Coterra Energy Inc (CTRA) 2010 Q3 法說會逐字稿

Good morning, I will be your conference operator today. At this time I would like to welcome everyone to the Cabot Oil & Gas third quarter 2010 conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. (Operator Instructions).

I would now like to hand the program over to Mr. Dan Dinges, Chairman, President, and CEO. Please go ahead, sir.

Thank you, Operator. Good morning, appreciate you joining us for this third quarter teleconference call. I have Scott Schroeder, our CFO; Jeff Hutton, VP of Marketing; Matt Reid, VP of our South Region; and Phil Stalnaker, VP of our North Region joining me today for the call. Before we start, forward looking statements included in the press release apply to my comments today. Now let's get into our releases last night for the quarter.

Cabot Oil & Gas reported clean net income of approximately $32 million, or $0.31 per share, which exceeded consensus expectations. When you compare these numbers against the previous year third quarter, lower natural gas prices, even with our higher production, did not match the previous year numbers. The selected item for the quarter were mainly an impairment and pension-termination-related expenses. The impairment includes two legacy South Texas fields that have not received any capital, and we have no planned operations for 2011. The pension charge relates to the acceleration of cost for the plan, which the Company terminated September 30, 2010. This amortization will occur for the next five quarters as we go through the regulatory process to unwind the plan. I highlighted the quarter, and I think a very positive trend was the 41% production growth versus last year's comparable production volumes for the third quarter.

Sequentially, from the second quarter, production grew 18%, another significant accomplishment as the Company exceeded it's production guidance targets. Additionally, year-to-date growth levels are 22% over last year's first nine months, and in fact, yesterday, our year-to-date matched the full-year level reported for 2009, so our production for the remainder of the year will represent year-over-year growth. Natural gas prices, everybody's aware, very soft, realizations experienced a 27% decline for the quarter while oil prices remained strong. Both realizations were positively impacted by hedges for the quarter.

In terms of hedging, we remain relatively unhedged for 2011, but we did add a costless collar contract for all of 2011, which is indicated on our web site. In our guidance, we did post new guidance increasing fourth quarter production for 2010 and established 2009 guidance. The full-year expectation for 2010 is now about 25% reported growth. As we move into 2011, and with the second phase of Lathrop Steel pending, we are providing volumes for the first quarter of 2011 only. However, with no additional capacity from Lathrop, growth expectations are approximately 20% for 2011 full year, and, depending on the ultimate timing with Lathrop, percentage growth would only increase from that floor. As soon as we have full clarity on this point, we will communicate the timing and fine-tune further growth expectations.

The new guidance for cost highlights the impact of the expanding production base combined with operations focused in just three basins for 2011. Additionally, the capital program changes are identified, establishing 2011 at $600 million and moving the remainder of 2010 up $65 million to $790 million. The two main reasons for the capital increase are our participation in non-operated wells in the Haynesville/Bossier combined with the increased cost of pumping services industry is seeing across the board. To assist with capital allocation in 2011, the Haynesville/Bossier area, we are working on a joint venture to fund this area for 2011. Additionally, we have provided for an increase to our estimates for pumping services commensurate with current levels plus added a factor for inflation. Also, we will reduce our rig activity in both regions next year. However, we will still be able to realize our production growth projections established in our guidance.

Let's move to operations. While we currently have operations ongoing in the Marcellus, Haynesville, and Eagle Ford for 2011, we will concentrate our capital allocation in the Marcellus and Eagle Ford. In the South Region for the remainder of 2010, Cabot is participating in 16 outside-operated Haynesville /Bossier wells that are currently drilling, completing or waiting on completion, with working interests generally ranging from 10% to 20%. Results to date in the play continue to show production at high initial rates with excellent recoverable reserves. This is true for both the Haynesville and Bossier formations.

We continue to be encouraged by the Bossier wells on and around our acreage. Cabot has participated in Bossier four wells in this area; two of the wells have been completed and have performed equal to or better than the Haynesville completions. The other two remaining wells are scheduled to be completed before year-end. This recent success reinforces or belief that our acreage is located in a core area for both zones. Though unpopular today, our capital allocated this play continues to capture a significant resource potential for the future. As I previously mentioned, Cabot is seeking a 33% working interest, non-operated -- non-operating partner in our Haynesville/Bossier acreage. This joint venture would potentially include some up-front consideration, plus a capital carry and an AMI, which allows for participation in future acreage acquisition. This process is moving forward as we speak.

Moving down further South Texas, as reported last night, the Company successfully completed it's third Eagle Ford well, the Arminius Energy Trust 2H, which is 100%-operated Cabot well. Located in Frio County, was drilled to a total depth of 13.175 with a 4325-foot lateral and is cleaning up and hit a peak rate of over 600 barrels equivalent yesterday. This well is located in our Buckhorn area. The fourth Company-operated well, the Cromwell Ranch 1H, another 100% Cabot well, located on La Salle County, was drilled with a lateral length of 6000 feet and is scheduled for completion in the next couple of weeks. Additionally -- additional drilling in the prospect area is scheduled for later this quarter. Cabot holds approximately 53,000 net acres in the oil window of the play and has over 300 net potential locations.

Also in the Eagle Ford oil trend, drilling on our 18,000-acre area of mutual interest with EOG is scheduled to begin by year-end. Each company, as you might be aware, contributed 50% of the acreage in the JV with the operator EOG. The current plan is to keep at least one rig active in the JV area throughout 2011. With our South Region capital being allocated between our operated Buckhorn area and the EOG JV, we anticipate potentially doubling our oil volumes in the -- in 201 1 from 2010.

Now let's move up to the North Region and the Marcellus. We achieved a new production high of 245 million cubic foot gross per day, predominantly from 43 horizontal wells, and had an outstanding quarter with production growth for the third quarter increasing approximately 74% over the second quarter of 2010. During the quarter, Cabot had two wells exceed the 20-million-a-day for a 24-hour initial production period. One well had a lateral of 4659 feet and 18 stages, while the other had a lateral of 3960 feet with 15 stages.

Also during the quarter cabot completed a three-well pad with a total of 55 frac stages and the three wells are producing a combined 47 million cubic foot, which was highlighted also in the press release last night. Cabot continues to run seven fit-for-purpose rigs in the Marcellus. Today we have a total of 44 stages currently being completed, 93 stages waiting on pipelines and 336 stages waiting on completion. With the prolific nature of the wells and completions that we're drilling, coupled with balancing our capital allocation, we will be adjusting our rig count in 2011 to five rigs. Right now we are planning 54 horizontal wells in Susquehanna in 2011, which will provide a significant growth profile.

On a seismic front, Cabot has completed shooting 250 square miles of thread 3D seismic data and has participated in the acquisition of an additional 85 square miles of 3D seismic in Susquehanna. Right now we have all of the 335 miles of 3D data in-house being interpreted, which covers approximately 60% of our acreage position in the Marcellus. As many of you are aware, at our Lathrop compression station, Cabot is still waiting on the air quality permit for three additional compressors, which was discussed last quarter. Cabot continues to have discussions with the Pennsylvania DEP to resolve this issue.

On a positive note, we believe with further engineering, we can tweak Lathrop Phase 1 to add 10 million to 20 million cubic foot more per day. Additionally, we are working toward the development of three additional compressor sites, two of which will be in limited operation during the latter part of 2011. Our expectation is, at a minimum, we will be able to free-flow gas through both of these new compressor sites. None of these potential upsides are in our 20% growth sales forecast for 2011. Our Marcellus is quite a remarkable resource, and even with lower natural gas prices and gas being out of favor with investors, our economic returns are in the top quartile of the food chain. Case in point, while we have seen many strong wells, particularly most recently, our EUR guidance is still only 5.5 Bcf. At the current EUR, 5.5 Bcf in current pricing, our rate of return will compete with most oil and wet gas projects very favorably. We will update our EUR for Marcellus after our year-end reserve bookings.

Also, Cabot continues to evaluate, along with expert consultants, a nine square-mile area in Susquehanna where the Pennsylvania DEP suspended drilling and fracking operations almost a year ago. Cabot has compiled records of the existence of methane in and around the Dimock area long before Cabot began drilling for natural gas. Additionally, Cabot provided copies of sworn affidavits from residents along Carter Road and other areas who acknowledged they had always had methane in their water and even ignited their water prior to Cabot drilling in their community. Cabot has demonstrated it can remediate the pre-existing methane in the wells by installing methane separation systems. In a technical meeting between the Pennsylvania DEP and Cabot just three days prayer to the DEP's announced pipeline plan, the DEP acknowledged to Cabot that methane separators have worked in other areas in the state and will work in the Dimock. This proven technology is a quicker, cost-effective, permanent solution to treat the pre-existing methane condition. Cabot offensive has been required to offset the sudden change in the direction of the preferred solution by the Pennsylvania DEP.

Now let's move back to operations. In the Rocky Mountains, in the North Region, our initial rank wildcat in Nevada was dry, but it did provide us information to carry to our other two areas in Nevada. It did not condemn our original prospect concept. We just encountered the section a little bit shallower than anticipated. We do plan on shooting additional seismic and continuing our evaluation out there. In regards to our Montana Heath play, we should be moving a rig in in the next week or so.

As we continue to execute our program in both regions and look ahead to 2011, we are very well-positioned to weather this commodity cycle, while still economically building the Company. We have a focus on the Marcellus and Eagle Ford for 2011, with a program that is geared towards cash flow expectations. We are fully aware of concerns of over-expending cash flows in this market and this type of market, and we will manage these concerns. Additionally, even in this soft natural gas pricing environment, the vast majority of our capital scheduled tobe allocated towards the Marcellus and Eagle Ford, will deliver very good rate of returns for our shareholders. Operator, with that, we'll be more than happy to take any questions.

(Operator Instructions). We will pause for just a moment to compile the roster. Your first question comes from the line of Brian Lively with Tudor, Pickering, Holt.

Good morning, Dan.

Hey, Brian, how are you?

Doing all right. In the 2011 $600 million CapEx budget, can you split that between what you're going to spend in the Marcellus versus the other areas?

We're going to spend $350 million in the Marcellus and $250 million in the South Region.

And within that $350 million Marcellus number, I think you were saying you could see around 30 wells uncompleted at the end of this year, so I'm sure that would carryover into next year. Is that the right way to think of the budget?

Yes, it's the right way to think of the budget. But also with our 54 wells scheduled in 2011, as we get to some of those wells at the end of 2011, there will be some carryover into 2012 also.

Right. And then thinking about the Lathrop Phase II compression and how that could limit production next year, can you just discuss how much gas you'll be able to free-flow if you're not able to get the compression on line?

Well, we're going to be looking at the compressor station to the east of the Lathrop Teal stations, and we're also going to be looking at free-flowing gas in a compressor station to the north of our area. And I don't know exactly and have not seen from the region exactly the timing of the well completions in and around those particular compressor sites, but as a -- as I guess a buoy to go by, Brian, that these wells certainly come on at rates that will buck the anticipated line pressure at those particular sites. And our initial rates that we're seeing out there, particularly with the additional lateral links and frac stages, are typically greater than $10 million a day.

Do you need that Lathrop Phase II compression, then, if the rates are, and the pressures on the wells, are above the pipeline pressure to start with?

Sure. We've been producing out there now wells -- in fact, of our 43 horizontal wells, we have a couple of wells that have produced well over a year, almost a year and a half, and those particular wells still flowing at good rates are not over 1000 pounds flow-tubing pressure today. So those are the type of wells that you would like to have compression on.

Okay. That's helpful. Last question -- if you're able to get the permit, how many additional completions do you think you'll take in the Marcellus next year?

I'm not following exactly what you're asking.

So the plan is 54 wells -- sorry, yes, 54 wells next year.

Right.

If you get the permit in place, how many additional completions do you think you'll take in the Marcellus with that extra capacity?

Well, we have the Lathrop station, we think, could add an additionally up to about -- between 105 million and 120 million cubic foot a day. And when you look at the prolific nature of these wells, for example, just three wells we completed on the Greenwood site are producing over 45 million cubic foot per day, just from three wells. So within the 54 wells that we have scheduled for 2011 and the carryover completions that we see from 2010 with this program, we think we will be able to utilize all of the additional Lathrop compressors and also maybe free-flow some gas into those additional compressor sites.

Thank you.

Thank you.

Your next question comes from the line of Brian Singer with Goldman Sachs.

Thanks, good morning.

Hey, Brian.

On the three wells that you announced from the zipper fracs, can you talk about what you think the EURs are, and how indicative you think those can be relative to future wells you plan to drill in Susquehanna?

Well, the -- it's early-term, obviously, on the production curve. And we have seen with our -- again, our extended laterals and additional fracs, Brian, we have seen some very, very good rates and the wells holding up very well. We are working and starting our push towards year-end reserves. We do 100% reserve audit, as you might be aware. We are pushing towards doing that. And what we're going to do is after we get our reserve audits, we have a production history from some of these longer laterals, more fracs at the year-end. We're going to re-look at our EUR, the 5.5, and I think we'll be adjusting that, but to where we'd be adjusting it right now, Brian, I think it'd be premature.

Got it. Thanks. And I guess when you think about moving more toward pads, and I assume, based on these results, but correct me if I'm wrong, you'd probably look to do more -- use more of the zipper frac technology. What are you seeing in terms of how long it would take to drill the well, complete the well, tie the well into sales?

It's going to depend on -- we're doing a six-well pad site right now. And we're drilling on the sixth well on that pad site. So we have had a rig there -- let me visit with Phil once sec. How long have we had a rig on that pad?

Roughly five months.

Okay. So we've been on that pad site right at five months. We're finishing up the sixth well right now. We'll move a crew on there, and I would bet that crew will be there a month or more fracking that pad site.

Right.

Okay so on the -- one of the things we're doing is we're keeping pressure when we're completing these on the offsets, we're moving in between the wells to be able to maintain pressure as we frac the offset well. So it takes a little bit more time just to move up and hook up to the other wells. But that's probably the timing on that particular pad site.

Great, thanks. Then lastly, and I apologize if you mentioned this in your opening comments, but I think you did mention you had built in some cost inflation into the $600 million for next year. Could you be a bit more -- provide a little bit more color on where versus today's costs you're assuming we trend next year that's built into that $600 million?

Yes. We put in, from say what we're seeing on the current frac pumping service per stage cost and the recent bids we received. We'd use those in our capital program estimates and we put a 5% to 10%, depending on the area and the service, into our capital program.

Great. Thank you.

Thank you.

Your next question comes from the line of Michael Hall with Wells Fargo.

Thanks. Good morning, everyone.

Good morning, Michael.

Just a little more on the $600 million spending outlook for next year. Is there any land associated or assumed within that level?

Yes, we had $25 million in the program.

Is that just primarily infill (inaudible) in the Marcellus, or the --

Yes. Just -- it's consolidating positions in the Marcellus as we continue to do that up there, and it's also to pick up any additional acreage in any well units that we have scheduled.

Okay. And then on the -- in the south, the Eagle Ford spending level, is it at $125 million, about half of that, $250 million, or is it -- how should I think about that?

Probably, it's a little bit more than half of that. It's a little bit more than you had mentioned.

Okay. And so what kind of type curve are you seeing in the Eagle Ford currently and the doubling liquids volumes next year?

I'm sorry, you broke up just a little bit on me.

What sort of type curve are you assuming for the Eagle Ford program next year in your commentary that you can double liquids volume?

Well, we're kind of looking at the Armenia wells that we've just drilled and used those wells that -- the initial rates. And right now we're still obtaining the decline curve, but we're used what industry has right around in that area for the decline curve.

Okay. Fair enough. And then lastly, if you think about getting Lathrop, let's say we assume it's on for the second half, Phase II, what is the completion backlog look like as you head into 2011? Have you looked at that?

Well, we have some wells that we already have completed. And I'll mention that we have a number of wells that we're currently completing, we have 44 stages we're currently completing. We have eight wells with 93 stages that are waiting on pipeline. And those -- and again the wells that we're currently completing. So we have a pretty good line-up to flow into Lathrop once we can get that air quality permit.

Okay. I guess one more then. On the timing and on the air quality permit, any -- obviously not necessarily going to give us the effective timing currently, but any thoughts on when you might have additional clarity on that? When are you hoping for? Having some better certainty around that?

Yes, we have, again, submitted the information to the DEP. The DEP has had it. The regulatory process in Pennsylvania right now is I think at best unpredictable for us at this stage. We continue, though, to communicate and make every effort to answer any questions or information that they request of Cabot. We also are continuing to make requests to have meetings with the DEP, and to make sure we can facilitate and answer any questions that they might have.

So speculating on the timing is difficult. We do know that they had issued recently a permit and that permit was a permit that was similarly situated as Cabot's Lathrop station. So we're confident that the process used to award that permit would be available to Cabot also.

Okay. Very good. Thank you very much.

Thank you, Michael.

Your next question comes from the line of Gil Yang with Bank of America Merrill Lynch.

Good morning. The -- it sounds like your capital budget for 2011 would be unaffected by when -- by the timing of the Lathrop permit issuance. Is that correct?

Yes.

Okay. So it would really -- the only difference to us in some sense would be that the exit number of wells that you had awaiting on pipeline would be different, but you wouldn't spend more or less money if -- once the permit is issued, right?

That's correct. We have our budget set, plan on five rigs in the Marcellus. We do anticipate Lathrop to -- three compressors to be installed at Lathrop. We've only given guidance for first quarter though at this stage. Again, with the prolific nature of the wells that we see up there, we think the 54 wells and the completions that we have scheduled during 2000, actually between now and through 2011, that we will be able to increase our production up there significantly with those wells.

Could you give us maybe two scenarios. If Lathrop came on January 1 or didn't, how many wells would you exit the year waiting on pipeline, and how about if Lathrop didn't come online, how many wells you'd be waiting on pipeline at the end of the year?

You talking about at the end of 2011? Talking about the end of 2010?

No, no. So, in one case, if Lathrop came on, was on for the full year and another case if it was not on at all, what would be the exit rate -- exit number waiting on pipeline wells in either case?

Well, we have, again, not only do we have the planned three compressors at Lathrop that we are looking forward to installing and producing into. We are also moving forward with the additional compressor sites. And we are moving forward to set compression there also, but we will free-flow gas through those compressor sites, and how many wells we're able to free-flow through that we are still in the planning stages of the total number that would be able to -- and would like to drill in and around those particular compressor sites versus in other areas. So that is still work in progress to look that far out, Gil. So I don't have the exact number of how many we would exit.

Okay. And do those new pressor locations -- what permitting issues are required there?

We'll still be submitting the similar-type permits. I think one of the things that I have read out there is, in light of an election that's coming up November 2, I have read that the -- both the candidates out there have a desire to define the regulatory process in a clear manner and to allow science and technology and clarity to rule as they make decisions. So I look forward to the Pennsylvania DEP able to communicate to industry in a way that would add clarity and allow me to be able to answer the questions that I always get.

Okay. Does -- is there any chance that the Lathrop permits come after these other permits, or do you think that they'll all come in one big lump, or will they be done sort of in the order of which they were filed?

No. I think Lathrop would come before the other permit sites.

Okay. And then, last question on Eagle Ford. The one -- I guess your first well was flowing flat for six week. Is that on pump? When did it go on pump? And how long do you think it would stay flat? What's the UR implication of that?

Well, we certainly expected that it would decline. We certainly expect that. I'll let Matt make a comment on it.

No, it's actually -- we've got actually tubing run on that well and it will be flowing, I would anticipate, for, oh, a couple of months. We've got gas-lift valves running in it, as well. Liquid or no gas-lift initially and then put it on pump after that.

Okay. Do you have a EUR expectation for the well?

We've got some typical curves in the area. I would say we're somewhere between 250,000 and 300,000 barrels.

Okay. And what would be the rate of return on that well? What was the cost and what would be the rate of return?

The cost on the initial well, of course we moved a rig out of east Texas. A typical well in there is going to be about 7.5 million to 8.5 million, rate of return is about 40% de-tax.

Okay. Thank you very much.

Your next question comes from the line of Ray Deacon Pritchard Capital

Yes, Dan, I was wondering in the $250 million you're going to spend in 2011, how does the mix shift between Haynesville and Pettit? Is there more activity in the Pettit in there if you've got all the leases held? When do you get the leases held?

We do not have Pettit drilling in that number, Ray. We're going to be, again, mainly focused down in the Eagle Ford.

Okay. Got it. And just one other question. With the -- with fracking and the Marcellus, I guess, do you feel the need to lock up a frac crew on a long-term basis, and how many of these 11 locations do you have firm dates lined up?

We are out right now, Ray, bidding frac crews and trying to establish a longer-term relation on our program out there in the Eagle Ford. So, yes, we are out there in the market, and we would -- excuse me, in the Marcellus. We are out there trying to establish a term relationship.

Okay. Got it. Thank you very much.

Thank you, Ray.

Your next question comes from Biju Perincheril with Jefferies.

Hi, good morning.

Good morning.

A couple of questions. First on the CapEx, can you give us sort of how much you spent this year and what you plan to spend next year for midstream and leasing?

Yes. We've spent about $125 million on leasing this year, and Scott --

$58 million on pipeline.

And $58 million on the pipeline gathering.

Next year, $20 million and $27 million.

And next year it's $20 million and $27 million.

$20 million and $27 million, okay. And then if Lathrop comes on, let's say around mid-year or so, what would be the additional CapEx that you would need to tie in those wells? And similarly for those, you mentioned that you have been working on three other pipeline types and there's nothing in the volume guidance for those. But is there anything for -- in the CapEx number, and if not, what could be the added incremental there?

Yes. The-- in our number for facilities is the tie-in for the Lathrop compressors. We have included, and we include in the cost of our completions, about $150,000 per well that is a kind of a capture amount for pipelines and hook-ups from the well pad to the compressor site. All of that is ongoing right now. In fact, we have all of -- majority of that in place already. So any, a big incremental capital, it's not necessary.

Okay. So say Lathrop comes on, at these prolific wells, you might be hooking up a few more wells. But you're saying about $150,000 per well is what will be needed to hook up those wells?

Yes. But we already have some of those wells hooked up. They're ready to go, it's just a matter of hooking up the compressor site.

Okay. And then the other compressor -- all of the other pipeline taps, those are also in the CapEx numbers?

That's correct.

Okay. And then I know you just mentioned you're looking at maybe some dedicated crews for Marcellus. But what we're overseeing in the Eagle Ford area, how are you thinking about the program, especially for next year? You were counting on pretty significant volume ramp-up from there.

Yes. And we are also getting crews right now for the Eagle Ford.

Okay. How many rigs are you going to run there next year? Are you looking at a program that would necessitate a dedicated crew for the year?

We would hope to have a couple of rigs running down there the entire year.

Got it. Okay. Thanks. Thanks for the time. That's all I had.

Thank you, Biju.

Your next question comes from the line of Robert Christianson of Buckingham Research.

Yes. In East Texas, I gather that there are a number of wells that have been drilled case but not completed, what waiting on frac crews. What would you estimate that potential volume, associated volume is that didn't show up in your quarter?

We have a number of wells, Robert, that are either waiting on pipeline hookup or waiting on completions. Have probably pushing 10 wells that are waiting on completion. And we have in those wells a varying amount of working interest ownership. So I don't have that exact net production number. But a number of them are waiting on completion.

I appreciate that. The seconds thing, on this Lathrop station, I mean, what is the exact issue? It sound like you had to go back and resubmit information. What is -- is it Knox or what unusual issue exists with this particular compressor station?

Well, the original application was submitted as a single-source point for emissions. In other words, the calculation to be done at Lathrop station, and that was pursuant to regulations and the requirements. Somewhere in approximately May timeframe the DEP indicated that the determination of issuing air quality permits will be based on an aggregation calculation. And that means to aggregate not only the Lathrop emissions but also aggregate it with the Teal compressor site also. And in an aggregation sense, there's not been any clarity on that particular process. And in fact, we're uncertain on whether or not does aggregation mean that every well that is hooked up to the pipelines and the compressor station, does that have to be included, and does future wells that would be hooked up to that pipeline have to be included. We're uncertain about all that, and there hasn't been clear definition provided to industry to answer that question.

So the -- boiling it down, its bottom line is are they making a decision as the regulations had provided for on a single-source air quality permit, or are they going to consider aggregation as their requirements to issue air quality permits. That's the defining question.

Just coming to the Eagle Ford, would you think your acreage, your 53,000 net acres, is, if we looked across it, do you think the rock qualities could be better away from the current wells you drill? Should we have expectations for better performance off better rock? That's question one. And question two, what are the early indications of the rock quality over on the JV acreage with EOG relative to what you've shown us you're capable of today?

Well, we have certainly anticipate the differences in the three areas that we have acreage. The offset wells to EOG's -- to the EOG JV just to the east of us, I think some of those wells are IPing over 1000 barrels a day with also associated gas. And the area that we have and what we're producing, I think, I would not be surprised that we don't see EURs over the 300,000 barrels that Matt indicated with a consistency with the laterals and the 20-stage fracs versus a 12- to 15-stage fracs. And we are evaluating in our area in (inaudible) we are just evaluating the industry activity up there. We think the EURs up there are going to be a little bit less. We also think the drilling and completion costs, because it's a little shallower, will be less also.

So that particular acreage up there, and there's about 10,000-something acres up there, that particular area up there is going to take a little bit of evaluation from industry and a couple of wells up there to determine the returns and economics for that particular acreage. So I think we are going to see differences throughout -- not only throughout our acreage but the industry will see throughout the trend differences in the Eagle Ford.

One final, if I may, when these things do go on pump, do you put them on electric submersible pumps or are they on pump checks? What happens there at the end? Which is more cost effective or how does it go?

Well, we've done both. We've actually, early on to get a lot of the fluid from the frac off the formation, we've gone to submersible pumps or to gas-lift. And then we eventually moved toward a conventional rock pump as rates come down to the 200-, 300-barrel range.

Thank you very much.

Thanks, Robert.

Your next question comes from the line of Marshall Carver with Capital One South.

Yes, good morning. A couple of questions. On the production guidance for Q4 and also in the third quarter, looks like you had good gas production growth but a tweak down on oil. Why the tweak down on oil guidance?

Because we have in order to handle our capital allocation, we had scheduled earlier more Pettit wells to be drilled. But with the number of non-op Haynesville/Bossier wells we have postponed some of the Pettit drilling, which was oil-related.

Okay. That makes sense. Then on the -- both the Chainman Shale and the Heath play, could you mention how many net acres you have in each of those plays, expected well costs and if there are any well results around for each of those plays, please?

Yes, I'll let Phil Stalnaker, our VP of our North Region, answer that.

In the Chainman, we have over around 72,000 net acres. That was a rank wildcat, nothing else right around that particular area. In the Heath, we have over 100,000 net acres in that area. There are -- looks like there's some recent activity, but no result from the Heath in that area.

Okay. And the expected well costs?

On the Heath, we're looking at, on this initial well, approximately $4 million. Completed.

And how much was the Chainman well?

The dry hole cost is a little over $2 million, $2.5 million.

That's it for me. Thank you.

Thank you, Marshall.

Your next question comes from Jack Aydin with KeyBanc.

Hey, Dan.

Hey, Jack, how are you?

Good. On the -- going back to Lathrop station, your competitor got the permit -- was that single-source, based on a single-source, or aggregated source?

We understand it was based on a single-source.

Okay. Good on that one. Now, second, regarding the Haynesville, is basically looking for JV or carry, how -- what kind of progress you making in that area?

We have a third-party that's helping us out with that. We have CAs that have been executed, and we have a data room schedule set up, and we have a bid deadline set up also.

What's the deadline? The bid deadline?

December 15.

Okay.

The bid's due December 15.

Okay. Third question. Looking at your guidance, it looks like the exploration expenses guidance for the fourth quarter looks kind of high. What did you bake in into those numbers?

Let me get what that is. Okay. We had $7 million in the Buckhorn seismic in that.

Okay. Thanks a lot.

Thank you, Jack.

And your final question comes from the line of Michael Hall with Wells Fargo.

Thanks for the followup. Just quickly wanted to -- you threw out I think $7.5 million to $8.5 million per well in the Eagle Ford there, a bit higher maybe than it has been. Can you break that out between what the completion cost is versus the drilling cost?

Yes. We have probably about $3 million or so in the drilling and $4.5 million or so or a little bit more in the completion depending on the number of stages.

Okay. And then one more if I may, just coming back to the spending program for 2011 and how it interacts with the Lathrop air quality permit. In the worst case if you don't get it, why not spend less -- it sounds like you'll spend the money no matter what. I'm just trying to kind of understand that given the big backlog.

Well, yes, it's a fair question, Michael. We fully anticipate, again, getting the permit, and we're moving ahead because our expectation, if you put it on a risk-basis and chance-of-success-basis, we fully expect to get the permit. The type of permit that we're requesting is not a unique permit for the oil and gas industry. It is just purely a clean, simple, compressor station. A compression -- in any shale play area that has gas, compression is going to be needed. So approval of this type of facility is going to be done if they want production. It's just that easy. So if in fact we find that the Pennsylvania DEP has made decisions this they don't want compression up there, I think you're going to see industry make a whole sale change and not spend as much capital up there, and we'd be one of them.

Okay. That's very helpful. Thank you. Then I guess one last one. There was some discussion or some headlines yesterday that there may be a moratorium on the Pennsylvania State Forest leasing, will that at all impact your leasing plans for next year?

No. No, it will not.

Great. Thank you very much.

Thank you, Michael.

And you have a followup question from Robert Christianson with Buckingham Research.

Yes, thank you. On hedging in 2011, it appears to us that you did not add additional hedges in 2011. Is the inability to hedge more, the unwillingness to hedge more, or even a view that gas prices get better and no reason to position more gas forward? Could you help us on the hedging story at Cabot, please.

Yes, Robert. We did hedge an oil contract recently. So we did add a hedge there. As far as gas hedges, we wish we were 100% hedged at where we're hedged right now in 2010, but we're not. We do think that, as far as where the strip price is right now, hedging at this level we think would be a purely a defensive hedge, and you could make the argument both ways. I'll go ahead and make that defensive hedge but we think we'll have price realizations at least where the strip price is today.

But with your cost structure, that would not appear to be running at profitable levels where strip prices are today, or barely, I guess, on 2011 with the cost structure all in of like 392.

Yes.

In BTU.

Well, if you look at the curve fits and the economics that we're running, for example, where we're allocating two-thirds of our capital in the Marcellus, we're using a current EUR of 5.5 bcfe. We have our current IPs that we're seeing up there. And using your number, Robert, and using our current existing completion costs, we, at $4, we are pushing 100% return, so we think that is a very good return for our shareholders.

Got it. So on everything that's incremental in the Company, great returns. Historic doesn't play under the forward deck. Is that how to interpret that?

I'm not understanding your question.

Well, to me, on a go-forward basis, as you define the Marcellus, highly economic at $4, or 100% returns. Everything else, your cost basis in the entire Company, looking at your per-unit cost, look, all in, taxes DD&A, G&A, was $392 million in the quarter per Mcf. So the economics aren't there for the historic assets but on everything that's involved with growth, Marcellus and Eagle Ford, fantastic returns.

Right, and that goes back to the statement I first made, I wish we were 100% hedged at our current strip price -- I mean our current hedge price.

Thank you very much.

Thank you.

There are no further questions at this time. I now hand the program back over to Management for any further comments or closing remarks.

Well that's it, Operator. I appreciate everybody's interest, and we do look forward to, not only our ongoing program for 2010, but rolling into 2011, and I think you can see with some of the numbers that we put out today that we are yielding very positive returns for the shareholder with every $1 spent. Appreciate your interest and consideration, thank you.

This concludes today's conference call, you may now disconnect.