西南能源 (SWN) 2011 Q1 法說會逐字稿

Greetings and welcome to the Southwestern Energy first quarter earnings conference call. At this time, all participants are in a (inaudible). A brief question and answer session will follow the formal presentation. (Operator Instructions) As a reminder, this conference is being recorded.

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

Thank you and good morning. With me today are Greg Kerley, our CFO, and Brad Sylvester, VP of Investor Relations. If you have not received a copy of yesterday's press release regarding our first quarter 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 in the Forward-Looking Statements sections of our Annual and Quarterly filings for the Security 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 continue to deliver top-tier results and I am equally enthusiastic about the rest of 2011. We continue 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 a 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 7.0 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 our operating areas. We placed 137 operated wells on production in Fayetteville Shale during the first quarter which resulted in gross operated production reaching 1.7 Bcf a day at March 31, 2011. Our operator 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 primary due to location differences and the mix of wells and increased line pressures.

In March we placed several wells on production in our more than most northern area of the field, which encountered higher line pressures in the rest of the field. This had an effect of lowering the initial production rate for those wells. We continue to test tighter well spacing, and at March 31, 2010, we 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-acres to 50-acres spacing, and approximately 70% can be developed at a maximum of 65-acres 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 [trists] are being drilled by other operators in the field.

In northeast Pennsylvania, we have approximately 173,000 net acres prospective for the Marcellus Shale. We are very encouraged by what we've seen to date. At March 31, 2010 we had completed 14 operated Marcellus Shale wells on five pads located in the our Greenswick 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 Greenswick area, our practice is to place several wells on 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 2010 are currently producing an average rate of 4.3 million cubic foot per well, and three wells placed on production in February 2011 are currently producing an average rate of 5.8 million cubic feet per day per well. On April 18, 2011 we placed three additional horizontal wells on production at a gross rate of 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 productions tubing. All of our wells are currently producing without the benefit of compression into line pressures of approximately 1100 (sic - see Press Release) pounds, and gross operated production from the area is currently 60 million cubic foot per day.

In March 2011, we went 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. Final terms of the gathering agreement are currently being negotiated, however first volumes to be delivered to the interstate pipeline could be as early as the second quarter 2012. Also -- 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, the New Brunswick, the acquisition of approximately 410 miles of 2D data is scheduled to begin in May 2011 and will continued through the third quarter. We also plan to do another phase of geo-chem acquisition that is planned to start in the third quarter. At the beginning of the year, we reported approximately 490,000 net increase in our new venture plays that were not part of New Brunswick. As of April 15, 2011, we have more than 620,000 net acres leased, and are still on scheduled for the 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 sales agreement for the sale of certain oil and gas -- oil and natural gas leases, wells, and gathering equipment in Shelby, Saint Augustine, and Sabine counties in East Texas for approximately $85 million. The effective date of the sale is January 1, 2011 and a standard closing adjustment will be include, it will include natural gas sales proceeds and capital invested in 2011 prior to the closing. The sale includes only producing rates from the Haynesville and middle Bossier shale intervals, approximately 900 -- 9,700 net acres. The net production from the Haynesville and middle Bossier shale intervals at this -- in this acreage was approximately 7 million cubic foot per day as of April 15, 2011, 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 are excited about our development of Fayetteville shale, we're increasing our activity in Pennsylvania, and have on tap drilling our first new ventures wells over the next few years. I will not turn it over to Greg Kerley, our Chief Financial Officer, who will discuss the financial results.

Good morning. As Steve noted, our financial and operating results for the quarter were stronger than we expected and continue to highlight our industry leading low-cost structure. We reported earnings for the first quarter of $137 million, or $0.39 per share compared to earnings in the first of 2010 of $172 million, or $0.49 per 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 national gas prices. Our average realized gas price of $4.12 per Mcf was down more than $1 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 notional volumes of 171 Bcf of our remaining 2011 gas production at a weighted average forward 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 $178.3 million during the quarter down from $250 million in the same period last year. Are all-in cash operating cost, 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 average amortization rate was primarily the 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 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 increased in gathering revenues from our Fayetteville and Marcellus Shale plays, partially offset by increased operating costs and expenses. At March 31, 2011, 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, 2011, we have $531 million borrowed on a $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 ration of only 8%.

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

Thank you. (Operator Instructions) Our first question comes from Scott Hanold with RBC Capital Markets. Please proceed with your question.

Good morning.

Good morning.

In the Marcellus, obviously those are pretty strong well results, and given that, are you all thinking about potentially stepping up activity a little bit, and is there ability to do so? Or is it more of an infrastructure-related constraint?

We will step up to summer activity as we noted I think last conference call. We have one rig running right now. That rig count will go up here in a few months, to two rigs. We will exit the year with two. And then 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 will start seeing more rigs go out in the field, especially on that eastern acreage. But right now, we can run one to two rigs through the rest of the year, and we have take-away for that.

Okay. So you are playing it to the capacity. Okay. And then, on the new ventures play, it sounds like you guys increased your position fairly meaningfully during the last update. Can you give a little bit of color in terms of, do you think there's more acreage to be picked up? And is this all in one specific area or a couple of areas? And when do you feel comfortable about giving us some further details here?

As far as the acreage goes, [we'll] report, whether it is on a Q or a 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 have done the title work on, you've confirmed that they actually have the mineral rights, and you paid the check. There's obviously some acreage out there that we've signed deals with people on, that we're right now 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 is acreage you want to get.

And 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 we're working title on that, so you're going to see numbers go up, and we also have more acreage that we want to get. And the whole concept was, is we thought it would take at least through the first half of the year to get the acreage that we wanted on the first project, so we are going to drill and then we can 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 will 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 are 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 roll out. And we are in different stages in picking up acreage because of that. In some cases, we are just starting to pick up acreage, in other cases like the ones we'll drill later this year, we are getting closer to being done with the acreage from that perspective. So that's kind of the game plan as it goes out.

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

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

Well, from a looking forward, since we are looking out four to five years in advance, we haven't put a bias on anyone as far as looking forward, saying look just for gas, or look for just 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 you can't accelerate the oil, and the gas plays come up first, but if I had to guess right now, those first wells will be on an oil play.

Okay. I appreciate the color. Thank you.

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

Hello, 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?

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 is one of the reasons why it is a January 1, 2011, date, and we will be reimbursed for that capital that we invested there. So there's going to be, when you look at -- later see some report from us, you'll see that we have some capital invested in East Texas, and then we will have income on the other side, we're reimbursed for that. But as we look forward to the rest of the year in East Texas, we will have very little capital being spent in East Texas, which is what we really started the year with it. From a net-net effect, we would only have a couple of wells in the James lines that we'd have real true capital for and 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, of that $100 million, close to $80 million of that is just the fact that we have drilled faster in the Fayetteville Shale. We started the year, and if you ever want to put it kind of in perspective, last year we averaged just over 10 days per well, between 10 days 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 really our last call in February, we adjusted that down to just a little less than eight days, and now we are thinking we are in the mid-eights to low-eights for what's going to happen for the rest of the year in the total number of days to drill a well. And what that's done is created the ability to drill more wells, same number of rigs running.

And when you think about what we are trying to 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 on 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 that direction. And what is happening is we are learning we can drill faster than we thought. So really the capital budget almost entirely is increased because we are learning we can do it faster.

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

I don't know exactly the answer to that yet. But again, to put it in perspective, two years ago we drilled about 500 wells and it took 15 rigs. Last year, we did just under 13 rig average and drilled about 550 wells. And this year, it looks like we are going to drill about 500 wells with 11 rigs. So, I don't know exactly what we will end up the year with on a -- 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, 10 the right number. And so, that is something later in the year to figure out.

Okay. And then moving on to 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 monetization timing, given that you are going to have a production ramp here in this year and next?

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

Okay, great. Thanks, guys.

Our next question comes from Nick Pope with Dahlman Rose. Please proceed with your question.

Morning, guys.

Good morning.

Quick question on the spacing. I know you talked a little about it in the past, but whenever you look at the 30-acre 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?

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% is a good average number as you look out in the future.

And the other thing about the spacing, we are making all of 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 of quarters, we can talk more about exactly what the interference we are 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 change on that also.

Okay. Excellent. And with the Marcellus, the 60 million cubic foot per day gross number, what is that on a net basis on the current production?

We are roughly 50 million a day net.

All right. That's my two.

Yes, if you think about our -- right now we're drilling at about 95% working interest. And our net interest to us is about 85%. So 0.95 times 0.85.

Okay. Appreciate it. Thank you.

Your next question from Brian Singer with Goldman Sachs. Please proceed with your question.

Thank you. Good morning.

Good morning.

Based on the improved results and efficiencies you are seeing, and the extent to which you are 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?

I think, we want to stay within shot of cash flow neutral. And I say within shot, if you think about what we are 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 is outside of cash flow is that $180 million in new ventures. And then we are getting some cash flow on the Pennsylvania side, but whatever the net difference on Pennsylvania is. So we are a couple hundred million, between $200 million and $300 million outside cash flow, and we want to continue doing that going forward. So the extent that, 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 have 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 to 2012, 2013, we're putting hedges out there as well. So the idea is to make sure that we have 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.

Okay, 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?

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

When we start thinking about new ventures, we are in the beginning of this cycle where we are going to drill a couple of these a year. If you just assume that it takes seven wells, eight wells, nine wells to prove up a large acreage block, then starting in 2012 you are going to see us drill several wells on new venture projects. So, there will be a couple this year, but it could be 10-plus next year, and then that will be kind of a 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 will be any issues that direction.

Now, obviously if we find something and it is significant, then you are on a whole new game, and 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 fill-in behind, for the most part, with less experienced people.

Great. Thank you.

Our next question comes from Gil Yang with Bank of America, Merrill Lynch. Please proceed with your question.

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 need to run geo-chem and 2D seismic? Or do you know more about these new areas that you can almost, sort of immediately, start drilling?

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 confirmed that. And then you had to decide whether you had a hydrocarbon generation system, and we've done geo-chem and figured that out. And now we are 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 number.

The other projects we are 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 a well, but none of them have the lead-time issues that we'd have in the New Brunswick area.

Okay. Great. In regard to the down spacing, 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?

It is a combination. We have -- I won't say they're better, we have good wells in that area. The down spacing is kind of in the center part of the field, it is not on the outside peripheral, so it's in the, what I call the heart of the field. But it, for the most part, is also on 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.

Okay, do you think the expectation is that the, in the thicker region, that the down spacing would be to do wells that are adjacent to each other, but at somewhat different depths so that you more fully penetrate the thickness?

There could be one area in the field that that could happen. We've got, in the thickest parts of the field, the upper and lower -- or the upper and lower Fayetteville are separated by a line. 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 have actually done a couple of our spacing tests where we did land two low and one high. And in one case, we saw no communication. 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 to most of the rock.

The other thing I would just mention to everyone, we've talked about the Moorefield in the past. We have drilled a couple of Moorefield wells at the end of last year. One of those are on production, and is giving us some encouragement, and so you may see us talk more about the Moorefield, which is down just below the Marcellus -- or I'm sorry, 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 are talking about spacing here.

All right. Thank you very much.

Our next question comes from Rehan Rashid with FBR. Please proceed with your question.

Morning, Steve. Quick couple of questions. One, on the cost structure side. What kind of inflation are you witnessing in the Fayetteville, and what is the outlook, number one. And maybe another one for Greg. Feels like the balance sheet is under-levered even before the midstream monetization, call it. Some thoughts on that front? And I may have one more follow-up.

Well, as far as the cost and cost pressures, in the Fayetteville Shale, we remind everyone we are vertically integrated in several of the things we are doing. So the biggest two areas that we have to worry about is the casing in tubulars, and then also the pumping services. Pumping services we have contracts with all the vendors that we are doing that through basically 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 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 they 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.

On the balance sheet side, we are about 28% debt to cap. There is 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 new ventures, that could cause us to want to run at that a lot harder. So there's a lot of unknowns, and 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 is 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 are appropriately leveraged.

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 are 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 are just looking at midstream to figure out how and when that maximum value is going to be there. So if it is now, we will do something now, and if it is later, we will do something later. And so really there, we'll take into account all the tax ramifications for shareholders and us as well on a 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.

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 geo-chem work, any incremental thoughts there? What did it tell you, so that you are progressing on a second set now? Thank you.

Let me start with the New Brunswick geo-chem. In that geo-chem, 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 pass at geo-chem 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 of 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 the days, we had about, I would say, it's over 10 -- 10, 12 wells that really, on our original schedule, would have been later and actually be second quarter.

Part of the reason for that scheduling for it being second quarter and then actually getting it done in 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 it was going to be in second quarter, done in the first quarter.

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

Thank you.

(Operator Instructions) Our next question comes from Amir Arif with Stifel Nicolas. Please proceed with your question.

Good morning, guys. First question is just on the Marcellus. In terms of your other production guidance outside of Fayetteville, it's about 56 to 58 Bs. Can you let us know how much of that is related to Marcellus? And also just your thought plans 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? Just some color on how you're thinking about ramping it up.

I think, as you think about us going through the rest of the year, we are 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 to 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 will see a ramp up, but the second rig that is coming in is actually coming into what we call a range area in the far eastern area. And the production from those wells won't be until 2012. So I think what you're going to see is a little bit of a hockey stick when we get in 2012.

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

I don't have that exact number in front of me. If I had to guess, 20 -- we're at 14 wells now, 25 wells, 26 wells, something like that.

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 some color on 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?

Our G&A was down on a prime CF basis. Our LOE was up slightly over last quarter, but was right in the middle of our range of guidance. And on our LOE said, we had a little bit more salt water disposal fees, and had a little bit more compression fees. But other than that, I think our costs are pretty much as we expected.

And the midstream, actually, had a very nice bump up.

Right.

Of the midstream operating income? I mean relative to Q4, is what I was looking at. The throughput numbers were up, but the operating income was down -- .

Yes, that ratio -- .

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

I see.

Not necessarily recurring.

Okay, but in general, Greg, if I am thinking about the midstream operating income, if throughput grows 15%, the operating income should grow roughly in line with the same gross?

Yes, it should, Amir.

Okay, sounds good. Thanks, guys.

Our next question comes from David Heikkinen with Tudor, Pickering, Holt. Please proceed with your question.

Good 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 are going to be running rigs, what your first gathering compression capacity is this year and next year? And then the same question on pipeline capacity?

Well, you can either call it three areas or four areas. We've got the area we are drilling right now in [Greenswig], which is right on top of a pipeline that goes north-south, and ties Millennium and Tennessee Gas. And as we mentioned in our press release, we have purchased firm capacity on both Millennium and Tennessee, as well as we're doing some spot capacity. 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 through our 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 will be significantly more that we could handle, and part of the firm that we purchased on Millennium and Tennessee Gas matches with when that pipeline will be in early 2012.

So we could have a couple bumps on the road if we go -- if 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, that we may not be able to buy something off just a spot, and we have a little bit of issues. But I think between now and the end of 2012 going to 2013, we go from basically having 90 million a 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 have been fortunate, both Millennium and Tennessee Gas just went through a new RFP process to get in new customers, and we have been able to buy that firm. So I think we are 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.

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

Yes, the Fayetteville is -- 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 at 10% for every $1 we invest. To get to that number in the Fayetteville Shale is right at $4 today. And as we drill the wells faster, and 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 $3.80s, now we are talking in the low $3 and maybe have a two handle on it for economics for a 1.3 PVI. Depending on whether it's at 5 Bcf to 6 Bcf well, or if it's a 8-plus Bcf well.

But 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 2012 and then into 2013.

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 take-away, we do have that one block of acreage that's in Lycoming County. We will drill a couple of wells on that this year with actually a third rig that will come in just to drill a few wells. And we will start working on a take-away on that as well. But what you will see us do as we look out into 2012 and beyond, you will see us working in basically three general areas, that Greenswig area, the eastern part, Susquehanna County, and the Lycoming County, and that will build up to five-plus rigs in the not-too-distant future, and go that direction with it. So that is kind of our general game plan. We are getting all of the infrastructure in place to do that, and we are really excited about the fact that the wells are coming up much better than we expected.

And thanks. I don't say great quarter very often, but that was a good turn-around. So thanks a lot.

Thank you.

Our next question comes from Dan McSpirit with BMO Capital Markets. Please proceed with your question.

Gentlemen, good morning. 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?

I am 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 desks 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 M&A works is when everyone agrees on the direction of the price. Right now, in general, we don't quite agree on general direction of 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 am kind of wondering, it may be the fall when we start seeing the storage a little more obvious, that you start seeing contracts being signed. But we do have contracts, which is a lot different than it was this time last year. We have done a lot of discussions, both our Company and the industry. And we are comfortable that the power generators are going to be using more gas, right now using more gas, but just when and how will any long-term contract be signed.

Okay. You say you are not in agreement with the direction of the price of the commodity. What is your view?

Well, from a contract negotiation standpoint, this thing is going up, going up fast. (Laughter) As I said before, what we are working on, and what we're planning on is staying conservative. We don't know what is 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. And when you start looking out to 2013, 2014, where it has popped up. And so that is the discussions we are having with them. They would like go to back to the forward curve a month and a half ago, and we like the forward curve now.

(Laughter) Okay. 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 lease hold, or is there a goal involved here? And when do you conclude the leasing process itself, or when does it begin to slow?

Each of our project areas have specific acreage goals, and they also have with them what I will call control goals, where there is a -- you pick up the acreage, but there's a certain amount of acreage you want to make sure that you have at least 50% of, or whatever that state or region's areas are, so you can control what your future is. And so we have those two sets of goals for each one. I won't go into details what those are because without going into details about the individual projects, but keep in mind what we are 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 are looking at.

And the only reason they would not be a couple hundred thousand acres is if they were way thick and it was two-for-one, 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 are ready to go. And we will head out and do that.

And the only thing that would sidestep that at all is if there's a large amount of industry participation, they drove prices up above what we wanted to invest for the acreage that was there, and we just couldn't get anymore, and then we'd talk about it at that point in time. But right now we don't have that situation. So it's really just the acreage goal and the amount we want to control.

Very good. Thank you.

Our next question comes from Hsulin Peng with Robert Baird. Please proceed with your question.

Good morning, everyone. My questions are regulatory related. The first question is, (inaudible) there is 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 CS, with the new CSTC proposed rules, how is any delay affect your hedging strategy? And will there be a collateral posting requirement?

I missed the first question. Which Pennsylvania rule, or Pennsylvania issue were you worried about?

I think yesterday, Pennsylvania came out with the SEC 10,000 -- .

Oh, yes. Well, let me just start with the hedging part of it.

Okay.

We're still trying to figure out exactly what the SEC's going to do. It looks as if we are 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 as a Company wouldn't 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 the hedging at that time. So we're just watching like everyone else. And I don't even have a guess. I read the same thing everyone else does, and it keeps 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 they want the fee to go in the areas where the industry's working on the roads and doing the things that is there. We are all for that to the extent that the industry is damaging roads or if there is 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.

The exact $10,000 or whatever that kind of fee is, I have not looked at it close enough. It won't affect our operations, I don't think, and anything that we're doing if it ended up that direction. But the key to ours is, don't just collect a fee or collect a tax, and distribute it someplace else, and then not help the area that is really being most affected by whatever that is, so.

Great. Thank you very much.

At this time I would like to turn the call over to management for closing comments. Thank you.

Thank you. 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 of 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 am proud of what they are doing in the field. 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 nine days, having all these (inaudible) that says nine days and then being in the mid-eights right now, that is a great job those guys have done, and that helps us set up the future. One of the key things, like I said, that we have to figure out is how fast we can drill so we can figure out how many rigs we really need.

Marcellus, again, pleasant surprises there. New ventures are 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 are dedicated to keeping transparent in what we do, and so as we get the information in, we will get that out to you, whether it is new ventures, or Marcellus, or Fayetteville, or whatever that is.

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

This concludes today's teleconference. You may disconnect your lines at this time, and thank you for your participation.