Southwestern Energy Company

Q2 2011 Earnings Teleconference

Friday, July 29, 2011

Officers

 Steve Mueller; Southwestern Energy; President and CEO

 Greg Kerley; Southwestern Energy; CFO

Analysts

 David Heikkinen; Tudor, Pickering, Holt; Analyst

 Scott Hanold; Royal Bank of Canada; Analyst

 Joe Allman; J.P. Morgan Chase & Co.; Analyst

 Brian Singer; Goldman Sachs; Analyst

 Gil Yang; Bank of America/Merrill Lynch; Analyst

 Scott Wilmoth; Simmons & Company International; Analyst

 Marshall Carver; Capital One Southcoast, Inc.; Analyst

 Peter Kissel; Howard Weil, Incorporated; Analyst

 Robert Christensen; The Buckingham Research Group; Analyst

 Michael Bodino; Global Hunter Securities; Analyst

 Brian Kuszmar; George Weiss Associates; Analyst

Presentation

Steve 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 at www.swn.com.

Also, I would 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 and the Forward-Looking Statements sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe these 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. Our production continues to grow, primarily driven by the Fayetteville Shale operations. However, we are 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 Bcfe 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 well play and hope to get 2 wells tested and drilled by the end of the year.

Now to talk about each of operating areas. We placed 149 operated wells on production in the Fayetteville Shale during the second quarter, which resulted in gross operated production reaching 1.8 Bcf per day at July 25th. Our operated horizontal wells had 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 five days or less. In total, we have drilled 55 wells to date in five 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 feet per day, which is down from the first quarter, primarily due to the shorter lateral lengths, location difference in the mix of wells and more pad drilling, which creates additional well interference and uneven loading of compressors. The lowest average monthly production this quarter was in April, where we placed 55 wells on production at an average rate of 2.7 million cubic feet 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 with what we've seen to date. At June 30th we had 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 it's 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 operated production from this area is currently approximately 104 million cubic foot per day. We continue to place several wells on production from single pad at a 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 a 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 a 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 will be placed on production in 2012.

Switching to new ventures. In New Brunswick, we are on schedule to drill at least 1 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 are also in the 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 tighter grid of 2D 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 an unconventional oil reservoir found in Southern Arkansas and Northern Louisiana. It ranges in vertical depths from 8,000 to 11,000 feet; its lateral extends over a large area and ranges in thickness from 300 to 550 feet. Our investment in the 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'll 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, it is an Upper Jurassic age, 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, ceiling formations, thermal maturity and oil characteristics are found in the area of Southern Arkansas and Northern Louisiana. Porosity ranges from 3% to 10% in the area and anticipated pressure gradient is 0.62 psi per foot, so it is overpressured.

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

We have assembled log data on 1,145 wells covering five states to evaluate the Brown Dense and acquired over 6,000 miles of 2D 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 we'll spud it 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 planned over the entire Brown Dense interval before 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 has sourced 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 and I'll provide more updates on those in the future.

Finally, at East Texas, we sold certain oil and natural gas leases and wells 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 and proved 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 an 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've 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 in 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 it remains one of the lowest in our industry. Our all-in cash operating costs, which include lease 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 full 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 a result of the sale 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 finding and development costs of our drilling program.

Operating income from our Midstream Services segment was $60 million for the second 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 30th 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 30th we had $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, so now we’ll turn back to the operator who will explain the procedure for asking questions.

Questions and Answers

David Heikkinen:  Good morning, 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 Eagleford, but depths and well designs and kind of costs. Would 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?

Steve 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 guesses we can, that first couple of wells we talked about with 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:  And you think about somewhere in the 10 -- 12 to 15 stages kind of in that lateral length?

Steve Mueller:  That’s where 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 carbonations material in it, and so it could be that it’s not even a slick-water frac when it’s all done. There could be some other frac technique and then the stages, and the other things would be -- could be completely different. So if you think about in the typical slick-water frac scenario, you had a 10 to 12-stage frac for a 4,500-foot lateral, but we’re just going to have to play it by ear. And when I say science on those first wells, we will be experimenting with different kinds of stimulation, not just going in and, say, “Let’s do 10 and 12 stages and go from there.”

Scott Hanold:  And then it sounds like you ought to start measuring the Fayetteville drill times in hours, not days, but that’s all I’ve got.

Steve Mueller:  Thank you.

Scott Hanold:  Thanks, good morning.

Steve Mueller:  Good morning.

Scott Hanold:  Maybe to stick on the Smackover, since we’re there right now, can you talk -- probably the Brown Dense formation is probably not something we’re all too familiar with, but what other types of analogies or wells out there you saw that may give you some encouragement, or at least lend you to believe there’s oil in the tank and maybe this reservoir is fracable?

Steve 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, in fact, about 6,000 miles of seismic and there’s been 70 wells that at least touched the Brown Dense and we’ve 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 most of what we’re looking at. There’s 32 wells in that area that have actually drilled into the Brown Dense. Not all of them have 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 on 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 a 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 completion tests. As I saw shows in them, they were moving up into the more conventional zones in Smackover and above, and those were in the 40-to-50-barrel a day type short-term test range on them.

We had a total of eight cores that we had some -- that actually were partially, or in one case, almost went through the entire Brown Dense. Of those eight cores, most of them, all we had was the core reports. We didn’t actually see the rock. On two 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 and do some tests on those rocks.

And I’ve got to tip my hand to Bob Christiansen. For those of you who looked at the cover of our Annual Report or of our presentation, that is a piece of that rock from the Brown Dense, and on there -- you can go back and look at it -- but the light streaks in there are the porosity and permeability that we have on that rock, and you can compare. One of the reasons it was put on the cover is you can start comparing that back to the other plays that are out there, but I think you'll see it compares very favorably with the kinds of shales and kind of rock that several other 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 triaxial testing to figure out fracability. That piece of rock was brittle. Now, as we've gone through all this, we went from 32 all the way down to just one piece of rock, so I can’t tell you the whole play is going to be brittle, but that’s kind of a basis for our encouragement for what we’re doing.

Scott Hanold:  Okay, good. Thanks for that color. And then moving to the Fayetteville for my follow-up question, can you talk in terms of just periodic performance of some of the more recent wells? Obviously, there’s going to be some fluctuations from those initial test rates, but over the last, say, two to three quarters, if you look at sort of the relative decline rates from, say, the 30 day to the initial rate from the 60 to 30 day, that looks a little bit steeper than what you’d experienced in the year or two before. Is there anything I should read into this?

Steve Mueller:  We’re not reading anything into it. If you look -- and one of the reasons I gave the kind of a monthly -- a little bit of monthly information, the 60 day is truly just -- it’s not an average of 60 days. It is the point at 60 days on that well and I gave some numbers that in April, we were 2.7 million a day average. Well, the 60-day rates are the April rates. So what you’re just seeing on the 60 days is the lower IP in April.

When you look at the overall chart, I think -- and you really want to look out 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 shallower wells, a little bit shorter laterals, and they have a little bit lower rates, you're going to drill several of them right there in that one spot and then you’re going to move the rig to another spot. And so

some months, or some quarters, may have a little lower rate and the 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 in that we may drill five or six or eight wells off of a 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 in the past. And I think that both of those will start telling you 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 about a million acres gross. We've actually produced. On our company-operated wells, we've only put about two -- a little over 2,100 wells on production and the industry drilling in our acreage probably has another 500, 600 wells.

So when you put that in perspective, you're in the 200 to over 200 -- spacing of over 200 acres per well at this point in time. So that would be a lot of wells to go and you're going to see us bounce around a little bit, but I’m not too worried about it. I think it’s just the factor of going into the pad, more and more in the pad drilling, which the other side of it, you’re seeing no drilling.

Scott Hanold:  Okay. Okay. So near term, 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 --

Steve Mueller:  Yes, there’s isn’t much changing. So with the little bit of data that I have right now, we’re up a little bit from 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 two things we’re 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 compression backup, 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 spacing that we’re looking at. It makes a big difference if it’s eight 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 stabilized general trend will last for a long time, even though the quarters may bounce around.

Scott Hanold:  Okay, appreciate it. Thank you.

Joe Allman:  Thank you. Good morning, everybody.

Steve Mueller:  Good morning.

Joe Allman:  Hey, Steve, just following up on Scott’s question there, so you’ve brought the

production to about 2,100 wells and you’ve got, let’s say, 8,000 more to go -- I’m not sure how many more to go, but -- so going forward, I mean, will the laterals generally be shorter or do you think you'll 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 or -- and lower EURs potentially? And in terms of infill drilling, just will that infill drilling affect the results going forward in terms of -- based on the interference?

Steve Mueller:  Let me start with kind of the end of that question and I’ll kind of work back from there. One of the basic things I think you were trying to ask is we've been concentrating on 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 of sections. When I say a “handful,” I think it’s four sections that are actually drilled with nine 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 six or wells or five 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 in place. We do drill shorter laterals there and there’s some mechanical reasons for that. So up on the north end of our acreage, those laterals will average less than 4,000 feet. South end of the acreage, they’ll probably average well above 4,000 feet.

And when you kind of look at it in general, I think the overall average -- and we've been saying this for a long time -- will be something above 4,000. Whether it makes it to 4,500, I don’t know, but somewhere between 4,000 and 4,500-foot laterals. So the little bit of drop in laterals this time just tells you we’re drilling more wells in the northern end of our property. That’s all it was really doing [from] that standpoint, but I think it gets there between 4,000 and 4,500 feet.

The longest lateral we've drilled to date -- I believe we just had a record this quarter. It was around an 8,800-foot lateral that we drilled this quarter, and that had some geologic reasons. There’s a fault block; there’s a skinny fault block and the only way you can get the reserves 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 7,000 feet.

Joe Allman:  Okay. And so I guess addressing the infill drilling, you still have a long way to go before you --

Steve Mueller:  Yes.

Joe Allman:  Okay. That’s the answer.

Steve 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 interest is about 75%, so when you factor that up, it’s over 10,000 gross wells to drill.

Joe Allman:  Got you, got you. Okay. And then just a follow-up for Greg, just on the Midstream monetization, so you’ve taken a delivered 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, what we look at and 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.

Steve Mueller:  And let me jump in 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 other 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 just continue to have discussions and keep working through it.  And, as Greg said, as we build budgets and as we look at various things and figure out how to finance things, that will come more into the equation as we work it.

Joe Allman:  Okay.  That's all very helpful.  Thank you.

Brian Singer:  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 the Smackover as additive to your overall rig count going forward?  Or should we expect a flatter or lower rig count in the Fayetteville?

Steve Mueller:  I think what you want to think about is additive.  What our strategy going forward in the Fayetteville Shale is, is basically -- and we're doing it this year -- is basically have the Fayetteville Shale live within its own cash flow.  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 live within its 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 or 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 in 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 we said we need to drill 10 wells on that one.  We'll get New Brunswick tested next year and there will be several wells ultimately you'll probably have 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 as a ramp up where we're probably doing between 10 and 20 wells a year on new ventures.  And so we should investing roughly the same amount of money on the leasing side, but whatever that -- depending on which play it is and how much it costs to drill a well in those plays, you'll see that go up in that direction as well.  

So I would expect in 2012, where the last 2 or 3 years, we've roughly been in the $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:  Okay, thanks.  And I guess, following up on that, what if any cost inflationary pressure are you seeing in the Fayetteville?  And how does gas macro and demand in gas prices play into your level of activity there, if at all?

Steve Mueller:  Well, I think as far as the cost pressure on the Fayetteville itself, we have not seen the kinds of things that the rest of the industry's talked about in some of the other plays.  And there's two reasons for that.  We own a lot of the equipment on the rig side.  And when I say a lot of the equipment, we not only own the rigs, we own some other things that go with the rigs that explains that.  So we've had that locked in for several years and it will continue to be locked in.

That sand plant is continuing to do great for us.  And the sand plant on the Fayetteville will -- makes us about $140,000 or saves us about $140,000 a well, as we look at that sand plant.  And that will continue doing that for the life of it.  

And the two biggest costs we have are the pumping services -- and because that's more now just a commodity and it's a relatively, on a pumping scale, an easy pump for most contractors. And the equipment we have in Fayetteville doesn't work as in Eagle Ford and certainly doesn't work in the Haynesville.  So it's kind of tailored for this area.  We haven't seen a lot of upward pressure.  I think it's only 4% or 5% total from last year.

And then on the other big cost is the steel and our casing and tubing.  We haven't seen an increase there of any significance.  We'll watch that and certainly as rig count goes up there's going to be upward pressure on that.  But to remind everyone there, we've got a long-term contract with US Steel to supply that and it's an indexed price.  So even there it might go up, but I think we're going to get one of the better prices for steel when it does go up.

So overall, we continue to think that in Fayetteville -- we've guided this year to be a little bit less total dollars than last year to drill equivalent wells.  We think we can do that for the next two or three years easily, even with the little bit of upward cost inflation, just on the days that we're going to save drilling.

Brian Singer:  Great.  Thank you.

Gil Yang:  Couple comments, or two other questions on 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:  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 last couple quarters -- fourth quarter, first quarter?  Presumably it was higher because your EURs seemed to be lower this quarter.

Steve Mueller:  Let me jump in on that one.  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 PUDs that we drilled versus others.  And I don't know those either, frankly, so I couldn't give you those numbers if 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 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 are 2.9 Bcf wells.  And so I think the end conclusion of that is, as far as far as the DD&A rate goes, we in the Fayetteville Shale have been around $1.00 the last couple of years.  We're still around $1.00.  And as long as our overall Company DD&A rate's above $1.00 you'll see it kind of work its way down over time.

Gil Yang:  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 seemed to sort of flat-line for maybe the last couple of months in that chart that you had.  I guess it's to the end of the quarter, presumably.  But it looked like it sort of was flat for a couple of quarters.  Does that suggest that going forward should we expect that to continue and all of the growth will come out of the Marcellus?  Or is there some glitch in the production from take-away capacity or whatever that's causing that flat-lining of production?

Steve Mueller:  You know, 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 of the components 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've 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.  But if the question is, is the Fayetteville done and it's 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 I'll try to give everyone just a general and remind everyone of, we committed a couple of years ago to two large pipe coming out of the area.  But [when] that still does ramp up

and we get the last bit of that production toward the end of this year, going into early 2012.  And by the end of this year we'll have about -- between 2.2 and 2.4 Bcf a day of capacity that we can take out of the Fayetteville Shale.  And it's not our intent -- we may not hit those numbers exactly -- but it's not our intent to pay firm on stuff we're not producing.  So we'll keep working it up.

Gil Yang:  All right.  Thank you.

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

Steve Mueller:  Actually, it's probably predicated on our best guess the number of 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 the firm roughly 100 million a day, little over 100 million a day.  That will ramp up to the end of 2013's the last jump of what we purchased so far.  And we'll be up over 400 -- 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 that you're buying.  And so when we look at Marcellus, we know we need to drill at least 1,000 wells.  If you ramp up to five to six rigs, and with what we're assuming we can drill them today, that lets 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 -- we don't have enough capacity for that whole 10-year period.

Scott Wilmoth:  Yes, I guess I should have rephrased my question.  Is that ramp dependent on the Midstream financing, or is that going to be part of your --

Steve Mueller:  No, it's going to be dependent on how fast we can put equipment out and how fast pipeline's getting built so we can tie in lines.  We don't want a bunch of wells waiting on pipelines.

Scott Wilmoth:  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--

Steve Mueller:  Well, 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:  And how do you expect that PDP to trend over time?

Steve Mueller:  Well -- and 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 go up in the next 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've got a little more upside on what you can book as reserves, but there's not a whole lot to that.

Scott Wilmoth:  Okay.  Thanks, guys.

Marshall Carver:  Question on production guidance.  You had a good production beat in the second quarter and then had several stronger wells later in the quarter you were just talking about earlier in the call.  Does this imply that you're unchanged 3Q guidance is conservative?  Or do you plan on putting fewer wells on line or how should we think about that -- 3Q versus 2Q?

Greg Kerley:  We will have fewer wells that are coming on line 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 a range of -- the vast majority of what will be drilled between now and the end of the year will not be coming on until probably the end of the first quarter of 2012, or April of 2012 when some of the other additional gathering gets built.  We also had kind of a high well count in the Fayetteville Shale that came on this quarter, too, that -- higher than normal.  So we had both of those things kind of working in our factor.  But we don't see the same kind of timing and stuff in the balance of the year.  We can't see it right now.  Things could change in that and if our drilling days continue to go down, that would also change that.  But we feel pretty -- we feel very comfortable that our numbers right now are very reasonable in our range.

Marshall Carver:  Okay, that's helpful.  And a follow-up -- on the new ventures plays, do you think you're going to be spudding a well in another new venture play later this year?  Or is it just going to be the Brown Dense?  Or do you not want to comment on that?

Steve Mueller:  We'll get -- I'm hoping to get two wells drilled and tested in Brown Dense.  I doubt whether we'll have another well in another play, though we are getting close on a couple.  So I would expect that sometime in 2012 we'll make some announcements about some other ones.

Marshall Carver:  Okay.  Thank you.

Peter Kissel:  Hi, good morning, guys.  A quick question.  In the past you had 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 what-not if there’s any change to that with another quarter under your belt?

Steve 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, roughly the same EURs, and so that’s all 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 dependent 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, and it look like a 4 Bcf well, and about $5 million to $5.5 million to drill it, we were saying Marcellus was in the low $4.  If it happens to be a 5 Bcf well that drops down into the $3.60, $3.70 range, the 1.3 PVI.  If it’s above 8 it drops down in the low 3s.  So we’re just – we’re still trying to figure-out what the EUR there is.  We’d like to say if anything it’s downward on what it’s 1.3 is, not up.

Peter Kissel:  Got you.  Okay, thank you.  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?

Steve Mueller:  I don’t know, you know, it’s going to go up with the production, pretty much follow production.  This year, to remind everyone, we said it’d be in the $270 million, $270 million range.  So, whether that’s $290 million, $300 million something, I don’t know.

Peter Kissel:  Okay, great.  Thanks for taking my questions.

Robert Christensen:  Hey, thanks for the positive recognition there, Steve.

Steve Mueller:  Well, you started it, Bob.

Robert Christensen:  Well, I guess the Princeton Geology (inaudible) was the secret to that, credit to the [phase], that’s the phase.  But, 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 and months go by and we have to wait for a frac crew to get in there?

Steve Mueller:  Actually, I’ll kind of answer, the frac crew and the rig question.  We’re going to use one of our rigs, and that way we didn’t have to worry about tipping a hand on it.  And they’ll move down here as soon as we get a permit.  And from a frac crew standpoint we’ve been working with Schlumberger for the last eight or nine months, helping us with some of the science, and they’ve promised us a frac crew will be ready whenever we need them, so.

Robert Christensen:  And on the frac it sounds like you might not use slick water.  What are the other alternatives?

Steve Mueller:  Well, you know, if you go back and think about the Fayetteville Shale we started with cross link and we worked through various foams and other things.  I don’t think you’re going to have to worry about foams over pressure 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 tracks, as well as slick water.  And I’m not saying that the first well is not going to have slick water fracs on it, but in the sequence of wells we will test other kinds of fracs and frac fluids.

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

Steve Mueller:  There’s only two recent wells.  There’s a well drilled about two years ago by EOG.  It’s called the EOG Hensley Well.  It was drilled in I think it was Lafayette County, Arkansas.  It was almost on the Arkansas, Louisiana line, close to the Texas border, and was in a deeper part of the play than what we’re really targeting.  And we thought it would be in the gas window, it tested a million 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 – I’m trying to look at – Columbia County.  It was drilled by Bremer 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, though, in that short horizontal.  They also had some problem I know fracing so they didn’t get all the stages they wanted.  That well tested about 40 barrels a day, and it was reported to the Arkansas Oil and Gas Commission was that 40 barrel a day rate.  Didn’t report any gas but there’s reports that there were some small flares in 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 Bremer Anderson Group has permitted a well south of the one they drilled, and there’s 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 to get some drilling results on.

Robert Christensen:  Okay.  Thanks very much.

Steve Mueller:  Thank you.

Michael Bodino:  Good morning.

Steve Mueller:  Good morning.

Michael Bodino:  Just a couple of quick questions.  Number one on the Brown Dense, it’s a big thick zone.  And we pulled some logs here and there and we note that outside of some of the obvious issues with some of the shales interbeddened in this there’s some zones that have pretty nice porosity, there’s some zones that look like they may be more fractured.  When you’ve got a big thick section like this what’s the process on how you decide where to lay the lateral?

Steve Mueller:  I think our first well, are going to lay it as low as we can, and for those who have looked at the logs there’s a kind of 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, they’re not going to go down as much, and so they 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 those sections are actually getting tested.  And this is a large area so while we start in the lower part, and I’m sure it’s like a lot of these places where there are certain middle or upper is going to look better and you’re going to have to go into those zones at

some point in time.  But to start with we’ll land low and then go from there.

Michael Bodino:  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 five rigs next year, with the forward curve in 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 kind of going to govern it toward its – I hate to say self-funding, but trying to get this thing toward more self-funding?  Or is this going to 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?

Steve Mueller:  Yes, to run a rig, whether it’s Fayetteville or Marcellus is roughly $100 million to do a rig.  We will invest this year in infrastructure and drilling to about $250 million, a little over $250 million in Marcellus.  If we ramp-up and add three or four 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 to the Company and then we’re trying to ramp this thing up and had to go from there.  We can easily handle $300 million to $400 million more dollars with our capacity we have as a Company right now.  So I don’t think you’re going to see us in an issue where we have to worry about that part of it.

Michael Bodino:  Okay.  Thank you very much.

Steve Mueller:  Thank you.

Brian Kuszmar:  Hey, good morning, guys.

Steve Mueller:  Good morning.

Greg Kerley:  Good morning, Brian.

Brian Kuszmar:  When I look at your new Marcellus zero time plots, everything looks like it’s basically just pushed out flat from three months ago in play, 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 hit line pressure on those wells in terms of days of production?

Steve 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 on compressors at 600 pounds.  We’ve got a lot of the other wells are well above 1,000.  So I think probably in the average is about 1,000.  We do have some compression 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, pipes we’re laying and some – the DTE line most of the wells we’ll drill in the second half of the year will get on early next year on the process.  And so you’ll start seeing a little bit of help there just as you start getting on actual decline and that, of course, will start going down from there.

But, as you said, those plots are a little bit different than most plots.  It’s taken longer to get up to the highest peak.  That’s kind of what I was talking about on the Fayetteville, we’ve had some issues with when we put a pad on we didn’t have enough compression, it’ll take longer to get to highest peak.  

You’ll see that consistently here for awhile and as we get our old backlog out of it.  And then when you look at that plot we had, you’ll see there’s a jump-up in some of the ends of some of those wells.  The last one we put compression on those wells, you’ve seen that jump-up.

Brian Kuszmar:  All right, sir.  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?

Steve Mueller:  Yes, we do.  A model is a model.  There’s all kinds of variables that go into that.  But I think, for those who follow Cabot, I don’t know that any of these would be 30 million a day wells, but they would certainly match with Cabot’s high teens, low 20s on those if you just did 100 pounds or 150 pounds pressure kind of things.

Brian Kuszmar:  I see.  Okay, perfect.  That’s it.  Thanks, guys.

Steve Mueller:  Thank you.

Steve 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 throughout.  You look at New Brunswick and the Brown Dense, and then you look at the other 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 there’ll be some bumps on the road, and then there’ll be some good days as we 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.

Explanation and Reconciliation of Non-GAAP Financial Measures

We report our financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However, management believes certain non-GAAP performance measures may provide users of this financial information with additional meaningful comparisons between current results and the results of our peers and of prior periods.  

One such non-GAAP financial measure is net cash provided by operating activities before changes in operating assets and liabilities. Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.

See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the three months ended June 30, 2011 and June 30, 2010.  Non-GAAP financial measures should not be considered in isolation or as a substitute for the Company's reported results prepared in accordance with GAAP.