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Southwestern Energy (NYSE:SWN)

Q1 2011 Earnings Call

April 29, 2011 10:00 am ET

Executives

Steven Mueller - Chief Executive Officer, President and Director

Greg Kerley - Chief Financial Officer, Executive Vice President and Director

Analysts

Brian Singer - Goldman Sachs Group Inc.

Scott Hanold - RBC Capital Markets, LLC

Dan McSpirit - BMO Capital Markets U.S.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Hsulin Peng - Robert W. Baird & Co. Incorporated

Amir Arif - Stifel, Nicolaus & Co., Inc.

Gil Yang - BofA Merrill Lynch

Scott Wilmoth - Simmons

Rehan Rashid - FBR Capital Markets & Co.

Michael McAllister - Sterne Agee & Leach Inc.

Nicholas Pope - Dahlman Rose & Company, LLC

Operator

Greetings and welcome to the Southwestern Energy First Quarter Earnings Conference Call. [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.

Steven Mueller

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 and the forward-looking statements section of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe these expectations expressed are based on reasonable assumptions, they're 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 am equally enthusiastic about the rest of 2011. We continue to maintain well cost 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 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, I'll talk about each of our operating areas. We placed 137 operated wells on production at Fayetteville Shale during the first quarter, which resulted in gross operating 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 5 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 initial pressure rates for those wells. We continue to test tighter well spacing and at March 31, we have 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 to 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 continued to be refined and additional spacing tests that 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, we have completed the 14 operated Marcellus Shale wells on 5 pads located in our Greenzweig area and Bradford County. Net production in 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 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 at an average rate of 6.3 million cubic foot per day per well; while 3 wells placed on production in November of 2010 are currently producing at an average rate of 4.3 million cubic foot per well; and 3 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 3 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 the 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 operating 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. 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 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 TD 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 is planned to start in the third quarter. At the beginning of the year, we reported approximately 490,000 net acres in our new venture 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 2 wells in the second half of the year. In our other areas, we participated in drilling 2 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 -- 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 -- it will include natural gas sales proceeds and capital invested in 2011 part of the closing.

The sale includes only our producing rates from the Haynesville/Middle Bossier Shale intervals, approximately 997 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 proven 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 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 of $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 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 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 over 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 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 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, doing 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 1/4% 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'll explain the procedure for asking questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC

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?

Steven Mueller

We will step up some of our activity as we noted, I think, last conference call. We've got one rig running right now. That rig count will go up here in a few months to 2 rigs. Well, that's at a year or 2. Then as we look into 2012, as we get more of this capacity in and we mentioned that DTE deal is in early 2012, you'll start seeing more rigs go out in the field, especially in our eastern acreage. But right now, we can run 1 to 2 rigs through the rest of the year and we've got takeaway for that.

Scott Hanold - RBC Capital Markets, LLC

Okay. So you're playing it to your capacity, 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 on it in terms of do you think there's more acreage to be picked up? And is this to all in one specific area or a couple of areas? And when do you feel comfortable about giving us some further details here?

Steven Mueller

As the far as acreage goes we've report already whether it's on -- whether a Q or a K or it's whether it's sort of what I just said today, is the acreage that you've done basically 3 things on. You signed the deal, you've 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 were right and doing title work on and then we'll pay the check unless you have a lease on 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 the individuals who we think they own the mineral rights and was working title on that. So you're going to see the 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're going to drill and then we could go drilling 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 5 years, we'll drill a couple of these a year and have a total of 10 drilled over 5 years. Some years may be one, some years maybe 3 or 4, but in that group of 10 that you drill over 5 years, we're expecting 2 to 3 to be successful and those 2 to 3 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're in different stages in 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 this year, play to this year, we're getting closer to the drilling [ph] 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 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 to drilling those wells.

Scott Hanold - RBC Capital Markets, LLC

But will you comment on sort of 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?

Steven Mueller

Well we, as you said, were -- from a looking forward, since we're looking out 4 to 5 years in advance, we haven't put a bias on anyone as far as looking forward, saying we look just for gas or we 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 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 in oil play.

Scott Hanold - RBC Capital Markets, LLC

Okay, I appreciate the color.

Operator

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

Scott Wilmoth - Simmons

I'm 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?

Greg Kerley

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 that we invested there. So there's going to be, when you look at the later season and reports furnished, you see we got some capital invested in East Texas, and then we'll also have income on the other side that were reimbursed for that.

But as we look forward to the rest of the year in East Texas, we'll have very little capital spending in East Texas, which is what we really started the year with, from a net-net affect, we would only have a couple of wells in the James Lime 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 $8 million of that is just the fact that we drilled faster in the Fayetteville Shale. We started the year, and in general, put into kind of perspective -- last year, we averaged just over 10 days per well, between 10 to 11 days to drill a well. We started the year thinking we're 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're thinking we're in the mid-8s to low 8s for what's going to happen for the rest of the year in total number of days to drill a well. And what that's done is created the ability to drill more wells, same number of ridge running.

And when you think about what we're trying to learn this year, there were 2 big things we're trying to learn -- we want to continue getting the information on the spacing and work that out, so we'd know what to drill when we get to the pad drilling towards the end of the year. The other thing we were 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 of that direction. And what's happening is we're learning we can drill faster than we thought. So really the capital budget, almost entirely, is an increase because we're learning we can do it faster.

Scott Wilmoth - Simmons

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

Steven Mueller

I don't know exactly the answer to that yet. But again, kind of put in perspective, 2 years ago, we drilled about 500 wells and took 15 rigs. Last year, we did just under 13 rig average and drilled about 550 wells. And this year, looks like we drilled about 500 wells on 11 rigs. So I don't know exactly what we'll end up the year with or how many wells we can drill per rig, but once we figure that out, then we can say, is 11 the right number, 12 is the right number, 10, the right number. And so that's something later in the year to figure out.

Scott Wilmoth - Simmons

And then moving on the 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 here in this year and next?

Greg Kerley

Well, Scott, this is Greg. You're right in that we are in the last innings of the audit, a 3-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 for -- from a strategic standpoint and expect that, that decision we've made probably in the last half of this year.

Operator

Our next question comes from Nick Pope with Dahlman Rose.

Nicholas Pope - Dahlman Rose & Company, LLC

A quick question on the spacing, I know you talked a little about 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 spacing?

Steven Mueller

I think a good estimate right now would be around 10%. In the past, we talked about in some areas as close, as low as 6% to 7%, in some areas, it's 12%. But I think that 10% is 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 has 6 months or less production on them on a lot of these ones we did last year.

And so, expect in the next 2 couple of quarters, we can talk more about exactly what the interference we're seeing and maybe -- there maybe some slight revisions on that 30/70. If there have been revisions, it would be to a closer spacing, not a farther spacing. So you may see some couple of percent difference change in that also.

Nicholas Pope - Dahlman Rose & Company, LLC

And then with the Marcellus, the 60 gross number, what is that on a net basis, on the current production?

Steven Mueller

We're up to 50 million a day, net. 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.

Operator

Our next question comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

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?

Steven Mueller

I think we want to stay within a shot of cash flow neutral. And when I say within shot, if you think about what we're doing this year, the Fayetteville Shale, all of our conventional properties, all were within cash flow. And the only places where we're 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 is the net difference on Pennsylvania. So we're couple of hundred million, $200 million and $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 give is well over $4.50. And as we look out 2012, 2013, we will put the 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 to try to live outside of cash flow or try to hit a certain number of rigs or well count or production, whatever that is.

Brian Singer - Goldman Sachs Group Inc.

Got it, thanks. And then secondly, can you talk to people needs and where you stand as you ramp up? And then maybe also touch on whether you're planning asking allocation at human resources to some of your New Ventures?

Steven Mueller

I think from a total company wide-need, we're in good shape. We geared up really a couple of years ago to run even more wells than we have now. It's really more rigs and we've got less rigs running. So that helps a little bit on the people side, but we've got an ongoing hiring campaign. We got -- I think it's 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 7, 8, 9 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 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 4 or 5 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 in that direction. Now obviously, if we find something and it is significant, then you're on a whole new game and we've already talked about that. We have the skill sets and we've got enough man strength to pull out key people to move into a project -- if it's a brand-new project and selling behind for the most part with less experienced people.

Operator

Our next question comes from Gil Yang with Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch

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 area, are you going to need to run geochem and 3D seismic or do you know more about these new areas that you can almost immediately start drilling?

Steven Mueller

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. Then you have to decide whether you had a hydrocarbon generation system. We've done geochem to figure out that and now we're doing seismic to figure out the general regional geologies so we started locating wells. So that's a 2 or 3 year process we -- on that end member. The other projects we're working, almost everyone 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 an acreage together. In a couple of instances, we may want to shoot one or 2 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.

Gil Yang - BofA Merrill Lynch

And with regards 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?

Steven Mueller

It's a combination. We have good wells on there. The downspacing is kind of the center part of the field. It's not on the outside portfolio, so it's in the, what I call, the heart of the field. But for the most part, it's also in some of the very thicker parts of the rock as well. So it's a combination of thickness of rock, gas and plays and also the characteristics of the rock, which are kind of in that central part of our play.

Gil Yang - BofA Merrill Lynch

So do you think the expectation is that in the thicker region, that the downspacing would be to do wells that are taking [ph] each other but it's somewhat different depths so that you more fully penetrate the thickness?

Steven Mueller

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 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 effort. And we've actually done a couple of our spacing tests where we did land too low and one high; and in one case, we saw no communication; in another case, we saw a communication. So we are 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 end, hoping that it would connect to most of the rock.

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

Operator

Our next question comes from Rehan Rashid from FDR.

Rehan Rashid - FBR Capital Markets & Co.

Quick couple of questions. One, on the cost structure side, what kind 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 under levered even before the Midstream monetization, call it. Some thoughts on that front? And then I might have one more follow-up.

Steven Mueller

As far as the cost and cost pressures, in the Fayetteville Shale, we remind everyone we're very integrated in several of the things were doing. So the biggest -- the 2 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 of the vendors so we're doing that through basically first quarter. It goes through February next year. And so we already know those costs, how those are built in and you would seen a reflection of that in the first quarter.

On the tubular casing side, we have seen about 6% increase in costs over the last 4 or 5 months. And that mainly has to do with basically some of the Japanese deal that didn't take out in the world market and causing the whole world market to go up. I don't know what they predict there, just to say that we got a little bit of cost upward pressure on the steel side of it.

Greg Kerley

On the balance sheet side, we're 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 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's why really a lot of that stuff that 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.

Steven Mueller

And I'd like to reinforce Greg's comments, we don't have any clue what our gas prices are 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 into account all the tax ramifications for shareholders and us as well on the Midstream. And we'll also figure out what the maximum value is. And if it's not now, then we won't do anything now.

Michael McAllister - Sterne Agee & Leach Inc.

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 far set of geochem work, any incremental thoughts there? What did it tell you so that you're progressing on the second set now?

Steven Mueller

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 infill in and pick specific areas and make sure that first off, the first part geochem showed us the right data and actually do some more detailed 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 production increase. We did put some more wells on production. We actually drilled 7 more wells than we had planned because of the days. We had about, I would say, it's over 10, 10 to 12 wells that really on our original schedule would've been later and actually second quarter. Part of the reason for that scheduling for the 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 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 the 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, let's say, 10 maybe even 15 well lags because of weather. So a lot of it is weather related but it is pulling those wells forward and when we did it.

Operator

[Operator Instructions] Our next question comes from Amir Arif with Stifel, Nicolaus.

Amir Arif - Stifel, Nicolaus & Co., Inc.

First question is on the Marcellus. I mean, 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 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?

Steven Mueller

As you're thinking about us going through the rest of the year, we're drilling these wells on pads. There will probably be 2 more pads that get completed between now and the end of the year and then the third one, right at the very end of the year. So you're going to see 2 or 3 wells, 2 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 the 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 hockey stick when you get in 2012.

Amir Arif - Stifel, Nicolaus & Co., Inc.

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

Greg Kerley

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

Amir Arif - Stifel, Nicolaus & Co., Inc.

And then just a second question on the Midstream side, even though your throughput was up, your operating income was down. Can you just give some color in terms of the cost side? Was it more onetime or is it some additional costs that are creeping into that side of the business?

Steven Mueller

Our G&A was down on a per Mcf basis. Our LOE was up slightly over last quarter but it was right in the middle of our range of guidance. And on our LOE side, we had a little bit more salt water disposal fees and we have a 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.

Steven Mueller

Right.

Amir Arif - Stifel, Nicolaus & Co., Inc.

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.

Greg Kerley

Yes, the operating income in the fourth quarter also included some marketing margin that was somewhat of an aberration, not necessarily recurring.

Amir Arif - Stifel, Nicolaus & Co., Inc.

But in general, Greg, if I'm thinking about the Midstream operating income, throughput grows 15%, the operating income should grow roughly in line with the same growth?

Greg Kerley

Yes, it should, Amir.

Operator

Our next question comes from David Heikkinen [indiscernible] with Tudor, Pickering,, Holt.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Steve, looking at your Marcellus position -- I'm thinking about your acreage position and your LOE 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 2 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.

Steven Mueller

Well, there really -- you can either call it 3 areas or 4 areas. We've got the area drilling right now in Greenzweig, which is right on top of a pipeline that goes north, south and ties with Millennium and Tennessee Gas. And as we mentioned in our press release, we have purchased farm comparison both Millennium and Tennessee as well as we're doing some spot capacity. The farm -- the first that the farm 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, it is a north-south line that will run across through our far 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 than we could handle. And part of the farm that we purchased on Millennium and Tennessee Gas matches was when that pipeline will be in early 2012. So we could have a couple of bumps in 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 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 into 2013, 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 and 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 farm. So I think we're okay at least over the next couple of years. Obviously, if the wells keep being as strong as they are, we have to talk in the next 6 months about what we want to be beyond 2012, but I think we're okay from here.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

And then Steve, just thinking on PVI basis, can you give us some thoughts around have initial wells also looked like they're tracking 68 Bcf at these wells cost in the Marcellus? How does that compare to the Fayetteville just on the PVI?

Steven Mueller

The Fayetteville is -- remind everyone that this Present Value Index and we look for 1.3 Present Value Index, which is nothing more than giving our investors $1.30 discount or 10% for every dollar we invest. To get to that number on the Fayetteville Shale, it's right at $4 today. And as we drill the wells faster and the wells get a little cheaper, that works down a couple of pennies. What we thought was going to be the case in the Marcellus even 3 months ago, we were talking about Marcellus then being in the $3.80s. Now we're talking in the low $3 and maybe have team handle on it for economics for 1.3 PVI. Depending on whether it's at 5 to 6 Bcf well or if it's an 8-plus Bcf well.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

But thinking about kind of return on capital employed and kind of overall funding cost, as you ramp the Marcellus, it isn't the same scale as the Fayetteville but should actually see direction go well in '12 and then into '13?

Steven Mueller

Yes, we're going to get to it as fast as we can get to it -- and one thing 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 of wells on that. This year was actually a third rig that was coming in to drill a few wells and we'll start working on a takeaway on that as well. But what you'll see is due as we look out into 2012 and beyond, you'll see us working in basically 3 general areas, the Greenzweig area; the eastern part Susquehanna County; and then the 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 of the infrastructure in place to do that and we're really excited about the fact that the wells are coming much better than we expected.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Thanks. I don't say great quarter very often but that was a good turnaround, so thanks a lot.

Operator

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

Dan McSpirit - BMO Capital Markets U.S.

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?

Steven Mueller

I'm not sure if I could say they've advanced. We 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 they would sign a contract and what that price would be? In general, it's kind of like the M&A market. The only time M&A work is when everyone agrees on the direction of the price. Right now in general, we don't quite agree on general direction in which way the gas price is going. So I don't know, if you would ask me in December, I would guess that both our company and the industry would've had some contracts signed by now. I'm kind of wondering -- it maybe 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've done a lot of discussions, both in our company and the industry, and we're comfortable that the power generators are going to be using more gas -- right now, using more gas, but just when and how will the long-term contract be signed.

Dan McSpirit - BMO Capital Markets U.S.

Okay, and you say you're not in agreement with the direction of the price of the commodity. What's your view?

Steven Mueller

Well, from a contract negotiation standpoint, this thing is going up, it's going up fast. But as I said before, we're working on it. 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 '13 and '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 - BMO Capital Markets U.S.

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?

Steven Mueller

Each of our project areas have specific acreage goals and they also have with them what I'll call control goals where 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 regions, areas obviously you can control what your future is. And so, we got those 2 sets of goals for each one. I won't go into details about what those are without going into details about the individual projects. But keep in mind, what we're trying to do is replace Fayetteville Shale with 2 or 3 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 of 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, they drove prices up above where we want to invest for the acreage that was there and we just couldn't get anymore and then we talked 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.

Operator

Our next question comes from Hsulin Peng with Robert Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated

My question is all regulatory related. He first question is you said something that 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 SEC proposals, how, if any, do they affect your hedging strategy and will there be a collateral posting requirement?

Steven Mueller

I'm answering the first question, which Pennsylvania rule or Pennsylvania issue were you worrying about?

Hsulin Peng - Robert W. Baird & Co. Incorporated

Well, I think yesterday, Pennsylvania came out with the [indiscernible] 10,000.

Steven Mueller

Let me just start with the hedging part of it. We're still trying to figure out exactly what the SEC is 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, we 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, whether it 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'll just have to look at the price of the hedging of that kind. So we're just watching to everyone else and I don't even have a guess. I read the same thing everyone else does and it's just going back and forth.

As far as the well fee in Pennsylvania, I think their proposal is about $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 close enough. It won't affect our operations. I don't think anything that we're doing would end up in that direction. But the key to ours is, don't just collect a fee or collect the tax and distribute it someplace else and then not help the area that's really being most affected by whatever that is.

Operator

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

Steven Mueller

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 properties destroyed and we're working right through that and I'm proud of what they're doing in the field. I'm proud of what our group's have been doing overall. And then you look at the Fayetteville Shale in particular, thinking you're going to drill nine days, nine days and then be in the mid-8s rates right now, that's a great job those guys have done and that helps us set up the future. One of the key things that I said we have to figure out is how fast can we drill so we can fare how many rigs we really need.

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

Operator

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

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