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Executives

Steven Mueller - Chief Executive Officer, President and Director

Greg Kerley - Chief Financial Officer, Executive Vice President and Director

Analysts

Brian Singer - Goldman Sachs Group Inc.

Scott Hanold - RBC Capital Markets, LLC

Robert Christensen - Buckingham Research Group, Inc.

Brian Kuzma - JP Morgan

Scott Wilmoth - Simmons & Company International

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Peter Kissel - Howard Weil Incorporated

Gil Yang - BofA Merrill Lynch

Marshall Carver - Capital One Southcoast, Inc.

Joseph Allman - JP Morgan Chase & Co

Michael Bodino - Global Hunter Securities, LLC

Southwestern Energy (SWN) Q2 2011 Earnings Call July 29, 2011 10:00 AM ET

Operator

Greetings, and welcome to the Southwestern Energy Second Quarter 2011 Earnings Teleconference. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Steve Mueller, Chief Executive Officer of Southwestern Energy. Thank you. Mr. Mueller, you may begin.

Steven Mueller

Thank you, Christine. Good morning and thank you for joining us. With me today are Greg Kerley, our CFO; and Brad Sylvester, our VP of Investor Relations. If you have not received a copy of yesterday's press release regarding our second quarter results, you can find a copy on our website, www.swn.com.

Also, I'd like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors in the Forward Looking Statement sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

Now let's begin. We're excited to report one of the best quarters ever for our company. We posted outstanding growth in earnings, cash flow and production in the second quarter. Despite the current gas price environment -- that's in spite of the current in the gas environment, our production continues to grow, primarily driven by the favorable shale operations. However, we're also beginning to see the impact of our Marcellus Shale activities on our production, where operator production from Marcellus shale is over 100 million cubic feet per day from 17 horizontal wells.

Total production growth was 25% during the quarter, fueled by our Fayetteville Shale play, which grew by 28%, with production of 107 Bcf. We also produced 5.1 Bcf from the Marcellus Shale, 6.3 Bcfe from East Texas and 4 Bcf from our Arkoma operations.

Finally, we announced the new potential unconventional horizontal oil play, and hope to get 2 oils tested and drilled by the end of the year.

Now we'll talk about each of our operating areas. We placed 149 operated wells on production in Fayetteville shale during the first quarter, which resulted in gross operating production reaching 1.8 Bcf per day at July 25.

Our operated horizontal wells at an average completed well cost of $2.8 million per well, with an average drilling time of 8.2 days during the second quarter.

We also placed 10 wells on production during the quarter that were drilled in 5 days or less. In total, we have drilled 55 wells to date in 5 days or less. By the way, just last week, we had our fastest ever at 3.75 days.

Our average initial producing rates were approximately 3 million cubic foot per day, which is down from the first quarter, primarily due to the shorter lateral lengths, location differences in the mix of wells and more pad drilling, which creates additional well interference and uneven loading of compressors.

The last month average monthly production this quarter was in April, where we placed 55 wells on production, an average rate of 2.7 million cubic foot per day. These numbers improved as mix changed during the quarter, and by June, our average initial production rate was 3.4 million cubic foot per day.

In Northeast Pennsylvania, we're very encouraged by what we've seen to date. At June 30, we have completed 17 operated Marcellus Shale horizontal wells in our Greenzweig area in Bradford County. Net production from the area was 5.1 Bcf in the second quarter of 2011 compared to 2.8 Bcf in the first quarter and 0.8 Bcf in the fourth quarter of 2010.

In May, we initiated compression on 7 wells, and this reduced the average line pressure on those wells by 600 to 650 pounds. The other 10 wells, however, are currently producing without the benefit of compression into line pressures of over 1,000 pounds. Gross operating production from this area is currently approximately 104 million cubic foot per day.

We continue to place several wells in production from single path of [ph] time and the results continue to be strong. There is one specific well we'd like to talk about, that's the Ball Myer 1H. It was placed on line in June. This well had completed lateral of 4,500 feet and was fracture stimulated in 19 stages and is currently producing at a tubing-constrained rate of approximately 7.8 million cubic foot per day, at flowing tubing pressure of 1,400 psi after 33 days of production.

Prior to this well, our horizontal wells had average lateral lengths of approximately 3,900 feet and have averaged 10 stages of fracs in our completion. Going forward, our future horizontal wells are expected to average 12 to 13 stages per well, with estimated completed well cost for those wells of $5 million to $5.5 million per well.

In August, we will be moving a second rig into Pennsylvania to begin drilling our Range Trust area in Susquehanna county. For the remainder of 2011, we expect to drill 3 wells in Greenzweig area, 9 wells in the Range Trust area, 10 wells in the Price area and 2 wells in Lycoming County. The majority of these wells we placed on production in 2012.

Switching to new ventures. In New Brunswick, we are on a schedule to drill at least one well in the second half of 2012. We have started the acquisition of approximately 410 miles of 2D data and hope to have that finished in September. We're also in second phase of geochem acquisition, which will provide more information on a potential hydrocarbon generation. That work should be completed by next month.

Early in 2012, we plan to shoot a tie[ph] a group of 2-D seismic to help give us a better understanding of where to drill our first well. Outside of New Brunswick, we currently have approximately 835,000 net undeveloped acres in connection with other new venture prospects. Of these 835,000 acres, we have approximately 460,000 net acres in a new unconventional horizontal play targeting the Lower Smackover Brown Dense formation. It is interesting to note that this happens to be almost the exact same number of acres we had when we announced the Fayetteville Shale play back in August of 2004.

The Brown Dense is a nonconventional oil reservoir found in Southern Arkansas and Northern Louisiana. It ranges in vertical depths from 8,000 to 11,000 feet. It's laterally extensive over a large area, and ranging in thickness from 300 to 530 feet. Our investment in undeveloped acreage in the play area to date is approximately $150 million or $326 per acre, and our leases currently have an 82% average net revenue interest.

We will begin by targeting the higher gravity oil window under our lease, which we believe could be 40% to 55% API range. This formation is below the Haynesville and Smackover and is an upper Jurassic-aged, kerogen-rich, carbonate source rock, which covers an area from Texas to Florida.

We extensively reviewed the Brown Dense across the entire region and have indications that the right mix of reservoir depth, thickness, porosity, matrix permeability, sealing formations, thermal maturity and oil characteristics are found in the area of Southern Arkansas and Northern Louisiana. Frosty [ph] ranges from 3% to 10% in the area, and anticipated pressure gradient is 0.62 psi per foot, so it is overpressured.

Estimated matrix for permeability based on various methods of measurement ranges from less than 0.1 millidarcy to more than 1 millidarcy. Both porosity and matric permeability are comparable to metrics reported in the Eagle Ford play in South Texas.

We have assembled a log data on 1,145 wells covered in 5 states to evaluate the Brown Dense, have acquired over 6,000 miles of 2-D seismic and have gathered and analyzed rock data from cores and cuttings from 70 wells that penetrated the Brown Dense zone. At this point, we currently have more data about the Brown Dense than we had on the Fayetteville Shale when it was announced.

We hope to receive a permit to drill our first well in Columbia County, Arkansas in August. And will spud later in the third quarter. This well is planned to drill to a vertical depth of approximately 8,900 feet and has a planned horizontal lateral length of 3,500 feet. This well will be extensively logged and a full course of plan over the entire Brown Dense interval before the well is completed. The completed well cost of this first well is approximately $10 million, which will have more than $2 million of science work.

Our second well is planned to spud later this year, with a total vertical depth of approximately 10,700 feet and a 6,000-foot horizontal lateral in Claiborne Parish, Louisiana. We plan to drill up to 10 wells in 2012, as we continue to test this concept. This formation serves several large conventional oil and gas fields, and our hope is to use horizontal drilling technology to unlock at least as much potential. Positive test results could significantly increase our activity in this play over the next several years.

We're also working on other new ventures, we'll provide more updates on those in the future.

Finally, in East Texas, we sold certain oil and natural gas leases and wells and gathering equipment in Shelby, San Augustine and Sabine counties for approximately $108 million before the customary purchase price adjustments. This divestiture included only the producing rights in the Haynesville and Middle Bossier Shale intervals in this acreage, with net production of approximately 7 million cubic foot per day as of May 25, 2011, improved net reserves of approximately 25.1 Bcf at the end of the year 2010.

We have deposited $85 million of proceeds from this sale to facilitate potential like-kind exchange transactions.

I will now turn it over to Greg Kerley, our Chief Financial Officer, who will discuss our financial results.

Greg Kerley

Thank you, Steve, and good morning. As Steve noted, our financial and operating results for the quarter were some of the best in our history. We reported earnings for the second quarter of $167 million or $0.48 a share, which was a 37% increase from the prior-year period.

Our discretionary cash flow was a record $448 million in the second quarter, up 30% from $346 million for the same period in 2010. The comparative increases in earnings and cash flow were primarily due to the growth in our production volumes, as Steve spoke about earlier.

Our results stand out even more when you consider that our average realized gas price was comparatively flat with the same period last year. We realized an average gas price of $4.30 in Mcf in the second quarter compared to $4.27 a year ago.

Our hedging activities helped to increase our average gas price by $0.46 per Mcf during the second quarter. We've continued to increase our hedge position, and in the last few months, we hedged an additional 56 Bcf for 2011 at an average price of $5.11 per Mcf, 40 Bcf in 2012 at an average price of $5.01 and 60 Bcf in 2013 at an average price of $5.16.

As a result, we currently have NYMEX price hedges on place on notional volumes on 160 Bcf or over 60% of our remaining 2011 gas production at a weighted average floor price of $5.21 per Mcf.

Operating income for our E&P segment was $223 million during the quarter, up 37% compared to $163 million in the same period last year. Our cost structure continues to be a huge benefit and remains one of the lowest in our industry.

Our all in cash operating costs, which include these operating expenses, general and administrative expenses, taxes other than income taxes and net interest expense, were $1.23 per Mcf for the second quarter of 2011.

Our full cost pool amortization rate also declined, dropping to $1.28 per Mcf in the quarter, down from $1.33 in the prior year. The decline in the average amortization rate was primarily the result of the sales of certain East Texas oil and natural gas leases and wells in late 2010 and 2011, as the proceeds from the sales were appropriately credited to the full cost pool, combined with our lower funding and development cost of our drilling program.

Operating income from our Midstream Services segment was $60 million for the first quarter, up 36% from the prior-year period. The increase in operating income was primarily due to the increase in gathering revenues from our Fayetteville and Marcellus shale plays, partially offset by increased operating costs and expenses.

At June 30, our Midstream segment was gathering approximately 2 billion cubic feet of natural gas per day through almost 1,700 miles of gathering lines in the Fayetteville Shale play compared to gathering approximately 1.6 billion cubic feet per day a year ago.

As you may recall, we have been considering various strategic alternatives for our Fayetteville Shale gathering assets. We have been very deliberate in our analysis. However, we have not yet made a decision on which alternative, if any, we should pursue.

At June 30, we had a $544 million borrowed on our $1.5 billion credit facility at an average interest rate of around 2% and had total debt outstanding of a little more than $1.2 billion, resulting in a debt-to-book capital ratio of 27% and a debt-to-market capital ratio of only 7%, which is one of the lowest in our peer group.

That concludes my comments. And now we'll turn back to the operator, who will explain the procedure for asking questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is from David Heikkinen with Tudor, Pickering.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Steve and Greg and Brad, just trying to think about analogies for the Brown Dense. The reservoir sounds somewhat similar to the volatile oil window maybe in the Eagle Ford. But depths and well design and kind of cost, will that be more similar to a Bakken-type well, as you think about length of lateral number of stages? Or can you build any sort of analogies of how you're thinking about it?

Steven Mueller

One of the things we don't know at this time is exactly what the stimulation is going to look like. But taking the best guess as we can, that first couple of wells we talked about was all the science. Those will be up over $10 million as wells go. We think that once we get through the first wells that have science on them, we can drill wells for roughly $7 million, in that range. And that's assuming somewhere between a 4,500 and 6,000 foot lateral. And the reason there's such a broad range on that is in Arkansas right now, 4,500 is about the longest you can drill a lateral. On the Louisiana side, you can go between 6,000 and 8,000 feet on laterals.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

And you think about somewhere in the 10 -- 12 to 15 stages kind of in that lateral length?

Steven Mueller

That's what we're looking at. But when you look at this, this is a carbonate that's very, very dirty and has a lot of shale and carbonation material in it. And so it could be that it's not in the slick water frac when it's all done. There could be some other frac technique and then stages, and the other things could be completely different. So if you think about a typical slick water frac scenario, you had 10 to 12 stage frac for 4,500 foot lateral. But we're just going to have to play it by year. And when I say science in those first wells, we will be experimenting with different kinds of stimulation, not just going in and say, let's say 10 to 12 stages and go from there.

Operator

Our next question comes from Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC

Maybe to stick on the Smackover, since we're there right now. Can you talk -- it's probably -- the Brown Dense formation is probably not something we're all too familiar with. But what other types of analogies there are wells out there you saw that may give you some encouragement, at least led you to believe there's oil in the tank and maybe this reservoir is frac-able?

Steven Mueller

Yes. Let me run down some numbers, and there's quite a bit of numbers here. But in our press release and what I just said, I talked about the entire play. And in fact that 6,000 of seismic and that 70 wells in it were at least touched the Brown Dense, and we'd actually looked at 1,100 wells. In South Arkansas and Northern Louisiana only, we put together about just over 3,000 miles of 2D. We've reprocessed about 1,000 miles of that. The dips in the area are very gentle 2-degree dips, and there's very little faulting. And when I say very little, there's some 50-foot faults that cover small areas. But other than that, we should be able to land in zone, shouldn't have to worry about faulting and that's what we're looking at. There's 32 wells in that area that have actually drilled into the Brown Dense. Not all of them has gone through it, but they've drilled into it. Of those 32 wells, we were able to find mud logs on 17 of them. All 17 of those mud logs had mud log shows, we were able to analyze that in those wells. There were 11 wells that actually tested oil. The first one of those was tested in 1941. There were a couple of completions. The best well on a completion standpoint from vertical was a 1984 well. It was drilled in Union Parish, Louisiana and actually produced about 7,000 barrels of oil. Most of the other ones were either DSTs or very short of completion tests as I saw it shows and now we're moving up into the more conventional zones, in Smackover and above. And of those, we're in the 40 to 50 barrels a day type short-term test range in them. We had a total of 8 cores that we had some -- that actually were partially or in one case almost went through the entire Brown Dense. Of those 8 cores, most of them all we have was a core reports. We didn't actually see the rock. On 2 of them, we were able to look at the rock in detail and go foot by foot and inch by inch and look at it. And on one of those cores, we were able to actually take a piece of the rock, do some tests on those rock. And I've got a tip my hand to Bob Christensen. For those of you who looked at the cover of our annual report or our presentation, that is a piece of that rock from the Brown Dense. And on there, if you can go back and look at it, with the light streaks on there, the porosity and permeability that we have on that rock. And you can compare -- one of the reasons we put it on front of the cover -- and you can start comparing that to the other plays that are out there. But I think to see and compare is very favorably with the kinds of shales and kind of rock that several companies are drilling in other plays. So that was the data we had. On the piece of rock that we actually could do some work on, we did actual testings to figure out frac-ability. That piece of rock was brittle. Now as we've gone through all of this, we went through 32, all the way down for just one piece of rock. So I can't tell you the whole play is going to be brittle. But that's kind of the basis for encouragement for what we're doing.

Scott Hanold - RBC Capital Markets, LLC

Okay. Good. And then moving to the Fayetteville for my follow-up question, can you talk in terms of just your periodic performance in some of the more recent wells? And obviously, there is going to be some fluctuations in those initial test rates. But over the last, say, 2, 3 quarters, if you look at sort of the relative decline rates from, let's say, the 30-day to the initial rate and from the 68- to the 30-day , it looks a little bit steeper than what you'd experience in the year or 2 before. Is there anything I should read into this?

Steven Mueller

We're not reading anything into it. If you look -- and one of the reasons I gave the kind of a monthly, little bit of monthly information, the 60-day is truly just an average of 60 days. It is the point at 60 days on that well. And I gave some numbers that in April were 2.7 million a day average. Well, the 60-day rates are the April rates. So what you're just seeing on 60 days is the lower IP in April. When you look at the overall chart, I think, and you really want to look at it in the future, I think that's basically -- the basis of your question, it's going to get more lumpy. And by lumpy, since we're drilling pad areas, if we're in one spot, and they're a little bit lower, a little shallow well, a little bit shorter laterals, and at a little bit lower rates. You're going to drill several of them mark down that one spot, and then you can move the rig on the other spot. And so some months or some quarters may have a little lower rate, and other quarters may have a little bit higher rate depending on what's going on. And then you're also going to see it on the overall total production curve, and that we may drill 5 or 6 or 8 wells off of the pad. And then we'll put a bunch of those on at one-time, and so you're going to start seeing some step jumps, where it was more smooth the past. And I think that both of those will start telling you of the phase we're at in our drilling program. When you still look at it, we've tested about 600,000 acres on our acreage that we've got. And that's a net acreage number. It's almost 1 million acres gross. We've actually produced on our company-operated wells, we only put about 2 -- a little over 2,100 wells on our production. And the industry drilling in, in our acreage [indiscernible] 500, 600 wells. So when you put that in perspective, you're in the 200 -- over 200 -- spacing of over 200 acres per well at this point in time. So we've got a lot of wells to go. And you're going to see it bounce around a little bit, but I'm not too worried about it. I think it's just a factor going into the pad more and more in the pad drilling, which the other side of it, you're seeing on drilling.

Scott Hanold - RBC Capital Markets, LLC

Yes, okay. So near term, I mean, what is sort of your -- is there anything to think about in terms of the results we'll see over the next couple of quarters about where you're drilling and whether it's on pads or just some...

Steven Mueller

There isn't much changing. So with the little bit of data that I have right now, we're up a little bit from the last quarter. But I could see maybe a quarter go up, and a quarter go down a little bit. I think the real key that we're looking for, as we go in the future, the 2 things we are watching closely is how fast we can really drill wells off pads. So we can start trying to figure out how many wells you can drill with the rigs that you have going out in the future. And I think the other key that we're trying to figure out is, and you don't see it so much in the IP data, with the exception of where we get a little bit of comparison back up, but what's going to be interference? We think from all the experimental work we've done, that it should be around 10% interference total on the wells and the space that we're looking at. It makes a big difference if its 8% or if it's 12%. So we've got to get that fine tuned and we'll know a lot more about that towards the end of the year. So I think it'll bounce around a little bit. If you really do have that 10% that we're expecting, what you're going to see going into next year, you're going to start seeing a stabilized, general trend. And that stabilize your own trend that last for a long time, even though the quarters may bounce around.

Operator

Our next question comes from Joe Allman with JPMorgan.

Joseph Allman - JP Morgan Chase & Co

Steve, just following up on Scott's question there. So you brought to production about 2,100 wells, and you've got, let say, 8,000 more to go, I'm not sure how many more to go. But going forward, I mean, will the laterals generally be shorter? Or do you think you still have several thousand laterals that are going to be greater than 4,000 feet and a bunch greater than 5,000 feet? And in terms of locations, do you expect that the locations that are left would suggest lower IP rates and lower EURs potentially? And in terms of infill drilling, will that infill drilling affect the results going forward in terms of -- based on the interference?

Steven Mueller

Let me start kind with kind of the end of that question and I'll kind of work back from there. One of the basic things that I think you're trying to ask is have we been concentrating our drilling historically in the very best areas and then we've got worse areas going forward in the future. And if you look at our distribution, across the field, we only have a handful section, when I say handful, I think it's 4 sections that are actually drilled with 9 or more wells on them. And we've said that across the field, we'll end up with 10 wells on the sections. We have, I think it's less than 20% of the sections with even 6 or more wells or 5 or more wells on them. So you've got 80% that you're going to have to drill, several wells on the section still. So what happens there is you're not -- you shouldn't say degradation because of where you're drilling. Now as we talked about in the past, the shallow part of the field, just because it's shallower has less gas and plays, we do drill shorter laterals there, and there's some mechanical reasons for that. So up in the north end of our acreage, those laterals will average less than 4,000 feet. South end of the acreage, they're probably averaged well above 4,000 feet. And when you kind of look at it in general, I think the overall average, we've been saying this for a long time, will be something above 4,000. Whether it makes the 4,500, I don't know, but somewhere between 4,000 and 4,500 foot laterals. And so the little bit of drop on laterals this time just tells you we're drilling more wells in the northern end of our property. That's how it was really doing in that standpoint. But I think you get to between 4,000 and 4,500 feet. Longest lateral we've drilled to date, I believe, we just set a record this quarter, it was around 8,800 foot lateral that we drilled this quarter. And that had some geologic reasons. There's a fault block, there's a skinny [ph] fault block and the only way get the reserve is to drill the 8,800 foot. The reason that we're not drilling longer than 4,500, when you look at the faulting and look at all the other characteristics that go with it, it just averages out, that it's going to be 4,500. Some will be shorter, and some will be 6,000 and 7,0000 feet.

Joseph Allman - JP Morgan Chase & Co

Okay. So I guess, addressing that you get the infill drilling, you're still a long way to go before you...

Steven Mueller

Yes.

Joseph Allman - JP Morgan Chase & Co

Okay, so that's the answer?

Steven Mueller

And going back to your number, on a net basis, we have something like 8,000 wells to drill. And to remind everyone, our average working [indiscernible] is just about 75%. So when you factor that up, it's so over 10,000 gross well to drill.

Joseph Allman - JP Morgan Chase & Co

Got you. Okay. And then just a follow-up for Greg, just on the midstream monetization. So you've taken a deliberate approach. Can you give us some more details on what you're thinking about these days?

Greg Kerley

Well, we're going to continue to study it. And as we continue working towards the end of the year, as we develop our 2012 capital program, I think the capital requirements and what we look at, what we plan to do next year will also factor into that versus our cash flow, whether what alternatives, if any, that we need to supplement cash flow.

Steven Mueller

And let me jump and add something to that. We have had a lot of discussions both internally as management and our Board of Directors about what to do with Midstream and how to get the best value out of it. And I can tell you, one of our concerns is -- one of our key premises is to keep things as simple as possible. And when you start doing things with the Midstream rather than just flat selling it, it starts getting complex in what you're doing. And so we're still debating what that complexity means long term. We know what we can make short term, but what's the real value as you go long term? And we'll continue to think about that and work with it. We haven't come to any decisions on any method or any kind of structure. We haven't eliminated any. All we have is to just continue to have discussions and keep working through it. And as Greg said, as we built budgets and as we look to various things and figure how to finance things, that will come more into the equation as we work it.

Operator

Our next question comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

As you look to the balance of this year, but more importantly, in future years, how should we think about capital and rig allocation between the Fayetteville and Marcellus and now potentially, here, the Smackover? Do you see ramping the Marcellus and then the Smackover as additive to your overall rig count going forward? Or should we expect a flatter or lower rig count in the Fayetteville?

Steven Mueller

I think what you want to think about is additive. What our strategy, going forward, in the Fayetteville Shale is basically, and we're doing it this year, basically at the Fayetteville Shale live within its own cash. And actually, I think over the next couple of years, it will give some cash flow back to the company to help support some of the New Ventures. But to the extent that it can get [ph] those cash flow, it will ramp up along the way. And then any financing or any money we raise or anything in that direction will go to accelerating both New Ventures and the Marcellus. Today, there's one rig. We'll have the second rig in about a month. Towards the end of the year, early next year, we should have a third rig out there. And we haven't put our 2012 budget together yet, but I wouldn't be surprised if we exit next year with roughly 5 rigs running the Marcellus. And then in New Ventures, as we start doing these New Venture plays, and Brown Dense is the first one of those, and so we need to drill 10 wells on that one. We'll get New Brunswick tests the next year, and there will be several wells. Ultimately, you're trying to do in New Brunswick to figure out if that play works. And then we'll start talking about this other acreage at some point in time. What you're going to see starting next year is a ramp up, where we're probably drilling between 10 and 20 wells a year on New Ventures. And so we should be investing roughly the same amount of money on the leasing side. But whatever that -- depend on which play it is and how much it cost to drill wells in those plays, you'll see that will go up to that direction as well. So I would expect in 2012, with the last 2 or 3 years, we've roughly been $1.8 billion to a little over $2 billion range. You will see a jump up in 2012. And we'll talk more about that towards the end of the year.

Brian Singer - Goldman Sachs Group Inc.

Got it. And I guess, for following up on that, what, if any, cost inflationary pressure are you seeing in the Fayetteville? And how does gas macro, demand in gas prices play into your level of activity there, if at all?

Steven Mueller

Well, I think, as far as the cost pressure in the Fayetteville itself, we have not seen the kinds of things that the rest of the industry's talk about in some of the other plays. And there's 2 reasons for that. We own a lot of the equipment on the rig side. And when I say a lot of equipment, we not only own the rigs, we own some other things to go with the rigs, that explains that [ph]. So we've had that locked in for several years and will continue to be locked in. And that sand plant is continuing to do great for us. And the sand plant on the Fayetteville well makes us about 140,000, Marcellus is about 140,000 well, as we look at that sand plant. And that will continue doing that due to the likelihood. And the 2 biggest costs we have are the pumping services and because that's more now just a commodity and it's relatively, on a pumping scale, an easy pump for most contractors. The equivalent we have in Fayetteville doesn't work as well. And Eagle Ford, it certainly doesn't work in Haynesville. So it's kind of tailored to this area. We haven't seen a lot of upward pressure. I think it's only 4% of 5% total from last year. And then on the other big costs is the steel and their casing and tubing. We haven't seen an increase there with any significance. We'll watch that. And certainly, as rig count goes up, there's going to be upper pressure on that. But to remind everyone there, we've got a long-term contract U.S. Steel, to supply that. And it's an index price. So even there, it might go up. I think we're going to get the one with better prices for steel when it does go up. So overall, we continue to think that in Fayetteville -- we guided this year to be a little bit less total dollars in last year to drill equivalent wells. We think we can do that for the next 2 or 3 years easily, even with a little bit upward cost inflation just on the bays that we're going to see drilling.

Operator

Our next question comes from Gil Yang with Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch

A couple of comments sort of on -- questions on sort of your drilling results in the Fayetteville. Greg, you made the comment that your DD&A was lower because of the lower F&D costs. Presumably, that's because the F&D of the wells you're drilling are lower than your aggregate cost pool. Is that right?

Greg Kerley

That's correct.

Gil Yang - BofA Merrill Lynch

Can you talk about what the incremental F&D that you added in this quarter was versus the incremental F&D that you added in the first -- in the last couple of quarters, fourth quarter, first quarter? It really is higher because your EUR seem to be lower this quarter.

Steven Mueller

Let me jump in on that. There's a lot of variables in that, and so I wouldn't make that jump at all because you don't know how many wells we booked or didn't book, or how many wells were positively drilled versus others. And I don't know those either, frankly, so I couldn't give you those numbers but I knew them. So I would just say in general, remind everyone, at the end of the year, we were booking 2.4 Bcf wells or PUDs. And we can certainly, as we drill wells, I think that certainly we can book 2.4 Bcf or better in the future. And on the PDP wells at the end of the year, the ones where we had a history on them that we drilled and had PDP, those were 2.9 Bcf wells. And so I think the end conclusion of that is as far as DD&A rate goes, we in Fayetteville Shale have been around $1 dollar for the last couple of years. We're still around $1, as long as overall company DDA rates is above $1, you'll see it kind of work its way down over time.

Gil Yang - BofA Merrill Lynch

Okay. That's fair. And then the follow up related to the well results. Can you just comment on what the trajectory for volumes you expect out of the Fayetteville because it seems that's sort of a flat line from maybe the last couple of months in that chart that you have. I guess, it's to the end of the quarter, presumably. But it looks like it's sort of flat for a couple of quarters. Does that suggest that going forward, should we expect that to continue in all the drills that will come out of the Marcellus? Or is there some glitch in the prediction from take-away capacity or whatever that's causing that flatlining of production?

Steven Mueller

Yes, production and how fast it goes up or how fast it goes down has several components to it. And one of the components certainly is how good the IPs in the wells are. And one component is how fast you're drilling, and the other component is how many rigs you're running. And I would say all of those are kind of capital budget related things. We kind of guided for the year what we think we're going to do. I believe that having a 28% increase year-over-year in the Fayetteville is probably a pretty good increase in our production to date. And we'll just talk about it more as we start talking about building 2012 out. The question is, is the Fayetteville done? Is it going to flatten out and tip over? I just can't imagine that's going to happen with the number of wells that we have out there. So the other thing to kind of give everyone just a general and remind everyone of, we committed, a couple of years ago, to 2 large pipe coming out in the area. That still does ramp up. We'll get the last bit of that production towards the end of this year going to early 2012. And by the end of this year, we'll have about between 2.2 to 2.4 Bcf a day of capacity that we can take out of Fayetteville Shale. And it's not our intent, we may not hit those numbers exactly, but it's not our intent to pay for [ph] on stuff that are not producing. So we'll keep working it up.

Operator

Our next question comes from Scott Wilmoth with Simmons & Company.

Scott Wilmoth - Simmons & Company International

You mentioned exiting next year potentially in the Marcellus with 5 rigs. Is that predicated on external capital from the Midstream? Or if you get additional capital, could that number go higher?

Steven Mueller

Actually, it's probably predicated on our best guess, a number wells that we're going to ultimately drill and what's reasonable. Again, we've had to buy firm capacity in the Marcellus. And today, we've got on a firm roughly 100 million a day, a little over 100 million a day. That will ramp up to the end of 2013, is the last jump of what we purchased so far. And we'll be up over 400 million, closer to 450 million a day of capacity we have. And then all this capacity you buy you have to hold for a certain period of time. Whether it's Fayetteville Shale or Marcellus, both of them are 10- to 15-year term firm that you're buying. And so when we look at the Marcellus, we know we need to drill at least 1,000 wells. If you ramp up to 5 to 6 rigs, and with what we're assuming we can drill today, that let's you build up to those kinds of numbers and keep that capacity for 8 or 10 years. So that's kind of the logic behind it. So I don't think you'll see us, say, go to 10 or 12 or 13 rigs because then that would -- we don't have enough capacity for that whole 10-year period.

Scott Wilmoth - Simmons & Company International

Yes. I guess I should rephrase my question, is that ramp dependent on the Midstream financing? Or is that going to be part of your...

Steven Mueller

No. It's going to be dependent on how fast we can put equipment out and how fast pipelines are getting built, so we can find [ph] in lines, we don't want a bunch of wells waiting on pipelines.

Scott Wilmoth - Simmons & Company International

Okay, great. And then you mentioned PDP bookings at 2.9 Bs. What's the average lateral length of those PDPs? And how do you expect those to trend over time, given your EUR chart that you guys put in your...

Steven Mueller

I think last year's average lateral length was about -- just under 3,500-foot lateral length. That was the average for last year.

Scott Wilmoth - Simmons & Company International

And how do you expect that PDPs to trend over time?

Steven Mueller

Well, I mean we talked about this in the past. Lateral length is certainly going to average higher in the future, and you should get -- as you're contacting more rock, you should be able to get more out of the rock. But the other part of it is we're going to drill more and more wells that have some interference ultimately with them. And so if we drill up into that 4,500 foot range that I was talking about -- or 4,300 foot that I was talking about before, and you put a 10% interference factor on there, you'll get a little more upside on what you can book as reserve, but there's not a whole lot to that.

Operator

Our next question comes from Marshall Carver with Capital One.

Marshall Carver - Capital One Southcoast, Inc.

A question on production guidance. You had a good production beat in the second quarter and then had several stronger wells later in the quarter, as you were just talking about earlier in the call. Does this imply that your unchanged 3Q guidance is conservative? Or do you plan on putting fewer wells online? Or how should we think about that, 3Q versus 2Q?

Greg Kerley

We will have fewer wells that are coming online between now and the end of the year in the Marcellus, as Steve mentioned before. I mean I think at least what we're talking about is in the range of the vast majority of what will be drilled between now and end of the year will not be coming on until probably the end of the first quarter of 2012 or April 2012, when some of the that additional gathering that gets built. We also had kind of a high well count in the Fayetteville Shale that came on this quarter, too, higher than normal. So we had both of those things kind of working in our factor that we don't see the same kind of timing and it's that it's at the balance of year, you can't see it right now. Things could change in that. And if our drilling days continue to go down, that will also change that. But we feel pretty -- we feel we're comfortable that our numbers right now are very reasonable in our range.

Marshall Carver - Capital One Southcoast, Inc.

Okay. That's helpful. And a follow-up, on the New Ventures plays, do you think you can be spudding a well in another New Venture play later this year? Or is it just going to be the Brown Dense? Or you do not want to comment on that?

Steven Mueller

The wells -- we'll get, I'm hoping to get 2 wells drilled in Texas [ph] and Brown Dense. I doubt whether we will have another well on another play. But we are getting close on a couple. So I would expect that sometime in 2012, we'll make some announcements about some other ones.

Operator

Our next question comes from Peter Kissel with Howard Weill.

Peter Kissel - Howard Weil Incorporated

Quick question. In the past, you'd mentioned that a 1.3 PVI was achievable in the Fayetteville at about $4 gas. And in the Marcellus, I believe, it was about $3.25 on the gas side. I was just curious to see if with some of the cost adjustments and whatnot, if there's any change that would another quarter under your belt?

Steven Mueller

There really isn't much change at all in those general numbers. The Fayetteville is still right around $4. And we're drilling the wells for about the same and for at same EURs, so that's how we're working that way. And the Marcellus, we're still trying to figure out what the EUR is going to be of our wells. They're certainly performing better than we had originally expected. And so depending on what the ultimate EUR is, if anything, there's downward pressure on that numbers that are out there. And I think a year ago, when we only had one well in production, it looked like a 4 Bcf of well and about $5 million to $5.5 million to drill it, we were saying Marcellus is in the low $4. If it happens to be a 5 Bcf well, that drops down into the $3.60, $3.70 range to get 1.3 PVI. If it's above 8, it drops down in the low 3s. So we're just still trying to figure out what the EUR there is. Well like I said, if anything, it down on whether [ph] it's 1.3s and up.

Peter Kissel - Howard Weil Incorporated

Got you, Okay. And then just one follow-up question on the Midstream. Do you have an idea at this point as to what the Midstream EBITDA could look like in 2012?

Steven Mueller

I don't know. It's going to go up with the production, pretty much follow production. And this year, to remind everyone, we said it would be in $270 million range. So whether it's $290 million, $300 million, something, I don't know.

Operator

[Operator Instructions] Our next question comes from Robert Christensen with Buckingham Research Group.

Robert Christensen - Buckingham Research Group, Inc.

Anyway, hold my hand a little bit on one question. You do have a frac crew dedicated to this first well, it's not going to be a well where you drill it, months go by and we have to wait for a frac crew to get in there.

Steven Mueller

Actually, I'll kind of answer the frac crew and the rig question. We're going to use one of our rigs. And in that way, we didn't have to worry about tipping a hand on it. And then we move down here since we get a permit. And from a frac-ing standpoint, we've been working with [ph] for the last 8 or 9 months, helping us to some of the science. And they've promised us a frac crew will be ready whenever we need them so.

Robert Christensen - Buckingham Research Group, Inc.

And on the frac, it sounds like you might not use slickwater, what are the other alternatives?

Steven Mueller

Well, if you go back and think about Fayetteville Shale, we started to do cross link. And we worked through various foams and other things. I don't think you going to have to worry about foams overpressured here. But I could see us trying some different kinds of cross-links. I could see some acid-driven because there's a lot of carbonate here -- some acid-driven fracs, as well as slickwater. And I'm not saying that the first well is not going to have slickwater fracs on it. But in the sequence of wells, we will test other kinds of fracs and frac fluids.

Robert Christensen - Buckingham Research Group, Inc.

Have there been any other horizontals by industry attempted yet? I mean, are yours really the first?

Steven Mueller

There's only 2 recent wells. There is a well drilled about 2 years ago by EOG, It's called EOG Hensley well, it was drilled in, I think it's Lafayette County, Arkansas. It was almost on the Arkansas, Louisiana line, close to Texas border. And was in the deeper part of the play than what we're really targeting. And we thought it would be in the gas win and it tested a million [ph] a day. That was a vertical well. Then recently, earlier this year, I said earlier this year, late last year, there was a well drilled in Columbia County, it was drilled by Gramer [ph] Anderson. And it did have a short horizontal. And I don't know the exact link that horizontal. I know they wanted to drill between 3,000 and 4,000 feet but had some mechanical problems with it. They did get a frac off in the zone [ph] in that short horizontal. They also had some problem on frac-ing. So didn't go on all stages they wanted. The well tested about 40 barrels a day. And was reported to the Arkansas Oil and Gas Commission, with that 40-barrel day rate. It didn't report any gas. But there's reports that there were some small flares on location. Those are the only recent wells, and that's the only horizontal. It's just a very short horizontal that was done. There are a couple of wells permitted, the Gramer [ph], Anderson group has permitted a well south of the one they drilled. And there's a -- part of the company called J-W Operating that has permitted another well in the area. So I think there's going to be some other companies that you get some drilling results on.

Operator

Our next question comes from Michael Bodino with Global Hunter Securities.

Michael Bodino - Global Hunter Securities, LLC

Just a couple of quick questions. Number one, on the Brown Dense, big, big zone and you re-pooled some logs in there, and we note that. Now outside of some of the obvious issues with some of the shales embedded in this. There are some zones that have a pretty nice porosity, there's some zones that look like there may be more fractured. You've got a big, big section like this, what's the process on how you decide where to lay the lateral?

Steven Mueller

I think our first well, we're going to lay it as low as we can. And for those who looked at the logs, there's kind of a hot streak down there in the lower part of it. And consistently, there's some pretty good porosity in the lowest part. But as you said, there's porosity streaks throughout it. So we'll start low, and with the thought that the fracs -- if anything, will go up, if they're not going to go down as much, and so it might catch up into some of the other part of it. And then part of those first 10 wells, we'll have to decide how much, not only what kind of frac we're doing but how much of the section is actually is actually getting tested. And this is a large area. So while we'll start in lower part, and I'm sure it's like a lot of these places where a certain middle or upwards is going to look better and you're going to have to go into those zones at some point in time. To start with we'll land low and then go from there.

Michael Bodino - Global Hunter Securities, LLC

Okay. That's very helpful. The second question I have was up on the Marcellus. Getting back to that whole concept of maybe moving toward 5 rigs next year, with the -- the Cabot Oil [ph] & Gas, payouts are reasonably quick on these wells economics are attractive on a well-by-well basis. There's kind of a natural governor here with infrastructure. But if you move into a more accelerated pace in the Marcellus, is it logical to think that as you move forward here this thing will -- you're going to kind of govern it towards it, I hate to say self-funding, but trying to get this thing toward more self funding? Or is this going to be a major capital need from the company to fund this for the foreseeable future? How fast do you want to go ultimately with this play?

Steven Mueller

Yes. To run a rig with Fayetteville or Marcellus is roughly $100 million, to do a rig. We will invest this year in infrastructure and drilling of about $250 million, a little over $250 million in Marcellus. If we ramp up that 3 or 4 rigs, you're adding $300 million to $400 million to that. We certainly can handle all of that. It's not like the Fayetteville was where we had almost no cash flow as a company and they were trying to ramp this thing up and had to go from there. We can add -- easily handle $300 million to $400 million more with our capacity we have as a company right now. So I don't think you're going to see this as an issue where we have to worry about that part of it.

Operator

Our next question is from Brian Kuzma with George Weiss Associates.

Brian Kuzma - JP Morgan

When I look at your new Marcellus zero-time plots, everything looks like it's basically just pushed out flat from 3 months ago in playing essentially those wells are constrained, I guess? And I'm just curious what your flowing pressures look like today and when you think you'll have line pressure on those wells in terms of days of production.

Steven Mueller

I don't know what our average is. But I would guess it's somewhere around 1,000 pounds. We have that group of wells and compressors at 600 pounds. We've got a lot of other wells are well above 1,000. So I think probably on the average it's about 1,000 B. We do have some compressions that's going to go in later this year that will get some of these other wells on compression. And as we said, we'll get a couple more wells on this year. But really, because of some pipeline that -- pipes [indiscernible] and some PUDs of the DT line, most of the wells we'll drill in the second half of the year, we'll get on early next year on the process. And so you'll start seeing a little bit of help there, just you'll start to get an actual decline in that pipe and that pressure start to go down from there. But as you said, those PUDs are a little bit different than most PUDs. It's taking longer to get up to the highest peak. And it's kind of what I was talking about on the Fayetteville, we've had some issues with, when we put a pad on it, we didn't have enough compression and it take longer to get to the highest peak. You'll see that consistently here for a while as we get it early backlog out of it. And then when you look at that PUD we have, you'll see there's a jump up in some of the end, in some of those wells. Well, that's more for those compressions on those wells, you're seeing it jump up.

Brian Kuzma - JP Morgan

All right. And so like if you -- do you guys have models that would indicate like what type of IP rate it would be capable of if it was unconstrained?

Steven Mueller

Yes, we do. And a model is a model. There's all kind of variables to go into that. But I think for those who followed Cabot, I don't know if any of these would be $30 million a day wells. But they would certainly much with Cabot's high teens, low 20s on those if you just do 100 pounds, 150 pounds pressure trend points.

Operator

Mr. Mueller, we have no further questions at this time. I would now like to turn the floor back over to you for closing comments.

Steven Mueller

Thank you, Christine. I guess, the best way to sum this up is go back to the cover of our annual report, where we talked about core values. What this year and what we've been trying to do as a company is to bring value plus for all of our investors. And when you look at the Fayetteville and Marcellus are certainly the right things. It doesn't really matter what the gas price is, those are making some good money all throughout. You look at New Brunswick and the Brown Dense, and then you look at the others, the 375,000 acres, and we've got exciting potential. And then you look at our numbers, and I don't know if we have all the right people, but certainly, we keep delivering on the numbers. So we've got the people in place. And so we're just going to keep working the formula as we work through it. And will there be some bumps on the road, and there will be some good days, but we'll go through it. But we're convinced, if we keep working the formula, we can deliver and continue doing good for our shareholders. And with that, I'd like to thank you for joining us, and have a great weekend.

Operator

Ladies and gentlemen, this does conclude today's teleconference. You may disconnect your lines at this time. Thank you for your participation, and have a wonderful day.

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