Coterra Energy - Earnings Call - Q3 2011

Transcript

Speaker 4

Good morning. My name is Holly, and I will be your conference operator today. At this time, I would like to welcome everyone to the Coterra Energy Quarter Three 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. I would now like to turn today's call over to Dan Dinges, Chairman, President, and CEO. Please go ahead, sir.

Speaker 2

Thank you, Holly. I appreciate everybody joining us this morning. I have in the room with me today Scott Schroeder, Jeffrey Hutton, Steve Lindeman, our Vice President of Engineering, Matt Reid, our Vice President of the South Region, and Phillip Stalnaker, our Vice President of our North Region. Let me just make an opening comment that the forward-looking statements included in the press release do apply to my comments today. At this time, we have many things to cover, and I'll also try to expand on the press releases that were issued last night. I'll briefly cover the third quarter financial results, a discussion of operations in Pennsylvania, Texas, and Oklahoma. Additionally, I will discuss our outlook for the next 15 months for Coterra Energy.

Before I get into the details on these topics, let me start with a summary of our impressive results so far, year to date in 2011, and a quick overview of expectations for 2012. In 2011, Coterra Energy will grow production in the 40% to 46% range net of asset sales. We will grow reserves 10% plus. We will reduce, or at a minimum, maintain total debt at a level below $1 billion. This is all generated by a program that encompasses a total rate account of seven, which I think indicates the prolific nature of our portfolio. If we look ahead to 2012, our expectations will be, and this is off of a larger base, grow production between 45% and 55%. We'll grow reserves again 10% plus, maintain a reduced debt without asset sales, and again, all generated from a total rate account of seven.

I think from the guidance I have seen from industry, Coterra Energy's numbers are unmatched. In fact, I've been in the business for over 30 years, and it's rare that I've seen numbers that can demonstrate this amount of growth in a cash flow neutral to cash flow positive program. Coterra Energy's financial reported for the third quarter had clean earnings of $35 million and with discretionary cash flow of $165 million. This quarter continued the consistent trend of low natural gas price realizations, offset by very robust production growth. We expect natural gas prices to remain range-bound through the remainder of 2011 or until seasonal factors kick in. Additionally, we do anticipate further production advances for the remainder of the year as infrastructure capabilities do become available, though we have not included these in our fourth quarter guidance.

In terms of third quarter production, the company posted a 39% growth rate between comparable third quarters, reporting 50 BCF. We continue to enjoy high growth rates from our gas portfolio, but I am particularly pleased to see the results of our liquids initiative with over 100% growth in oil and related liquid volumes between comparable third quarters. Clearly, this increase comes from our Eagle Ford effort. With more wells coming online, we do expect to see an ongoing increase in our liquids production. For guidance, last night we posted new guidance with regard to 2012 production. We initiated with a range of growth between 45% and 55%. We provided detail for the first quarter only due to the fact that there are several infrastructure projects in the works with estimated 2012 start dates. As we have seen this year, multifaceted projects have timeframes that can slide.

Our expectation is we will have a much clearer, more exact timing on this front by the February call when we could give more specific details. With that said, I'm emphasizing again, at a minimum, we anticipate 2012 production growth to be in the 45% to 55% range. In terms of 2011 fourth quarter, we maintained our existing guidance with nine months of actual production having already exceeded last year's record total level. Our expectation for 2011 will be far and away better than any time in our history. This rate also takes into account the sole production and several infrastructure delays. In terms of infrastructure, Laser Pipeline just came online this week up in Pennsylvania, and Springville Pipeline is still expected in mid-December. Again, no incremental volumes in 2011 from Springville Pipeline are contemplated for us to stay within our guidance.

Cost guidance has been updated with no change in our fourth quarter of 2011. However, our third quarter of 2012 reflects reduction to operating expense, DD&A, and financing, and increase to transportation, G&A, and maintain other taxes and exploration expense. The overall impact in 2012 is a lowering of costs from previous guidance levels. Obviously, the reduction of our unit costs will yield incremental dollars to the bottom line. We do expect this reduction trend to continue throughout 2012. We have maintained a strong preference to deliver a disciplined approach to capital spending. The asset sales of 2011 have allowed the expansion of our current year program to about $825 million to $875 million. You'll recall we said on the second quarter call the number would move up from the $600 million mark to around $750 million.

This slight increase from there is a result of our drilling efficiencies that have allowed more wells to be drilled in Pennsylvania, Texas, and Oklahoma, more completions, although still constrained by infrastructure, and more leasing activity in our key areas, and a couple of new ideas. For 2012, we expect our program to be in the range of $850 to $900 million. The planned program range is fully funded at the low end with a $4 gas price, and the program generates a cash flow surplus at the high end with a $4.50 gas price. Bottom line, we have positioned ourselves for one of the highest % production growth of our peer group while staying within cash flow. In addition, we are able to achieve our goals with just seven rigs, an excellent indication of our capital efficiency.

Our industry has a tendency to significantly outspend cash flow to achieve, in some cases, a much lower growth rate. No new hedges were added in the third quarter, with one 2012 oil hedge added thus far in the fourth quarter. The company has 28 contracts for the remainder of 2011 production, 28 contracts for 2012, excluding the five basis-only hedges, and five contracts for 2013. You can evaluate those on our website. Past move to operations in the North Region, our Marcellus results in Susquehanna continue to achieve new milestones. Let me again highlight some of the key records that we have set: new 24-hour production record of 517 million cubic feet per day from only 94 horizontal wells. Coterra's fastest well to produce 3 BCF took only 223 days. Our fastest well to 4 BCF took only 347 days.

We're adding drilling efficiencies with our fastest well to TD, took just 12.5 days, and that was a 3,500-foot lateral. Coterra's area of the Marcellus produced 16 of the top 20 wells in Pennsylvania during the first half of 2011. During the quarter, we turned in line a total of 18 wells, 17 horizontals, and one vertical well. The sum of the production of these new wells was 153 million cubic feet per day, but the production was curtailed due to infrastructure restrictions. Currently, we have four rigs operating in Susquehanna with an additional new build scheduled to arrive in November. Also, we currently have a total of 497 stages in various phases of completion. 213 of those are being completed, are cleaning up, or are waiting to turn in line. 284 of those are waiting to be completed.

We continue to make progress on the many infrastructure projects that will ultimately create one of the largest takeaway capacity systems in the United States. This week was the initial in-service date of the Laser Pipeline located in the northern area of Coterra Energy's leasehold in Susquehanna. The Laser Pipeline is ultimately designed to carry 150 million cubic feet per day of Coterra Energy's production for sales into the Millennium Pipeline System in New York. At Laser, we currently have a total of four wells cleaning up into the line. We have been asked about the Marcellus in the northern portion of our acreage. The gross section is slightly shallower and is approximately 240-foot thick versus approximately 350-foot thick where we've been drilling. Keep in mind, the thickness we see in this northern area remains considerably thicker than the Marcellus seen throughout Pennsylvania.

We anticipate keeping a rig active in the north area and adding volumes throughout the fourth quarter. We're excited to have Coterra Energy's Marcellus production into a new marketplace. Next, we are anxiously awaiting the startup of Springville Pipeline, now scheduled for early December. Significant progress has been made to date, including the completion of the compressor station, significant progress on the major bores, and completion of the tap into the Transco Pipeline. This is great news as we await the finishing touches on the 24-inch pipeline. Transco, just like the Millennium Pipeline, represents new markets for Coterra Energy to immediately access.

One new development we're excited about regarding Springville, which we did release last night, is that Coterra Energy and Williams have agreed to terms regarding the unsubscribed capacity on Springville, essentially increasing our position from 300 million cubic feet per day of takeaway to 625 million cubic feet per day. The additional capacity will be available mid-2012. With this as a backdrop, the majority of our 2012 production will be going to markets not served today by Coterra Energy, which we think is an improvement. When you combine the incremental capacity of 325 million per day to the pre-announced plans for our infrastructure, our mid-year 2012 takeaway now stands at 1.325 BCF per day, and the year-end total takeaway capacity grows from the 1.2 BCF per day to 1.525 BCF per day.

Let me also add that the various other projects and expansions we have discussed previously are all on track for on-time completions. As we reported last night, with the delays in moving gas on Laser and Transco, we have combined and been compelled to deliver all of our Marcellus production into one single 24-inch Tennessee pipeline. With the gap on gas competition from the surrounding areas, pricing for our Northeast Marcellus producers has seen downward pressure. While we have heard numerous rumors regarding the price we have received for our gas, Coterra's monthly average price in the fourth quarter has remained above $3 per MCF during this soft period. We are mindful that our pending takeaway projects to diversify our production into multiple downstream markets on new interstate pipelines will relieve some of this tension. Now let's move to the South Region.

In our Buckhorn area in the Eagle Ford, the company has drilled a total of 24 wells. Each well is a 100% working interest well in Frio and LaSalle County. Twenty-one of these wells are on production, with two wells completing, one well waiting on completion, and one well drilling. The two most recently completed wells produced at initial 24-hour rates of 938 barrels of oil equivalent per day and 791 barrels of oil equivalent per day. In our AMI area with EOG, there are six wells presently on production in this 18,000-plus acre area, with three of these wells drilled and completed in the third quarter, and the results are at anticipated levels. Gross production from both areas in the Eagle Ford is over 7,600 barrels of oil equivalent per day. Coterra intends to drill or participate in 25 to 30 net Eagle Ford wells in 2011.

Now moving to Oklahoma, Beaver County, where we have our Marmaton operation, Coterra has continued its effort there with participation as planned in seven non-operated wells, with a few more to go in this quarter. Last night, we highlighted the latest two wells, and these wells were a significant uptick from our excellent initially operated well. The second Coterra operated well was spud last week, and the well is designed for a 4,000-foot lateral with approximately 16 frac stages. Coterra intends to drill two additional operated wells and will participate in eight to ten total non-operated wells in 2011. Coterra now controls approximately 61,500 net acres in the play, which is up from the 54,000 we previously announced. We believe the results that we will see in the Marmaton will provide us very favorable economic returns.

In the Heath, we have gathered as much information as we could from a poorly drilled and completed well. We status the well as unsuccessful and will take the information we collected and continue our science work in the area. The science effort drove our exploration costs above guidance, essentially $0.03 for the quarter. Fortunately, we do have long lease terms remaining to work with. Now moving to 2012 plans. In Pennsylvania for 2012, Coterra Energy will have on average five rigs running. We're planning 70 to 78 Marcellus wells. We also anticipate running one and a half frac crews for the year. In Texas and Oklahoma, we will remain focused on liquids production. In the Eagle Ford Shale, Coterra Energy will drill or participate in 20 to 30 wells.

In the Marmaton play, we anticipate that the company will participate in the drilling of between 25 and 30 gross wells, with the majority of these wells being operated. Plans call right now for the company to operate two rigs in the South, one in Eagle Ford and one in the Marmaton. We believe our 2012 program will yield greater efficiencies from a dollar invested perspective than our 2011 program. We will demonstrate operational efficiencies in both drilling and completion, along with some moderation in our overall service cost per completed well. Additionally, we continue to improve efficiencies in our vertically integrated operation with our internal construction of locations, roads. We also provide water hauling and handling and frac tanks and other various assembly things that we have in-house. In closing, Coterra Energy's operations remain simple.

Focus our gas efforts solely in the Marcellus and allocate dollars to the oil window of the Eagle Ford and Marmaton, which will drive our double-digit growth in reserves and production year over year, all within an anticipated cash flow neutral program. With that summary, Holly, I'll stop and be happy to answer any questions the group might have.

Speaker 4

Thank you. At this time, we'd like to remind everyone, if you would like to ask a question, press star one on your telephone keypad. Your first question comes from the line of Brian Singer, Goldman Sachs.

Speaker 0

Thank you. Good morning. Brian, two questions. You made a comment in your opening comments that for the incremental volumes that you signed on Springville for next year would be touching new markets. Can you add a little bit more color on that, and are there any implications in terms of real-life prices or costs?

Speaker 3

Yeah, I'll let Jeff handle that, Brian.

Speaker 0

Good morning, Brian. What we mean by that is the new gas going down Springville will enter Transco's pipeline, the Leidy system. That pipeline goes over to the southern part of New York, and it actually connects with a number of different utilities and interstate markets that Millennium Pipeline does not currently serve. We should be better off in a number of different ways with new markets, both in the Northeast and actually down by call on Transco to the Baltimore and DC areas. As we see this new capacity come on, is there any change in how we should think about either your realized prices or your costs based on the contracting that you've done here? Not a lot.

The gas price that we'll receive going into Transco and, quite frankly, into Millennium and Tennessee, all that is based primarily on the Appalachian kind of pricing that you would normally see against the Dominion Index or Millennium Gas Transmission Index. Got it. Thanks. Lastly, Dan, free cash flow at the $4.25 gas, let alone a higher gas price, is a pretty rare event as you move closer to this period. Can you just talk to how you're thinking about allocation of that cash, additional liquids drilling, acquisitions, debt paydown, dividends, etc.?

Speaker 3

Our allocation right now is scheduled basically two-thirds, one-third. Two-thirds going to the Marcellus and one-third going towards liquids.

Speaker 0

I guess there's a way to think about the potential for more substantial free cash flow that you would use that cash to ramp up drilling in the Marcellus at double the rate that you would ramp up the drilling or in terms of capital as you ramp up drilling elsewhere. I'm kind of thinking really out into 2012 and maybe beyond here.

Speaker 3

Yeah, Scott wanted to make a comment here.

Speaker 1

Brian, right now, as you saw, the plan is 850 to 900. That'll be dynamic like every year's plan is. Clearly, if we take a snapshot right now, that excess will just be used to pay down the revolver. There's no thought at this point of any kind of dividend increase, picking up on what you said. Some of that money could eventually, if we have a need in terms of lease expirations or a new idea or a new project, go for some of those new science ideas too.

Speaker 0

Great. Thank you.

Speaker 4

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

Speaker 0

Good morning. With the Marcellus capacity at 1.5+ BCF a day at year-end 2012, when do you guys think you'll actually be able to fill that capacity? I'm just looking for, you know, is that a 2013-2014 event?

Speaker 2

That's a good question, Brian. It is safe to say that we have very high expectations of our area. Otherwise, we wouldn't have added additional capacity. I think we are being prudent in the market we have today with the commodity price where it is, as we continue to gain efficiencies in our development, moving more and more towards a full-blown development mode. Right now, we are just going to try to get out of the fourth quarter of 2011 and move into the first quarter of 2012. We have set our guidance for 2012. We do, believe me, internally have a lot of work going on beyond 2012, but I'm not prepared to make those projections.

Speaker 0

Okay. Could you maybe comment a little on what are the constraints there? I mean, it's great for the free cash flow positive situation with where you guys are at. Is that going to be a throttle, do you think, going forward, given the returns on the wells? Would you, if able, actually accelerate some of that growth and outspend a little bit?

Speaker 2

Right now, our plan is to stay within cash flow. Fortunately, our program has very good capital efficiency within it because of the area we're in, that even at a $4 MCF, we can stay within cash flow. We'll generate a little bit of positive cash flow at a $4.50 price. I think we're in a very unique situation in that case. We do fully appreciate the present value aspect of enhancing the profile of our cash flow stream. At the right opportunity, we will take advantage of that. Right now, I think it's prudent in this market to stay within what we see as a forward curve and a cash flow neutral program.

Speaker 1

Brian, let me add also, you know, the tendency in our industry and part of the dynamic in our industry has been the need to capture leases. This program laid out for 2012 captures the leases, all of the leases that would be expiring in 2012. We have no lost opportunity within that cash flow neutral program. That would be a dynamic where you might outspend, but Coterra Energy doesn't need to do that.

Speaker 0

That's fantastic. On the asset sales, do you guys have an updated expected proceed? I saw that you gave a closing time for the Rockies in October. What's the total proceeds for the year now?

Speaker 3

We're probably pushing $375 million.

Speaker 0

Okay. Last question from me. Dan, you might have said this in the prepared remarks, but I didn't hear it right. What was the breakdown of Marcellus production and Eagle Ford production in Q3?

Speaker 2

No, I did not say that. I'll let Scott work through that.

Speaker 1

Brian, give me a call afterwards. We did not break it down by that. Again, you get an idea in the press release. The gas production in West Virginia is roughly 50 million a day. Rocky Mountains for the quarter was roughly 25 million a day. The rest would be in Pennsylvania.

Speaker 3

Okay, that works. Thank you.

Speaker 0

All right.

Speaker 4

Your next question comes from the line of Pierce Hammond, Simmons & Company.

Speaker 1

Good morning.

Speaker 0

Good morning, Pierce.

Speaker 1

The first question is, what gas price differentials for Susquehanna County are you embedded in your 2012 guidance?

Speaker 3

I will refer to Jeff on that also.

Speaker 0

Okay. For 2012, we're using the, again, we'll be selling off the Dominion Index and the Columbia Index at probably $0.08 to $0.10 and above NYMEX. I might add to that too, that the markets that we'll be accessing on Transco and Millennium, we have seen some downward pressure to the differentials in Pennsylvania on Tennessee. We think that is temporary. Once we get to the new market areas, we'll see what I'll call back to normal pricing at positive differentials to the NYMEX.

Speaker 1

Perfect. Are you experiencing any service cost relief specifically on the completion side in the Marcellus right now?

Speaker 2

On the 2012 program, Pierce, we're in the process of gathering all our service costs and closing down some annual contracts for some of our services. It is our expectation, as I mentioned, that our service costs will moderate both in the South Region and the North Region per completed well cost.

Speaker 1

Perfect. The last question for me, there's been some reports that you're in the Smackover Brown Dense. I was just curious what your drilling plans were there, as well as what acreage you've leased out.

Speaker 2

We have several projects that are out there that our guys work on from an exploratory sense. With it being just exploratory in nature, we don't typically comment on what we're doing that far ahead of the curve.

Speaker 1

All right. Thank you very much.

Speaker 2

Thank you, Pierce.

Speaker 4

Your next question comes from the line of Amir Arif, Stifel.

Speaker 0

Thanks. Good morning, guys.

Speaker 2

Morning.

Speaker 0

Just another question in terms of how you're thinking about 2012. What would cause you to increase your rig count from above the 5? I mean, I know you've got the takeaway capacity. You talked about wanting to live within cash flow. If we see an improvement in gas prices, is that the signal you're waiting for, or is it simply a matter of trying to do it at a steadier pace?

Speaker 2

Yeah. Our approach to business, just as a general comment, is we have so much money to work with. We're going to try and strive to stay within a budget. We set our benchmarks to stay within that budget with the assumption of what gas price we've used in our model. Certainly, if we have the opportunity to see an increase in the commodity price from what we've used, certainly we'll consider drilling additional wells.

Speaker 0

Okay. There's no desire to hedge in additional volumes and accelerate production growth?

Speaker 2

Hedging is and will remain a consideration for us. I would love to be able to hedge a strip that would lock in some of what we're discussing here. With that lock-in of a significant hedge position, I think we would probably look at our capital program with those hedges locked in place. A 12-month strip at this stage is probably in the $4 to $4.50 range.

Speaker 0

Yeah. That makes sense. Okay. Just another question in terms of the two wells you highlighted in the Marcellus, the 4Bs and 3Bs in less than a year. These are not the extended laterals. Is there something different you were doing on these wells?

Speaker 2

No. They're just some, you know, and geologically, we find ourselves fitting some wells in various different areas that we've been drilling. Those are some of the poster boy wells that we've had that produced very well. Frankly, we do have a couple of wells to see what they'll do that we do not restrict as much as we do some of our other wells. These are wells that we have brought on and allowed them to make up a great deal of our production that may be the sacrifice of some of the other wells that we'll pinch back.

Speaker 0

Just one final question. Can you give us a summary of, or just a rough number of how much acreage will be held by production after the end of your 2012 drilling?

Speaker 2

We anticipate that it'll be after 2012 drilling or 2011 drilling?

Speaker 0

After the 2012 drilling, I mean, after the program you've laid out for 2012.

Speaker 2

Oh, after 2012 drilling, I'm thinking we'll have, even though we'll come back in after we evaluate the production from those wells, we'll probably have some more drilling. We will have more drilling to come back in to drill in some of this acreage that we do have held by production. I would say 35 to 40%.

Speaker 0

Okay. Just to follow up to that, at what point do you think you'll start doing either more pad drilling or start using some of your more extended laterals that you've been testing? At what point do you start changing the way you're developing these wells?

Speaker 2

Yeah, you know, it's a little bit of a forward look, but as we increase our production and we increase our cash flow, once we're able to continue to capture our acreage in a very methodical process, which we're doing right now, and we increase our cash flow enough to allow incremental drilling, I think that's when we'll come back in and have those types of pad sites set up for 6 wells, 8 wells, 10 well type of pad drilling.

Speaker 0

Okay, it sounds like that's a 14 or 15 events type of thing before we at least start changing.

Speaker 2

If we could get, we continue to grow our production, and if we could get a little bit of help from the commodity price, it could be an earlier event than that.

Speaker 0

Okay. Sounds great. Thanks.

Speaker 2

Thank you.

Speaker 4

Your next question comes from the line of Gil Yang, Bank of America.

Speaker 0

Good morning. Could you comment on what your, I know you're cleaning up the four wells near the Laser Pipeline area. Do you have any sort of comment on what those wells look like in terms of comparison to the rates that you're seeing in the more southern area?

Speaker 2

It is still very early, and they've only had them on like three days. They're still cleaning up, so the comparison would be a little bit earlier.

Speaker 0

Okay.

Speaker 2

A little bit early for that. Three wells into it, to give you an example, three wells into it on our wells in the southern area, we don't know exactly what they will do at that period of time either. In fact, we have wells that have cleanup going into the 30 to 45 to 60-day period as they continue to clean up. It is just way, way too early to make that statement.

Speaker 0

Is there no predictive value in the rate that they clean up at?

Speaker 2

No, there's not.

Speaker 0

Okay.

Speaker 2

Yeah.

Speaker 0

Okay. Great. What is your current average TD for the Marcellus?

Speaker 2

On well cost?

Speaker 0

Sorry. Days to drill the well.

Speaker 2

We're in between 16 to 18 days.

Speaker 0

Okay. If you look at your program for 2012 versus the program in 2011, is there proportionately going to be more spent on completions in 2012 than 2011, or is it going to be the similar distribution?

Speaker 2

No, we're going to spend some more dollars. We'll be spending more in 2012 on completions than in 2011.

Speaker 0

Can you give some of the guidance as to how much is going to be for each drilling versus completion?

Speaker 1

Yeah, we don't have that number. I think from a macro perspective, remember, up until recently, we had one frac crew in the Marcellus, and we've taken advantage of the dynamic in the marketplace up there to have two crews for a period of time. As you can see, they have worked up. When we had this call in July, we were around 600 stages backlogged. Now we're just under 500. We expect that 500 will decline further as it relates to next year, more to more of a working inventory between 200 and 300 stages. If you think of the well numbers that we gave and the speech for 70 to 78 wells, assume they're all 15-stage fracs, that'll give you the number of stages for next year. Say, incrementally, we're going to work off the backlog, half the backlog of 250.

That'll give you an indication of the number of stages that gets done next year.

Speaker 0

Okay. Great. Just a final question. Can you comment on, you made the comment, Dan, that you expected services to show some kind of moderation. Is there a difference in drilling versus completion cost in the South versus the North? Is there more pressure on completion costs in the South than there is in the North and vice versa for drilling, or can you comment on that?

Speaker 2

I think the savings we anticipate simply because the majority of the costs are attached to the completion cost. The majority of what we think we would be able to save in 2012 compared to 2011 will fall in the completion side. We don't expect a great deal of change in the drilling side for cost, actual cost in the North and South. We do anticipate that in the North, we think we would be able to gain efficiencies with each drilling dollar spent by virtue of our penetration rates.

Speaker 0

Okay. Great. Thank you very much.

Speaker 2

Thank you.

Speaker 4

Your next question comes from the line of John Abbott, Pritchard Capital.

Speaker 1

Thank you very much. My question's already been asked.

Speaker 2

All right, John. Thanks.

Speaker 4

Your next question comes from the line of Ray Deacon, Green Murray.

Speaker 1

Yeah. Hey, Dan. I had a question about current well costs in the Marcellus. Also, yesterday, Ray mentioned 5.7 to 6.5 BCF he used for EUR, and said that looked like about a 30% recovery, implying there was some, you know, some potential to increase EURs. I guess I was just wondering what your thoughts were on that.

Speaker 2

As far as comparing the drilling cost, I think range, and if they're talking about what area were they talking about, Ray, do you know?

Speaker 1

I think in the Southwest, they were saying 5.7, and then in Lycoming, they were saying they thought 6.5 was the current number.

Speaker 2

Okay. Yeah. The well cost in Southwest Pennsylvania is that's shallower over there. As we've been able to see, and as the PA DEP has put out on well results, Southwest does not deliver quite the rates that we're seeing in the northeast portion of Pennsylvania. As you move west from our area, I think it's also indicative that you don't get quite the rates as you move west into the area that is being drilled, that the IPs or EURs are as robust as what we are seeing in our particular area. As far as the drill costs in the southeast, they are very similar at the $6.5 to $7 million range, depending on the number of frac stages.

Speaker 1

Great. Thanks. Your 10 BCF EUR well that you booked last year, what recovery factor does that work out to, and where could that go, I guess?

Speaker 2

Making the comparison, you'd use 30% on Range's recovery. Keep in mind that just the geology is such that southwest Pennsylvania has a much thinner section than we have. Our section is 240 to 400 feet thick. The in-place reserves that we have in that section compared to a 70-foot section or so is significantly different. The recoveries that we realize, and we're working on right now and have a third-party study out there that will be delivered to us at the end of the year, is trying to arrive at that recovery factor. We think we're going to see in our particular area, with the efficiency of our completions and no liquids in the majority of our reservoir, we don't have any relative perm issues or anything like that. We think we have very, very good high recovery factors that could push the 50% to 60% range.

Speaker 0

Got it. Thank you very much.

Speaker 2

Thank you.

Speaker 4

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

Speaker 1

Yes. Good morning. A couple of questions. You gave the number of gross wells, 25 to 30 gross wells in the Marmaton next year. How many net wells would that be?

Speaker 3

Go ahead, Matt.

Speaker 1

That would probably be in the range of, I think it's roughly 16 or so operated wells, and then I would estimate another 4 or so net wells that are non-operated.

Speaker 3

Just a question on, you did a great job monetizing Rockies and accelerating in the Marcellus this year. Why not monetize some other assets, maybe West Virginia or something next year and accelerate some more? Is that something you're considering?

Speaker 2

Yeah. Again, Mark, we have, Coterra has consistently evaluated our portfolio and made a number of portfolio rationalizations that have taken advantage of transferring our assets into a higher PV. Certainly, we'll continue to look at that opportunity out there if the market would allow.

Speaker 3

Okay, thank you.

Speaker 2

Thank you.

Speaker 4

Your next question comes from the line of John Nelson, Macquarie.

Speaker 0

Good morning. Just as a follow-up to the response on Gil's question, are there more spot frac crews available in northeast Pennsylvania now if you wanted them? As you look into 2012, do you see any constraint in the number of crews you can get dedicated?

Speaker 2

Yeah. I'll let Phil respond to that. You know, we have been picking up spot crews. You know, we have the one we've had full-time, and we've been picking up spot crews that do other jobs. Right now, we're not seeing any constraints in 2012.

Speaker 0

Great. On the extended laterals that were mentioned in the press release, do you have what the actual lateral length was?

Speaker 2

The lateral length was the longest, was like 6,100 feet.

Speaker 0

That will just. The spacing on that was the same as what you guys have been trying, or?

Speaker 2

Yeah. The spacing on that was about 250 feet or so. Those laterals, each of those laterals, I think one was about 5,500 feet, one 6,100 feet. One had 21 stages, the other had 26.

Speaker 0

Great. Thanks. Just last one for me. Do you have the amount spent on leasehold in the quarter?

Speaker 2

Oh, I don't have that. Scott, do you have?

Speaker 0

We could follow up off the line.

Speaker 2

Okay. Yeah. Thank you, John. John, it's between $30 million and $40 million.

Speaker 0

Great, thanks so much.

Speaker 2

Okay.

Speaker 4

Your next question comes from the line of Bijou Perincheril, Jefferies.

Speaker 0

Hey, good morning. A quick question. When you think about the incremental volumes on the Springville Pipeline, does your existing compression capacity and the new units that are coming on next year, is that enough, or do we need any new compression to get to that 625 on the Springville Pipeline?

Speaker 1

Yeah. Yeah. Sure. I'll take that one. The answer is yes. The expansion by Williams on Springville will include some additional units at their Wilcox station that will allow them to increase the capacity of the line from 300 to the 625 number. In addition to that, there will be some expansion and another new station that Coterra Energy and Williams will develop along the Springville lateral and also around the Tennessee Gas Pipeline area. There are lots of moving parts to this, and we're well on our way to get all of it wrapped up, at least the big part by mid-year and then the rest by year-end.

Speaker 0

Okay. If I think about, I think you had for next year, talked about two new compressor stations coming on, Lenoxville and I think the Williams Central. Are those volumes going to be incremental to what's going to be moved on Springville, or is that rerouting some of that?

Speaker 1

That's kind of a difficult question to answer because we're trying to develop a system there that has a lot of flexibility to it. Yes, Lenoxville will deliver gas into Tennessee Gas Pipeline solely. However, the Latrop station, for example, and the original Till station, and the new station we have on the volume boards, the Central compressor station, will be able to access multiple pipelines. The design of the system is to have access to three different interstate markets, three very large markets, and at the same time, maintain the field pressures that we think are ideal to produce these wells into and also access the higher price markets.

Speaker 0

Okay. That's helpful. I think you talked about this before. The two extended lateral wells that you mentioned in the press release, did you say those were not subject to any sort of, they were not choked back like some of the other wells, is that, or were you referring to other wells?

Speaker 2

They were brought on like our other wells that are brought on at a little bit of a moderated rate to allow us to continue to clean up. We did allow those to produce into the pipe at fairly aggressive rates. However, I would add to that that we did hold some back pressure. For example, as recently as yesterday, the wells were producing above line pressure in the 1,400-pound range.

Speaker 0

Okay, that's helpful. Thank you.

Speaker 4

Your next question comes from the line of Bob Christensen, Buckingham Research.

Speaker 1

Good morning. Thank you. About how much exploratory leasehold has the company booked so far this year, sort of outside of things we know about Marcellus, Eagle Ford, and Marmaton?

Speaker 2

Bob, part of what we again do on our exploration, we just try to stay behind the curtain for as long as we can until all the scouts discover us out there.

Speaker 1

Okay, fair enough.

Speaker 2

So yeah.

Speaker 1

Would you say it's more acreage at this time this year than last year? I mean, are you, is the company, because I'm trying to look out a bunch of years, is the company becoming more exploration, I guess, savvy and interested? Is the appetite growing in that direction, or do you just have so much to work with that's so high quality that you know about? I'm just trying to get a tendency of the company.

Speaker 2

Yeah. We love our position and what we have to work with, and we have 10+ years of significant opportunities within our portfolio right now. As far as our company being, you know, exploration savvy, moving out ahead of the curve, a good example of what we have internally already is by virtue of in 2005, when nobody on this line knew what the Marcellus was, Cabot was out leasing in northeast Pennsylvania for the Marcellus. We didn't talk about it, and we didn't bring it up. We just did our internal work and moved forward without anybody finding out about it until somebody discovered it that we were out there. I think we have the ability in-house and have had the ability in-house to move out ahead of the curve and be reactive and proactive both on new ideas.

Speaker 1

Just one final on the Heath, if I may. I think there were five other wells by industry up there. I just question, do you know of any successes in the Heath by others?

Speaker 2

What I've seen, and I don't have all the detailed data and information on the industry drilling up there, the brief reports I've seen, I have not been excited about. Again, a couple of wells don't kill a flame, particularly in a large geographic area. We just need to understand it a little bit better and see if it's going to have enough potential for us to make an economic play out of it that would compete with our capital efficient dollars.

Speaker 1

Thank you very much.

Speaker 2

Thank you.

Speaker 4

Your next question comes from the line of Michael Hall, RW Baird.

Speaker 0

Hey, good morning.

Speaker 2

Hey, Mike.

Speaker 0

Just two quick ones for me. I was curious if you had the rates on the cumes that you reported, maybe the average rate for the 2 BCF average for those 30 wells, and then perhaps the other rates that were reported in the ops update.

Speaker 2

The two wells that have been of note are still producing well over 15 million cubic feet a day each.

Speaker 0

Okay. How about those 2 BCF? Didn't you say 30 wells at average over 2 BCF a day? I was just curious if by chance you had the kind of average IP, I'm sorry, the average rate at the time of those cumes.

Speaker 2

No, I have not averaged those 30 wells, Mike.

Speaker 0

Okay. Fair enough. Sorry if I missed it, but the 2012 outlook, how many wells do you contemplate tying in, actually tying into sales in the Marcellus program in that outlook?

Speaker 2

How many wells do we anticipate tying in?

Speaker 0

Yeah.

Speaker 2

55 to 65.

Speaker 0

Great. That's all I had. Thank you very much.

Speaker 2

Okay, thank you.

Speaker 4

Your next question comes from the line of Brett Hall, Global Hunter.

Speaker 0

All right, good morning.

Speaker 2

Morning.

Speaker 0

Do you have provided EUR for Marmaton wells?

Speaker 2

Yeah, right now, this was early time, and we haven't changed that because we're still gathering a significant amount of data. We can see that some of the tweaking that's being done on maybe the amount of proppant that we pump and things have had some enhancements compared to our initially operated well with the non-operated wells that have been drilled. We're between, right now, and again, this is based on our first well, 175 to 225 BOE at this particular time. Maybe with additional stages, frac stages, and longer lateral lengths, that number would increase. Keep in mind, our initial well was a 10-stage frac.

Speaker 0

Okay. All right. Great. Thank you.

Speaker 2

Thank you.

Speaker 4

At this time, there are no further questions.

Speaker 2

Okay, Holly, I appreciate everybody's attention. I think just an ending comment that Coterra, I think, provides, and again, this is from many years in the business, one of the lowest risk stories to accomplish what I think is an industry-leading result with a cash flow neutral to cash flow positive program that generates an excess of 45% production growth and a 10+% reserve growth with the superior capital efficiencies. I don't think you're going to find that in a program that takes about seven rigs to accomplish those feats. Anyway, with that, I'll end it. I appreciate everybody's interest in Coterra. Thank you.

Speaker 4

Thank you for participating in today's Coterra Energy Quarter Three 2011 conference call. You may now disconnect.