SOUTHWESTERN ENERGY CO - FORM 8-K - EX-99 - SWN Q4 2011 TELECONFERENCE TRANSCRIPT

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8-K - SWN FORM 8-K Q4 2011 TELECONFERENCE TRANSCRIPT - SOUTHWESTERN ENERGY CO	swn022811form8k.htm

Southwestern Energy Company

Q4 2011 Earnings Conference Call

Tuesday, February 28, 2012 10a.m. E.T.

Officers

Steve Mueller; Southwestern Energy; President and CEO

Greg Kerley; Southwestern Energy; CFO

Brad Sylvester, Southwestern Energy; VP, Investor Relations

Analysts

Scott Hanold; RBC Capital Markets; Analyst

Gil Yang; Bank of America Merrill Lynch; Analyst

Brian Singer; Goldman Sachs; Analyst

Marshall Carver; Capital One; Analyst

David Heikkinen; Tudor, Pickering, & Holt; Analyst

Dave Kistler; Simmons & Co.; Analyst

Robert Christensen; Buckingham Research; Analyst

Dan McSpirit; BMO Capital Markets; Analyst

Joe Magna; Macquarie Capital Markets; Analyst

Presentation

Operator: Greetings, and welcome to Southwestern Energy's Fourth Quarter Earnings Teleconference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions)

As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Steve Mueller, President and CEO. Thank you, sir. You may begin.

Steve Mueller: Good morning, and thank you for joining us. With me today are Greg Kerley, our Chief Financial Officer, and Brad Sylvester, our VP of Investor Relations.

If you have not received a copy of yesterday's press release regarding our fourth quarter and year-end 2011 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 the 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.

Let's begin.

2011 was another record year for Southwestern Energy. We set new records in production reserves, and as a result of our 24% production growth, we achieved the highest earnings and cash flow in our

company's history.

We produced 500 Bcfe, driven largely by our Fayetteville Shale play, where our production grew 25% to 437 Bcf. Our production from Marcellus Shale also grew from 1 Bcf in 2010 to 23 Bcf in 2011, while our ArkLaTex production declined from 54 Bcf in 2010 to 40 Bcf in 2011.

Our year-end proved reserves also increased by 19% to a record 5.9 trillion cubic feet of gas. Approximately 100% of our reserves were natural gas, and 45% were classified as proved undeveloped.

We replaced 299% of our 2011 production at finding and development costs of $1.31 per Mcfe, including revisions. This, along with our all-in cash costs of $1.27 per Mcfe, gave us one of the lowest cost structures in the industry.

This year has already started out to be a challenge, but as I tell our employees, our goal is not just to survive; it's to thrive.

Now, I'll talk about our operating areas.

In the Fayetteville Shale, we added 1.2 Tcf of new reserves at a finding and development cost of $1.13 per Mcf.

Total proved reserves booked in the Fayetteville Shale play at year-end 2011 were 5.1 Tcf, up 17% from the reserves booked at the end of 2010.

We spud 580 operated wells in the Fayetteville Shale during 2011 and placed a record 560 operated wells on production, resulting in a gross production from our operated wells to increase from 1.6 Bcf a day at the first of the year to 1.9 Bcf per day at the end of the year.

We saw a continued improvement in our drilling practices at Fayetteville Shale in 2011 as our operated horizontal wells had an average completed well cost of $2.8 million per well, average horizontal length of 4,836 feet, and average time to drill of eight days from reentry to reentry. This compared to approximately the same costs in 2010 with a shorter lateral.

We also placed 73 wells in production during 2011 that were drilled in five days or less. In total, we have drilled 104 wells to date in five days or less.

It's amazing that it's taken seven years since first production to transition the Fayetteville Shale drilling program from establishing first wells in the section to drilling multiple wells from a pad. Our average initial producing rates were approximately 3.3 million cubic foot per day compared to last year's 3.4 million cubic foot per day average rate. And in the fourth quarter of 2011, this average rate was over 3.6 million cubic foot of gas per day.

Now, switching to Pennsylvania. We added 327 Bcf new reserves at a finding/development cost of $1.02 per Mcf.

Total proved reserves booked at our Marcellus Shale area at year-end 2011 was 342 Bcf, up from the 38 Bcf booked at the year-end 2010.

As of year-end 2011, we had spud 70 wells, 23 of which were put on production and 67 of which were horizontals.

Total [dated] production from the area was approximately 133 Mcf per day at December 31 and limited by online pressures.

Our operated horizontal wells had an average completed well cost of $6.4 million per well, average horizontal lateral length of 4,007 feet, and average of 14 -- of 12 fracture stimulation stages.

The average gross proved reserves from the undeveloped wells included in our year-end reserves was approximately 7.5 Bcf per well and approximately 8.6 Bcf per well for our proved developed wells in 2011.

As for new ventures, at December 31, 2011, we had 3.6 million net undeveloped acres, of which 2.5 million acres were located in New Brunswick, Canada, and the remaining approximately 1.1 million acres were located in the United States.

In New Brunswick, we have invested approximately $24 million through December 31, 2011 and have acquired 248 miles of 2D seismic. In 2012, we intend to acquire approximately 130 additional miles of 2D, and our current plan includes drilling in two stratigraphic well tests in the fourth quarter of 2012.

In our Lower Smackover Brown Dense play in Southern Arkansas and Northern Louisiana, we hold approximately 520,000 net acres at an average cost of $375 per acre.

Earlier this month, we began pulling back our first well in the area, the Roberson 18-19 Number 1-15H located in Columbia County, Arkansas. This well had a vertical depth of approximately 9,369 feet and a horizontal lateral length of approximately 3,600 feet and was completed in 11 stages. The lateral was landed in lower third of the zone, and subsequent core analysis indicated this section had some of the lowest permeability in the entire interval.

The well has been producing from 8 of the 11 stages fracture stimulated. It has produced for 20 days of the originally planned 20 to 30-day clean-up period. Well production began on day eight, with the highest 24-hour rates to date of 103 barrels of oil per day, 200 Mcf per day of gas, and 1,009 barrels of load water per day. 45% of load has been recovered to date.

Our second well, the Garrett 7-23-5H Number 1 located in Claiborne Parish, Louisiana, was drilled to a total depth in February 2012 of approximately 10,863 feet, with a 6,536-foot horizontal lateral, and fracture stimulations are planned to begin on March 1.

Knowledge gains from the first well led us to drill the second drill with no troubles and led us to target the Brown Dense drilling in the lateral and had no problems and led us to target the Brown Dense.

Drilling in the lateral was not only faster but oil shows and cuttings indicated better quality rock.

We have also spud our third well located in Union Parish, Louisiana, and it's drilling at 7,900 feet. We're looking forward to learning more about this play, and our activity could increase dramatically if it's successful.

We also discussed that we hold 238,000 net acres located in the DJ Basin in Eastern Colorado, where we will begin testing a new unconventional oil play targeting Middle and Lake Permian to Pennsylvania in carbonates and shales. The play ranges in vertical depth from 8,000 feet to 10,500 feet and are within the oil window.

Our primary Atoka/Marmaton objectives are alternating low permeability 20 to 100-foot-thick carbonates,

separated by 10 to 75-foot thick organic-rich carbonate mudstones, with total organic carbon estimates ranging from 2% to 27%.

Total thickness of the ejector section ranges from 300 feet to 750 feet. This acreage was attained for approximately $176 per acre, and the Company's leases currently have an 85% average net revenue interest, an average primary lease term of five years, which may be extended for an additional three years.

To date, no production has been established in the immediate area. However, they're having mud log shows and gas shows, well saturated cores, and free oil and drilling stem tests in the objective section.

We have measured 36% API oil, including occlusions and have seen microporosity in both the limes and shale in the lime sections, as well as microporosity in SCM analysis. The closet oil production from the objection formations is Great Plains Field, which is located 65 miles to the Southeast in Lincoln County. The field discovered in 2009 has 12 wells and has produced nearly one million barrels of 36 gravity API oil from conventional carbonate porosity zones.

Earlier this month, we submitted a drilling plan to the Colorado Oil and Gas Conservation Commission for approval to spud our first well in Adams County in the second quarter of 2012. This well is planned as a 9,500-foot vertical pilot well to the lower Pennsylvania and Morrow formation. The pilot well will be cored and in 2000 for lateral, we drilled in a Marmaton objective.

A second 9,500-foot vertical test is planned to the south, which will also drill to the Morrow formation and will core the objectives section.

Again, if this drilling program yields positive results, activity in this area could increase significantly over the next several years.

You probably noticed that I haven't mentioned gas prices. We're preparing for low gas prices throughout this year, as well as possibly for all of 2013. We will continue to be flexible with our capital investments and be sure that we are doing the right things with every dollar we invest.

As a result, we have decreased the 2012 capital investment program from our previous guidance in December. Currently, we plan to invest approximately $2.1 billion in 2012, compared to the $2.3 billion plan we announced back in December. The decrease is primarily from the Fayetteville Shale program, and the associated decrease in production is approximately 10 Bcf, or down 2% from the midpoint of our previous guidance. Gas production is not expected to grow at 13%.

We will remain focus on keeping our costs as low as possible during this time and will remain vigilant in upholding our commitment to create value for every dollar we invest.

I will now turn this 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 earnings and cash flow set new records in 2011 as our strong production growth combined with our low-cost structure had more than offset the impact of lower gas prices.

For the calendar year, we reported net income of $638 million, or $1.82 per share, up 6% from the prior year, while our cash flow from operations before changes in operating assets and liabilities was up 12% to $1.8 billion.

Operating income for our exploration production segment was $825 million compared to $829 million in 2010.

For the year, we grew our production of 500 Bcf and realized an average gas price of $4.19 per Mcf, which was down 10% from 2010.

We currently have 266 Bcf, or approximately 47% of our 2012 projected natural gas production hedged through fixed-price swaps and collars at a weighted average floor price of $5.16 per Mcf.

Our hedged position, combined with the cash flow generated by our Midstream Gathering business, provides protection on approximately 65% of our total expected cash flow for 2012.

Our detailed hedge position is included in our Form 10-K filed earlier this morning.

We continue to have one of the lowest cost structures in our industry, with all-in cash operating costs of approximately $1.27 per Mcf in 2011. That includes our LOE, G and A, interest, and taxes.

Our lease operating expenses per unit of production were $0.84 per Mcf in 2011 compared to $0.83 in 2010. The slight increase was primarily due to increased gathering costs in our Fayetteville Shale play.

Our general and administrative expenses per unit of production declined to $0.27 per Mcf in 2011, down from $0.30 in 2010. The decrease was primarily due to the effects of our increased production volumes.

Taxes other than income taxes were $0.11 per Mcf in both 2011 and 2010.

Our full-cost pool amortization rate also declined during 2011 to $1.30 per Mcf, down from $1.34 in the prior year. The decline was due to a combination of our low finding and development costs and the sale of natural gas and oil properties in East Texas.

Operating income for our Midstream Services segment rose 29% to $248 million in 2011, and EBITDA for this segment was $285 million. The increase was primarily due to increased gathering revenues related to our Fayetteville and Marcellus Shale plays and an increase in the margin from our gas marketing activities.

At December 31, 2011, our Midstream segment was gathering approximately 2.1 Bcf of natural gas per day through approximately 1,800 miles of gathering lines in the Fayetteville Shale play, compared to gathering 1.8 Bcf per day a year ago.

Our debt-to-total book capitalization ratio declined to 25% at the end of 2011, down from 27% at the end of 2010.

At December 31, 2011, we had approximately $1.3 billion in long-term debt, including $672 million borrowed on our revolving credit facility.

In summary, our financial and operating results in 2011 were some of the best in the company's history. We have the ability to weather the current low natural gas price environment and could not only survive but thrive in these times due to our strong balance sheet, the quality of our assets, and one of the industry's lowest cost structures.

That concludes my comments, so now we'll turn back to the operator, who will explain the procedure for

asking questions.

Questions and Answers

Operator: Thank you. We will now be conducting a question and answer session. In the interest of time, we ask that you limit yourself to one question and one follow-up question. (Operator Instructions)

Scott Hanold, RBC Capital Markets.

Scott Hanold: Steve, can you talk a little bit about the well results in the Smackover play? You indicated that it has low permeability in that lowest formation and you're looking at the next roll up a little bit higher. Can you talk about, just on a relative basis, what kind of perm you actually saw and how the upper member to that compares then and maybe put it in reference to some other unconventional plays to help us out as well?

Steve Mueller: Sure. We haven't got all of the information back on the cores for all the permeability, so some of the statements I'm going to make here are generalities from just a little bit of information. But to remind everyone, as we looked at this play going into it, we were looking at on the low side, 0.1 microdarcy and then we had a size 2 or 3 microdarcy type rock that we're looking at. The core had some very good permeability in the upper part of it and to put it into kind of a relative sense, the lower part was on that lower end of the microdarcy range; the upper was almost 5 times as good as the lower portion, as you looked at it.

Now, one of the questions you asked, why did we land in the lower part of the well. If you remember, going into this well, we didn't know what the fractures were going to do and we were about 500 feet away from a wet zone that we didn't want to fracture into. So we intentionally landed as low as we could in the zone, drilled out the lateral and then the very first test we did, if you remember, we frac'ed 3 stages and just fold those back to see if we were getting any unusual water. We weren't.

We did microseismic on the 3 stages; we went back, did the other 8 stages for a total of 11 stages, microseismic on it. And now that we've got the microseismic in, we've seen that we've only extended up our fracs somewhere around 100 to 150 feet above, so we didn't even get into the better rock with the fracs that we did in the first well and the first zone.

So, we're excited about having 100 barrels a day coming out of the rock we have at some of the lower permeability rock that's out there. It would be the lower end of either the Bakken or Eagle Ford type rock and we know we've got some better rock up above us. The second well in Louisiana, and you've got to remember, you're roughly 30 miles away, the actual porosity in it and permeability is thicker than in our first well and there's some geologic reasons we think that happened that direction.

But, we were able to land it in the top half and basically roughly the top third and what drilled much much faster and looks much better overall. To the point that on the first well, while we had good shows while we were drilling it, the shows we were seeing were just fluorescents. In the second well, we actually had a little bit of free oil in the pit. So, both of those have a little bit of difference to them as far as that goes.

Scott Hanold: Okay. Good color. In terms of, I guess you had about 1,000 barrels of water load on this one; what do you expect for the second one? Being higher up, it doesn't sound like you're concerned about frac'ing into any kind of water, but what would you expect if you put a stronger frac on this? Do you anticipate a better flow rate from the oil and is there any risk then to being higher up that you're going to frac into the ocean above?

Steve Mueller: I don't think there's any risk we're going to frac into the ocean, because again, that last frac only extended call it 150-feet at the most, up. And what we've landed right now, if it extends 150-foot up, it barely gets to the top of the zone. So that's not an issue at all from a frac'ing standpoint. You need to remember that the second well is a 6,500-foot lateral. We will frac it very similar to the first well as far as number of stages per so many feet of lateral. Roughly 400-feet apart on the stages. We will roughly do 3 to 4 perf intervals before each stage, so we'll wind up with over 20 stages of frac on the second well. So, even if it was the same quality rock, I would expect to get much better rates.

Now the other part of your question was, I think having to do with how much water should we expect when this is all done. And we don't see from core analysis, that much water in the formation itself, but that's one of the things we're trying to learn. We don't know what the amount of load water we ultimately have to get back before it's completely cleaned up. We know we're 45% now in the first well. We do know that as that load water's gone down, it took to the 8th day to see the oil as low water continues to go down or oil continues to go up, so all of that's still progressing. But there will be a point in here, even on the first well or any of these other wells we drill, where we'll determine how much low water gets left in the formation and how much we can actually get out and what the ultimate either gas or oil versus water rate is.

Scott Hanold: Thanks a lot. Are you going to press release the results of that or are we going to wait until your next quarterly update? How is that news flow going to come out?

Steve Mueller: We don't like press releasing wells, so my guess is we'll wait until the next time we have something to talk about, something else, whether it's the end of the quarter or something else we have to talk about.

Scott Hanold: Fair enough, thanks.

Operator: Gil Yang, Bank of America Merrill Lynch.

Gil Yang: Good morning. Just to continue along the Brown Dense, can you talk about what you saw in terms of API and sulfide for the oil in all three of the wells that you've seen information from so far?

Steve Mueller: We're looking at mid 30 API; 35-36 gravity API oil and that matches with the well test that we were in the area before. If you remember, there's some vertical wells that we had some tests on and so from that standpoint, oil looks about the same as any of the other ones out there.

On the H2S side, we're still trying to get a handle. There are days we get little whiffs of H2S and then other times we get almost no H2S. But right now it doesn't look like H2S is significant in any of the wells that we've drilled or where we're at today for 2 wells. And then we do have a little bit of CO2 that we're seeing in this well, and again, because we haven't got all the water lifted off of it, we don't know if that's going to stay in the well or not, but there's a few parts per million CO2 as well.

Gil Yang: Have you seen the CO2 in the vertical wells that you looked at?

Steve Mueller: They didn't report any. And again, those tests went from 1946 to like two years ago. The only really good information is the ones a couple of years ago and there wasn't any on that. CO2, if you have some kind of reaction at all with the carbonate that's in the formation, CO2 is just one of those things that comes with that and so as we frac the well, we could have easily had a little bit of CO2 just as part of that frac process and once the well cleans up, you may not see CO2. On the other hand, there may be just a little bit of CO2 with the gas.

Gil Yang: Can you talk about the negative revisions on performance in the Fayetteville in particular, but both for the two areas where you reported that?

Steve Mueller: I think the easy answer on the whole thing is there's all kinds of things that go into the various wells, but the easy answer is that it's mainly price. Because we're about $0.12 difference from year-over-year. I will say in the case of the Fayetteville Shale, we took a little bit different approach to how we're doing our reserves this year and that fine-tuned the whole project for us. And fine-tuning, we had a bunch of wells that were a lot better and we had a bunch of wells that were a little bit less and it kind of averaged out to that. So there isn't anything more than that.

Gil Yang: So what you're saying is that the negative revisions were to a large degree, they're really price revisions, not performance revisions?

Steve Mueller: The biggest negative revisions anywhere was in Arkoma. There was one field called the Overton Field, and some wells fell out because of price and then there was just some production revisions there. But like I say, there's not much there one way or the other on the revision side.

Operator: Brian Singer, Goldman Sachs.

Brian Singer: Two questions, the first is continuing on the Brown Dense. When you look at the lower portion that you did frac into, what are your thoughts on both oil in place, or more importantly, recovery rate and does the low permeability you saw there condemn up to a third of what you thought was theoretically possible previously?

Steve Mueller: We're trying to figure that out, Brian. One of the things we do is our first well and really the first, second and third well are all offsetting within a mile or so, some of these vertical tests that were done. And this first well, we offset about a mile or 1.5 miles away from another well. It was actually drilled on top of a structure and that original well was drilled on that structure as well.

It looks like that on the top of that structure, geologically the rock did not - at least the history of the rock wasn't the same as opposed to the rock that's off the structure. So, as you get over towards our well that we drilled in Louisiana and some of the other wells around there, that section that has good porosity actually gets thicker. So in our second well, almost 70% - 75% of the section has that high porosity in it; where in our first well it was almost 50/50. So as far as oil in place, certainly the tighter the rock, it doesn’t change so much the oil in place, but your recovery will change on that. And we're just going to need some more wells to figure out how variable that is and just to figure out what's going on from there.

Brian Singer: My follow-up is with regards to the Marcellus. Can you just compare and contrast the well results that you're seeing recently in Bradford County versus Susquehanna County?

Steve Mueller: We don't have any wells yet put on production in Susquehanna County. When we talked about all those wells that we drilled; we'll see our first Susquehanna wells come on production sometime in the middle of March. So I can't tell you much about those yet. In Bradford, we have a variance on those wells and I think the best well we have is probably well over 15 Bcf. And we talked about the averages, but I think the lesser of the wells we have out there are probably about a 5 Bcf well in what we've seen.

And they're really, as far as where is better and where is worse, we haven't seen that pattern yet to know exactly that. On the same pad, we'll drill three wells, it could vary from 6 to the 10 or 12 Bcf range.

Brian Singer: That’s great, thank you.

Operator: Marshall Carver, Capital One.

Marshall Carver: I have a couple of questions on the Fayetteville. You booked 2.4 Bs per well. When I look at that type curve plot that you provide and you show the curve with the wells over 4,000-foot laterals and almost all the wells you're drilling are 4,000-foot plus, it looks like your wells are tracking over a 3 Bcf type curve but you're only booking 2.4 and you didn't have many positive revisions. So what should I think about the difference between the type curves you're providing and what you're booking?

Steve Mueller: There's a few things to think about there. First off, when you think of our reserves, remember the definition of proved undeveloped has to be your 90% certain, so you're going to take your distributions and pick a median, rather than an average to start with. Secondly, all of those curves that we have in our literature, for the most part, except for just a little bit of drilling last year, were drilled on that mile-apart spacing as we were doing our first wells in the section. And we've always said, as we get to our pod drilling, what's going to happen is you're going to have somewhere around 10% interference in an ideal case. So what you need to do is back off of that. And again, if you back off what would be a 3 Bcf well, you get about a 2.7 Bcf well, and then you say you want to be conservative, you're down about 2.4 to 2.5 range as far as that goes.

The other thing to keep in mind is you book around where you drilled during the year and if you remember, we spent a lot of time during the year proving up acreage in what I call the edges of the field and that's where we booked our wells as we put the wells out there. So there's a little bit of distribution of wells. We only have around 1,600 wells total booked as far as PUDs and so there's a little bit of location this year versus some of the other years on it as well that goes into those PUD bookings.

Marshall Carver: Ok that’s very helpful, thank you. A follow-up; y'all talk about the PV to I hurdle and not wanting to drill wells that are below the PV to I hurdle. With current gas prices, is the Fayetteville below that hurdle now and if so, would you potentially reduce activity more if gas stays around $3.00 or are you drilling better locations to make sure you hit the hurdle rate?

Steve Mueller: What we've done with our 2012 budget, besides cutting back a little bit in the Fayetteville Shale from what we originally announced, we're also changing to the point where we're going to drill the very best wells. And again [I might add] any of these plays, let me just talk about in Pennsylvania, you've got distribution of reserves and you've got some very, very good wells, and then you've got some lesser wells in there with some kind of average.

We've talked about in the past that to drill our average well, we need around a $4 price. But we have at least a couple years worth of wells that we can drill if it stayed $3 flat forever in the Fayetteville Shale, and that's what we're doing. We're drilling those very best wells. May see a little bit of inefficiencies in what we're doing, as rather than drilling all the wells from a pad at one time, we'll go in and drill the best well off the pad and then move to another one. You also see us widening out our spacing a little bit here to make sure that we get better wells, and we'll come back later and put some more in-fill wells into that overall spacing.

So we're adjusting our program. But certainly if it's $3 flat forever, we've got wells to get us through this year and into next year, and we're looking for other ones beyond that.

Marshall Carver: Okay. That's helpful. I mean, do you have a feel for about how much better, on average, the wells will be that you're drilling this year versus last year in terms of EOR or IP?

Steve Mueller: Yes. We're going to need those three Bcf wells you were talking about.

Marshall Carver: Okay.

Steve Mueller: So that's what we're shooting for - it'll be plus three, plus three going on plus three and a half.

Marshall Carver: Okay. Thank you very much.

Operator: Joe Magner with Macquarie. Please proceed with your question.

Joe Magner: Thanks for taking my question. Just notice that the new ventures budget has dropped meaningfully. Just curious what the underlying drivers or revisions to that budget were. Is that to account for less drilling or reduced expectations around new programs? Just a little more information would be helpful.

Steve Mueller: What we did was, we had put in some dollars for some new plays in the budget and expanding some of the plays we're already working on, and we backed off on that. That's where most of the back-off is. And then we're watching the Brown Dense close. But we assumed we would do one less Brown Dense well than we said to prove it up. And we did that in the assumption the industry was going to drill wells around us and be able to do that.

So there's at least one well less, and then some acreage, and we'll just look at that and play it out through the year. If we come up with a really good idea, we're not going to slow down picking up that acreage on a good idea, especially if it's an oil idea. But that's where it's at. It's really not changing any of the drilling we want to do this year or the plays that we're getting close to finish on, it's not affecting those at all.

Joe Magner: Okay. And then in the new DJ Basin opportunity, my understanding is that the wells that have been drilled in that Great Plains Field were vertical wells. Can you just, I guess provide a little more information on how you decided to target horizontal in the [Morrow] section?

Steve Mueller: Yes, in the Marmaton.

Joe Magner: Marmaton section. And then just kind of what the overall geologic setting is that's being pursued there.

Steve Mueller: All right. To kind of get everyone in perspective, you hear about Niobrara Play. This is deeper than Niobrara. It's in the Pennsylvanian-age section. There's Marmaton, [our Atoka] interval roughly in that 8,000 to 10,000-foot depth range. The field that we talked about, the Great Plains Field, is quite a ways away. It's almost 65 miles away from where we're drilling our first well. And as you said, it's drilled and is being developed vertically. And the reason it's being developed vertically is there's over a 2,000-foot section of potential rock interval, and there's in that anywhere from 300 to 700 feet of potential pay that's within that interval.

Their best well in that field has -- this was drilled back in 2009. It's already produced 247,000 barrels in 20 months, and it IPd at 1,500 barrels a day. That's 24-hour IP. First 30 days was 634 barrels a day. So there are some very good wells in that field.

There's also some other wells in that field that their 30-day rates were as low as 100 barrels a day. So there's a lot of variability. And therein lies the thought behind doing it vertically versus doing [it] horizontally. We may end up ultimately having a vertical play here. But we think we've identified a

couple of fairly thick zones in our acreage that would lend itself well to horizontals. And if there is a lot of variability in a lateral sense, if we can do it the horizontals, we might be able to streamline some of that range they see in Great Plains, where they have 100-barrel-a-day wells and then they have 1,000-barrel-a-day wells there.

So don't know what the ultimate answer is going to be, whether it's going to be horizontal or vertical. But we'll start, that first well will be drilled through the whole section, we'll put a short lateral to see what happens in specifically the Marmaton interval. And then that second well is actually planned to be a vertical well. So we're still playing with both of those to go through.

The other thing just to note is that while Great Plains Field is the closest field to what we're doing, there is 96 wells in the immediate area in southeastern Colorado that have produced out of this section. So it's well known by the industry. It is only in the southern part of the state. And the very north end of our acreage gets on the edge of what will be the Niobrara play, but we really don't have Niobrara section on our acreage. This is that deeper Pennsylvania section for everything we're doing.

Joe Magner: So this is more like a sort of Texas panhandle stacked wash opportunity?

Steve Mueller: Yes, some of the section's almost identical to what's going on in the panhandle. But, yes, that's exactly what it is.

Joe Magner: Okay. I'll leave it there. Thank you.

Operator: David Heikkinen with Tudor, Pickering, and Holt. Please proceed with your question.

David Heikkinen: Good morning guys. First question, just thinking about the Lower Smackover Brown Dense, does the first well confirm or eliminate any acreage?

Steve Mueller: Not at this point it doesn't.

David Heikkinen: And to be clear, the frac, the water that you're producing is from the frac load, not the reservoir currently?

Steve Mueller: Yes.

David Heikkinen: And what percentage of frac load would you expect to be able to recover in kind of -- in that 30-day window? Or do you think it's going to take longer than 30 days now?

Steve Mueller: It looks like it'll take longer, and I don't know. I just don't have a good feel for that. We're continuing, as you saw, we're still getting 1,000 barrels a day of fluid back. So it's not cleaned up yet and it's still giving us frac fluid back. So I don't know. Is this going to take 45 days or 60 days or 90? I just don't know.

David Heikkinen: So I guess it would be hard to predict what a stabilized oil rate would be as well, given your (inaudible) --

Steve Mueller: I can't even --

David Heikkinen: -- water?

Steve Mueller: -- start guessing yet.

David Heikkinen: Exactly. Then thinking on another -- on the midstream, do you have a thought around what the industry-wide [or] gross exit rate would be for this year for your midstream business?

Steve Mueller: I would say, and what you're asking me to do is kind of predict besides what we're going to do, predict what the rest of the industry's going to do. I think we're seeing a slowdown in the other industry partners as well, but I haven't heard any exact announcements to know how much they're slowing down.

If you step back to October, November time frame, both the other major players, BHP and XTO, were going to actually add rigs. And it looked like [they were] going to add rigs in areas where we were going to be gathering gas for them.

Today we're getting indications that if there is any rigs added, they're not going to be drilled where we're gathering. So I would guess that through the year, we'll have a little bit of decline on our third-party guess, where today it's about 170 million to 180 million a day, it'll probably decline some, maybe 150 million during the year. And then we'll be growing our production in the Fayetteville Shale in a double-digit [kind of] rate. So whatever that comes up. You know, is that 2.3, 2.4 Bcf [a day]? Somewhere in that range - 2.2 - I don't know.

David Heikkinen: All right. And thanks. I've enjoyed following you over the last --

Steve Mueller: Good. It's great to hear from you, Dave, and good luck.

David Heikkinen: All right. Thanks a lot.

Operator: (Operator Instructions) Dave Kistler with Simmons and Company. Please proceed with your question.

Dave Kistler: Morning guys. Real quickly, with the adjustments to the capital budget that took place pretty rapidly here with the fall down in gas prices, how quickly would you look at revising that back upward if gas prices were to start to improve in the second half of the year? And where would you direct your first dollars as you put capital back to work?

Steve Mueller: I sure hope we come across that situation where it comes up in the second half of the year. But I think we're expecting that we're in the price range we're going to be through this year and the next year. The real key for adding anything back is what you think the long-term price is going to be. And so even if it jumped up for a short period of time at the end of the year, I don't know that that would make us change our mind. But if we started seeing the fundamentals change so that we could get something above that $4 range, certainly then you'd see us add.

Of the things we have in hand, we really would like to accelerate Pennsylvania, no matter what the price range is. But what [limits us] in Pennsylvania right now is our firm capacity. And we're following that curve with the rigs we have. We're working hard on adding more firm. And so you may see us even redirect some more capital that direction during the year.

Certainly on the new ventures, any of those come in, those are oil, those are different price dependency. You can see us do some things. And in the Fayetteville, we are doing things to get our costs down. And one of the things we're doing is we're going to go into the pumping business, and so we're going to further vertically integrate. We will have two units that we operate in operation by the end of the year. And we should save ourselves about $140,000 per well on the wells that we're drilling with our own pumping

equipment. So in that case, as we cut the cost down, then we might be able to add some rigs back in.

And then the other thing we're watching closely is just how fast we're drilling. In the December release, we said that we were going to drill in basically mid-seven-day time frame. We're beating that right now. So while we're dropping rigs, the well count isn't dropping as fast. So we have to watch that too.

But all of that we'll watch as we go through the year, and then we'll either add or subtract as the year plays out or as 2013 starts to unfold.

Dave Kistler: Okay. And then as a follow-up, a little while back you guys indicated that at $3 gas, you figure you have about 1,200 well locations in the Fayetteville, down from, say 8,000 locations at $4 gas. If we use sort of the same price mechanisms to think about maybe where year-end prices might end this year, I wouldn't imagine it would be a 1-to-1 decrease in your proved reserves, as a portion of it would be proved developed producing. But what kind of a decline do you think you'd have on your reserve base under that sort of a scenario where it went from $4 to $3, and your identified locations drop by 70%, 75%?

Steve Mueller: It will be challenging. And I don't know the exact answer. We have not gone through that calculation. But everyone needs to think about the fact, that now that you do reserves on a rolling 12-month average, as we even go into the second and third quarters, you're going to start seeing higher numbers last year roll off and lower numbers this year going into that average. So while year-over-year there was only something like a $0.15 or $0.16 difference in average price, that's going to -- that is going to decrease significantly by the time you get to the summer, just with the first three months of this year as you go through.

So I think all of the industry's going to have some challenges on what they can book and not book. But we haven't done enough analysis to be able to tell you what the issues are going to be. I just know there are issues coming up.

Dave Kistler: Okay. I appreciate the added color. Thanks, guys.

Operator: Robert Christensen with Buckingham Research Associates. Please proceed with your question.

Robert Christensen: Good morning, Steve. Two questions: The first is, can you give us sort of your logic as to where you go in the Lower Smackover? I mean, you started with Roberson, you go to Garrett, BML was chosen third. And just the logic of going around sort of that triangle - why first? Why second? Why third?

Steve Mueller: We picked Roberson where we did, we thought it was a little bit, it wasn't quite in the center of the oil window, but close to the center of the oil window. It was offset by some of the best control that we had, so we could land the lateral, and we were going to hit the lateral. Again, we don't have 3D out here, but we had a lot of wills that are drilled because on the top of the structure, we had a lot of wells that are drilled to the Smackover that we could go off of.

And then the thought was move into Louisiana, stay in the oil window, and just get a distance away near another well that had been tested before, and that was what we did with the second well.

The third and the fourth wells are similar to that and will be offsetting or near wells that have been drilled in the past, but spacing ourselves out, just to start seeing the rock characteristics, but for the most part, staying within what we think is the obvious oil window. And then when we originally put the program

together for a total of 10 wells, the six wells after that, the two things we’re going to do is start driving cost down on the wells themselves. Those first four are going to need a lot of science, but then we’re going to lessen the science for the other ones and we’re going to start pushing the boundaries of the oil window, either up-dip or down-dip, up-dip as you get towards immature oil and down-dip as you get towards the gas part of it.

That’s all going to change and really, even our fourth well to date is in limbo, exactly where it’s going to go, and the reason it’s changing is that the industry is also dwelling wells. So to the extent that one of those wells we’re going to drill somewhere in our sequence are close to one of the industry wells, we’re busily making agreements with the industry to trade information. So I can tell you the first three are still under that same logic that we had, but from four on, we’re revising it as we see other information come in.

Robert Christensen: And how many wells do you think the Company will now drill this year in the Lower Smackover Brown Dense?

Steve Mueller: I think what we have in the budget right now is five wells drilled this year, a total of six wells, but we’ll drill what we need to drill, and so if the industry gets some more wells down and we can learn the answer without having to drill as many, fine. If we need to drill some more, we’ll do that and we’ll just adjust our budget to where it goes, but right now, six total is what we’re thinking about.

Robert Christensen: One follow-on if I may -- when you expressed that the oil shows in the second well is actually turning into oil in the pits, how much better, I guess, is the porosity and permeability associated with that statement compared to the statement that we just saw florescence in the first well? Can we see quantity through that lens, if you will, that you’ve offered us?

Steve Mueller: I think you can start getting indications of quality. As you know, shows have a lot of variables with them, what your mud weight was, what the kind of muds you're using and how fast your drilling, so there’s all kind of things that go into that, but the second well drilled much faster with basically the same mud than the first well. That tells you that there was a different rock there and then probably had more porosity and permeability in it, and we did see more oil. So it tends to indicate more permeability. And when I asked our guys that exact same question and pressed them on it, they said, “Well, it looks about five times better than that lower zone in the first well.”

Now, that’s all relative. Is it five times better, eight times better or three times better? It’s just better. You don't have enough information to know and we don't have the ability to get chips like you do in conventional. You’d be able to get some chips from down hole and you’d be able to look at it and compare it. In our case, with the way we’re drilling, it’s very difficult to get chips, but you have to send it to a lab to even look at the porosity or permeability that’s in it. So we’ve got a core. The core is being analyzed right now and soon, we’ll know the difference, but it’s all relative at this point in time.

Robert Christensen: Thank you very much.

Steve Mueller: Thank you.

Operator: Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Please proceed with your question.

Dan McSpirit: Gentlemen, good morning. Recognizing the data you're working with is limited and that it’s early innings, how does the Brown Dense rank versus the new DJ Basin venture and anything else in the new venture’s portfolio, at least in terms of resource potential and what’s economically recoverable?

Steve Mueller: I can certainly compare the Colorado and Brown Dense. In the case of Colorado, you have had commercial production from that interval, at least in the immediate vicinity of where you're at, and it doesn’t have as many tests in the area. There’s only four wells within the area. We’re buying acreage that has gone into that zone, but they did have shows and those kinds of things on it, but since you have commercial production, I think the real issue in Colorado is the variability of the rock and can you get consistent commercial production?

In the case of the Brown Dense, the Brown Dense is much bigger. We’ve got 238,000 acres in Colorado and that’ll grow some, but it’ll be in a 250, 260 range. In the case of Brown Dense, you’ve got over 500,000 acres in roughly the same thickness objective interval. They're spaced out differently, but it’s roughly the same -- so the Brown Dense has a lot more in place to go after, but it’s going to take a lot more to figure it out too because it’s a bigger area.

So going into the Brown Dense, we had really three big issues -- how the drill -- when you frac, when you get into the water that’s above it, you don't have that problem in Colorado, and then can we make it commercial? We know we can drill it now. The second well drilled much, much faster. The third well, we’re blowing that one down. We’re getting the face done. We think we know where to land it in the Brown Dense, but we still have to figure out commercial there. So that’s kind of the differences.

Dan McSpirit: Okay. And then a follow-up -- on the Brown Dense itself and specifically the Union Parish well, how does the rock change moving west to east? How has the risk profile changed, that is? And how will that well be completed? Will it be completed any differently than the first two?

Steve Mueller: We’re still looking exactly on how the well is fracked, but basically, it’ll be completed the same. It’ll just have more fracture stages because it’s a longer lateral. And the third well, by the way, we’re going to try to do that. That’s in Louisiana also. That’s going to be a 9,000-foot lateral, so that’s even going to have more stages in it, but right now, we’ll frac them basically the same, with just minor variations, just to see the differences so we can really tell the difference in what’s going on with the rock, not the difference in how we’re fracking them to start with here.

As far as the way it looks in the rock, it’s a little bit thicker as you go to the east, so it’s probably 75 to 100-foot thicker in general in our second well than in the first well and again, that first well is over 350-foot thick. So it’s a very thick interval. When you look at a log that’s drilled through it, there’s distinct log characteristics that we’re trying -- we think we figured now that shows the better porosity rock versus the tighter rock and we’re in the early stages of understanding this.

So I want to emphasize we think we’re getting to understand it, but if we’re understanding it right, certainly the logs are about twice as thick for the good interval in the second well than they are for the first one, but again, the second well, we’ve got a core in and analyzing right now. The first well, we haven’t got all the permeabilities back on it. So we’ve still got some things to look at before I can pound the table and say it’s definitely getting better in one direction or another. We do know if you go far west, if you go over towards the Louisiana-Texas line, they're getting deeper. The rock is higher temperature, more cooked, and you get into gas. So in general, the oil window is going to swing around from Arkansas down into Louisiana in general.

Dan McSpirit: Thank you.

Operator: (Operator Instructions) Our next question is a follow-up question from Scott Hanold with RBC Capital Markets. Please proceed with your question.

Scott Hanold: Thanks. Hey, Steve, you mentioned about investing in some pressure pumping. What are the plans there? I mean, how much horsepower are you looking to add and what’s the cap ex on that spend this year?

Steve Mueller: We will basically do two frac spreads and I don’t know off the top of my head the exact horsepower. Total investment will be probably about $65 million for the two frac spreads and we’ll have them operational hopefully in the November timeframe of this year. So it’s really a cost savings for next year. As far as the capital budget, in the original capital budget, we had put $50 million in thinking the frac spreads would be done in early 2013, but counted as capital. In this one, with reduction of the $200 million, we've taken it completely out and we’re going to finance that through leasing. So it’s not a capital item right now the way the budget sits.

Scott Hanold: Okay. So it’s not in your budget.

Steve Mueller: Correct.

Scott Hanold: It’s a leaseback, okay. And then can you talk about the Fayetteville rig count right now? So are you running 11 rigs now and there’s been plans to drop one and then there’s two others coming off. Can you kind of give us the timing of that or tell me if I got that right?

Steve Mueller: We’re working on that. There’s 11 today. One will drop in the next week or two. Then what I think you'll see between now and some time in July, we’ll drop three more at least and possibly four more rigs -- I said three more -- three more from the 10 going down to seven, [four] total rigs from where we’re at today. And we’re still trying to get the finals on that, so we may run one rig a little bit longer as we look at it, but that’s roughly what we’re going to do, exit the year running seven big rigs in the Fayetteville shale.

Scott Hanold: Okay. And would production in the Fayetteville grow at that point or would it be fairly flat?

Steve Mueller: It will grow through this year. If you continue running seven rigs into the future, it flattens out pretty fast.

Scott Hanold: Got it, thanks.

Operator: Our next question is a follow-up question from Robert Christensen with Buckingham Research. Please proceed with your question.

Robert Christensen: The fourth well I thought was back up in Arkansas. Was that the case or --

Steve Mueller: That’s the way it has been planned, yes.

Robert Christensen: And the follow-on would be if the --

Steve Mueller: And let me add one thing in there, Bob. On that fourth well, originally, it was planned to be very close to where Cabot just recently drilled a well.

Robert Christensen: Right.

Steve Mueller: So as long as we can get information from Cabot, if it’s in Arkansas, it won't be where we originally planned it, I can tell you that. So we’re still looking at that.

Robert Christensen: All right. And if the formation thickens up enough as you go further to the east, would it ever make sense to maybe drill just a vertical well, in fact, just stimulate that first as opposed to going horizontal from the get-go?

Steve Mueller: We don't think that that will work, but we need to get some core information back. I won't say you’d never do it that way, but when you just look at the advantages -- in that second well, it took us about 14 days to drill that 6,600-foot lateral that’s out there. I know we can decrease that time and if you're down at 10,000 feet, you might as well take the few days extra it takes to drill the lateral and then add the fracs and get the added advantage to that, but we’ll certainly look at it, just like we’d look in Colorado, which is the best way to do it, vertical or horizontal.

Robert Christensen: So the second well, what was the total time to drill because you were in vertical for --

Steve Mueller: Roughly 50 days give or take. I don't remember if it was 50, 53, something like that.

Robert Christensen: 50 days all-in for the second well?

Steve Mueller: Right.

Robert Christensen: And what’s the rough cost on the difference between the first well and the second well, would you estimate? Is it a big step up or is it about the same?

Steve Mueller: Well, the first -- all these wells -- the first four that are under the core and all the science would be [above] $10 million. The first well, we actually got out -- I don't remember if -- it was [quite a few] thousand feet and wasn’t where we wanted it to be and had some problems with the well and backed up and redid the sidetrack. So that first well is probably $2 million, $1.5 million to $2 million higher than the second well just on redrilling the lateral, but ultimately, we think we can get these down in the $7 million to $8 million range is what we’re shooting for.

Robert Christensen: Do you think the second well is going to be more costly than the first well?

Steve Mueller: No, no.

Robert Christensen: Okay.

Steve Mueller: The second well will be cheaper than the first well by about $2 million at least.

Robert Christensen: Okay. Well, thank you very much.

Steve Mueller: Thank you.

Operator: Our next question is a follow-up question from Gil Yang with Bank of America. Please proceed with your question.

Gil Yang: Steve, you mentioned that you're going to drill, I think, a couple of stratographic vertical tests in New Brunswick. Can you just comment on sort of what you're looking for in those kinds of wells, what we should expect you to learn from those wells?

Steve Mueller: Sure. In New Brunswick, we need to get this other seismic shot, but if you think about

the sequence we've done, we think we found a new basin. We did a bunch of work to prove that it was there, shot seismic. Need to get a little bit more seismic done for the east that we didn’t get done in 2011 and the whole idea was to identify where the basin deeps were, where the -- if you spot any highs and then pick a couple of wells that could tell you actually what’s in the basin. At this point in time, you’ve got rock that comes to the surface north of where the basin’s at. You’ve got a basin to the south that’s got some wells in it, but these basins have no wells whatsoever.

So at least one of those stratographic tests will be in one of the deepest parts of one of those basins. You'll just drill right through the whole interval to try and figure out what’s there. Is the shale (inaudible) shale there or not? Is there any conventional targets that are possibly there? So it’ll just be -- just look at the section. The second well, depending on exactly where you’re at may have some other target to it, where you’ve seen something on the seismic that you want to investigate, but both of them basically are just trying to figure out what the section looks like so you can tie in more data so later you can then come back and actually drill wells that would have hydrocarbons as the objectives.

Gil Yang: Okay, so it’s basically to provide the subsurface data that ties you to the different horizons you’re seeing on the seismic?

Steve Mueller: Right. And then just to give you an example, while you see events on the seismic you’re just guessing at what the velocity is or what the depth is because you haven’t got any data to tie it to, you just – and the nearest data is 60, 70 miles away. So that first well just let’s you tie that in, it’ll let you figure out how to redefine your gravity magnetics that you work on the Basin. And so you’ll get that information, redefine everything again, and then you’ll actually start drilling for true objectives.

Gil Yang: Great. And another follow-up, and I think in your previous budget you had said that $4 gas, and you were very good in giving sort of the guidance based on the sensitivity based on different commodity price assumptions, and it looks like the current budget based on that is announced then of maybe $400 million, $500 million based on $3 gas, is that a fair assumption is what you’re pricing in in this budget?

Steve Mueller: It’s in that range. I don’t know if it’s quite to the $500 million range, but it’s in that range.

Gil Yang: But, right, but the base assumption is you’re sort of assuming $3 gas?

Steve Mueller: Yes.

Gil Yang: Okay, great. Thank you.

Operator: Our next question is a follow-up question from [Joe Magna] with Macquarie. Please proceed with your questions.

Joe Magna: Thanks. Just one quick follow-up. You mentioned that you had taken $65 million out of the budget for spending on the pressure pumping equipment, which bucket did that come out of? It doesn’t look like there was an obvious drop in midstream or other, I was just curious where that might have shown-up prior?

Greg Kerley: That was actually in the Fayetteville shale.

Joe Magna: Okay.

Greg Kerley: Anyway, it was about $50 million. Again, we thought we weren’t going to get the equipment till early next year. Now we’re much more comfortable we’ll get the equipment this year. So $60 million was total – although $50 million was actually in our budget.

Joe Magna: Got it. Thanks, that’s all I had.

Operator: Ladies and gentlemen, we have reached the end of the question and answer session. I would now like to turn the floor back over to Management for closing comments.

Steve Mueller: Thank you. We’ve had a lot of discussion today about the Brown Dense, had some discussion about Colorado, but what I want to leave you with is we’re very proud of what happened in 2011.

And we especially want to thank all of our employees. We’ve done a great job.

When you think about the Fayetteville and Marcellus I wouldn’t want any other assets in today’s price environment. We know we can overcome the challenges with those assets as we look out into 2012 and even as we look out in 2013. We know we can deliver for our shareholders in those events.

And then we’re really excited about 2012. Brown Dense, first well, a lot of questions answered, a lot of questions asked. We’re getting ready to drill in Colorado. I’m sure that will be the exact same thing, where those first few wells we’ll be asking as many questions as we answer them. But these are quality plays, and there’s the kind of things to expect from us as we look out into the future. We’ve got New Brunswick coming up, and then we’re still working on some other projects. There’s still some other acreage we haven’t talked about out there.

So we’re really excited about 2012. This is a year for us to thrive, this is a year irrespective of what gas price is doing, irrespective of what oil price is doing, irrespective of cost, that we think we can deliver for our shareholders, and we’re just looking forward to updating you in the future on that.

So thank you, and this concludes the conference.

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

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 twelve months ended December 31, 2011. 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.


	12 Months Ended Dec. 31,
	2011	2010
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$ 1,739,817	$ 1,642,585
Add back (deduct):
Change in operating assets and liabilities	26,201	(62,906)
Net cash provided by operating activities before changes in operating assets and liabilities	$ 1,766,018	$ 1,579,679

Finding and development costs - Finding and development (F&D) costs are computed by dividing acquisition, exploration and development capital costs incurred for the indicated period by reserve additions, including reserves acquired, for that same period. The following computes F&D costs using information required by GAAP for the twelve months ending December 31, 2011.


	For the 12 Months	Fayetteville	Marcellus
	Ending	Shale Play	Shale Play
	December 31, 2011	2011	2011

Total exploration, development and acquisition costs incurred ($ in thousands)	$ 1,960,106	$ 1,347,605	$ 332,384
Reserve extensions, discoveries and acquisitions (MMcfe)	1,459,456	1,211,210	229,224
Finding & development costs, excluding revisions ($/Mcfe)	$ 1.34	$ 1.11	$ 1.45
Reserve extensions, discoveries, acquisitions and reserve revisions (MMcfe)	1,493,201	1,196,041	327,328
Finding & development costs, including revisions ($/Mcfe)	$ 1.31	$ 1.13	$ 1.02

The company believes that providing a measure of F&D costs is useful for investors as a means of evaluating a company’s cost to add proved reserves, on a per thousand cubic feet of natural gas equivalent basis. These measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in Southwestern’s financial statements prepared in accordance with GAAP (including the notes thereto). Due to various factors, including timing differences and the SEC’s 2009 adoption of a number of revisions to its oil and gas reporting disclosure requirements, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods prior to the periods in which related increases in reserves are recorded and development costs, including future development costs for proved undeveloped reserve additions, may be recorded in periods subsequent to the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases in reserves independent of the related costs of such increases. As a result of the foregoing factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in Southwestern’s filings with the SEC, future F&D costs may differ materially from those set forth above. Further, the methods used by Southwestern to calculate its F&D costs may differ significantly from methods used by other companies to compute similar measures and, as a result, Southwestern’s F&D costs may not be comparable to similar measures provided by other companies.

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