Southwestern Energy Company

Q1 2011 Earnings Conference Call

Friday, April 29, 2011

Officers

Steve Mueller; Southwestern Energy; President and CEO

Greg Kerley; Southwestern Energy; CFO

Analysts

Scott Hanold; Royal Bank of Canada; Analyst

Scott Wilmoth; Simmons & Company International; Analyst

Nick Pope; Dahlman Rose; Analyst

Brian Singer; Goldman Sachs; Analyst

Gil Yang; Bank of America Merrill Lynch; Analyst

Rehan Rashid; FBR; Analyst

Amir Arif; Stifel, Nicolaus & Company; Analyst

David Heikkinen; Tudor, Pickering, Holt; Analyst

Dan McSpirit; BMO Capital Markets; Analyst

Hsulin Peng; Robert W. Baird & Co.; Analyst

Presentation

Steve Mueller:  Thank you and good morning. With me today are Greg Kerley, our CFO, and Brad Sylvester, our VP of Investor Relations.

If you've not received a copy of yesterday's press release regarding our first quarter of 2011 results, you can find a copy on our website at www.swn.com.

Also, I would like to point out that many of our comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control, and are discussed in more details 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.

To begin, I’m excited that we continued to deliver top-tier results and I’m equally enthusiastic about the rest of 2011. We continued to maintain well costs while growing production, and yesterday, we increased our guidance for the rest of 2011 to take into account our first quarter results and the stronger production we are seeing from the Fayetteville and the Marcellus. We posted production growth of 28% during the quarter, fueled by our Fayetteville Shale play, which grew by 34%, with production of 101 Bcf. We also produced 7 Bcfe from our East Texas, 4.2 Bcf from the Arkoma Basin and 2.8 from the Marcellus Shale, which we kicked off in late 2010.  

Now to talk about each of operating areas -- we placed 137 operated wells on production in the Fayetteville Shale during the first quarter, which resulted in gross operated production reaching 1.7 Bcf a day at March 31. Our operated horizontal wells had an average completed well cost of $2.8 million per well, with an average drill time of 8.4 days during the first quarter. We also placed 11 wells on production during the quarter that were drilled in five days or less.

Due to our fast drilling times, we have increased our 2011 capital investments program by $100 million to a total of $2.0 billion for the company. As a result, we expect to drill at least 30 additional wells in the Fayetteville Shale this year than we had previously planned.

Our average initial producing rates were approximately 3.2 million cubic foot per day, which is down from the fourth quarter, primarily due to location differences and the mix of wells and increased line pressures. In March, we placed several wells on production in our most northern areas of the field, which encountered higher line pressures than the rest of the field. This had an effect of lowering the initial production rates for those wells.

We continue to test tighter well spacing and at March 31, we had placed over 764 wells on production that have well spacing of 700 feet or less, representing approximately 65-acre spacing. To date, we have concluded that approximately 30% of the roughly 600,000 net acres drilled to date can be developed at 30-to-50 acre spacing and approximately 70% can be developed at a maximum of 65-acre spacing. We are still refining our conclusions with the goal of determining individual spacing for each section. Interference testing is ongoing; field-wide geologic and production models continue to be refined and additional spacing tests are being drilled by other operators in the field.

In northeast Pennsylvania, we have approximately 173,000 net acres prospected for the Marcellus Shale. We are very encouraged by what we've seen to date. At March 31, we have completed 14 operated Marcellus Shale wells on 5 pads located in our Greenzweig area in Bradford County. Net production from the area was 2.8 Bcf in the first quarter, compared to 0.8 Bcf in the fourth quarter of 2010.

In our Greenzweig area, our practice is to place several wells in production from a single pad at the same time and the results continue to be strong. Three wells that were placed on production in October 2010 are currently producing an average rate of 6.3 million cubic foot per day per well, while three wells placed on production in November of 2010 are currently producing at an average rate of 4.3 million cubic foot per well, and three wells placed on production in February are currently producing at an average rate of 5.8 million cubic feet per day per well.

On April 18, we placed three additional horizontal wells on production at a gross rate of over 4 million cubic foot per day per well. These wells are still cleaning up and they're also flowing up casing. Rates will increase after installation of production tubing. All of our wells are currently producing without the benefit of compression into line pressures of approximately 1,100 pounds and gross operated production from the area is currently 60 million cubic foot per day.

In March 2011, we entered into a letter of intent with DTE Energy to gather our future natural gas production from our eastern Range Trust area in Susquehanna County. The final terms of the Gathering Agreement are currently being negotiated. However, first volumes to be delivered to the interstate pipelines could be as early as the second quarter of 2012. We have also recently executed agreements with both Millennium Pipeline and the Tennessee Gas Pipeline, which will increase our ability to move Marcellus gas to premium markets.

I know that there are probably several questions about our New Ventures and let me make a few statements. First in New Brunswick, the acquisition of approximately 410 miles of 2D data is scheduled to begin in May and will continue through the third quarter. We also plan to do another phase of geochem acquisition that’s planned to start in the third quarter.

At the beginning of the year, we reported approximately 490,000 net acres in our New Ventures plays that were not part of New Brunswick. As of April 15, we have more than 620,000 net acres leased and are still on schedule for drilling at least two wells in the second half of the year.

In our other areas, we participated in drilling two wells in East Texas during the quarter, both of which were operated. In March 2011, we entered into a definitive Purchase and Sale Agreement for the sale of certain oil and natural gas leases, wells and gathering equipment in Shelby, San Augustine and Sabine Counties in East Texas for approximately $85 million. The effective date of the sale is January 1, 2011, and the standard closing adjustment will include natural gas sales proceeds and capital invested in 2011 prior to the closing. The sale includes only producing rights from the Haynesville and Middle Bossier Shale intervals, approximately 9,700 net acres. The net production from the Haynesville-Middle Bossier Shale intervals in this acreage was approximately 7 million cubic foot per day as of April 15, and proved net reserves were approximately 25 Bcf as of year-end 2010. We expect the transaction to close in the second quarter of 2011.

In closing, we’re excited about our development of the Fayetteville Shale, we’re increasing our activity in Pennsylvania and have on track drilling our first New Ventures wells over the next few years.

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

Greg Kerley:  Good morning. As Steve noted, our financial and operating results for the quarter were stronger than we expected and continued to highlight our industry-leading low-cost structure. We reported earnings for the first quarter of $137 million or $0.39 a share, compared to earnings in the first quarter of 2010 that were $172 million or $0.49 a share.

Our discretionary cash flow was $392 million in the first quarter compared to $418 million for the same period in 2010. The comparative decreases in earnings and cash flow were primarily due to the decline in natural gas prices. Our average realized gas price of $4.12 per Mcf was down more than $1.00 from the same period last year.

Our commodity hedging activities increased our average gas price by $0.44 per Mcf during the quarter, and with the favorable storage report yesterday, we were able to hedge some additional volumes for 2011, and currently have NYMEX price hedges in place on notational volumes of 171 Bcf of our remaining 2011 gas production at a weighted average floor price of $5.26.

As a reminder, our hedge position, combined with the cash flow generated by our Midstream Services business, which is not dependent on gas prices, provides protection on approximately 55% of our total expected cash flow for 2011.

Operating income for our E&P segment was $178 million during the quarter, down from $250 million in the same period last year. Our all-in cash operating costs, which include lease operating expenses, general and administrative expenses, taxes other than income taxes and net interest expense, were $1.30 per Mcf equivalent for the first quarter of 2011, and remains one of the lowest in our industry.

Our full-cost full amortization rate also declined, dropping to $1.31 per Mcf in the quarter from $1.41 in the prior year. The decline in the average amortization rate was primarily a result of the sale of the East Texas property Steve noted earlier, as the proceeds from the sale were credited to the full cost pool. Lower acquisition and development costs also contributed to the decline.

Operating income from our Midstream Services segment increased by 43% in the first quarter to $54 million. The increase in operating income was primarily due to the increase in gathering revenues from our Fayetteville and Marcellus Shale plays, partially offset by increased operating costs and expenses. At March 31, our Midstream segment was gathering approximately 1.9 billion cubic feet of natural gas per day through 1,623 miles of gathering lines in the Fayetteville Shale play, compared to gathering approximately 1.5 billion cubic feet per day a year ago.

At March 31, we had $531 million borrowed on our $1.5 billion credit facility at an average interest rate of around 2.25% and had total debt outstanding of a little more than $1.2 billion. This leaves us with a debt to book capital ratio of 28% and a debt to market capitalization ratio of only 8%.

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

Questions and Answers

Scott Hanold:  Hey, in the Marcellus, obviously those are pretty strong well results and given that, I mean, are you all thinking about potentially stepping up activity a little bit and is there an ability to do so, or is it more of an infrastructure-related constraint?

Steve Mueller:  We will step up some of our activity. As we noted, I think, in our last conference call, we’ve got one rig running right now. That rig count will go up here in a few months to two rigs, we’ll end the year with two, and as we look into 2012, as we get more of this capacity in -- and we mentioned that DTE deal that’s in early 2012 -- you start seeing more rigs go out in the field, especially on the eastern acreage. But right now, we can run one to two rigs through the rest of the year and we've got to take away for that.

Scott Hanold:  Okay. Okay. So you're playing it slow, okay. And then on the New Ventures play, it sounds like you guys increased your position fairly meaningfully during the last update. I guess, can you sort of give a little bit of color in terms of do you think there’s more acreage to be picked up and is this an all-in-one specific area or a couple of areas, and when do you feel comfortable about giving us some further details here?

Steve Mueller:  Yes, as far as the acreage goes, all we will report, whether it’s on a Q or K, or whether it’s what I just said today, is the acreage that you’ve done basically three things on: You signed a deal; you’ve done the title work on; you’ve confirmed that they actually have the mineral rights and you’ve paid the check. There’s obviously some acreage out there that we've signed deals with people on that we are doing title work on, and then we’ll pay the check and we’ll actually have the lease in hand and can file the lease.

And then there’s acreage you want to get -- it’s kind of a rolling sequence as you go through it. We still certainly have several contracts that we have signed with groups and individuals who we think they own the mineral rights and so we’re working title on that. So you'll be seeing numbers go up, and then we also got more acreage we want to get. And the old concept was that we thought it would take at least through the first half of the year to get the acreage that we wanted on the first projects that we were going to drill, and then we could go drill them in the second half of the year.

As far as how many projects, are we working on more than one? We are working on more than one. Just to remind everybody, the thought concept here is that over the next five years, we’ll drill a couple of these a year and have a total of 10 drilled over five years -- some years, maybe one; some years, maybe three or four, but in that group of 10 that you drill over five years, we’re expecting two to three to be successful and those two to three add up to be at least as much as what the Fayetteville Shale is going to be for us.

And so, you're in the very beginnings of seeing that rollout and we’re in different stages of picking up acreage because of that. In some cases, we’re just starting to pick up acreage; in other cases, like the ones we’ll drill later this year, we’re getting closer to be done with the acreage from that perspective. So that’s kind of the game plan as it goes out.

As far as when you’ll hear more, as we get the acreage in place and we’re getting to the point where we’re starting drilling wells, we’ll start talking about where the acreage is at, how many wells we think it’s going to take to determine if it’s going to be good or bad and what the schedule we’ll have for drilling those wells.

Scott Hanold:  Okay. But will you comment on sort of the liquids versus gas? I know you guys look at rate of return, but when you talk about the liquids versus gas in some of these areas?

Steve Mueller:  Well, since we’re looking out four to five years in advance, we haven’t put a bias on anyone as far as looking for it, saying look just for gas or look just for oil. We do have some oil plays; we do have some gas plays. We are picking up acreage on some oil plays and some gas plays and we’re trying to accelerate the oil. There’s always the chance that you don't -- can’t accelerate the oil and the gas plays come up first, but if I had to guess right now, those first wells would be in an oil play.

Scott Hanold:  Okay, appreciate the color. Thank you.

Scott Wilmoth:  Hey, guys, just trying to get a better understanding of the capital allocation with the increased budget, obviously, increasing in the Fayetteville with additional wells, but also losing East Texas. Can you kind of just help us walk through the moving pieces on that?

Steve Mueller:  There’s not a whole lot of moving pieces there. We were drilling some wells in East Texas to hold some acreage until we sold it and that’s one of the reasons that it’s a 1/1 date and we’ll be reimbursed for that capital we invested there. So there’s going to be, when you look at - - later, see some reports from us, you'll see that we’ve got some capital we invested in East Texas, and then we’ll have income on the other side where we’re reimbursed for that, but as we look forward to the rest of the year in East Texas, we’ll have very little capital being spent in East Texas, which is what we really started the year with. From a net-net effect, we would only have a couple of wells in the James Lime that we have real true capital for in production with that. And that really goes with our Conventional Arkoma as well.

Most of the increase in capital -- and when I say “most of it,” that $100 million, close to $80 million of that is just the fact that we've drilled faster in the Fayetteville Shale. We started the year, and to kind of put it in kind of perspective, last year, we averaged just over 10 days per well, between 10 and 11 days to drill a well. We started the year thinking we were going to average over nine days, just over nine days for the year. Then at our last call in February, we adjusted that down to just a little less than eight days and now we’re thinking we’re in the mid-eights to low-eights for what’s going to happen for the rest of the year until the number of days to drill a well, and what’s that done is created the ability to drill more wells, the same number of rigs running.

And when you think about what we’re trying learn this year, there were two big things we were trying to learn. We want to continue getting the information on the spacing and work that out, so we know what to drill when we get to the pad drilling towards the end of the year. The other thing we’ve been trying to figure out and what we want to do is how fast can we really drill so we know how many rigs we need to run to get to certain well counts and things of that direction?  And what’s happened is we’re learning we can drill faster than we thought. So really, the capital budget almost entirely is increased because we’re learning we can do it faster.

Scott Wilmoth:  So how does that change your kind of long-term rig assumptions in the play over the next couple of years?

Steve Mueller:  I don’t know exactly the answer to that yet, but again, to kind of put in perspective, two years ago, we drilled about 500 wells and took 15 rigs. Last year, we did just under a 13-rig average and drilled about 550 wells and this year, it looks like we’re going to drill about 500 wells with 11 rigs. So I don’t know exactly where we’ll end up the year with on how many wells you can drill per rig, but once we figure that out, then we can say is 11 the right number, 12 the right number, or 10 the right number? And so that’s something in the later year to figure out.

Scott Wilmoth:  Okay. And then moving onto Midstream, I think you guys are nearing the end of your strategic alternatives audit. Can you just kind of give us an update on thoughts on kind of monetization timing, given that you’re going to have a production ramp in this year and next?

Greg Kerley:  Well, Scott, this is Greg. You're right in that we’re in the last innings of the audit, a three-year audit, that we’re performing on the financial statements, so that’s nearing its end and we’re still trying to determine the best path forward from a strategic standpoint and expect that that decision we've made probably in the last half of this year.

Nick Pope:  Quick question on the spacing.  I know you talked a little about it in the past.  But whenever you look at the 30-to-50 acre spacing and the 65-acre spacing, what kind of interference are you expecting with wells kind of offsetting one another with those spacings?

Steve Mueller:  I think a good estimate right now would be around 10%.  In the past we've talked about in some areas as close -- as low as 6% to 7%, in some areas it's 12%.  But I think 10's a good average number as you look out in the future.  

And the other thing about the spacing, we're making all these comments really with wells that have six months or less production on them, on a lot of these ones we did last year.  And so expect in the next couple quarters we can talk more about exactly what the interference we're seeing and maybe there may be some slight revisions on that 30/70.  If there'd be any revisions, it would be to closer spacing, not a farther spacing.  So you may see a couple percent difference on that also.

Nick Pope:  Okay.  Excellent.  And with the Marcellus, the 60 gross number, what is that -- what is that on a net basis on the current production?

Steve Mueller:  We're roughly 50 million a day net.

Steve Mueller:  If you think about our -- right now we're drilling about 95% working interest, and our net interest to us is about 85%.  So 0.95 times 0.85.

Brian Singer:  Based on the improved results and efficiencies you're seeing and the extent to which you're comfortable spending above cash flow, what do you see as the key pricing points for natural gas where you would raise or lower activity in the Fayetteville?

Steve Mueller:  I think we want to stay within shot of cash flow neutral.  And I say within shot, if you think about what we're doing this year, the Fayetteville Shale, all of our conventional properties, all are within cash flow.  And the only places where we are investing that's outside of cash flow is the $180 million in New Ventures.  And then we're getting some cash flow on the Pennsylvania side, but whatever the net difference on Pennsylvania.  

And so we're a couple hundred million, $200 to $300 million outside cash flow, and we want to continue doing that going forward.  So to the extent that production increases, that gives us more cash flow.  

The other thing, we are, as Greg said, continuing to hedge.  Our target, if we can do it, will be to have about 50% of this year's production hedged at $5 or more, and we've been able to do that so far.  If that works, if you'd average, for instance, $4 for the rest of the year, our average that we get is well over $4.50.  And as we look out at 2012, 2013, we've been putting hedges out there as well.  

So the idea is to make sure that we've got the cash flow to do what we want to do, more than it is just try to live outside of cash flow or try to hit a certain number on number of rigs, well count, or production, whatever that is.

Brian Singer:  Got it.  Thanks.  And then secondly, can you just talk to people needs and where you stand as you ramp up?  And maybe also touch on whether you're planning a significant allocation of human resources to some of your New Ventures.

Steve Mueller:  Well, I think from a total company-wide need, we're in good shape.  We geared up really a couple years ago to run even more wells than we have now.  It was really for more rigs, and we've got less rigs running, so that helps a little bit on the people side.  But we've got an on-going hiring campaign.  We've got, I think 40 summer interns coming in and we've got something like 20 new hires coming in here over the next few weeks.  So we continue that program as well.

So I think we're okay on the people side.  When we start thinking about New Ventures, we're in the beginning of this cycle where we're going to drill a couple of these a year.  If you just assume that it takes seven, eight, nine wells to prove up a large acreage block, then starting in 2012, you're going to see us drill several wells on New Venture projects.  So it'll be a couple this year, but it could be 10-plus next year.  And that'll be kind of the running rate, between 10 and 20, for the next four or five years.  

So we will have to allocate and are allocating some of our manpower to that.  And they're already working that direction and we've already got some people assigned to that.  So I don't think there'll be any issues that direction.

Now, obviously if we find something and it is significant, then you're on a whole new game.  And we're -- we've already talked about that.  We have the skill sets and we've got enough men strength that we can pull out key people to move into a project if it's a brand new significant project, and filling behind, for the most part, with less experienced people.

Gil Yang:  Good morning.  For the New Ventures, the 620,000 acre project that you're looking at, can you give us an idea, Steve, of what the sort of sequence of events is going to be, in a sense of are you going to need to run like in the -- New Brunswick, are you going to run geochem in 2D seismic?  Or do you know more about these new areas that you can almost sort of immediately start drilling?

Steve Mueller:  Yes.  New Brunswick is, I would say, the far-end member of anything we do exploratory.  There, we think we found a new basin, and so you had to start with, did you find a new basin, and we confirm that.  Then you had to decide whether you had a hydrocarbon generation system.  We've done geochem and figured out that.  And now we're doing seismic to figure out the general regional geology so we can start locating wells.  So that's a two or three year process when you're on that end member.  

The other projects we're working, almost every one of them have enough seismic, have enough data in them, that once we get the acreage together, we will be able to drill wells soon after getting the acreage together.  In a couple of instances, we may want to shoot one or two seismic lines before we drill the well, but none of them have the lead time issues that we'd have in the New Brunswick area.  

Gil Yang:  Okay.  Great.  Regard to the downspacing, can you remind me, is your expectation that the tighter spacing, areas where you can have the tighter spacing, are those the areas where you have better or poorer wells to begin with?

Steve Mueller:  It's a combination.  We have -- I don't want to say the better -- we have good wells in that area.  The downspacing, they're kind of in the center part of the field.  It's not on the outside peripheral.  So it's in the, what I'd call the heart of the field.  But it, for the most part's also in some of the very thicker parts of the rock as well.  So it is a combination of thickness of rock, gas in place, and also the characteristics of the rock which are kind of in that central part of our play.

Gil Yang:  Okay.  So are -- do you think the expectation is that in the thicker regions, that the downspacing would be to do wells that are adjacent to each other but at somewhat different depths so that you more fully penetrate the thickness?

Steve Mueller:  There could be one area in the field that that could happen.  We've got, in the thickest parts of fields, the Upper and Lower Fayetteville are separated by lime.  And we're right now doing testing to figure out how well we're draining.  We land our wells normally in the Lower Fayetteville, how well we're draining the Upper.  And we've actually done a couple of Upper Fayetteville spacing tests where we did land two low and one high.  And in one case we saw no communication, in another case, we saw communication.  So we're working on that right now.  

But you may, in the future, see us drill some Upper Fayetteville wells that would be different than the Lower.  And when I talk about spacing here, we're basically talking landing the Lower and hoping that it would connect most of the rock.  

The other thing I'll just mention to everyone, we've talked about the Moorefield in the past.  We have drilled a couple Moorefield wells at the end of last year.  One of those is on production and is giving some encouragement.  And so you may see us talk more about the Moorefield, which is down just below the Fayetteville on the eastern side of the field.  So you may have a program there that would be different and in addition to all the things we're talking about spacing here.

Rehan Rashid:  Morning, Steve.  Quick couple of questions.  One, on the cost structure side, what kinds of inflation are you witnessing in the Fayetteville and what's the outlook, number one.  And maybe another one for Greg, feels like the balance sheet is underlevered even before the Midstream monetization, call it, some thoughts on that front.  And I might have one more follow-up.  

Steve Mueller:  Okay.  Well, as far as the cost and cost pressures, in the Fayetteville Shale, we've reminded everyone we're vertically integrated in several of the things we're doing.  So the biggest two areas that we have to worry about is the casing and tubulars, and then also the pumping services.  

Pumping services we have contracts with all the vendors, and we're doing that through basically the first quarter, not quite -- it goes through February of next year.  And so we already know what those costs are - those are built in.  And you're seeing the reflection of that in the first quarter.  

On the tubular casing side, we have seen about a 6% increase in costs over the last four or five months.  And that mainly has to do with basically some of the Japanese steel being taken out of the world market and causing the whole world market to go up.  And I don't know what to predict there, just to say that we've got a little bit of cost, upward pressure on the steel side of it.  Go ahead, Greg.

Greg Kerley:  On the balance sheet side, we were about 28% debt to cap.  There's a lot of things, obviously, that could affect our program going forward, especially in the second half of the year, again, as we continue to see positive results in the Marcellus, and the speed of drilling in the Fayetteville.  When you combine that with New Ventures, if we have early results, positive results in the -- in New Ventures, that could cause us to want to run at that a lot harder.

So there's a lot of unknowns and there's -- that also kind of coincides with the timeline of deciding what we want to do with the Midstream, what is the best answer for the company on a path forward there.  So that's why really a lot of that stuff will kind of fall into place in the second half of this year.  And we are cognizant of trying to maintain a very strong balance sheet, but also that we're appropriately leveraged.

Steve Mueller:  Yes.  And let me reinforce Greg's comment.  We don't have any clue what gas price is going to be in the future.  And so we are going to manage with a conservative balance sheet.  That will be the case.

And then the other part of it is, the reason we're looking at Midstream is we want to make sure that we get maximum value on every one of our assets for our shareholders.  And we're just looking at Midstream to figure out how and when that maximum value is going to be there.  So if it's now, we'll do something now, and if it's later, we'll do something later.  And so really there, we'll take in account all the tax modifications for shareholders and us as well on Midstream, and we'll just figure out what the maximum value is.  And if it's not now, then we won't do anything now.

Rehan Rashid:  Two more quick questions.  What portion of the guidance increase was because of new wells, incremental wells, and how much better base production?  And then second, on the Canadian, the first set of geochem work, any incremental thoughts there?  What did it tell you, so that you're progressing on the second set now?  Thank you.

Steve Mueller:  Yes.  Let me start with the New Brunswick geochem.  In that geochem, we were surprised pleasantly in that all of the survey areas that we did showed both oil and gas generation signatures.  And what we want to do now is kind of in-fill and pick specific areas and make sure that, first off, the first batch geochem showed us the right data, and actually do some more detail work to kind of get a general feel for that.

When you start talking about the increase in production, there's really, in my mind, a couple things that's happened in the first quarter on a production increase.  We did put some more wells on production.  We actually drilled seven more wells than we had planned because of the drilling days.  We had about, I would say it's over 10 - 10, 12 wells that really would have, on our original schedule, would have been later in actually the second quarter.  

Part of the reason for that scheduling, for it being second quarter and then actually getting it done the first quarter was, if you remember last year, we had a bunch of weather and we had some issues with the weather last year.  This year we had almost the exact same number of days of the same difficult weather.  But the guys in the field just did a great job and worked right through it.  And so we had almost no weather downtime in the first quarter, and that allowed us to get some of the planned work done that was really, we were thinking was going to be in second quarter, done in the first quarter.  

And so right now we're completely caught up on completions and drilling and everything where we were expecting that we'd have, like I say, a 10, maybe even 15 well lag because of weather.  So a lot of it is weather related, but it is pulling those wells forward and when we did it.

Amir Arif:  Good morning, guys.  First question is still on the Marcellus.  In terms of your other production guidance outside of Fayetteville, it's about 56 to 58 Bcf.  Can you let us know how much of that is related to Marcellus?  And also just your thought plan of how fast you want to ramp up Marcellus, is it more just waiting on more production history or are you waiting on the rigs?  Or just some color on how you're thinking about ramping it up.

Steve Mueller:  I think as you think about us going through the rest of the year, we're drilling these wells on pads.  There will probably be two more pads that get completed between now and the end of the year, and then a third one right at the very end of the year.  So you're going to see two, three wells two more times very similar I think to what you're seeing here, between now and the end of the year.  So you'll see a ramp up.  

But the second rig that's coming in is actually coming in to what we call our Range area on the far eastern area, and it's -- the production from those wells won't be until 2012.  So I think what you're going to see is a little bit of hockey stick when you get in 2012.

Amir Arif:  Okay.  So of the 45 wells you're going to drill there, how many of those are expected to come online this year?

Steve Mueller:  And I don't have that exact number in front of me.  If I had to guess, we're at 14 now, 25, 26 something like that.

Amir Arif:  Twenty-Five or twenty-six, okay.  And then just second question, on the Midstream side.  Even though your throughput was up, your operating income was down.  Can you just give us some color in terms of the cost side?  Was it more one-time or is it some additional costs that are creeping into that side of the business?

Steve Mueller:  Well, you know our G&A was down on an Mcf basis.  Our LOE was up slightly over last quarter, but was right in the middle of our range of guidance.  And on our LOE side, we had a little bit more saltwater disposal fees and we had a little bit more compression fees.  But other than that, I think our costs are pretty much as we expected.

Greg Kerley:  And the Midstream actually had a very nice bump up.

Steve Mueller:  Right.  

Amir Arif:  Midstream operating income?  I mean relative to Q4 is what I was looking at, the throughput number were up but the operating income was down.

Steve Mueller:  Yes, the ratio.

Greg Kerley:  Yes, the operating income in the fourth quarter also included some marketing margin that kind of was somewhat of an apparition.

Amir Arif:  I see.

Greg Kerley:  Not necessarily recurring.  

Amir Arif:  Okay.  But in general, Greg, if I'm thinking about the Midstream operating income, if throughput grows 15%, operating income should grow roughly inline with the same gross revenues?

Greg Kerley:  Yes, it should, Amir.

David Heikkinen:  Morning, Steve.  Looking at your Marcellus position and thinking about your acreage position and your early well results, they seem pretty similar to other operators in the area.  Their constraint really has been more gathering and compression, build-out plans initially, and then pipeline capacity build-out plans beyond that.  Can you walk us through for each of the two development areas where you're going to be running rigs?  What's your first gathering compression capacity is this year and next year?  And then the same question on pipeline capacity.

Steve Mueller:  Well, there really -- you can either call it three areas or four areas.  We've got the area we're drilling right now at Greenzweig, which is right on top of a pipeline that goes north-south and ties Millennium and Tennessee Gas.  And as we mentioned in the -- our press release, we have purchased firm capacity in both Millennium and Tennessee, as well as we're doing some spot capacity.  

And the firm, the first of the firm that comes on is later this year, November of this year, and then it builds over the next couple of years, well over 200 million a day.  That DTE pipeline we talked about is a north-south line that will run across throughout farther eastern acreage.  And that pipeline will have a capacity above 300 million a day.  We've committed to about 280 million at peak on that, but it'll be significantly more that we could handle.  And part of the firm that we purchased on the Millennium and Tennessee Gas matches with when that pipeline will be in early 2012.  

We could have a couple bumps in the road if we go -- these wells continue to be as strong as they are right now.  Towards the end of the year we could have a little bit of issues where we may not be able to buy something off just a spot, and we have a little bit of issues.  But I think that between now and the end of 2012, going on 2013, when we go from basically having 90 million day to day to well over 200 million, going on 300 million, available to us at the end of next year, into 2013.

So that's kind of the game plan.  We've been fortunate both Millennium and Tennessee Gas just went through a new RFP process to get in new customers and we've been able to buy that firm.  So I think we're okay, at least over the next couple years.  Obviously if the wells keep being as strong as they are we have to talk in the next six months about what we're going to do beyond 2012.  But I think we're okay from here to there.

David Heikkinen:  And then, Steve, just thinking on a PVI basis, can you give us some thoughts around kind of initial results look like they're tracking 6 Bcf, 8 Bcf at these well costs in the Marcellus -- how does that compare to the Fayetteville, just on a PVI?

Steve Mueller:  The Fayetteville -- and remind everyone that we use this present value index and we look for 1.3 present value index, which is nothing more than giving our investors $1.30 discount of 10% for every dollar we invest.  To get to that number -- and the Fayetteville Shale's right at $4.00 today.  And as we drill the wells faster and the wells get a little cheaper, that works down a couple pennies.

What we thought was going to be the case in the Marcellus even three months ago we were talking about Marcellus then being in the $3.80's.  Now we're talking in the low $3.00's and maybe have a $2-handle on it for economics for 1.3 PVI, depending on whether it's a 5 to 6 Bcf well or if it's a 8-plus Bcf well.

David Heikkinen:  So thinking about kind of return on capital employed and kind of overall finding costs, as you ramp the Marcellus -- and it isn't the same scale as the Fayetteville, but should actually see direction go well in '12 and then into '13?

Steve Mueller:  Yes.  We're going to get to it as fast as we can get to it.  And one of the things I didn't mention before when we were talking about the pipeline takeaway, we do have that one block of acreage that's in Lycoming County.  We will drill a couple wells on that this year with that -- was actually a third rig that will come in just to drill a few wells.  And we'll start working on the takeaway on that as well.  But what you'll see us do, as we look at -- into 2012 and beyond, you'll see us working in basically three general areas, that Greenzweig area, the eastern part Susquehanna County and then Lycoming County.  And that will build up to 5-plus rigs in the not too distant future and go that direction with it.

So that's kind of our general game plan.  We're getting all the infrastructure in place to do that and we're really excited about the fact that the wells are coming in much better than we expected.

David Heikkinen:  Thanks.  I don't say great quarter very often, but that was a good turnout.  So thanks a lot.

Dan McSpirit:  Have your discussions advanced at all with utilities or a utility with respect to a long-term contract on supply?  And if so, any additional color on what those terms might look like?

Steve Mueller:  I'm not sure I could say they've advanced.  We've talked to almost every major utility in the country.  We have contracts, or beginnings of contracts, on our desk from almost every major utility in the country.  And the big -- I think we know most of the terms and kind of the form of the contracts.  But the big issue is, is gas price going to go up or down in the near future and when would they sign a contract and what that price would be.  And in general, it's kind of like the M&A market.  The only time the M&A work is when everyone agrees on the direction of the price.  Right now, in general, we don't quite agree on a direction on which way gas price is going.

So I don't know.  If you would have asked me in December I would have guessed that both our company and the industry would have had some contracts signed by now.  I'm kind of wondering; it may be Fall when we start seeing the storage a little more obvious that you start seeing contracts being signed.  

We do have contracts, which is a lot different than it was this time last year.  We've done a lot of discussions, both our company and the industry.  And we're comfortable that the power generators are going to be using more gas and are right now using more gas.  It's just when and how would any long-term contract be signed.

Dan McSpirit:  Okay.  And you say you're not in agreement with the direction of the price of the commodity.  What's your view?

Steve Mueller:  Well, from a contract negotiation standpoint it's -- this thing's going up fast.  You know?  But as I've said before, what we're working on and what we're planning on is staying conservative.  We don't know what's going to happen.  Certainly rig count hasn't come off as much as we'd like, so we have some concerns about the near term.  But I think we have the same kind of positive outlook that the forward curve does, when you start looking out to '13, '14 where it's popped up.  And so that's the discussions we're having with them.  They would like to go back to the forward curve a month and a half ago, and we like the forward curve now.

Dan McSpirit:  Okay, got it.  And as a follow-up, Steve, you spoke about the process of negotiating and leasing acreage under New Ventures.  Can you comment at all on maybe the total amount of leasehold?  Or is there a goal involved here? And when do you conclude the leasing process itself, or when does it begin to slow?

Steve Mueller:  Each of our project areas have specific acreage goals.  And they also have with them what I'll call control goals where there's -- you pick up the acreage, but there's a certain amount of the acreage you want to make sure that you have at least 50% out of whatever that state or region's areas are so you can control what your future is.  And so, we've got those two sets of goals for each one.  I won't go into details about what those are, because we'll -- without going into details about the individual projects.  But keep in mind what we're trying to do is replace Fayetteville Shale with two or three of these.  So they are, for the most part large acreage blocks that we're looking at.  And the only reason they wouldn't be a couple hundred thousand acres is if they were way thick and it was 2 for 1, for instance, compared to Fayetteville Shale just because of the hydrocarbon in place, whatever that was.

So when we hit whatever those goals are, both the control goal and the total acreage goal, then we're ready to go and we'll head out and do that.  And the only thing that would sidestep that at all is if there was a large amount of industry participation and they drove prices up above where we wanted to invest for the acreage that was there and we just couldn't get any more.  And then we'd talk about it at that point in time.  But for right now, we don't have that situation.  So it's really just the acreage goal and the amount we want to control.

Hsulin Peng:  My questions are regulatory-related.  The first question is, in Pennsylvania there's a proposed well fee now and I was wondering if you have taken a look at it to see how it would affect your economics on your Pennsylvania wells?  

And the second question is also regulatory.  So with the new CFTC proposals, how, if any, do they affect your hedging strategy?  And will there be a collateral posting requirement?

Steve Mueller:  I'm missing your first question.  Which Pennsylvania rule or Pennsylvania issue were you worrying about?

Hsulin Peng:  Well, I think yesterday Pennsylvania came out with the $10,000 --

Steve Mueller:  Yes.  Well, let me just start with the hedging part of it.  We're still trying to figure out exactly what the SEC's going to do.  It looks as if we're not going to have to post.  But if it comes up that we have to post, I think that's going to significantly change our hedging philosophy and probably the whole industry.  It just doesn't make sense for us to basically have to post on a regular basis.  And then it comes in, will there be some kind of hybrid where we personally wouldn't, as a company, have to post, but someone else could post for us.  And that makes the hedging more expensive and then we just have to look at the prices of hedging at that time.  So we're just watching like everyone else.  And I don't even have a guess.  I read the same things everyone else does and the SEC's going back and forth.

As far as the well fee in Pennsylvania, I think what they're proposing is about a $10,000 fee per well.  I don't know about the amount.  Certainly the other part of it is that they want the fee to go in the areas where the industry's working on the roads and doing the things that's there.  We're all for that.  To the extent that the industry is damaging roads or if there's infrastructure that has to be built because of what we're doing, we ought to pay our fair share on that.  And so, as a company, we have no problems with that portion of it at all.  And the exact $10,000 or whatever that kind of fee is, I haven't looked at it close enough.  It won't affect our operations, I don't think, in anything that we're doing if it ended up that direction.

But the key to it -- ours is -- don't just collect a fee or collect a tax and distribute it someplace else and then not help the area that's really being most affected by whatever that is, so.

Steve Mueller:  Thank you.  You know, when you think about our quarter, as I said before, we had a great quarter.  Our guys did a great job in the field working through a lot of different things.  And even just recently, in the last couple days, we've had some tornadoes come through Arkansas.  We've had 14 of our families houses destroyed or parts of their property destroyed.  And we're working right through that.  And I'm proud of what they're doing in the field and I'm proud of what our groups have been doing overall.

And then you look at the Fayetteville Shale in particular, thinking you're going to drill 9 days, and then being in the mid-8's right now.  That's a great job that those guys have done.  And that helps us set up the future.  One of the key things, like I said, we have to figure out is how fast can we drill so we can figure out how many rigs we really need.

Marcellus, again, pleasant surprises there.  New Ventures we're right on track.  And then we put in the new slide in both the press release and you'll see in our presentation about Marcellus.  We're dedicated to keeping transparent in what we do.  And so as we get the information in, we'll get that out to you, whether it's New Ventures or Marcellus or Fayetteville, or whatever that is.  

And with that, I thank you for being part of our conference call.  Thank you.

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 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, 2011 and March 31, 2010.  Non-GAAP financial measures should not be considered in isolation or as a substitute for the Company's reported results prepared in accordance with GAAP.