Coterra Energy Inc. (CTRA) Q3 2011 Earnings Report, Transcript and Summary

Scott C. Schroeder - Chief Financial Officer, Vice President and Treasurer James M. Reid - Vice President and Manager of South Region Dan O. Dinges - Chairman, Chief Executive Officer, President and Member of Executive Committee Jeffrey W. Hutton - Vice President of Marketing Phillip L. Stalnaker - Vice President and Manager of North Region

Robert L. Christensen - Buckingham Research Group, Inc. Pearce W. Hammond - Simmons & Company International, Research Division Brian Singer - Goldman Sachs Group Inc., Research Division Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division Michael Hall - Stifel, Nicolaus & Company Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Biju Z. Perincheril - Jefferies & Company, Inc., Research Division John C. Nelson - Macquarie Research Marshall H. Carver - Capital One Southcoast, Inc., Research Division Gil Yang - BofA Merrill Lynch, Research Division Unknown Analyst - Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

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 Cabot Oil & Gas Quarter 3 2011 Conference Call. [Operator Instructions] I would now like to turn today's call over to Dan Dinges, Chairman, President and CEO. Please go ahead, sir.

Thank you, Holly. Appreciate everybody joining us this morning. I have in the room with me today Scott Schroeder; Jeff Hutton, VP Marketing; Steve Lindeman, the VP of Engineering; Matt Reid, our VP of South Region; and Phil Stalnaker, our VP 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 Cabot. But 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 '12. In '11, Cabot will grow production in the 40% to 46% range net of asset sales. We will grow reserves 10-plus percent. We will reduce or at a minimum maintain total debt at a level below $1 billion. And this is all generated by a program that encompasses a total rig count of 7, which I think indicates the prolific nature of our portfolio. If we look ahead, 2012, our expectations will be -- and this is off of a larger base, grow production between 45% and 55% or grow reserves again 10-plus percent, maintain or reduce debt without asset sales and again, all generated from a total rig count of 7. I think from the guidance I have seen from industry, Cabot'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. Cabot's financial report for 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 ranged 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'm 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 indicate -- 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. The guidance last night, we posted new guidance with regard to '12 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 at 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, let me emphasize 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 9 months of actual production having already exceeded last year's record total level. Our expectation for 2011 will be faraway better than any time in our history. This rate also takes into account the sold production and several infrastructure delays. In terms of infrastructure, Laser just came online this week up in PA, and Springville is still expected in mid-December, again, no incremental volumes in 2011 and from Springville are contemplated for us to stay within our guidance. Cost guidance has been updated with no change fourth quarter 2011. However, our first quarter of '12 reflects reduction to operating expense, DD&A and financing at increased to transportation, G&A and maintain owed taxes and exploration expense. The overall impact in '12 is a lowering of cost from previous guidance levels. Obviously, the reduction of our unit cost will yield incremental dollars to the bottom line. We do expect this reduction trend to continue throughout '12. We have maintained a strong preference to deliver a disciplined approach to capital spending. The asset sales 2011 have allowed the expansion of our current year program to about $825 million to $875 million. You'll recall that on the second quarter call, the number would move up from the $600 million mark to around $750 million. The 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 on key areas and a couple of new ideas. For '12, we expect our program to be in the range of $850 million 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 percent production growth of our peer group, while staying within cash flow. In addition, we are able to achieve our goals with just 7 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 '11 production, 28 contracts for '12, excluding the 5 basis only hedges and 5 contracts for '13. You can evaluate those on our website. Now, let's move to operations. In the north region, our Marcellus result in Susquehanna continue to achieve new milestones and again highlight some of the key records that we have set, new 24-hour production record of 517 million cubic foot per day from only 94 horizontal wells. Cabot'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. Cabot's area of the Marcellus produced 16 of the top 20 wells in PA during the first half of 2011. During the quarter, we turned in line a total of 18 wells, 17 horizontals and 1 vertical well. The summer production base newly -- new wells was 153 million cubic foot per day but the production was curtailed due to infrastructure restrictions. Currently, we have 4 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, or cleaning up or being -- or waiting to turn in line. 284 of those are waiting to be completed. We continue to make progress of the many infrastructure projects that will ultimately create one of the largest takeaway capacity systems in the United States. This week was initial in-service day of our Laser pipe -- the Laser Pipeline located in the northern area of Cabot's lease hold in Susquehanna, Laser Pipeline is ultimately designed to carry 150 million cubic foot per day at Cabot's production for sale into the Millennium Pipeline system in New York. At Laser, we currently have a total of 4 wells cleaning up into the line. We have been asked about the Marcellus in the northern portion of our acreage. The growth 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 PA. We anticipate keeping a rig active in the north area and adding volumes throughout the fourth quarter. We are trying to have Cabot's Marcellus production into a new marketplace. Next, we are anxiously awaiting the startup of Springville pipeline -- excuse me -- now scheduled for early December. Significant progress has been made to date including the completion of the compression 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 Millennium Pipeline, represents new markets for Cabot to immediately access. One new development, we're excited about regarding Springville, which we did release last night is that Cabot and Williams have agreed to terms regarding the unsubscribed capacity on Springville, essentially increasing our position from 300 million cubic foot per day of takeaway to 625 million cubic foot per day. This 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 Cabot, 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, midyear 2012 takeaway now stands at 1.325 Bcf per day. And the year end total takeaway capacity grows to -- from the 1.2 Bcf per day to 1.525 Bcf per day. Let me also add that various other projects and expansions we have discussed previously are all on track for on time completion. As we reported last night with the delays in moving gas, Laser and Transco, we have combined and been combined to deliver of our Marcellus production into one single 24-inch Tennessee pipeline with the gas on gas competition from the surrounding areas pricing for our northeast Marcellus producers have seen downward pressure. While we have heard numerous rumors regarding the price we have received for our gas, Cabot's monthly average price in fourth quarter has remained above $3 per Mcf during the 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 100% working-interest well in Frio and La Salle County. 21 of these wells are on production with 2 wells completing, 1 well waiting on completion and 1 well drilling. The 2 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 6 wells currently on production in this 18,000-plus-acre area with 3 of these wells drilled and completed in the third quarter and the results are at anticipated levels. Gross production for both areas in the Eagle Ford is over 7,600 barrels of oil equivalent per day. Cabot 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, Cabot has continued its effort there with participation as planned in 7 non-operated wells with a few more to go in this quarter. Last night, we highlighted the latest 2 wells, and these wells were a significant uptick from our excellent initially operated well. The second Cabot operated well was spud last week, and the well is designed for a 4,000-foot lateral with approximately 16 frac stages. Cabot intends to drill 2 additional operated wells and will participate in 8 to 10 total non-operated well in 2011. Cabot now controls approximately 61,500 plus 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-ed the well as unsuccessful, and we'll take the information we collected and continue our science work in the area. Science efforts drove our exploration cost 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, Cabot will have on average 5 rigs running. We're planning 70 to 78 Marcellus wells. We also anticipate running 1.5 frac crews for the year. In Texas and Oklahoma, we will remain focused on acreage production. In the Eagle Ford, Cabot will drill or participate in 20 to 30 wells. In the Marmaton, 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 2 rigs in the south, one in the 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 vertical integrated operation with our internal construction of locations, roads. We also provide water hauling and handling and frac-ing in other various and sundry things that we have in house. In closing, Cabot'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 and 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.

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

Two questions. You made a comment or made a statement in your opening comments there that with 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 kind of realized prices or costs?

Yes, I'll let Jeff Hutton handle that, Brian.

Brian, what we mean by that is the new gas going down Springville will enter Transco's pipeline, the lighting [ph] system. That pipeline goes over to the southern part of New York and actually accesses a number of different utilities and interstate markets that Tennessee gas pipeline does not currently serve. So we should be better off in a number of different ways with new markets both in the northeast and actually down backhaul 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 cost based on the contracting that you've done there?

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 on the gas transmission index.

Got it. And lastly, Dan, free cash flow at that $4.25 gas level at higher gas prices are a pretty rare event as you move closer to this period. Can you just talked how you're thinking about allocation of that cash additional liquids drilling, acquisitions, debt pay down, dividends, et cetera?

Well, our allocation right now is scheduled basically 2/3, 1/3. 2/3 going to the Marcellus and 1/3 going towards liquids.

So I guess the 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, and I'm kind of thinking really onto '12 and maybe beyond.

Scott wanted to make a comment here.

Brian, right now as you saw, the plan is 850 to 900, that will 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. But some of that money could eventually if we have a need in terms of lease expirations or a new idea or new project, some of that can go for some of those new science ideas too.

Your next question comes from the line of Brian Lively, Tudor, Pickering, Holt. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: With the Marcellus capacity at 1.5-plus Bcf a day at year end 2012, when do you guys think you'll actually be able to fill that capacity? And I'm just looking for, is that a 2013, 2014 event?

Well, good question, Brian, and it's safe to say that we have very high expectations of our area otherwise, we wouldn't have added additional capacity. I think being prudent in the market, we have today with the commodity price of where it is. And so we continue to gain efficiencies in our development moving more and more towards a full-blown development mode. But right now, we're just going to try to get out of the fourth quarter of '11 and move into the first quarter of '12. And we've set our guidance for '12. We do believe we internally have a lot of work going on beyond '12. But I'm not prepared to make those projections. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: 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. But is that going to be a [indiscernible] do you think going forward given the returns on the wells? Or would you, if able, actually accelerate some of that growth and outspend a little bit?

Well, right now, our plan is to stay within cash flow. And 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, so I think we're in a very unique situation in that case. And we do fully appreciate the present value aspect of enhancing the profile of our cash flow stream. And at the right opportunity, we will take advantage of that but 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.

[indiscernible] Let me add also 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 '12 captures the leases, all of the leases that would be expiring in '12. We have no lost opportunity within that cash flow neutral program. That would be a dynamic for you, you might outspend but Cabot doesn't need to do that. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: That's fantastic. On the asset sales, do you guys have an updated expected proceeds? I saw that you gave a closing time for the Rockies in October. What's the total proceeds for the year now?

We're probably pushing $375 million. Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. Last question for 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?

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

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, and the rest would be in Pennsylvania.

Your next question comes from the line of Pearce Hammond, Simmons & Company. Pearce W. Hammond - Simmons & Company International, Research Division: First question is what is the gas differentials for Susquehanna County? Are you -- are embedded in your 2012 guidance?

I will refer to Jeff on that also.

For 2012, we're using the -- again, we're reselling off the Dominion index and the Colombia index at probably $0.08 to $0.10 or above NYMEX. And I might add, too, that markets will be accessing on Transco and Millennium. We have seen some downward pressure to the differentials in Pennsylvania along [ph] Tennessee. We think that it's temporary and 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. Pearce W. Hammond - Simmons & Company International, Research Division: Perfect. And then are you experiencing any service cost relief specifically on the completion side in the Marcellus right now?

For our 2012 program, Pearce, we're in the process of gathering all our service cost and closing down some annual contracts for some of our services and it is our expectation as I mentioned that our service cost will moderate both in the south region and the north region for completed well cost. Pearce W. Hammond - Simmons & Company International, Research Division: Perfect. And then, the last question for me. There's been some reports that you're in the Smackover Brown Dense and I was just curious what's your drilling plans were there as well as what acreage you've leased up?

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

Your next question comes from the line of Amir Arif, Stifel. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Just another question in terms of how you're thinking about '12. What would cause you to increase your rig count from above the 5? I mean, I know you've got to take away capacity. You talked about one in the liquid and cash flow. But 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?

Our approach to business just as a general comment is we have so much money to work with. We're going to strive to stay within a budget. We set our benchmarks to stay within that budget with the assumption of what gas price we used in our model. And 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. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. So there's no desire to hedge in additional volumes and accelerate production growth?

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. But 12 months through at this stage is probably in the 4 -- is in between our $4 and $4.50. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Yes, that makes sense. Okay, and then just another question in terms of the 2 wells you highlighted in the Marcellus, the 4Bs and 3Bs in less than a year. These are not extended laterals, is there something different you were doing on these wells?

No, there's just some -- geologically, we find ourselves and some wells stand out in various different areas that we've been drilling. And those are some of the poster boy wells that we've had that produce very well. And 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. And so these are wells that we brought on and allow them to make up a great deal of our production that may be sacrificed to some of the other wells that we'll pinch back. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: And 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 '12 drilling?

We anticipate that it'll be -- after '12 drilling or '11 drilling? Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: After the '12 drilling. I mean after the program you've laid out for '12.

After '12 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 wells, some more drilling. Well, we will have more drilling to come back in to drill in some of those acreage that we do have [indiscernible] production. But I would say 35% to 40%. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: And just a follow-up to that. So 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?

Yes, and again, this is 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 type of pad site set up for 6 wells, 8-well, 10-well type of pad drilling. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: So it sounds like that's a '14 or '15 event, before you really start changing.

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

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

Could you comment on -- what is your -- I know you're cleaning up the 4 wells in -- near the Laser 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 most southern area?

Well, it's still very early, and there's -- only have them on like 3 days. So they are still cleaning up so the comparison would be a little bit earlier. A bit early for that. Three wells into it -- to give you an example, 3 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. So it's just way, way too early to make that statement.

And there's no predictive value in the rate of the cleanup?

No, there's not.

Okay, great. And what is your current average spud to TD for Marcellus?

On well cost?

Days of drills, the wells.

We're between 16 to 18 days.

Okay. And if you're looking at program for 2012 versus the program in 2011, is there proportionally going to be more spend on completions in 2012 than in 2011? Or is it going to be a similar distribution?

No, we're going to spend some more -- more dollars will be spent in '12 on completions than in '11.

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

Gil, 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 marketplace up there to have 2 crews for a period of time. As you can see, they have worked off -- when we had this call in July, we were around 600 stages backlog, now just under 500. We expect that, that 500 will decline further as it relates to next year, more to more of a working inventory between 200 and 300 stages. So again, if you think of the well numbers that we gave and the speeds were 70 to 78 wells, assuming all 15 stage fracs, that will give you the number of stages for next year. And then say, incrementally, we're going to work off the backlog, half the backlog of 250. That will give you an indication of the number of stages that gets done next year.

Okay, great. And just a final question, can you just 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 cost in the south than there is in north and vice versa that you're drilling or -- can you comment on that?

Well, 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 compared to -- in '12 compared to '11 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. But we do anticipate that in the north, we think we would be able to gain efficiencies with each drilling dollars spent by virtue of penetration rates.

Your next question comes from the line of Ray Deacon, Brean Murray. Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division: Dan, I had a question about current well cost in the Marcellus and also yesterday range mentioned 5.7 and 6.5 Bcf EUs, their EUR and so that looked like about a 30% recovery implying there were some potential to increase EURs. I guess, I was just wondering what your thoughts were on that.

Well, 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? Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division: Well, I think in the southwest, they were saying 5.7 and then in Lycoming, they were saying they thought 6.5 was the current -- it's current number.

Okay. Yes, and the well cost in the southwest PA is shallower over there. And as we've been able to see and as the PA DP has put out on well results, Southwest does not deliver quite the rates that we're seeing in the northeast portion of Pennsylvania. And 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. But as far as the drill costs are in the southeast are very similar at the $6.5 million to $7 million range depending on the number of frac stages. Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division: Got it. Great. So 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?

Well, and again, making the comparison, you used 30% on ranges recovery. Keep in mind that, again, just the geology is such that southwest PA has a much thinner section than we have. Our section is 240- to 400-foot thick. So the in-place reserves that we have in that section compared to 70-foot section or so is significantly different. So 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 that is trying to arrive at that recovery factor. But 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.

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

A couple of questions. On -- you gave a number of gross wells, 25 to 30 gross wells in the Marmaton next year. How many net wells would that be?

All right, Matt?

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 so net wells that are non-operated.

And just a question on -- yes, 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?

Yes, Marshall, we have been -- Cabot has consistently evaluated our portfolio and made a number of portfolio rationalizations that has taken advantage of transferring our assets into a more -- a higher PV. And certainly, we'll continue to look at that opportunity out there if the market will allow.

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

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? And then just as you look into '12, do you see any constraint in the number of crews you can get dedicated?

Yes, I'll let Phil respond to that.

We have been picking up spot crews. We have the one we've had full-time, and we've been picking up spot crews to do other jobs. And right now, we're not seeing any constraints in 2012.

Great. And then just on the extended laterals that were mentioned in the press release. Do you have what the actual lateral length was?

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

And then the spacing on that was the same as what you guys have been trying or...

Yes, the spacing of that was about 250 feet or so. And 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.

Great. And then just last one for me. Do you have the amount of [indiscernible] spent on leasehold in the quarter?

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

John, it's between $30 million and $40 million.

Your next question comes from the line of Biju Perincheril, Jefferies. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Quick question. When you think about the incremental volumes on the Springville line, 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 line?

Sure, I'll take that one. The answer is yes. And the expansion by Williams on Springville will include some additional units at their Wilcox Stations that will allow them to increase the capacity of the line from 300 to the 625 number. In addition to that, there'll be some expansion and another new station that Cabot and Williams will develop along the Springville lateral and also around the Tennessee Gas Pipeline area. So there's lots of moving parts to this. And we're well on our way to get all wrapped up at least the big part by mid-year and then the rest by year end. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: Okay. So think about -- I think you've had, for next year, talked about 2 new compressor stations coming on Lenoxville and I think the Williams Central. Are those volumes going to be incremental to what can be moved on Springville? Or is that rerouting some of that?

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 Lathrop station, for example, and the original Teel station and a new station we have on the drawing boards, the Central Compressor station, those will be able to access multiple pipelines. The design of the system is to have access to 3 different interstate markets, 3 very large markets, 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. Biju Z. Perincheril - Jefferies & Company, Inc., Research Division: That's helpful. And, Dan, I think you talked about this before. The 2 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 [ph] like some of your other wells, is that or were you referring to other wells?

Well, they were brought on like other wells that are brought on at a little bit of a moderated rate to allow us to continue to clean up. But 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.

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

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

Bob, part of what we can 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.

Okay, fair enough. Would you say it's more acreage at this time this year than last year then? I mean, 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 mean, I'm just trying to get a tendency of the company.

Yes. Well, we love our position and what we have to work with. And we have 10-plus years of significant opportunities within our portfolio right now. But as far as our company being 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 PA for the Marcellus. And we didn't talk about it, and we didn't bring it up. And we just did our internal work and moved forward without anybody finding out about it until somebody discovered it that we were out there. So I think we have the ability in-house and have that ability in-house to move out ahead of the curve and be reactive and proactive both on new ideas.

Just one final on the Heath, if I may. I mean, I think there were 5 other wells by industry up there. Just question, do you know of any successes in the Heath by others?

No. So far what I've seen, and I don't have all the detail data information on the industry drilling up there, the brief reports I've seen I have not been excited about. But, again, a couple of wells don't kill a play 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.

Your next question comes from the line of Michael Hall, R.W. Baird. Michael Hall - Stifel, Nicolaus & Company: Just 2 quick ones for me. I was curious if you have the rates on the cumes [ph] that you reported, maybe the average rate for the 2 Bcf average for those 30 wells and then perhaps the other rates reported in the ops update?

Well, the 2 wells that have been of note are still producing well over 15 million cubic foot a day each. Michael Hall - Stifel, Nicolaus & Company: Okay. And then how about those 2 -- did you say 30 wells that averaged over 2 Bcf a day? I was just curious if by chance you have kind of average IP -- I'm sorry, the average rate at the time of those cumes [ph].

No, I have not averaged those 30 wells, Mike. Michael Hall - Stifel, Nicolaus & Company: Okay, fair enough. And then 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?

How many wells do we anticipate tying in? Michael Hall - Stifel, Nicolaus & Company: Yes.

55 to 65.

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

[indiscernible] if you provided EUR for Marmaton well [ph]?

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

At this time, there are no further questions.

Okay, Holly. I appreciate everybody's attention, and I think I'll just say any comment that Cabot 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 the cash flow neutral to cash flow positive program that generates in excess of 45% production growth and a 10-plus percent reserve growth with superior capital efficiencies. I don't think you're going to find that in a program that takes about 7 rigs to accomplish those feat. So anyway with that, I'll end it and again, I appreciate everybody's interest in Cabot. Thank you.

Thank you for participating in today's Cabot Oil & Gas Quarter 3 2011 Conference Call. You may now disconnect.