Lease operating expenses for our E&P segment were $0.81 per Mcfe in the first quarter, down from $0.83 per Mcfe in the first quarter of 2012, primarily due to lower salt-water disposal costs associated with the Fayetteville shale play.  Our G&A expenses were $0.21 per Mcfe, down from $0.30 per Mcfe a year ago due to decreased information systems costs and adjustments to employee-related costs.  These adjustments are not expected to be recurring and we anticipate our G&A costs will be in line with our previously issued guidance of $0.26 to $0.30 per Mcfe for the remainder of the year.

Taxes other than income taxes were also lower at $0.12 per Mcfe, down from $0.13 a year ago, and our full cost pool amortization rate in our E&P segment fell to $1.09 per Mcfe compared to $1.33 last year.

Operating income from our Midstream Services segment rose 10% to $76  million during the quarter, primarily due to increase in gathering revenues from our Fayetteville and Marcellus shale plays.

At March 31, 2013, our debt to total book capitalization ratio was 36%, essentially flat when compared to the end of 2012 and our liquidity continues to be in great shape, with only $35 million borrowed on our $1.5 billion revolving credit facility.  We currently expect our debt to total book capitalization ratio at the end of 2013 to be approximately 31% to 33% at current strip prices.

In summary, 2013 already looks like a record year for Southwestern Energy with strong cash flow generation, an excellent balance sheet and a low-cost structure.  We are ready to deliver even more value, not only in 2013, but for many years to come.

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

Question-and-Answer Session

Operator:  Thank you.  We will now be conducting a question-and-answer session.  (Operator Instructions)  Our first question comes from the line of Dave Kistler with Simmons and company.  Please proceed with your question. 

David Kistler:  Good morning, guys. 

Steve Mueller:  Good morning. 

William Way:  Good morning.

David Kistler:  Real quickly, maybe going to the announcement you made on Monday first about the acquisition in the Marcellus, can you walk us through maybe some of the lease terms associated with those 162,000 acres?  Are some of it expiring rapidly?  What portion of that acreage will be acreage that you'll focus on for development in '14 and are there any kind of parameters that you can give us around prospectively for the breakdown of that acreage?

Steve Mueller:  Let me just kind of give you just a quick overview.  Certainly, this is acreage that has between four and five-year terms on it and then there are extensions.  Those extensions are expensive.  They are probably in the $3,000 to $4,000 type ranges to extend those for another four to five years, and there are some that will come up in 2013 and 2014.  When we did our analysis, we basically assumed that all of the acreage that was in '13 and '14, we would not renew.  In real life, it looks like that 160,000 acreage, probably about 40,000, we would not renew it this point in time for '13 and '14 as we go through the overall process.

As far as the general value, we think there is somewhere around half the acreage that ultimately, we will have wells better than 5 Bcf on it, and it takes a little bit of time to figure that out, but the real key for us was when we did the analysis, if we had $4 flat forever, we would take about 70 wells to get ourselves a PV10 or a 10% return on the acquisition.  And we're very comfortable we have a lot more than 70 wells, so we are really excited about the acquisition.  It fits right where we're at.

We have been trying to get that Susquehanna acreage for the last three or four years to fill our position in Susquehanna.  We've got in a lot more acreage along the way, so it's a good go real acquisition for us. 

David Kistler:  Great.  And maybe just one follow-up on the Susquehanna acreage -- I am assuming, based on kind of the net well parameters that were part of that release that it's non-operated acreage.  Is that a fair assumption or is the way that it is set up, it allows you to exercise longer laterals on your existing leases because they fall into these other areas?  Can you just kind of give us a little color on that? 

Steve Mueller:  Almost all this acreage is 100% operated.  There's very little that is outside operated.  Just Chesapeake hadn't drilled much on it yet, and so in Susquehanna, I think almost everything there is a little bit to the north and kind of goes in where Williams is at, but we have a little bit of partnership acreage on it, but most of it is 100% there.  But it's really just a matter -- they had not drilled much on the acreage, so the little bit of activity that was on the acreage was by other people putting it in a little bit of their acreage in units. 

David Kistler:  Okay, great.  I appreciate those clarifications, guys.  Thank you. 

Operator:  Our next question comes from the line of Amir Arif with Stifel.  Please proceed with your question. 

Amir Arif:  Thanks, good morning, guys.  I mean, I understand that you are still engaged in discussions in terms of the Brown Dense, but is there any color you can provide in terms of what issues are the sticking points, whether it's price, terms or well results?

Steve Mueller:  Yes, I wouldn't play -- I wouldn't put it that we're still in discussions.  Bill and I had a little bit of difference depending on where this is at.  We thought we had a deal with a group and they tried to renegotiate the terms.  That's not the way I work and we are not in the deal anymore.  Maybe we will come back in the deal, but it really was just simply that from that standpoint. 

The other thing about it in general, we've had a lot of debates whether we should get a partner or not get a partner.  Certainly, we knew a few months ago that we were the winner of the Chesapeake package and getting some dollars in on the Brown Dense side being able to apply it to Marcellus was attractive to us, but overall, we're only going to do a deal if it's a good deal and we're only going to do a deal if it's with someone we want to work with. 

So we're still looking at deals with the Brown Dense and certainly, if you can get a partner, you can go a little bit faster, but as I said in our press release, we have budgeted as if we didn't have one and we're on the pace to do exactly what we said we were going to do in that direction.  So it's just nothing more than somebody tried to change the terms on us and we're just not going to do -- work that way. 

Amir Arif:  Okay.  Just asking a little more into the changing of the terms, was that after they went through the data room or source sought data or could you just provide some color on that? 

Steve Mueller:  Going back to your question about was there more well control; there isn't any more well control at all.  When we made the announcement, we had basically a turn sheet with all the agreed terms on it and the major thing they needed to do was do due diligence and that was more on the land side of it.  It wasn't what the geology or anything in that direction, and as I said, no new geological or no new information on any direction.  It was just they wanted to go back and start over on some of the terms. 

Amir Arif:  Okay, appreciate that color.  The second question, looking at the acquisitions you did and the attractive acquisition price, any desire to look at maybe the acquisition market to get into some new areas, just given the attractive prices that are out there on your balance sheet rather than just as bolt-ons? 

Steve Mueller:  We have a couple of areas that we target and we're always looking at to get into and I will just remind everyone, we look at our acquisition effort as an extension of our new ventures.  We're not looking for significant production per se.  What we're looking for is something that we can use our talents to.  We can drill into, have a long running room on it, use our vertical integrations.  So to the extent there are any of those kinds of acquisitions in particular areas, we are definitely looking for those and in this case, it just happens to be one of them is right in our backyard in Marcellus. 

Amir Arif:  Okay.  Thank you. 

Operator:  Our next question comes from the line of Scott Hanold with RBC.  Please proceed with your question. 

Scott Hanold:  Yes, Thanks.  Could I talk a little bit about the Marcellus for a minute?  You guys added -- when did that additional firm kick in because it didn't look like 2Q production was increased at all, and generally, is there a line of sight on additional stuff out there? 

William Way:  The date of the additional 50,000 a day that we picked up comes in the latter part of this year.  We are looking for additional transportation, but we have secured the transportation that we need through '15, '16 in terms of our growth plans.  But we are out -- we would be out in the market looking for some additional opportunities. 

Steve Mueller:  I think the market is basically -- the way it's been the last six months or so, there are operators who have firm that are not using it because they are not drilling right now, and to

the extent that we can buy nine months or a year of firm, we're doing that.  There's a couple of deals we're working on right now that are a little bit longer than that that are kind of two-year type timeframes on them and that goes back to Bill's comment about working towards 2015, 2016 with some of the numbers.  And of course, we have our Constitution line that comes on in 2015.

From the standpoint of our new acreage, we have no firm on that new acreage, so part of what we're having to do right now is develop that budget, figure out what other firm we can add into the mix and figure out how fast we can go on that acreage.

Scott Hanold:  Okay.  And then with respect to your comment, Steve, that obviously, gas prices are up here a little bit, but you don’t feel compelled, I guess, to increase activity.  Now, I think the plan was based on a $3.50 gas price and to the extent that obviously, prices were better, it seemed like, at least in the Fayetteville shale, you'd add a rig.  I think it was every, what, $0.35 you could add a rig and stay within cash flow?  Has there been a change in thought in that in terms of like running the Fayetteville within sort of its cash flows?

Steve Mueller:  Well, there really hasn’t been a change in thought.  The Fayetteville shale, we'll keep it within cash flow, give or take a little bit.  If you look through the first five months of the year, I think the average NYMEX price is like $3.60.  So we just need to see it a little bit more to make sure that we have some more cash flow in the Fayetteville shale to go faster on.  We could decide, maybe in the fourth quarter, but as we're looking at it right now, just looking at  if we build the budget around $3.50 and the average price that we have in hand today is about $3.60, we're not changing it. 

Scott Hanold:  Okay, understood, thanks.

Operator:  Our next question comes from the line of Brian Singer with Goldman Sachs.  Please proceed with your question. 

Brian Singer:  Thank you, good morning. 

Steve Mueller:  Good morning. 

Brian Singer:  On the Marcellus, would you mind just talking to the various firm transport compression and drilling constraints in each of your four main Marcellus areas, what is constrained today and what changes do you see between now and the end of the year? 

William Way:  I guess I would start by saying in terms of constraints, I think it's we really are looking at completing compression in the Susquehanna area, so it's not a constraint.  We are able to flow gas through that, so it's just ramping up infrastructure in the field in line with our drilling schedule.  We have, right now, today, through the end of the year, about 600 million a day of firm transportation out of the area.  And we hold that number through 2015 where we ramp up to 750 million a day, so today, we're able to move all of our gas.  There are no constraints through the end of the year and into next year, there are no constraints.

We are actually slightly ahead and are utilizing other transportation that's being released in the area, and then balancing that with incremental transportation if we need it.  The Bluestone Line that we talked about at the end of last year will connect to Millennium within the next few days.  We've been able to move all of our gas south while that activity has been happening and so now, we will split-flow some gas north to Millennium and some gas south to Tennessee out of the Susquehanna area.

All the infrastructure is in place in Lycoming for the growth that we have scheduled and so really, the next sort of question mark becomes timing on longer term projects and we're doing some work around those to make sure that we have capacity in place to be able to move gas in the longer term.

Steve Mueller:  And let me add, we talk about constraint.  When we do the economics, in some cases, just because these are such strong wells, we've decided that we don’t need to turn on the compression and use that gas with the compression standpoint.  And so I wouldn’t put that as a constraint; it's just pure economics.

William Way:  Right.

Steve Mueller:  And whatever you're getting for the gas price, we the big compression projects we have this year are in our Northeast Susquehanna area and they're to basically matching as we grow our production, and as other wells start losing pressure from being put on earlier in the year.  So from that standpoint, I think there really isn’t a constraint, as Bill said.

Let me also add, we get all the questions all the time of how we compare to other companies and how we're doing.  One of the things that we did in the most recent data, we were able to take our production data and take the number of stages we have -- and I think that's all public information in Pennsylvania -- and then compare that to Cabot.  If you just zero out when we started, when they started put to a times zero, take the number of stages of fracs that we've had to date and the amount of production, both the stages and the amount of production are dead on top of each other for where we're at.

So I think from an infrastructure standpoint, we're right on schedule from what we're getting first stage.  We're right on schedule and the production is showing that we're at 400 million a day.  We're right on schedule.  So we're excited about that.  Another way to put that is our range wells are coming on a little bit slower than the Bradford wells, but as we get to the peak rates and you see that on 120 day rates on our chart, we've actually had a little bit of increase in production, even 120 days in one of those quarters, but they're looking very comparable.  So we're excited about this acreage and then on top of it, especially in Susquehanna, we've added another 50,000 acres or so.  We're really excited about what's going to happen there later on in the year.

Brian Singer:  That's helpful.  And to follow up on just a couple of points on your response, is there -- what is the impact from the Bluestone connection to Millennium?  Is that a volumetric impact or a price impact or just allows for diversification?  And then the compression that's coming on this summer, is that baked into your guidance or is there some avenue of upside if in fact, that does come on time?

Steve Mueller:  I think the compression is in our guidance.

Brian Singer:  Yes.

Steve Mueller:  When I say "I think," you never know until you put it on and see exactly what it does, but certainly we've factored it in as we go through.  And then Millennium does two things for you.  The Millennium tie, number one, it's a little bit different price.  You get a couple more cents if you go into Millennium, sell as much gas we can in that direction, but the other part of it is in case either one of the lines are down, whether they're down for maintenance or down for some other issues, you’ve got an outlet and you don’t have to worry about it.  So that's your two main things.

Brian Singer:  Thank you.

Operator:  Our next question comes from the line of Doug Leggate with Bank of America.  Please proceed with your question.

Doug Leggate:  I guess my first question's on capital, Steve.  I hear that you're not going to increase spending, at least not in absolute terms.  How about the allocation of capital now that you've got the Marcellus, the bigger position, how should we expect your relative capital within the portfolio to ship their own, maybe not so much second half of this year, but as we look into 2014?

Steve Mueller:  Trying to predict 2014's a little difficult right now.  I will say that we're drilling faster than we expected in the Marcellus.  And so if we would try to say in the 90 well range on the acreage we had before the acquisition, rather than running 4 rigs, it's more like 3 and a quarter rigs to do that.  And so we've got 4 rigs running today.  As we get towards the end of the year, we'll either be drilling more wells on our current acreage or we'll have spread out into the new acreage is what we're doing.

But right now, with 11 days to drill a well, we're drilling closer to 100 or a little over 100-well pace.  And so we're trying to adjust that into the end of '13, actually, and then we'll figure out what happens in 2014.

Doug Leggate:  Great.  My only other one is really you made a pretty interesting comment there about the assumption you made on the tight curves and the acquired acreage.  I think you said a 5 Bcf curve.  But looking at the tight records you've established up there already, obviously, that seems a little conservative.  I'm just curious to, is that a starting point or do you have reasons to think that these wells are going to be less productive in the balance of your portfolio or are you just being conservative?  I'll leave it at that.  Thanks.

Steve Mueller:  I think certainly part of our acreage is well under 3 Bcf, and there's a little bit of control for that.  And we've talked about even our current acreage in Lackawanna county, much of that's less than the 5 Bcf numbers.  And as you swing into Wyoming, there'll be some of that that's less than 5 Bcf with the little bit of well control that we've seen. 

In other areas, frankly, there's just not much well control.  So we're just going to have to go figure it out.  And obviously, in either of these we don't have well control, we look at what industry has done around us.  We've risk those numbers.  And that when we look at that risk kind of factors, we're thinking 50% or less is at 5 Bcf, we'll have to figure it out.

Now, the other side of that, we are offsetting some wells in Wyoming County, for instance, some of our acreage, that are already proved to be 10 Bcf wells or higher.  Some of the new acreage we have is right off studies in what Cabot has recently announced in Susquehanna County, and they're talking about wells much better than 5 Bcf there.  And certainly, some of our Tioga County acreage is sandwiched between what Shell's been doing and what we've been doing, and those, almost certainly, will have a lot of wells higher than 5 Bcf. 

So some cases we've got it pretty much down and we'll just have to figure out how much higher.  In other cases, we're going to have to drill some wells and put in some infrastructure just to figure out the quality. 

Doug Leggate:  Okay.  Steve, you have always been evolving your well design a little bit in your existing acreage.  Have you kind of figured out what your standard well is going to look like in the new acreage, or is that going to be more of like in a learning curve as well?  In other words, what's your standard well design going to be?

Steve Mueller:  Well design will be ongoing.  And I'm going to jump to Fayetteville and come back to Marcellus.  But if you think about the Fayetteville, we're 3,500 wells into drilling.  One of the reasons we had some low rates in January, what we were trying to do some little different fracs in an area, and those fracs didn't work the way we liked, we learned something from those.  One of the reasons that in April we had such higher rates that we announced was when we went right back to the same area with a slightly different frac and got better wells, significantly better wells.  So even there, we're learning.

In the case of the Marcellus, we are understanding a couple of things.  We think we know the rough spacing for the Bradford County.  We spent most of last year trying to do that.  In Lycoming County, we tried to pull a well at a very high rate, a couple wells at high rates.  They performed at high rates, well above 10 million a day.  But when we look at how their pressure drops, they seem to more act like the Haynesville, where rather than having a high rate, you want to come in with a medium rate, maybe a 7 million to 8 million a day-type well, and let that pressure stabilize as you go through it. 

We're trying to understand in both Bradford and Susquehanna whether the high rate is better long term or the low rates -- or a lower, medium rate is better long term.  And on our new acreage, to the extent that it's near where we've done some work, we can transfer that knowledge.  But a lot of that, we're just going to have to go in and start learning as we go through. 

So I don't think there's going to be just a formula either on stage spacing or on how hard to pull the well across our whole acreage block.  It's going to be individualized for each of the areas.  And the reason it's going to do that is from Lycoming to Susquehanna, there's over 2,000 foot depth difference across there, there's thickness differences across there, and there's pressure grading differences across there.  So all of that will affect how it produces and how you need to frac as you go through.  

Doug Leggate:  I appreciate the full answer.  Thank you.

Operator:  Our next question comes from the line of Arun Jayaram with Credit Suisse.  Please proceed with your question.

Arun Jayaram:  Steve, I wanted to talk to you a little bit about development plans in the Fayetteville.  You had obviously gone to wider spacing in order to help you meet the 1.3 PVI target in the lower gas price environment yet.  With prices now moving up, your well cost going down, what are the plans to shift back to your, call it your more original plan, which is tighter spacing?  Do you plan to do that this year or will that wait?

Steve Mueller:  It could happen in the fourth quarter.  Again, we just need to see how price is working.  And it's not so much tighter spacing as we've talked about in the past.  We're kind of drilling the better wells in the areas, so we're just not drilling at hardly any spacing.  We're just putting 1 or 2 wells near maybe a well was drilled before.

We'll get back to pad drilling once we're comfortable, we're in a $4 world or near-$4 world.  And certainly, the forward curve looks that way, as long as it holds in this shape.  You'll see us towards the end of this year, going into next year, going back to those pad-type drilling operations.

Arun Jayaram:  That's helpful.  Steve, you did provide --

Steve Mueller:  And the other thing -- yes, let me just put in there, this year we're going to average a little over 2 wells per pad.  So we're certainly not in a pad drilling situation right now. 

Arun Jayaram:  Steve, you gave us a lot of great detail in terms of the Marcellus in terms of 30-, 60-, 120-day rates and the average lateral length.  Seen quite a bit of volatility in the data.  I was wondering if you could maybe give us your thoughts on what you think the data suggests in terms of your Marcellus position.  And also, you have been moving around that lateral length a little bit.  Just some thoughts on as you move forward what you think the optimal lateral length could be.

Steve Mueller:  Yeah.  Brad asked the same question.  Why you putting that chart in there, it's got a bunch of junk on it, bouncing around?  It's bouncing around because we're really new in the project area.  So even if you look at well counts, well counts bounce around, let along the other parts of it. 

One thing, as I said before, that we've seen, and one of the reasons we've put the chart together this way, an IP, the initial high rate, really doesn't do us much value and we don't even get to the highest rate in Bradford, for instance, until you're at least 30 days out.  And in range, it's 45 to 60 days out before we see it.  So we try to get something where you could follow how it was going to happen over time.  And I think a lot of this is just erratic nature of being early in the program.  And some of those quarters, you remember, we're waiting on getting pipelines in and we put a bunch of wells on at once and fill up the system, another quarter you did something else.  So I think you just need to follow it through.

From an average lateral length, though, it's probably less than 5,000 feet.  It's probably low 4,000 -- I mean high 4,000s and less than 5,000, for the most part.  Lycoming, probably will average a little longer than that.  And certainly in our new acreage, as we get to parts of that, there may be some of that that averages longer.  But I don't think on average you'll see us much above 5,000 feet.

Arun Jayaram:  And then just one quick follow-up.  In terms of the number of stages, I think you mentioned that you're moving to maybe 17 stages on average.  Are you seeing the benefit of the additional stage in terms of recoveries or IP rates?

Steve Mueller:  I don't know that we're moving to 17 stage on average.  We're trying to figure that out.

Arun Jayaram:  Okay.

Steve Mueller:  And in Bradford County, we think that a 250- to 300-foot range, and I think we averaged last year like 280 or something.  But we think that range is the right spacing on fracs.  And so then it just goes back to what your average lateral length is and how many frac stages you have in a well.

We're trying to learn what it's going to be in Susquehanna, and I know some of our competitors have a tighter spacing there, and it may end up to be that way.  We just have to find that out.  So I think it'll just depend on each area exactly what that is.  And that's why you see a lot of us talk about first stage numbers, because each areas going to be a little different on the total number of stages.

Arun Jayaram:  Very helpful.  Thanks, guys.

Operator:  Our next question comes from the line of Ray Deacon with Green Capital.  Please proceed with your question.  Ray Deacon, you are now live.

Ray Deacon:  Hey, Steve.  Sorry, I was on mute.  I just had a question.  I've heard you talk in the past about you being fine with your firm transportation situation if the wells were 5.5. Bcf or less.  And so I guess is the right way to think about that, that if you do get numbers higher than that, that -- is it so kind of beyond 2014, is when you feel like you would need to schedule in further firm transportation versus what you have now?  Is that what you're seeing?

Steve Mueller:  What we've talked about in the past, we believe that we want to have most of our production covered by firm.  And we think that's important to get it to a liquid point, especially as fast as Marcellus is growing.  We don't know what you're going to get on an interruptible or day market.  And so we originally, and this is almost 2 years ago now, developed a program and developed a plan where we said, what's the maximum rate that we could have and hold it flat for 8 to 10 years?  And that number, with the assumptions we had at that point in time, assuming around 5 Bcf wells and a little over 5 million a day on average rates, said that we're somewhere just short of 800 million a day was that peak rate that we could have.  And then we designed our current capital program just backing off of that and going back to where we're at today, and it came to be drilling around 100 wells a year, that we follow the 4-rig program, and that's what we started doing last year and got us to this year.  We're into that framework.

If the well performances on average are a little bit higher, we'll tack on a little bit of firm that's out there and it'll be roughly an 800 million day range, and we'll hold that flat for that period of time. 

If we saw either in the new acreage something or on the acreage we have now where they're significantly better wells on average, then certainly we'd have to go find some more capacity.  And today, while we combine little pieces of capacity from other operators, if we needed to, for instance, add 100 or 150 million a day or more, you'd have to commit to some new pipe, and that's 2 years out.  So that goes back to your comment about when you'd accelerate the capital.  You'd accelerate the capital as you were seeing the firm in place, and that'd be a little bit farther down the road.

Ray Deacon:  Okay, got it.  And is generally new sort of a second tranche of firm transportation, does it end up usually costing more than the early stuff that's put in?  Or what would be your guess there?

Steve Mueller:  Not necessarily. 

Ray Deacon:  Not necessarily.

Steve Mueller:  But it depends on how you're getting it and where you're getting it from.  Certainly, if it's just by Tennessee Gas doing something to their line and adding compression, that's usually less cost than putting in a brand new line.  But it really, it depends on the distance you're going, how big the line is, and whether it's a new line or how you're getting the capacity so it doesn't have to change.

Ray Deacon:  Okay.  Got it.  And just one more quick follow-up.  I guess in terms of looking at Bradford and Susquehanna County, I guess, where would you say you are?  Kind of in Bradford, it looks like you're getting much, much better results.  I mean, are you kind of in the 5th or 6th inning there?  And what would you say about Susquehanna?

Steve Mueller:  Well, Bradford, we've drilled on all corners of that block and we're feeling that we know it fairly comfortably.  So it truly is in a pad mode.  And while we're learning and we tried this well we talked about in the press release, trying to learn how to do it a little bit better, we understand the geology and how it changes and what's going on there.

In Bradford, in the -- I mean in Susquehanna, in the fourth quarter, we put our first wells on, and they were in the northeast area, but at the far south tip of that.  During the first quarter, we started to work along the Bluestone Pipeline a little bit north, and by the end of the year, we'll have wells all the way up almost to the New York border and have wells almost to the eastern side of that northern block of acreage.

So at that time, we'll at least understand the geology.  To understand how you frac and how you get the best well out of that, that's something beyond this year into next year and maybe a little later than that.

Ray Deacon:  Great.  Thank you very much.

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

Dan McSpirit:  You spoke about PUD reserves returning to books on price in your prepared comments.  Can you elaborate on that statement and maybe speak to at what price and how much has returned?  And as a follow-up to that, what should be expected with greater strength in price here going forward?

Steve Mueller:  Yes, the last comment, if you look at SEC rules you have to use a 12-month rolling average.  The actual 12-month rolling average in price is something like $0.20 higher than it was at the end of the year, so you didn’t have much increase in price. 

We added about 200 PUDs in the Fayetteville Shale, a little less than 200, and for those that remember we had just over 200 at the beginning of the year, so we doubled the PUD count for the Fayetteville Shale, and that’s where he’s talking about the increase in count mainly.  Obviously, that $0.20 helps a little bit on the tail end of wells, it helps a little bit in the Marcellus it was mainly in Fayetteville.

Dan McSpirit:  Okay, and as a follow-up, on the Marcellus, and this is more clarification here, on the Marcellus acquisition you say that about 50% of the acreage will have wells with five Bcf recoveries or greater, that’s net of the 40,000 net acres that will be allowed to expire, correct?

Steve Mueller:  I think that’s total acres I was talking about, 160,000.  There’s certainly 40,000 of that is going to be gone here in the next two years.

Dan McSpirit:  Got it.  Thank you.

Operator:  Your next question comes from the line of Charles Meade with Johnson Rice.  Please proceed with your question.

Charles Meade:  Morning, thanks for taking my question.  You guys have provided a lot of good detail on the Marcellus here, but I’d like to go in a fully different direction and ask you about two of your new ventures, plays.  And specifically on the Steiner reentry, did you always have the plan to just try one completion design on these first five stages and see how that went or did the – or did you see something when you completed those stages that made you just want to let the well flow and see what it did?

Bill Way:  No, our original plan was to complete that – or drill that lateral and then complete it in two phases, where we do the first five stages, let it flow for awhile, look at the patch, look at the quality of the performance and then go back into it and complete the remainder of that, so there’s no change to our plan.

Charles Meade:  Got it, and do you –

Bill Way:  We’re pretty encouraged by what we’re seeing so far, we’re just – it’s early days.  We received, you know, we had oil patch come in the first two days and then we’re continuing to monitor it and it’s still cleaning up.

Charles Meade:  Got it, got it, and do you have a different completion design for those – for the next 11 stages than you did for the first five here?

Bill Way:  We’re going to finalize that once we see what happens in these first five stages and so, and we’ve done this before on other wells, we will split, complete it, look and see where we are, what the performance is on the recipe that we used and then go back, make adjustments or not, depending on what we see, and then do the remainder of the completion.

Charles Meade:  Got it, and then that kind of gets to my next question, it sounds like you’re going to take a similar approach for the Dean horizontal?

Bill Way:  That’s correct.  We’ve done the first six stages and now we are – we’ve pulled back, we’re evaluating the results of that, we’re evaluating combining that with the results of the other wells in the area where we’ve learned from and then – sorry, my voice is going – and then we will optimize that frac and then move forward again.

Charles Meade:  Got it, got it.  And when might you think that you’ll have something you’ll be able to share on either of those or on both of those wells?

Bill Way:  I think it’s going to be later in the year.  We don’t – I don’t have an exact timing, we’re really trying to incorporate the learning’s.  One of the things about drilling in these plays is trying to optimize our learning as we go, and so we want to capture all the value of the data, of the testing that we’ve done, and so I don’t have a time for you yet, but we’ll let you know as soon as we get ready to move forward.

Charles Meade:  Got it, yes, there’s definitely a tradeoff there.  Thank you for the added detail.

Bill Way:  Thank you.

Operator:  Your next question comes from the line of Bob Christiansen of Buckingham Research.  Please proceed with your question.  Bob Christiansen, you’re now live.  Okay.

Well, our next question comes from the line of Biju Perincheril with Jefferies & Company.  Please proceed with your question.

Biju Perincheril:  Hi, good morning.  I had a question going back to the well designs in  Marcellus and, Steve, you talked about in Bradford County sort of what you think is the ideal length for frac stages, but the latest well it looks like the Blamehood well you are getting improved productivity with  shorter frac stages.  Can you talk about the design going forward and what’s the information you’re still looking for there?

Steve Mueller:  Good morning.  It’s almost exactly what Bill said in the last question.  We need to look at it.  Certainly, you’re getting higher rates, but rates aren’t the only part of it, you have to look at the pressure drive down and the overall affects on the production.  And if I had to guess today, as we compare it to some of the other wells we’ve done where we’ve gone on a slower ramp up on rate, on just the pure rate part of it, the slower ramp up looks like it holds pressure longer than the higher rate.

Now, certainly, part of that has to do with how close you put  the stages together, but where we’re in now, adjusting on the stages, is at 250, 275, or 300, we’re not in is it 250 or 150.  So we’re still fine-tuning, but we’re above 200 from the stages, the space on the stages.

Biju Perincheril:  Okay, and then can you give us some data on your sort of average 30-day rates or 60-day rates in Susquehanna versus Bradford County and Lycoming?

Steve Mueller:  Well, in Susquehanna and Lycoming we barely have 60-day rates, I mean we’re – we’ve got some 80’s maybe or something in that range.  Lycoming in general is – what we have – when we drilled a couple of those early they were short laterals, but if you take a 4,500 foot lateral, most 4,500 foot lateral wells are producing between seven million and eight million a day type numbers. 

And Susquehanna at around something beyond the 60-day mark we’re still – a lot of those wells are still increasing along their maximum rates, but they’re in the six plus million a day type average range for those wells and there’s some that are much better than that, there’s some a little bit lower than that in Susquehanna, but that’s kind of the general part of it. 

And then you can compare that to the Bradford, Bradford is mainly what’s in that presentation material that we have there, but you can see those rates are six million, six-and-a-half million, seven million day type range.

Biju Perincheril:  Got it, okay.  And then one last question, looking at the acreage that you recently acquired and especially in Susquehanna, it looks like there’s not been a lot of permitting activity on that very east end side of Susquehanna, and can you talk about is there any geologic reason for that or is that mostly that those acreage had a longer expiry?

Steve Mueller:  In general, the eastern side of Susquehanna hasn’t had much permitting because you haven’t had a way to get the gas out.  That Bluestone line that just went in December is the main way all of the industry will get their gas out of that area. 

Now from a geologic standpoint the center of Susquehanna County is for the total Marcellus is thicker, and when you go north towards New York or east towards New Jersey, so it is bending a little bit, but from a general perspective you’re talking about 30 or 40 foot thickness change across that little interval geologically as you go through there, so it’s basically we need to get the Bluestone line in so you can start hooking up some wells.

Biju Perincheril:  Very good.  Thanks, that’s helpful.  Thank you.

Operator:  Our next question comes from the line of Nick Pope with Cowen Securities.  Please proceed with your question.      

Nick Pope:  Good morning, guys.

Bill Way:  Good morning.

Nick Pope:  A quick question on the acquisition, what is the royalty running on kind of the acreage that you acquired and where is that relative to where you’re at on kind of the heritage Marcellus asset?

Bill Way:  It’s very similar to the acreage that we have, it’s about an 84% NRI.

Nick Pope:  I think everything else has been answered, so thanks, guys, thanks for the time.

Bill Way:  Thank you.

Operator:  Our next question comes from the line of Hsulin Peng with Robert W. Baird.  Please proceed with your question.

Hsulin Peng:  Good morning.  So just a quick clarification question, on the new ventures project, I think that has assumed a JV partner, and so if you’re not going now in Brown Dense how would you – where would you get the additional allocation dollars from?

Steve Mueller:  Well, I don’t think we ever said exactly how much we were investing in the Brown Dense, but we had originally in our budget about 2.5 net wells, and we may invest a little bit more in another well this year, and top the ones we’ve drilled now.  But we can move money around within the joint venture budget to do that, so it doesn’t require anymore budget as we go through.

Hsulin Peng:  Go ahead?

Steve Mueller:  But it just has to do with where we might be drilling someplace else or what acreage we might be picking up and how fast we pick-up acreage.

Hsulin Peng:  Right, got it.  And then can you comment on the progress you are making toward the $10 million well cost target that you had previously mentioned?

Steve Mueller:  You know, we’ve drilled two wells since last quarter, both of those came on time, and if we didn’t have a lot of science to them on a 4,000 foot lateral would be in that I’d say mid 10 range, 10.5 to 10.7 range, somewhere in that range.

Hsulin Peng:  Okay, no, that’s good.  And then the last question, I know – I don’t think you can comment on the Paradox, but I was just thinking so Fidelity, we know Fidelity is drilling in the area, as well, and I was wondering if you can say, are you thinking about similar results to what they have been doing there?

Steve Mueller:  We will be – our objective is the King Creek interval, and King Creek interval, the section the King Creek is in is a very large section, but we’ll be going for the King Creek, which I believe is the same thing they’re going for, and you’ll see us have some activity later this summer out there.

Hsulin Peng:  Okay, all right.  And my other questions have been asked.  Thanks.

Operator:  And since there are no further questions at this time I’d like to turn the floor back over for closing comments.

Steve Mueller:  Thank you.  One of the questions everyone should ask about a company is how do you measure yourself?  Today in this quarter we talked about a lot of things, revenue, costs, cash flow, earnings, project economics, production activity, talked a lot about learning, and we’ll continue to measure and talk about those things as we go forward in the future.

For us this year we’ve got a special measure in 2013 and that’s to deliver more, and you saw a little bit of a glance of that in our discussion today for the first quarter.  Our economics continue to improve in the Fayetteville Shale as we drive down the costs, lower costs allows us to have more activity.  We talked about that in the Marcellus.  We’d also like to have more activity in the Fayetteville.  But what’s amazing about this is Fayetteville now has been producing almost eight years, and you’re only barely one-third to the locations that we have to drill out there.  So we have a lot more to do in the Fayetteville Shale.

When you think about the Marcellus we’ve got exceptional results from the wells we have, and as I said before production for frac stage is comparable to anyone in northeast Pennsylvania, and we’re still learning and we’re still developing more and better wells.  And then on top of that we’ve got some new acreage where we’re going to create more options, more wells, be able to do more vertical integration, and actually have more production and more value.

We’ve mentioned, just to the last question about our new ventures projects, we’ve got four of them that we’ve identified, we have 1.3 million acres, and we’ve got a lot more ideas, and you’ll see at least one more come out this year. 

And then, finally, we’re delivering more with less.  When you think about our capital budget, our capital budget is $100 million less than last year, the capital budget in the Fayetteville Shale is $200 million less than last year, that’s been our pride and joy, and yet we’re growing production at 13%, giving you more production with less capital.  Of course, we’ve got less days, we’ve got less costs, and one of the reasons we have less costs is that we’re using less water and we’re working towards our goal that by 2016 we’re net neutral as far as freshwater goes.

Again, for us, 2013 is a year more, and the first quarter is just a start on what that more is.  I thank you for the time you have taken from your busy schedules to listen to us today and have a great weekend.

Operator:  This concludes today’s teleconference.  You may disconnect your lines at this time.  And thank you for your participation.

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 March 31, 2013 and March 31, 2012. 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.