SWN - Southwestern Energy Company

Q4 2010 Earnings Conference Call

Friday, February 25, 2011

Officers

 Steve Mueller; Southwestern Energy; President, CEO

 Greg Kerley; Southwestern Energy; CFO

Analysts

 David Heikkinen; Tudor, Pickering, Holt & Co.; Analyst

 Jeff Hayden; Rodman & Renshaw; Analyst

 Marshall Carver; Capital One Southcoast; Analyst

 Scott Wolmuth; Simmons & Company International; Analyst

 Scott Hanold; Royal Bank of Canada; Analyst

 Brian Singer; Goldman Sachs; Analyst

 Gil Yang; Bank of America Merrill Lynch; Analyst

 Rehan Rashid; FBR Capital Markets; Analyst

 Bob Morris; Citigroup; Analyst

 Dan McSpirit; BMO Capital Markets; Analyst

Presentation

Operator:  Greetings, and welcome to the Southwestern Energy Fourth Quarter Earnings teleconference.

At this time, all participants are in a listen-only mode. A question-and-answer session will follow the presentation. (Operator Instructions). As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Steve Mueller, Chief Executive Officer for Southwestern Energy. Thank you. You may begin.

Steve Mueller:  Thank you, and good morning, and thanks for joining us. With me today is Greg Kerley, our CFO, and Brad Sylvester, our VP of Investor Relations.

If you've not received a copy of yesterday's press release regarding our fourth quarter and year-end 2010 results, you can find a copy on our website, www.SWN.com.  

Also, I would like to point out that many of the 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 detail in the Risk Factors and the Forward-Looking Statements sections of our annual and quarterly filings with the Securities and Exchange Commission.  

Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may materially differ.

To begin, 2010 was a record year for Southwestern Energy. Despite lower realized gas prices, we set new records in 2010 for production, reserves, earnings and cash flow. We posted production growth of 35% fueled by our Fayetteville Shale play where our production grew 44% to 350 Bcf. We also produced 34 Bcfe from our East Texas, 19 Bcf from Arkoma and 1 Bcf from Marcellus, which we kicked off late in the year.

Our year-end proved reserves also increased by 35% to a record 4.9 Tcfe. It says in my notes here approximately 100% of reserves are natural gas, but I think I can say that essentially all of our reserves are natural gas. 55% were classified as proved developed in 2011, slightly higher than the 54% in 2009. We again recorded net positive reserve revisions during the year, primarily due to the improving performance from our Fayetteville Shale wells and positive price revisions due to the higher average gas prices.

We replaced 430% of our 2010 production and finding development cost of $1.02 per Mcfe, including revisions. Our cost structure is one of the keys in this current price environment and our finding and development costs and production costs continue to be among the lowest in the industry.

Now, let’s get into some more details. We’ll start by talking about the Fayetteville Shale. The Fayetteville Shale continues to deliver exceptional results. Our 2010 drilling program in the Fayetteville Shale added 1.6 Tcf of new reserves at finding and development cost of $0.86 per Mcf. This includes a net upward reserve revision of approximately 273 Bcf due to improved well performance and positive revisions due to the higher average gas prices. Our finding and development costs in the Fayetteville Shale, excluding these revisions, was $1.04 per Mcf.

Total proved net gas reserves booked in the Fayetteville Shale at the end of the year 2010 were 4.3 Tcf, up 39% from the reserves booked at the year-end 2009. The average gross proved reserves for the undeveloped wells included in our year-end 2010 reserves was approximately 2.4 Bcf per well, up from 2.2 Bcf per well at year-end of 2009, and based upon our current drilling pace, we have approximately three years of drilling inventory booked with our PUDs.

We spud 658 wells in the Fayetteville Shale during 2010 and placed a record 553 operated wells on production. We continue to prove our drilling and completion practices as our operated horizontal wells had an average completed well cost of $2.8 million per well, compared to an average $2.9 million per well in 2009. The decrease in our drilling times, and other savings and benefits from our vertical integration, have more than offset longer average lateral lengths.

Our average initial producing rates were approximately 3.4 million cubic foot per day compared to last year’s 3.5 million cubic foot per day average rate. During 2010, 40% of our operated wells were drilled on a periphery of the field as the first well in the section, which created a slightly different mix of wells compared to our 2009 results.

As for an update in our spacing tests, at year-end 2010, we had drilled nearly all of our wells’ spacing tests and over 80% of these wells are currently on production. We expect to have additional production data by the end of the first quarter of 2011 on the remaining 40% of our acreage where more results are needed. As part of that process, we are also performing interference tests on certain of our closer spaced areas.

Switching to Pennsylvania, we invested approximately $118 million in Pennsylvania during 2010 and participated in 21 wells, of which six were completed and 15 were in progress at year-end. These six are all operated horizontal Marcellus Shale wells located in our Greenzweig area in Bradford County. The production for those wells tested between 4 and 8 million cubic foot per day and since then, we've placed three additional operated horizontal wells in our production on February 18^th, all of which were located in the Greenzweig area.

Total daily gross operated production from the area is currently 45 million cubic foot per day without compression. Flowing tubing pressures range from 1100 to 1300 pounds and choke sizes range from 23/64th to 40/64th. The wells we are currently completing have average lateral lengths of approximately 4500 feet and are averaging seven to 10 frac stages. We anticipate our Marcellus activity to grow substantially in 2011 with one and a half rigs running in 2011 compared to only one rig running for 10 months last year. We plan to invest approximately $265 million in Appalachia, which includes participating in a total of 40 to 45 wells, all of which will be operated.

In our East Texas operating areas, we invested approximately $150 million and participated in 25 wells, of which 17 were successful and eight were in progress at year-end. In June of 2010, we sold certain oil and natural gas leases, wells and gathering equipment in East Texas for approximately $358 million, which included all the producing rights to the Haynesville and Middle Bossier Shale intervals and approximately 20,000 net acres. We retained 10,000 net acres, which we believe is prospected for the Haynesville and Middle Bossier Shale intervals.

Our first Middle Bossier test on this acreage, the Harris B-1H well, was placed on production February 9 with a 14-stage frac. Like many wells in the play, this well is on restrictive flow-back and reached a production rate of 9 million cubic foot per day at 7900 pounds on a 17/64th choke on the 11th day of the flow-back.

In our Conventional Arkoma program, we invested $13 million and only participated in nine wells. In 2011, we will again concentrate on Fayetteville and Marcellus and will reduce the amount we plan to invest here and in East Texas.

Now, switching to New Ventures -- at December 31, 2010, we held over 3 million net undeveloped acres in connection with our New Ventures prospects, of which a little over 2.5 million net acres were located in New Brunswick, Canada, and the remaining 490,000 net acres are located in the United States. In March of 2010, we announced that the Department of Natural Resources of the Province of New Brunswick, Canada, had accepted our bids for exclusive licenses to search and conduct an exploration program in the province in order to test new hydrocarbon basins. In 2010, we invested approximately $10 million of the approximately $47 million to be invested in the province over the next three years.

In January of this year, we received initial information from a geo-chemical survey we had conducted during 2010. Nearly 2,000 samples were taken in more than 35 traverses. All the traverses had signatures indicating some combination of oil and gas source rocks. Most of our 2011 activity in New Brunswick will be shooting 370 miles of regional 2D, along with performing more geo-chem work.

In 2010, we invested a total of approximately $145 million in our new Ventures Programs and in 2011, we plan to invest approximately $170 million in New Ventures, which includes drilling in at least one new area.

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

Greg Kerley:  Thank you, Steve, and good morning. I’m very pleased to report that 2010 was the best year in the Company’s history from a financial perspective. For the calendar year, we reported net income of $604 million or $1.73 a share, up 16% from last year’s adjusted net income. Cash flow from operations before changes in operating assets and liabilities was $1.6 billion, up 10% compared to last year. Our earnings and cash flow both set new records for the Company, as our production growth of 35% more than offset the effect of significantly lower realized natural gas prices.

Our annual results for our E&P segment were truly exceptional. Operating income for this segment was $829 million compared to $750 million, excluding the non-cash ceiling test impairment in 2009.

For the year, we grew our production by 35% to 404.7 Bcf and realized an average gas price of $4.64 an Mcf, which was down from $5.30 per Mcf in 2009.

We increased our commodity hedge position over the last few months and currently have 186 Bcf, or approximately 40% of our 2011 projected natural gas production, hedged through fixed-price swaps or collars at a weighted average floor price of $5.30. Our hedge position, combined with the cash flow generated by our Midstream business, which is not dependent on gas prices, provides protection on approximately 55% of our total expected cash flow for 2011. Our detailed hedge position is included in our Form 10K filed this morning.

We continue to have one of the lowest cost structures in our industry, with all-in cash costs of approximately $1.30 per Mcf in 2010 and a three-year average of $1.35. When you include our finding and development costs, our full-cycle costs are $2.32 in 2010, down $0.10 from $2.42 for a three-year average.

Our lease operating expenses per unit of production were $0.83 per Mcf in 2010 compared to $0.77 in 2009. The increase was primarily due to increased gathering and compression costs and increased costs related to higher water disposal volumes in our Fayetteville Shale play.

Our general and administrative expenses per unit of production declined to $0.30 per Mcf in 2010, down from $0.35 last year. The decrease was primarily due to the effects of our increased production volumes which more than offset the effects of increased compensation and other employee-related costs primarily associated with the expansion of our operations in the Fayetteville Shale.

Our taxes, other than income taxes, were $0.11 per Mcf in both 2010 and 2009.

Our full-cost pool amortization rate also declined during 2010 to $1.34 per Mcf, down from $1.51 in the prior year. The decline was due to a combination of our lower finding and development costs, the ceiling test impairment recorded in the first quarter of 2009 and the sale of natural gas and oil properties in the second quarter of 2010.

Operating income from our Midstream Services segment rose 56% to $192 million in 2010 and EBITDA for this segment was $221 million. The increase was primarily due to the increased gathering revenues related to the Fayetteville Shale play.

At December 31, 2010, our Midstream segment was gathering approximately 1.8 billion cubic feet -- Bcf per day -- excuse me -- through 1,569 miles of gathering lines in the Fayetteville Shale compared to gathering 1.3 Bcf per day a year ago. Our gathering system in the Fayetteville Shale has developed into a strategic asset that not only supports our E&P operation, but enhances our overall returns. We’re currently considering various strategic alternatives for recognizing and maximizing the value of this asset.

We strengthened our balance sheet during 2010 and our long-term debt to total capitalization ratio declined to 27%, down from 30% at year-end 2009. At December 31, we had approximately $1.1 billion in long-term debt, including $421 million borrowed on our revolving credit facility. On February 14, we amended and restated our credit facility which was scheduled to expire in February 2012. The maturity date was extended to February 2016 and the borrowing capacity was increased to $1.5 billion, up from $1 billion. The facility includes an accordion feature that permits us to increase the facility to $2 billion with agreement of existing or new lenders. We believe our credit facility will provide us with significant liquidity over the next several years. It is a totally unsecured facility, not tied to a borrowing base.

We invested $2.1 billion during 2010, compared to $1.8 billion in 2009, and we currently expect that our total capital investments for 2011 will be approximately $1.9 billion. There is clearly uncertainty today regarding natural gas prices, so our capital plans will remain flexible.

In summary, 2010 was an exceptional year for us, as we posted record results both from an operational perspective and a financial perspective. We’re uniquely positioned to weather the current price environment with our strong balance sheet, excellent liquidity and one of the industry’s lowest cost structures. And we are fortunate to have the largest position in one of the most profitable plays in the country and we look forward to adding even greater value for our shareholders through our positions in the Fayetteville and the Marcellus in our new exploration plays.

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

Questions and Answers

Operator: (Operator instructions) Our first question comes from David Heikkinen with Tudor, Pickering, Holt.

David Heikkinen: On the new ventures I guess a couple of questions. First, in 2010 how many areas did you drill and then how many wells justified that $45 million in PV-10?

Steve Mueller: In which area?

David Heikkinen: In your new ventures program.

Steve Mueller: We didn't drill any wells in 2010 in new ventures.

David Heikkinen: How do you justify -- what's justifying the PV-10 change from 2009 to 2010 in your 10K?

Steve Mueller: In new ventures?

David Heikkinen: Yes, I just saw a $45 million PV-10 number.

Steve Mueller: I don't know what that is. I don't know that we've got a 45 million PV-10. Oh, you're talking about Appalachia? That's Pennsylvania.

David Heikkinen: You have Appalachia broken out and then you have new ventures. I can ask Brad off line.

Steve Mueller: We were having some problems getting our 10K in the right columns last night and there may be an issue there. I don't know.

David Heikkinen: Okay. Going outside of that then, as you think about drilling in one new area, it's 2 operated wells; is that a drilling commitment or is that purely because of leasing commitment or is it actually driven by what you're already seeing?

Steve Mueller: We don't have any leasing commitments. Where we're at, we're picking up acreage on more than one play actually and we're very comfortable by midyear we'll pretty much have the acreage picked up on at least one of those ideas and so we can start drilling the second half of the year. So it's just driven on our expectations of what we can pick up acreage wise and when we think we can drill after that.

David Heikkinen: Okay.

Operator: Your next question is from Jeff Hayden with Rodman & Renshaw.

Jeff Hayden: Sticking with the new ventures theme for a sec, not sure if you'd be willing to tell us some of the areas that some of that acreage is targeting or where it's located I should say, but would you be willing to tell us whether it's going more after oil prospects or gas prospects?

Steve Mueller: You're right; we're not going to tell you where it's at, because we don't want to get a lot of competition. I can say that on a couple of them we're well over 80% and even up to 90% on our acreage leasing. That's why we're sure we can drill some wells later this year. As far as oil versus gas, we've always said that if we can accelerate an oil play over a gas play, we will do that, so I wouldn't be surprised if at least something we drill this year has some oil component to it.

Jeff Hayden: Okay. Second question, you guys said PUD bookings for Fayetteville were up to 2.4 Bcf; would you be able to give us what your PDP bookings are for wells drilled in the Fayetteville say over the last couple of years?

Steve Mueller: The wells we drilled in 2010 in the Fayetteville shale that we had enough information on so we can do a decline curve and actually book those wells was 2.85 Bcf. That compares to 2009 at the same time last year of around 2.9 Bcf.

Jeff Hayden: Okay.

Operator: Your next question is from Marshall Carver with Capital One Southcoast.

Marshall Carver: You talked about your capital program would be dynamic depending on gas price; is there a certain gas price you could say that you would be cutting activity or how are you planning on measuring that? So that's one question and the other is, what's the PVI on your wells that you're drilling now?

Steve Mueller: As far as the capital program, I'm fairly comfortable today that we can do the capital program we have in front of us. And the reason I say that, with our hedge position, if it averages $4.00 gas for the year and we get to the guidance numbers that we have out there, $4.00 gas gives us about $4.50 NYMEX price with our hedges that we have in place today. So that works for us and that goes back to the PVI of these various projects.

To get a 1.3 PVI in the Fayetteville shale we need right around $4.00 -- just a couple of cents over $4.00. And to get a PVI that we have 1.3 that we targeted in the Marcellus is actually lower than that, it's the high $3.00. So as I said, with what we've done hedging this year and we didn't talk much about it, but in 2012 we're hedged the same amount of gas, a little bit lower hedge, but if you look at 2012 we're going to average around $4.40-$4.50 range with what we have hedged now there too. So I think the next couple of years we can invest at this rate and be fine with what we're doing.

Marshall Carver: So it sounds like if you think gas is going to go below $4.00 and stay there, you'd consider cutting but in this $4.00 range you don't plan on changing definitely.

Steve Mueller: For the most part. If anything, as the year goes and we get some better results potentially in some areas like the Marcellus or we start seeing some things in new ventures, you might see us invest a little bit more just to set the future up.

Marshall Carver: Thank you.

Operator: Your next question is from Scott Wilmoth with Simmons & Company.

Scott Wilmoth: Hey guys, just thinking about fracing techniques in the Fayetteville, I heard from another operator this earnings season about highway fracs in the Eagle Ford. I know you guys have talked about fiber fracs in the past, but do you guys have plans to test highway fracs and just kind of what you guys are looking at on that front?

Steve Mueller: We're certainly looking at the highway frac technology, which is basically a pulsed frac with a little bit different combination of water and frac propane as you know. We're looking at that both in the Marcellus and in the Fayetteville shale. We'll actually try some in the Marcellus I think before the Fayetteville, but we're looking in both areas.

Scott Wilmoth: Great. News out this morning of another E&P entering into a long-term contract with a utility. I know you guys have talked about that in the past. Can you just give us an update on where you guys are on that?

Steve Mueller: We are in discussions with several different groups, not just utilities, about long-term contracts and we have given RFPs basically to various groups, but we haven't gotten to the point yet where we've got a deal signed, but we're continuing to work down that road. And depending on the group, when we start talking about long-term, long-term for some is as short as three years and for others it's in the 10 year range, but that's what long-term is when we talk to people out there.

Scott Wilmoth: Thanks.

Operator: Your next question is from Scott Hanold with RBC.

Scott Hanold: I guess in the Fayetteville this year you're going to be probably wrapping up the last of your HBP for the most part and you're going to test some of that federal acreage. What can we expect from that area up there? Can you talk a little bit about the geology relative to some of what's now known as the core of the Fayetteville?

Steve Mueller: This year in the Fayetteville shale in that federal acreage, far Northwest corner, we are planning to drill 8 wells. We drilled 3 wells at the end of 2010; those are all going to be vertical wells. They will be similar to the early days of the Fayetteville where we cored them, did a bunch of science to figure out exactly what we had there. To remind everyone, in the Fayetteville federal acreage there's a couple of seismic lines and basically no well control, so the control we have is the drilling we've done up right next to the federal acreage and then there's some outcrops north of the federal acreage so you know the shale is in the acreage, you just don't know much about it.

In general, an outcrop is thinner than the average in the field and then of course it goes to some of the best parts of our field kind of butt up against the federal acreage. So I expect that it will be a variety of different kinds of rocks. I think there will some different fault blocks and some things going on in there, but the key this year is drill these 11 wells, get the core data, start working that into our overall regional geology picture. We have designed basically a three phase 3D program that will go over a two to three-year period of time and you'll see us start  going into that program late this year. And then we'll kind of work our way through that exploration phase.

Scott Hanold: Okay, just so I understand that right, you said there will be 8 horizontal wells drilled this year?

Steve Mueller: No, the 8 vertical wells. Those will all be vertical; the 3 last year and these 8 will all be vertical, total of 11 vertical wells.

Scott Hanold: Does that hold the acreage then?

Steve Mueller: You don't really have acreage hold in this case. We have put together what we call an exploration unit. As part of the commitment to the exploration unit you have to drill 11 wells, so this will basically keep the exploration unit in shape. On that exploration unit we have the ability to drill over 100 wells, but somewhere between that 11 and 100 you start breaking the exploration unit up into development units. And so what we're doing this year and next year is learning enough so we can actually start drilling some horizontal wells and then decide what to do on the production unit standpoint.

Scott Hanold: Thanks. And then the follow-up question is, you talked a little bit about the PUD bookings that it was booked for wells that were drilled in 2010 of around 2.85 Bcf.

Steve Mueller: Let me break in. Those were not the PUDs. The PUDs were 2.4. The 2.85 was the wells drilled in 2010.

Scott Hanold: Correct. And so how did that conversation go with your reservoir engineers or how do you look at it when you run those sort of example type curves you put in your presentation that shows some of your more recent wells following a curve that looks to potentially near 4 Bcf; how do you think about what these get booked on in your proved reserve number?

Steve Mueller: You have to remember, the SEC rules say that you have to be certain or nearly certain in the values that you put in there for your reserves, so on the PUDs you're not going to give it an average number, you're going to have something less than an average number. And what that probably is telling you is that at least over the next few years you'll continue to see upward revisions in what we've got on the PUD side. That goes more to the rules, not necessarily to what we have in our curves or what we have for the area.

When we do reserves we break the Fayetteville shale play up into several pieces and we have type curves for each one of these pieces and then as we look at a given year or look at a given group of wells that are in those PUDs we use the appropriate type curve for that area. So, sometimes there will be a little bit of variance just on where you may be drilling, but by far the biggest portion, the difference between a 2.4 Bcf PUD and 2.85 Bcf well you drilled last year is just the SEC rules.

Scott Hanold: Okay, so if I were to ask you the question, what's the difference between the 2.85 and maybe the kind of 3 to 4 Bcf curves that seems like a lot of wells are following, is there upward revision potential there or is that just a mix?

Steve Mueller: There is. And let me just give you a feel for that. I mentioned that in 2009 the average well that we drilled at that time was booked to 2.9 Bcf. The reason I said the average well at that time, those wells have also grown in their estimates. Again, SEC bookings you have to be certain, certainly on the PDP portion, so now we're well over 3 Bcf on that same group of wells in 2009 that were 2.9 Bcf wells.

Scott Hanold: Thank you.

Operator: Your next question is from Brian Singer with Goldman Sachs.

Brian Singer: Can you discuss a very big picture of the competitive landscape in the Fayetteville as we've seen a number of operator shifts here; XTO to Exxon, Petrohawk to Exxon, it looks like Chesapeake's assets are going to shift more to an aggressive BHP? What do you see others doing differently and do you see the potential acceleration of activity by any of those players, particularly BHP, does that make you need to be more aggressive in the contracting for services, fearful of cost inflation, etc?

Steve Mueller: It's hard to say right now what BHP is going to do. I can talk a little bit about our interrelationships with XTO and what they're talking about. If we look at last year, up until the fourth quarter we barely had 100 total AFEs from other operators that we had an interest in and then in the fourth quarter going to the first quarter we've almost got 100, most of those from XTO. So they certainly, in the areas that we have small interests, are accelerating what they're doing. I would assume that BHP will want to go faster. I don't know that.

As far as our company and our costs are concerned, one of the things we've done over the last couple of years for those that follow this, we ran 15 rigs a year ago.  Today, we're running 12 rigs.  The reason we could do that is that we cut those days out and we can drill roughly the same number of wells.  As we look into the future we think drilling 12 wells in the future and dropping down to eight days will actually let us go faster.  And I'll just remind everyone that we own 11 rigs and we're actually going to move one of the rigs we own in East Texas up, so all 12 rigs later in the year will be rigs that we own.  So we've got that cost locked.

On the pumping services side, we bid year-to-year and in some cases we have a rolling bid that goes out past a year.  We've done that from basically February time frame this year through February of next year and know those costs.  And then, the other big cost we have is the steel side and we have a long term contract with a single company to supply us all of our tubulars and casings.  

So I think we're okay as far as costs go.  Our crews are there.  They've been there for a while and we're kind of based for some of the various companies when we don't own it ourselves vertically.  So I think that will accelerate.  If there is going to be probably an issue, it's probably a few years away.  If in fact all of us are drilling quicker in the Fayetteville shale, you may get a little more overall takeaway capacity out of the basin.  But again, for right now, I think there's plenty of takeaway and that's a couple years out.

Brian Singer: Thanks.  That's really helpful color.  And then, as a follow up, as we've seen your lateral length increase in the Fayetteville, where do you ultimately see that going?  How long do you think we can see your laterals there?

Steve Mueller: I think this year you could see it go up from basically 4,500 to the 4,700-plus range.  And then, ultimately, it's going to be something greater than the 5,000 feet.  And I would say that would probably be a year out or so when you start seeing that on a fairly consistent basis.  The reason for 5,000 feet versus 8,000 or 10,000 or some other number is when you look at our map and you start laying out where you've put wells at different lateral lengths--and I'll use 10,000 feet, for example--you can drill a 10,000-foot lateral, but when you lay it out on your map, you find there's a bunch of spots where you need 2,000-foot laterals to fill in around it and it averages back down to 5,000.  So I don't know what the ultimate combination of them is going to be, but it sure looks like around 5,000 is going to be the average.

Brian Singer: Great.  Thank you.

Operator: Our next question comes from Gil Yang with Bank of America Merrill Lynch.  Please state your question.

Gil Yang: Good morning.  Could you--for the geochemical tests in the new ventures area, in New Brunswick, could you comment on what the significance of the results are in terms of does it help you direct your activity and what percentage of the 2.5 million acres has source rock and is viable and what percentage does not?  And can you tell if it's biogenic or thermal?

Steve Mueller: Geochem is an indicator.  It doesn't tell you anything.  It kind of indicates you in a certain direction.  And the first reason for doing the geochem out there was to see if you got any indications at all of some kind of micro seep so it would tell you something about the source rock.  One of the things we've had experience as an industry, if you do a large number of geochem tests and see nothing, you probably either don't have a mature basin or you don't have source rock and you really need to be very careful going forward from there.  So we were encouraged to see that at least there is micro seeps and you're both getting some oil indications and some gas indications in those micro seeps.  So it tells you there is at least some source rock in the area and that source rock has been able to generate some kind of hydrocarbon so that they have come to the surface and you'll be able to sample them on the surface.

Now, having said that, there is no correlation to what's economic, not economic, whether you have traps or any of the other things that you need to have hydrocarbon.  So it's just one of those steps along the way.  The first step was do magnetics and gravity and confirm you had basins there.  And then, we laid out the geochem grid.  So we get some indications that there are some hydrocarbons.  We're seeing some indication that there's hydrocarbons there.  The next step is to shoot the seismic.  That will tell us what the section looks like and we can start tying in where the source rock might be, and then that helps you figure out could it be an oil source or a gas source and it also starts giving you indications of what kind of plays you could have.  

And then, probably we'll shoot another set of seismic after this first pass regional and finally get to the point where you can actually drill a well where you can actually see that you really do have source rock, or if you have a hydrocarbon system that will be economic or not.  So this is one step in my six or seven-step process.  But the significance of it is that it did show over large portions of the surveys that we did at least some indication of oil or gas.

Gil Yang: Okay.  But does it help you risk the 2.5 million acres at all?  I mean, where some of the acreage is not viable?

Steve Mueller: We're trying to figure that out at this point in time.  As I said, we did over 35 traverses and those traverses covered all the acreage we have and also went off of our acreage, both in areas that we knew there was no hydrocarbons as kind of a test, so we could see what a test looked like with no hydrocarbons, and then covered down into some of the fields that we know are productive.  And I can tell you all the traverses had some indication somewhere in the traverse, but we're trying to figure that out. We've only had the data for a little less than a month.  So that's something we can update you more on here in a couple quarters.  

Gil Yang: Okay.  And then, just second question is can you comment on how long your laterals are going to be in the Marcellus ultimately do you think?

Steve Mueller: Well, we haven't thought that out yet.  I would kind of remind everyone where we're at.  We are in for the most part Bradford and Susquehanna County.  That's almost 90,000 of our acres, and then we go up over 110,000 acres with the Lycoming.  Bradford/Susquehanna we butt up against the Cabot and Chesapeake wells that are out there.  And I know they've got some fairly long lateral lengths.  But we just haven't had enough experience yet to know either lateral length what the right amount is or the number of fracs that you put on those wells.  When you jump to our big chunk of acreage in Lycoming, we have not drilled a horizontal well ourselves.  We'll drill our first horizontal wells there this year. Again, there is a lot of industry activity and we'll learn from the industry.  But for us, that's a question probably to ask us later in the year.  To begin with, we'll do basically what we're doing right now, and that's 4,000 to 4,500, and then we'll see how it works from there.  

Gil Yang: Okay.  Thanks a lot.

Operator: Our next question comes from Rehan Rashid with FBR Capital Markets.  Please state your question.

Rehan Rashid: Good morning.  On your midstream, any more kind of timeline in terms of monetizing or optimizing the value there?

Steve Mueller: Not really.  And one of the things we've talked about as we've had presentations in that, there's a couple of things you need to do before you can make any decisions about what you're going to do in the midstream.  And one of them is just get all of your finances audited.  We're doing that process right now and that's a several month process.  And so, later this summer we'll have that or later this spring we'll have that.  And then, we've got to figure out exactly what we might want to do, and we are working with investment advisors on that.  So we're working that process, but I wouldn't expect much from us until summertime as far as what we might do and what we've got.

Rehan Rashid: Got it.  On the other areas, maybe this is a bit of a philosophical question.  So many other competitors have kind of jumped into the liquids discussion quite earlier than kind of what we are having here.  How should I think about--just kind of strategically or philosophically the impact on how far you would have to stretch your variables to say, okay, now this acreage might kind of make more sense, and maybe asking are we having to now go down the risk curve even more because we kind of started a little bit later than competition?

Steve Mueller: And I assume your talking about our new ventures?

Rehan Rashid: Yes.

Steve Mueller: Kind of two general responses there.  When I say we're looking at some things that are oil, we're looking at oil.  They're not a rich condensate play or something like that.  If it was rich condensate, I'd say we're looking at rich condensate.  So we truly are looking at some oil.  And then, are we too far down the curve and have they already found it?  I think that's where you're going.  Is that all the best ones we've found already?

Rehan Rashid: Yes.

Steve Mueller: We certainly don't think so.  We are able to come up with some good ideas, or at least what we think are good ideas.  We're not seeing much competition in those areas.  And so, we're comfortable that--at least with what we know today that we can get things that are very comparable to what other people are drilling.  And I'll just remind everyone, about 20% of the rock in the world is your carbonate and conventional sandstones that we've been drilling for as an industry for over 100 years.  That other 80% is these shales we're talking about.  And when you start talking about oil in particular, we've only been looking for that for five years.  So I think there's going to be several oil plays still to be found that are going to be very good oil plays.  So I'm comfortable not only with what we have today, but I think we've got a good opportunity in the future to find other oil plays, if that's where we targeting.

Rehan Rashid: Got it.  Thank you for the answer.  Real quick on the New Brunswick side.  Apache, of course, has had some issues in terms of their initial testing there.  Could you maybe give us some feel for how your acreage is different than theirs?  And then, second, if you find gas, is my understanding correct that we are close to some sort of a major pipeline that takes gas into Boston directly?

Steve Mueller: As far as how our acreage compares or relates to them, we have about 2.5 million acres, a little over 200,000 acres or around 200,000 acres that's in the same basin with where Apache drilled its well.  So to the extent that whatever Apache finds is good or bad, it will have an effect on that 200,000 acres I think.  The other 2.3 million acres is what we think are in a probably more than one sub basin, but in one new basin that we think we've found.  And we just don't have enough information to tell you how that's going to compare at this point in time.  That's what we're trying to do all this work for.  I'm trying to think of the other part--what the other part of your question was.

Rehan Rashid: That's it.  Just--and if you find gas, I mean--.

Steve Mueller: --Oh, yes--.

Rehan Rashid: --How far away are we from infrastructure?

Steve Mueller: The Maritimes and Northeast Pipeline runs right through our acreage.  That is the pipeline that brings in the offshore eastern coast Canadian gas into the Boston markets.  At any point in time it's got about 200 million a day of excess capacity on it.  And we understand that that can be scaled up with some compression.  So if we find gas initially, we can certainly go into that line.  On the other side, if there happens to be some oil in some of our acreage, there's an oil refinery on the coast there in New Brunswick.  So we can basically get oil to market fairly easy and at least first pass we can get gas to market going into the Boston markets.

Rehan Rashid: One last one.  I apologize for hogging the call here.  But midstream EBITDA or income growth, should we kind of track the growth rates quite similar to what we had '10 versus '09 into '11 and '12?

Steve Mueller: I would just look at what we've said for our forecast in our production.

Rehan Rashid: Okay.

Steve Mueller: And for the most part, if you look at the breakdown on our midstream today, there's about 170 to 180 million of that 1.8 Bcf a day that's third party gas.  And I--which is roughly 10%.  I think as you look down the road, this kind of goes back to the previous question on how fast some of the other people will go because that's--the third party gas we're picking up is for some of the other operators out there.  But I wouldn't guess it will ever be more than 10%.  So just pretty much proportional to whatever we've guided in that--.

Rehan Rashid: --Yes--.

Steve Mueller: --Should be in the future numbers.

Rehan Rashid: Perfect.  Thank you so much.

Operator: (Operator Instructions.)  Our next question comes from Bob Morris with Citigroup.  Please state your question.

Bob Morris: Good morning.  Of the 170 million you plan to spend on new ventures this year, how much of that is for New Brunswick?

Steve Mueller: I think it's about 14 million--$12 to $14 million in New Brunswick.

Bob Morris: And then, the remainder, which is quite a bit, where is that going?  How much is that for acreage and where else is that capital going to in new ventures this year?

Steve Mueller: We're going to drill at least one well and we don't have the details exactly on that well.  But I would assume 10 million or so between one or two wells to drill--$10 to $12 million, and then the rest of that is going to be for the most part on acreage.  There's a little bit of seismic and other things we're picking up.  But that's a few million dollars worth.

Bob Morris: And then, on the acreage.  You've got 491,000 outside of New Brunswick.  You said that in a couple plays you're 80 to 90% of what you want.  So in those couple of plays where you're most of the way there, will those end up being 100,000-acre positions or sort of what are you targeting in those key plays that are furthest along as far as how much acreage you're going to have when you go into testing?

Steve Mueller:  We want whatever acreage we're at to have significance to us as a company.  And kind of the way we decide -- define significance as a company is, is it -- that any one of these plays, if you took two or three together could replace a Fayetteville Shale.  

Now, obviously, depending on thickness and exactly what your targets are and that, you can get different amount of total acreage and be significant.  And I'll use Marcellus for instance.  While we've got 170,000 acres in Marcellus, it's about not quite twice as thick as the Fayetteville Shale, and on a gas-in-place is almost double.  So there, having 150,000 acres is like having 300,000 acres in the Fayetteville Shale.  

So it's hard to give it to you on an acres basis.  But suffice us to say, what we're trying to do is replace the Fayetteville Shale with two or three projects.  So they will be significant, either because they're sitting in a large acreage position or significant because they're thick targets we're going after.

Bob Morris:  Okay.  Thank you.

Operator:  Our next question comes from Dan McSpirit with BMO Capital Markets.  Please state your question.

Dan McSpirit:  Folks, good morning.  Thank you for taking my questions.  Just a point of clarification here.  Of the 490,000 net acres leased under new ventures and that lies outside New Brunswick, again, how many prospects are involved and how much of that acreage actually lies in new verse, say existing or known plays?

Steve Mueller:  Well, I won't tell you how many are involved.  We won't go that far quite yet.  But as far as, I'll kind of define new for you and then tell me if that's what you were thinking about.  

I'll define new as something that the industry may know about but is very early days as opposed to, I'd say Eagle Ford I wouldn't put in new category.  So I'll define new as that, and if that doesn't work for a definition, we can come back to that.

But all of the acreage we're picking up would be in that definition of new.

Dan McSpirit:  Very good.  Thank you.

Operator:  Our next question comes from David Heikkinen.  Please state your question.

David Heikkinen:  Kind of detailed question. On the Fayetteville, I was going through some RPC information and they kind of bucketed their pressure pumping contracts in two things, one that was long-term contracts and the other for the Fayetteville, where they talked about 40% increases on a year-over-year basis for pressure pumping.  

I'm guessing, given your relationship with RPC, you're probably more in bucket one than bucket two.  But can you talk at all about that?

Steve Mueller:  Yes.  We're definitely on the low side, not on the high side of that.  Without going in a lot of details, we have, at any point in time, four to five different vendors that supply us pressure pumping in the Fayetteville Shale.  Each one of those have a little different contract with them.  But when you look at the pumping that we do and the price per stage, we're one of the cheapest in the Fayetteville Shale in the industry.  

So we have been historically one of the cheapest.  It's fairly easy to pump and will continue to be the cheapest as we go forward.  

The other thing to remind everyone is we are vertically integrated there also.  While we don't do the pumping, we supply all of our sand and water ourselves, and actually do a lot of the site work for them that they might do in other cases.  So the only thing that we bid is pumping, and it's some of the easier pumping that they do.  

So we're certainly not seeing anywhere near 40%.  So our numbers are actually less than 10%.

David Heikkinen:  That's helpful.  Thanks, Steve.

Operator:  Ladies and gentlemen, there are no further questions at this time.  I'll turn the conference back over to management for closing remarks.

Steve Mueller:  Thank you.  I'd like to close and just say that we had a great year in a real difficult price environment, and we're really excited about 2011.  

We're going to continue to work to drive our costs down this year and we're going to finally get the chance, and we've been talking about it for several years, where when we got to pad drilling we could start seeing more efficiencies of Fayetteville Shale, and we're going to see that by the end of this year.  And we're going to exit the year, I'm very comfortable drilling eight days per well.  And I know we've targeted and talked about the fact that we're going to be nine average.  We're going to start with that nine, but it'll -- once we get to the pad, that's going to drop and hopefully it'll get less than that.

When we think about Marcellus, again, it's an exciting year in the Marcellus.  We're going to take that 40 million a day production that I talked about now and we should exit the year consistently doing 100 million a day gross production in that area.  

And then we've had a lot of questions today about our new ideas, and I'm excited that we get a chance to also start testing some of those and I'm excited that New Brunswick continues to give us good information as we get into New Brunswick.

And the one thing I want to leave you with is, if you think about our history, in the early 2000s, it was Overton, and we learned a lot there.  Then it was Fayetteville, and we continued to learn a lot there.  Now we've got Marcellus this year and we're going fast up that curve.  And we're really looking forward to drilling a couple new [onto] these projects and get to start that over again.

So with that, I thank you for listening.  I will keep you updated on progress in the quarters to come.  And have a great rest of the earnings season.  Thank you.

Operator:  Thank you.  Ladies and gentlemen, this concludes today's conference.  All parties may now disconnect.  Have a great day.  

Explanation and Reconciliation of Non-GAAP Financial Measures

We report our financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However, management believes certain non-GAAP performance measures may provide users of this financial information with additional meaningful comparisons between current results and the results of our peers and of prior periods.  

One such non-GAAP financial measure is net cash provided by operating activities before changes in operating assets and liabilities. Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.

Additional non-GAAP financial measures we may present from time to time are net income attributable to Southwestern Energy, diluted earnings per share attributable to Southwestern Energy stockholders and our E&P segment operating income, all which exclude certain charges or amounts.  Management presents these measures because (i) they are consistent with the manner in which the Company’s performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the Company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.

See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the twelve months ended December 31, 2010.  Non-GAAP financial measures should not be considered in isolation or as a substitute for the Company's reported results prepared in accordance with GAAP.

Finding and development costs - Finding and development (F&D) costs are computed by dividing acquisition, exploration and development capital costs incurred for the indicated period by reserve additions, including reserves acquired, for that same period. The following computes F&D costs using information required by GAAP for the twelve months ending December 31, 2010.

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