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

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.

Gil Yang - BofA Merrill Lynch Marshall Carver - Capital One Southcoast, Inc. Jeffrey Hayden - Rodman & Renshaw, LLC Scott Wilmoth - Simmons Rehan Rashid - FBR Capital Markets & Co.

Robert Morris

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 have 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 higher average gas prices. We replaced 430% of our 2010 production as finding and development costs to $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 at Fayetteville Shale added 1.6 Tcf of new reserves at finding and development costs 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 higher average gas prices.

Our finding and development costs in Fayetteville Shale, excluding these revisions, was $1.04 per Mcf. Total proved net gas reserves booked in Fayetteville Shale at the end of the year 2010 were 4.3 Tcf, up 39% from reserves booked at the year end 2009.

The average gross proved reserves in 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 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 had 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 perforated field as the first well in those sections, which created a slightly different mix of wells compared to our 2009 results. As for an update on our spacing test, at the year end 2010, we had drilled nearly all of our wells spacing test 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 in 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 flows wells tested between four and eight million cubic foot per day and since then, we replaced three additional operated horizontal wells on production on February 18th, all of which are located in the Greenzweig area. Total daily gross operated productions in the area is currently 45 million cubic foot per day without compression.

Flowing tubing pressures range from 1,100 to 1,300 pounds and choke sizes range from 23/64s to 40/64s. The wells are currently completed at average lateral lengths of approximately 4,500 feet and are averaging seven to 10 frac stages.

We anticipate our Marcellus activity growth substantially in 2011, with 1 1/2 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 in the Haynesville and Middle Bossier shale intervals and approximately 20,000 net acres.

We retained 10,000 net acres, which we believe is prospective 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 nine wells in the play, this well is on restricted flowback and reached production rate of 9 million cubic foot per day at 7,900 pounds on a 17/64 choke on the 11th day of the flowbacks. 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 we'll 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 we invested in the province over the next three years. In January of this year, we received initial information from a geochemical 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 geochem 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.

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 the segment was $829 million compared to $750 million, excluding a 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 in 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 in 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 10-K 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 our 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 to $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 over the 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 for our Midstream Services segment rose 56% to $192 million in 2010 and EBITDA for the segment was $221 million. The increase was primarily due to increased gathering revenues related to the Fayetteville Shale play.

At December 31, 2010, our Midstream segment was gathering approximately 1.8 Bcf per day 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 until 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 totally unsecured facility, not tied to a borrowing base.

We invested $2.1 billion during 2010, combined 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 in 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.

I now will turn it back to the operator, who'll explain the procedure for asking questions.

First, in 2010, how many areas did you drill? And then how many wells have survived that $45 million in PV-10?

In which area?

In your New Ventures program.

We didn't drill any wells in 2010 in New Ventures.

How do you justify the quirks that's by in the PV-10 change, from '09 to '10 in your 10-K?

In New Ventures?

Yes, this $45 million PV-10 number.

I don't know what that is.

I don't know that we had a $45 million PV-10. Are you talking about Appalachia?

As opposed...

Yes.

That's Pennsylvania.

You have Appalachia broken out and then you have New Ventures. I can ask Brad offline.

Brad, you get offline on that one. The PV-10 on New Ventures is -- we were having some problems getting our 10-K in the right columns last night and there may be an issue there, I don't know.

Kind of going outside of that then, as you think about drilling in one new area to two operated wells, is that a drilling commitment or is that clearly because of a leasing commitment? Or is it actually driven by what you're already seeing?

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 second half of the year. So it's just driven on our expectations, what we think up acreage-wise and when we think we can drill after that.

Sticking with the New Ventures theme here for a sec, I'm not sure if you'd be willing to tell us in 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?

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. So that's why we're sure we can drill some holes later this year.

As far as oil versus gas, we've always said, if we accelerate in oil play over 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.

Second question, you guys said your 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?

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

You talked about your capital program with the dynamic putting on gas price. Is there certain gas price you can say that you would be cutting activity or how are you planning on measuring that?

And so that's one question and the other is, what's the PVI on your wells that you're drilling now?

Well, 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 gas for the year and we get to the guidance numbers that we have out there, a $4 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 in these various projects.

To get a 1.3 PVI in the Fayetteville shale, we need right around $4, just a couple of cents over $4. And to get a PVI that we have 1.3 that we targeted in the Marcellus, it's actually lower than that.

It's for high $3. So as I said, as long as we're done hedging this year and we didn't talk much about it but in 2012, we're hedged to the same amount of gas.

A little bit lower hedge but if you look at 2012, we're going to average around that $4.50 range. It's what we have hedged now there, too.

So I think for the next couple of years, we can invest at this rate and be fine with what we're doing.

So it sounds like if you think gas is going to go below $4 and stay there, you'd consider cutting, but in this $4 range, you don't plan on changing anything?

For the most part. If anything, as the year goes and we get some better results potentially in some areas like 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.

Just thinking about fracing techniques in the Fayetteville. Heard from another operator in 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 planned to test highway fracs and just kind of what you guys are looking at on that front?

We're certainly looking at the highway frac technology, which is basically a post-frac with a little bit different combination of water and frac proper [ph] 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 at both areas.

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?

We are in discussions with several different groups, not just utilities, about long-term contracts. And we have given RFPs [ph] basically to various groups.

But we haven't gotten to a point yet where we've got a deal signed, but we're continuing to work down that road. And depending on the group, we start talking about long-term, long-term for summer 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.

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. I mean, what can we expect from that area up there?

Can you talk a little bit about the geology relative to what's now known as the core of the Fayetteville?

This year in the Fayetteville Shale, in that federal acreage far northwest corner, we're planning to drill eight wells. We drilled three 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 have there.

To remind everyone, the Fayetteville federal acreage, there's a couple of seismic lines and basically no well control. And 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 in outcrop, it 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 be 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 two- to three-year periods of time and you'll see a start going into that [ph] program late this year.

And then, we'll kind of work our way through that exploration phase.

Just so I understand there, so you said there that there'll be eight horizontal wells drilled this year?

No, the eight vertical wells.

Oh, I'm sorry. Those eight wells will be vertical?

Those will all be vertical. The three last year and these eight will all be vertical, a total of 11 vertical wells.

Does that hold the acreage in?

You don't really have acreage hold in this case. We had put together what we call an exploration unit.

As part of the commitment to that exploration unit, you have to drill 11 wells, so this will basically keep the exploration unit in shape. Under 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.

The follow-up question is on, you talked a little bit about the PUD bookings and it was booked for wells that were drilled in 2010 of around 2.85 Bcf. How does...

Let me break in. Those were not the PUDs.

The PUDs were 2.4. 2.85 was the wells drilled in 2010.

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 that 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 do you get booked in your proved reserved number?

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, we are 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.

But that goes more to the rules, not necessarily to what we have on 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 tight curves for each one of these pieces.

And then as we look at a given year or look at a given group of wells in all those PUDs, we use the appropriate type curve for that area. So sometimes, there'll 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 we drilled last year is just the SEC rules.

What's the difference between the 2.85 and maybe those kind of 3 to 4 Bcf curves that it seems like a lot of the wells are following? Is there upward revision potential there or is that just a mix?

Yes, there is and let me just give you a feel for that. I mentioned in 2009 that average well that we drilled at that time was booked at 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 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.

Can you discuss a very big picture, the competitive landscape in the Fayetteville as we've seen a number of operatorships here XTO to Exxon, Petrohawk to Exxon, it looks like Chesapeake's assets is 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 for your full of cost inflation, et cetera?

It's hard to say right now what BHP is going to do. I can talk a little bit about our inter-relationships 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 interest in. And then in the fourth quarter going into the first quarter, we almost got 100, most of those from XTO.

So they certainly, in the areas that we have small interest, 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 who followed us, 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 driving down to eight days will actually let us go faster. And I'll just remind everyone that we own 11 rigs and we'll actually going to move one of our rigs down in East Texas.

That's 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 up past the year.

We've done that from basically February time frame this year to February of next year 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 cost goes. 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 ourselves vertically. So I think they will accelerate.

If there's going to be probably any issue, it's probably a few years away. If, in fact, all of us are drilling quicker in the Fayetteville Shale, there's maybe a little more overall takeaway capacity out of the basin, but again for right now, I think there's plenty of takeaways and that's a couple of years out.

And then as a follow-up, as we've seen your lateral lengths increase in the Fayetteville, where do you ultimately see that going? How long do you think we can see your laterals there?

I think this year, you can 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 5,000 feet.

And I would say that would probably be a year out or so, we start seeing that on probably a 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 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'd 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.

For the geochemical tests in the New Ventures or 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 billion acres has source rocks and are viable and what percentage does not? And can you tell us if it's economic or thermal?

Geochem is an indicator. It doesn't tell you anything.

It's kind of an indication of 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 microseeps that would tell you something about the source rock. One of the things we've had an experience as an industry, if you do a large number of geochem tests and see nothing, you probably don't have a mature base or you don't have source rock and you really need to be very careful going forward from there.

So we are encouraged to see that at least there is microseeps and you're both getting some oil indications and some gas indications in microseeps. So it tells you there's 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, you know the sampling on the surface.

Now, having said that, there's no correlation to what's economic, not economic, whether you have traps or any of the other things because you need to have hydrocarbons. So it's just one of those steps along the way.

The first step was to do magnetics and gravity to confirm we had basins there. Then we laid out the geochem grid, though as you get some indications that there's some hydrocarbons, we've seen some indications that there's hydrocarbons there.

Next step is to shoot the seismic. That'll 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, it could be an oil source or a gas source. And it also starts to give you indications of what kind of plays you could have.

And then probably 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 if you really do have source rock or if you have a hydrocarbon system that will be economic or not. So this is one step on a [ph] 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.

Does it help you risk [ph] the 2.5 million acres at all? I mean, where some of the acreage is not viable?

We're trying to figure that out at this point in time. As we 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 can see what the tests look like with no hydrocarbons and then cover it 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 only have the data for a little less than a month. So that's something we can update you more on here in a couple of quarters.

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

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 over Lycoming.

Bradford and 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 draw our first horizontal well there this year. Again, as law of industry activity, 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 in the 4,000, 4,500 and then we'll see how it works from there.

On your Midstream, any more timeline in terms of monetizing or optimizing the value there?

Not really. 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 Midstream, and one of them is just to 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 advisers 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.

On the other areas, maybe just a bit of a philosophical question. So many other competitors have kind of jumped in to the liquids discussion quite earlier than kind of what we're having here.

How should I think about this strategically, philosophically, the impact on how far you would have to stretch your variables to say, okay, now these acres might make more sense? And maybe asking, are we having to now go down the risk of even more because we kind of started a little bit later than competition?

I assume you're talking about our New Ventures?

Yes.

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 plays, something like that. If it's rich condensate, I'd say we're looking at rich condensates.

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 of the best ones are found already. We certainly don't think so.

We are able to come up with some good ideas, at least what we think are good ideas. We're not seeing much competition in those areas.

And so we're comfortable, at least with all 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, in the industry for over 100 years.

That other 80%, these shales we're talking about, and we 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 all we have today, but I think we've got a good opportunity in the future to find other oil plays, if that's what we're targeting.

Real quick on the New Brunswick side. Apache, of course, has had some issues in terms of 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're close to some sort of a measured pipeline that takes gas into Boston, currently?

As far as how our acreage compares or relates to them, we have, of that 2.5 million acres, a little over 200,000 acres, around 200,000 acres, that's in the same basin with where Apache drilled its wells. So to the extent that where 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 probably more than one sub-basin, but in one new basin that we think we 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 what the other part of your question was.

That's it. If you find gas, I mean, how far are we from infrastructure?

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 markets fairly easy and at least first pass, we can get gas to market going into Boston markets.

But midstream EBITDA or income growth, should we kind of track the growth rates quite similar to what we had in '10 versus '09 into '11 and '12?

I would just look at what we said for our forecast and our production. And for the most part, if you look at the breakdown on our Midstream today, there's about $170 million to $180 million of that 1.8 Bcf a day that's third-party gas, 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'll ever be more than 10%.

So just pretty much proportional, whatever we've guided in that is what's supposed to be in the future numbers.

Of the $170 million you plan to spend on New Ventures this year, how much of that is for New Brunswick?

I think its about $14 million, $12 million to $14 million in New Brunswick.

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 New Ventures this year?

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 million 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.

And then on the acreage, you've got 491,000 outside of New Brunswick. You said that in a couple of plays here, 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? Or for this long [ph], how much acreage you're going to have when you go into testing?

We want whatever acreage we're at to have significant success as a company and in entirely [ph] we decided to find [ph] significance to the company uses it -- that any one of these plays, if you took two or three together, could replace the Fayetteville shale. Now obviously, depending on thickness and exactly what your targets are on that, you can get different amount of pool acreage and be significant.

And use Marcellus for instance, 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 they're 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 acreage basis.

But suffice it 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 certainly [ph] a large acreage position or significant because it's thick targets we're going after.

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 versus a existing or known plays?

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're thinking about.

I'll define new as something that the industry may know about but it's 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 the definition, we can come back to that.

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

Kind of detailed question on the Fayetteville, just going through some RPC information and then kind of bucketed there, pressure pumping contracts and 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?

Yes. We're definitely on the low side, not on the high side of that.

Without going into 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 we'll 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%.

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

Now we're going to continue to work to drive our costs down this year and we're going to finally get the chance that we've been talking about for several years where when we got to pad drilling, we could start to see more efficiencies in the 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.

I know we've targeted and talked about the fact that we're going to be nine average. But we're going to start with that nine.

Once we get to the pad, that's going to drop and hopefully we'll get less than that. When we think about Marcellus, again, it's exciting here in 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 if 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.

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. And then there was Fayetteville, and we continue 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 of new ones of 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.