cubic foot per day, we would expect this six-well pad site to be able to produce around 70 to 80 million cubic foot uncurtailed. On the 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're well on our way to finalize 26 stages in this completion. Coterra Energy 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 a 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 cubic foot per day, and the Teal station will have another 100 million a day to get us to that 550 I previously mentioned. Actually, flowing capacity will be tied to the interstate takeaway capacity and the completion of the Williams-Springville pipeline 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's most visible, the Heath. We have a completion crew scheduled for late May. This well is designed for an eight-stage frack and will 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. In our Buckhorn area, the company has successfully completed three recent Eagle Ford wells. Each well is a 100% Coterra 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 per day equivalent. The 345 barrels per day was a well that we got a little bit out of zone in.
Nevertheless, it's early in our 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 three wells that have been drilled in our 18,000-plus acre AMI with EOG. Coterra 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, Coterra has finalized two agreements that would allow us to maintain a large percentage of our Haynesville acreage with no capital investment. These agreements will provide Coterra 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 Coterra has been working on is to sell a minority interest in some non-operated units, both producing and non-producing, with net production to Coterra of approximately 4 million cubic feet per day. That is executed and moving towards close. Combined, these agreements will allow Coterra 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 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.
Cash proceeds are expected to be in the range of $50 million to $55 million, subject to final adjustment. In closing, Coterra Energy'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 in the Eagle Ford, which will increase our oil reserves and our production year over year. 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 have 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.
Speaker 4
Thank you. At this time, I would like to remind everyone, in order to ask a question, please press star, then the number one on your telephone keypad. Your first question comes from Brian Singer of Goldman Sachs.
Speaker 2
Thank you. Good morning. Hey, Brian. A couple of 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?
Speaker 1
Yeah. We have, of course, the five rigs are currently running on five different pad sites, and those particular wells or those rigs on some of those pad sites, we have 500 and combined, we have 560 stages, fracked stages that have pipe run. 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 frack crew to move from the current pad site it's on to another pad site.
Speaker 2
Got it. I'm sorry, was there a backlog as well, and maybe I missed that, of wells that have been drilled but haven't yet been completed?
Speaker 1
Yeah, that is included in the 560.
Speaker 2
Included.
Speaker 1
Yeah.
Speaker 2
Okay.
Speaker 1
We are currently, of course, drilling wells right now that we're maybe at TD we haven't run pipe on yet that would add to that count.
Speaker 2
Got it. As you think about 2012, can you talk about your activity and availability in getting additional, securing additional firm transport and compression capacity? Are you seeing, how active are you there? Are you seeing any changes in terms then? Are you seeing any changes in the tightness in the market?
Speaker 1
Yeah. 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 takeaway. I'll let him answer some of that.
Speaker 3
Hey, 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, I see, about 150,000 a day of takeaway going north to Millennium, and that'll 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 mid-year of 2012, and we'll be getting some additional capacity going south to Transco. The Byrd project in 2012 will be to the east of our core area at Lenoxville. We have a compressor site there planned, we have right of way, and we'll be drilling some additional wells there for 2012.
Speaker 2
Great. Thanks. Lastly, with a lot of 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? Do you anticipate any additional costs of compliance or costs on the environmental side?
Speaker 1
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.
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 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 frack water, and we are not taking any of our produced frack fluids to any of these sites. It's not a fact on Coterra Energy. I think with the decision made, I think the majority of industry will be recycling their produced water.
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 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. With our full disclosure now of frack fluids and chemicals on the Groundwater Commission's website, frackfocus.org, I think the clarity and concern about what we put in frack 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. We are doing all we can right now to mitigate any potential risk. 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. We do our fair share, and we spend millions and millions of dollars to mitigate any risk.
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, 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.
Speaker 2
Thank you. Appreciate it. Thanks so much.
Speaker 1
That was a little long-winded, Brian, but I'll get off my platform.
Speaker 4
Your next question comes from Michael Hall of Wells Fargo.
Speaker 2
Thanks. Good morning and congrats on the final quarter.
Speaker 1
Thanks, Mike.
Speaker 2
Just curious if you could kind of help me understand how you work 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. With one frack crew doing three stages per day and, like you said, 20 pumping days per month, I'm having trouble seeing how that crew's 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're thinking about that.
Speaker 1
Good, fair question, Mike, and I appreciate it. We have, in fact, moved 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 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 with the infrastructure build-out, which we're getting very, very close to on the Lathrop compressor station, dehydration units, and additional pipelines. 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 frack crew. It'll 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. It is in our plans to have more than one frack crew out there.
Speaker 2
Okay. Great. It makes sense. I guess one more, you've got a lot of pipelines being built out in the region. Obviously, you've got a lot of 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 build-outs?
Speaker 1
I'll let Jeff Hutton answer that, Mike.
Speaker 2
Great. Thanks.
Speaker 3
Yeah, 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, interstate pipelines have eminent domain, and these are all FERC-approved projects. We have no issues surrounding those projects in terms of being built. Also, Millennium has an open season. They'll be expanding that pipeline, kind of the same set of circumstances with them. Transco's got a project on the books, and again, same story. You get into kind of the midstream projects that do have permitting and regulatory issues that are not federally regulated. So far, I'm knocking on wood here. Laser pipeline has 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 far, it's looking good.
Speaker 2
Okay. I guess actually 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. You've got 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 takeaway capacity?
Speaker 3
Yeah, sure. The laser, again, 150,000 a day with some additional capacity being negotiated. That pipeline's going to operate at fairly low pressure in this part of the Marcellus. It's going to operate in the 600-pound range, which means it will have free float capabilities up there, we think, for quite a while. It shouldn't be compressor limited. That's, you know, 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. In the eastern part of our block at the Lenoxville area, we've planned, we already have a 12-inch tap there with Tennessee and a compressor site. We were able to free float quite a bit of gas into Tennessee without compression prior to building Lathrop.
We intend to do the same thing, although there are already compressors ordered and the site is there and right of way is acquired. I would say that's kind of an end-of-the-year first quarter 2012 timing. The 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.
Speaker 2
Okay, that's helpful. Thanks very much. Thanks for your time again.
Speaker 1
Thanks.
Speaker 4
Your next question comes from Gil Yang of Bank of America.
Speaker 0
Good morning.
Speaker 1
Morning.
Speaker 0
You mentioned you had DD&A reductions in the quarter. Can you comment on whether that was from better well performance or lower capital costs expected going forward?
Speaker 1
It was a culmination of the true-up from the year-end reserves that all kind of flowed 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. It's also, you know, if you think about our Marcellus gas, it's got a UOP 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 two-thirds to three-quarters of our production base. That's the dynamic that is driving the DD&A rate down.
Speaker 0
Okay. It's not a since-year-end change. It's just that you true it up to what you reported for the year-end.
Speaker 1
Right.
Speaker 0
Okay. For the pads, what's the expectation for the well reserves on the pads versus the individual expectations that you have today?
Speaker 1
There is really no difference in our expectations if we drilled a six-well pad site versus a 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. We do think we do get some incremental gain. It is not, you know, 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 sites.
Speaker 0
Okay. Any interference is offset by the synergies of the simul frac?
Speaker 1
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?
Speaker 0
No, I just meant the drainage volumes are overlapping, so you're not getting the full EUR for each well because they're overlapping a little bit.
Speaker 1
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 downspacing, we'll be able to answer that better on exactly what the appropriate spacing is going to be for the most efficient drainage.
Speaker 0
What are 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?
Speaker 1
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.
Speaker 0
Okay. Just to follow up on Brian's question, how much deliverability is held back in those wells that are being restricted today?
Speaker 1
On just the one well, on the six-well pad site, we think there is an incremental 20 to 30 million a day just on that six-well pad site. Some of the other wells that we are holding back have a flow tubing pressure 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, but it's some volumes. I just don't have the exact number.
Speaker 0
Okay. When the pipelines are all set up and ready to go in the third quarter, how much will that deliverability still be there for that, for example, for that six-well pad? Will it still be 20 to 30 million, or will that deliverability have disappeared by then because of well decline?
Speaker 1
You certainly know every well has declined. We haven't seen exactly what these particular wells will do because they haven't been producing that long. 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.
Speaker 0
Okay, great. Thanks a lot.
Speaker 1
Thank you.
Speaker 4
Your next question comes from Amir Arraf of Stifel.
Speaker 2
Thanks. Good morning, guys.
Speaker 1
Morning.
Speaker 2
Just to 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 restrictions on capital or takeaway constraints? Is it a six-well pad site, or are you thinking smaller developments just given the field-level constraints with building the pads?
Speaker 1
I think we've just now gotten to our six-well pad site. I think that's a very efficient pad site. We might be looking in the future at an eight-well pad site, but we have not made that determination yet. We certainly think a six-well pad site is a very efficient site.
Speaker 2
If there wasn't the takeaway capacity, 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?
Speaker 1
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'll 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, 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 here in the Marcellus. We'll 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.
Speaker 2
Okay. 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?
Speaker 1
About 280.
Speaker 3
279.
Speaker 2
Okay. 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?
Speaker 1
Yeah, I'll let Matt Reid, our Vice President and Regional Manager, take that one.
Speaker 3
No, the majority will be in the Buckhorn area. There'll be no wells in Powderhorn this year. The remainder of the wells will be in our joint venture with our partner over in what we call our Presidio area.
Speaker 2
Okay, that's all for me. Thanks.
Speaker 1
Thank you.
Speaker 4
Your next question comes from Ray Deacon of Pritchard Capital.
Speaker 2
Yeah. Hey, Matt, I was wondering if I could follow up with a question. What's your current thinking on EURs in the Eagle Ford?
Speaker 3
We've got a wide range. It depends on, you know, lateral lengths, but our EUR is roughly 375,000 to 600,000 barrels of oil equivalent.
Speaker 2
Gotcha. Great. How much of that is liquids versus gas, would you guess?
Speaker 3
The majority of it's liquids, a vast majority. I'm not going to do the percentages for you. A very small % of it's gas, I would say.
Speaker 2
Okay.
Speaker 3
Not even 85% of its liquids.
Speaker 2
Okay. Got it. Great. 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? Some companies talk about maybe 10% or something, and I was wondering how much of that you have locked in.
Speaker 1
We have it locked in, right? We have our drilling equipment and our frack crew locked in on an annual contract. We would expect, and those obviously are the largest components of a completed well cost, we would expect our cost to remain fairly flat.
Speaker 2
Okay. Great. Any update on any plans to further test the Purcell line? Have 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?
Speaker 1
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. 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. I will say that our one Purcell well that we have up there has done extremely well, and it is an EUR. That well is 8 to 10 BCF, so we've been very pleased with that particular Purcell completion.
Speaker 2
Great. Thank you very much.
Speaker 4
Your next question comes from Eric Hagen of Lazard Capital Markets.
Speaker 2
Hey, good morning, Dan. Just had a follow-up on the questions from Amir about optimal development mode. In terms of lateral lengths, it sounds like you've been experimenting with various lengths. What is the range, and do you think you've decided on an optimal length at this point?
Speaker 1
Are you talking about in the Marcellus or the Haynesville?
Speaker 2
Yeah, the Marcellus. Yeah, the Marcellus.
Speaker 1
Yeah, it's still a little bit early, Eric. There's a couple of items. One, you know, we're averaging probably, oh, 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, the 6,100-foot usable lateral and 26 stages, was a pretty good step above what we have been doing. We are 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. I would say that another, 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's areas that there's still some folks that have held out.
There's not forced pooling or joint pooling in the Pennsylvania area. 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.
Speaker 2
Thanks. One quick follow-up on that was you have about, I think, 550 or 560 stages being completed. 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?
Speaker 1
I think you could probably back into it a little bit. For example, our six-well pad site, we're producing 51 million a day. It has the upper 70s in the number of frack stages in that particular pad site. We're thinking that deliverability from that pad site would be 70, 80 million cubic foot a day, and that would be inclusive of a 30-day average.
Speaker 2
Okay. Great. That's very helpful. Thanks.
Speaker 4
Your next question comes from Ronnie Eisman of JPMorgan.
Speaker 2
Good morning, guys. Just a couple of quick questions. Once the Williams-Springville pipeline is in place, how long do you think it'll take Coterra Energy to achieve 5.550 BCF of production?
Speaker 1
Right now, Ronnie, when you look at our guidance for the third and fourth quarter, the Williams-Springville pipeline is scheduled sometime during the third quarter, and it would probably be towards the latter part of the third quarter. You know we hedge a little bit on exactly what our exit volumes are going to be for 2011. We do have some backlog. We are running dual tracks here with pipelines, with completions of wells, with configurations on the free flow areas that Jeff had talked about earlier at the Lathrop compressor station and over at our Lenoxville facility. When you look at the year-end, I don't know, we'll be between, you know, this is a swag, 410 to 450 million cubic feet a day gross, something like that.
Speaker 2
After the Williams-Springville pipeline comes on, you won't be infrastructure constrained?
Speaker 1
At that point in time, I think we'll be almost heads up, except with the frack crews. That's what my comment was on adding additional frack crew when we see more clarity on that happening. That happening being the Williams-Springville pipeline commissioning, we do anticipate as rapidly as we physically can to frack additional wells and get them turned in line.
Speaker 2
Great. Last question, the closed-loop system that you're utilizing, what is the impact on costs?
Speaker 1
Are you talking about for drilling, or are you talking about for the flowback frack fluids?
Speaker 2
For the frack fluid, yeah.
Speaker 1
Frack 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. There's very little incremental cost attached to the recycling aspect of it. We do also have closed-loop systems on all five of our drilling rigs for the drill cuttings and whatnot. That's a closed-loop system, and it's about $60,000 incremental cost or something for those closed-loop systems per rig.
Speaker 2
Okay. Great. That's all I had.
Speaker 1
Thanks, Ronnie.
Speaker 4
Again, to ask a question, please press star one. Your next question comes from Dan Morrison, Global Hunter.
Speaker 2
Hey, guys. Real quick, have y'all seen in any of your legacy acreage positions, especially in the Mid-Continent, any of the kind of emerging plays coming in your direction? Or maybe worth talking about at this point?
Speaker 1
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, there's the Marmiton, 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.
Speaker 2
Okay. Any timing on when you think you might have something worth talking about?
Speaker 1
At the end of our second quarter call, we'll probably mention a couple of things that we're doing up there.
Speaker 2
Great. Thanks.
Speaker 4
Your next question comes from Brian Lively, Pickering Energy Partners.
Speaker 2
Good morning. Now that you guys have some more runtime on especially some of the more recent wells, can you update us on your 2P case for EURs per well in the Marcellus?
Speaker 1
We haven't seen anything that would be different than what our 2010 program yielded, and that was a 10 Bcf per well. 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.
Speaker 2
Okay. Thinking about that 2010 program, do you have handy maybe the average 6-month and 12-month cumulative production numbers on a per-well basis?
Speaker 1
I don't, we had Steve Lindeman's kind of shuffling over there to look at it.
Speaker 2
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?
Speaker 1
The average net per quarter of what production, what area, Brian?
Speaker 2
Just Marcellus only.
You answered the other one.
Speaker 1
The average.
Speaker 2
Okay. Yeah.
Speaker 1
Let's get that specific number and let Steve Lindeman answer your question, Brian. Thanks.
Speaker 2
Brian, just some 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 below 2 BCF, and by the end of the third year, 3 BCF.
Okay. That's really helpful. In the Eagle Ford, last question I have, unless you guys have the actual net Marcellus numbers, on the Eagle Ford.
Speaker 1
Oh, it's 3 BCF in the first quarter.
Speaker 2
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, you know, depth location, or is it completion-oriented? Just what is your sense there?
Speaker 3
It's 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'd at the 958 number that Dan 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, out of zone. I would kind of discount that well as an issue with the treatment. We are tweaking our treatment, and I think we're pretty close to getting that to where we wanted.
Speaker 2
Okay. What are you guys seeing in terms of total completed costs right now for the Eagle Ford?
Speaker 3
It depends. Again, it depends on where you are, and it depends on lateral lengths. I would say it's somewhere between the $7 million, $8.5 million dollar number.
Speaker 2
Okay, appreciate it.
Speaker 4
At this time, there are no further questions.
Speaker 1
Okay. I appreciate everybody joining us. 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 Williams-Springville pipeline. 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. At this stage, with basically a flat budget of $600 million, we're still anticipating growing this company production and reserves in a significant manner. We look forward to our second quarter release.
We think we'll have some additional clarity and maybe some new items to talk about. Thank you very much.
