Form 8-K

Southwestern Energy

Third Quarter 2012 Earnings Conference Call

Friday, November 2, 2012, 10:00 a.m. ET

Officers

Steve Mueller; Southwestern Energy; President and CEO

Bill Way, Southwestern Energy; COO

Craig Owen; Southwestern Energy; CFO

Jeff Sherrick, Senior VP of Corporate Development

Analysts

Dave Kistler; Simmons and Company, International; Analyst

Brian Singer; Goldman Sachs; Analyst

Scott Hanold; RBC Capital Markets; Analyst

Hsulin Peng; Robert W. Baird; Analyst

Charles Meade; Johnson & Rice Co.; Analyst

Brian Lively; Tudor, Pickering; Analyst

Arun Jayaram; Credit Suisse; Analyst

Dan McSpirit; BMO Capital Markets; Analyst

Presentation

Operator: Greetings, and welcome to the Southwestern Energy Third Quarter 2012 Earnings Teleconference Call. (Operator Instructions) It is now my pleasure to introduce your host, Steve Mueller, President and CEO, Southwestern Energy. Thank you. Mr. Mueller, you may now begin.

Steve Mueller; President and Chief Executive Officer

Good morning and thank you for joining us. With me today are Bill Way, our Chief Operating Officer, Craig Owen, our Chief Financial Officer, Jeff Sherrick, our Senior VP of Corporate Development, and Brad Sylvester, our VP of Investor Relations.

If you have not received a copy of yesterday’s press release regarding our third quarter 2012 results, you can find a copy on our website at 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 differ materially.

To begin, I would like to say that our thoughts and prayers are with our friends, families and employees on the East Coast. A storm like this puts everything into perspective, and we are hoping that you were able to find higher ground and can be as comfortable as possible during this very uncomfortable time.

With that being said, I wanted to take a moment to express how proud I am of our third quarter results. We continue to make meaningful progress in lowering our costs. This, along with our growing production, the growing cash flow from our Midstream business and our hedge position continue to help our earnings and cash flow move higher. Our wells in the Fayetteville Shale have improved and our Marcellus production is growing and is expected to ramp dramatically later in the fourth quarter. We also have several New Ventures projects underway and look forward to knowing more about the Brown Dense later this year and will have more results from our Colorado and Montana plays in the first quarter of 2013. Plus, we have some other ideas we are working on that we hope to unveil soon.

U.S. demand and production data for August is scheduled to be released today and everyone who follows those numbers knows how difficult it is to predict individual monthly data points. The trends, though, are

obvious. Gas rig count is less than half of that a year ago and the data already has shown nearly flat.

“Lower 48” gas production since the beginning of the year as a partial reflection of the decrease in rig activity. The low gas price has increased demand the past three months almost 11% over 2011 and the combination of flat supply and increasing demand has averted the potential “over full” storage problem that was a foregone conclusion for many just a few short months ago.

What does this mean for the future? As this week has shown, weather is still the main variable but the continued narrowing of the supply-demand imbalance gives cause to be more constructive about 2013 gas prices. A strong case can be made for a 2014 yearly average gas price above $4.00 as the many newly announced gas power plants start coming on line to help maintain healthy demand. As shown this past year, demand does change with change in price and as price rises both the possibility of some rig count returning and less coal to gas fuel switching is very real. This will have the tendency to keep average yearly prices below $5.00 for the foreseeable future.

At SWN, we use these tendencies to help plan, but “what if?” is always in the back of our mind. What if the general economy drops? What if it begins to expand? What if oil rig count increases along with higher associated gas or what if weather is different than expected? Our job is to deliver in whatever case of “what if?” and as you will hear today, SWN continues on the path of delivering and improving on the projects in our portfolio.

I will now turn the call over to Bill for more details on our operations and then to Craig for a recap of our financials.

Bill Way, Executive Vice President and Chief Operating Officer

Fayetteville Shale Play

Thank you, Steve, and good morning everyone. In the Fayetteville Shale, we placed 105 operated wells on production in the third quarter, resulting in net production of 123.6 Bcf, which is up 10% from a year ago. Our operated horizontal wells achieved a record quarterly average initial production rate of 3.8 million cubic feet of gas per day, up from 3.5 million cubic feet of gas per day in the second quarter. Our average completed well cost was $2.6 million per well with an average drilling time of 6.8 days during the quarter. We also set a new company record for drilling time of a well in our Sharkey pilot area that reached total depth in late September. This well had a total vertical depth of approximately 3,800 feet with a drilled lateral length of 3,625 feet and was drilled in just under 3 days. As a result of our optimization efforts on our drilling portfolio, we expect to see our average production on a per well basis continue at or around these levels over the next few quarters.

Supporting our successful vertical integration strategy, we took delivery of the first of two fracture stimulation fleets in September. Our newest team of employees has already put this equipment to work in the Fayetteville Shale play and has successfully fracture stimulated two wells.

On the midstream side, our gas gathering business in the Fayetteville Shale continued to perform well and at September 30th was gathering approximately 2.2 billion cubic feet of natural gas per day through 1,837 miles of gathering lines, compared to gathering approximately 2.0 billion cubic feet per day a year ago.

Marcellus Shale

Before I speak about our Marcellus business, as Steve said, our thoughts go out to the people in the Northeast U.S. who are dealing with the impacts of Hurricane Sandy. A special thanks to all of our employees in Pennsylvania for their terrific planning and preparation for this storm. Because of their efforts we have fared very well so far with no damage or injuries to report. Our Tunkhannock office was fully operational throughout the storm. We did not shut-in any of our production. We will continue to monitor the situation closely and remain focused on the safety of our employees and our communities.

During the third quarter, we put 9 wells on production. Our total well count stood at 50 operated producing wells, including 44 wells in Bradford County and 6 wells in our Price area in Susquehanna County. Net production from our Marcellus properties was 15.1 Bcf, which is up approximately 50% over the second quarter and more than double from a year ago.

During the quarter, we commissioned the remaining Greenzweig compression and booster compression, enabling the full field to access SWN compression. All wells can now deliver into Stagecoach with access to both Millennium and TGP transport lines.

In our Range Trust area in northern Susquehanna County, we have 25 wells currently either waiting on completion or on the Bluestone Pipeline, the southern portion of which is estimated to be placed into service into TGP 300 around the end of November.

We expect our production to increase dramatically from our Marcellus properties over the next 14 months. From today’s current gross operated rate of over 200 million cubic feet of gas per day, we expect our year-end rate to be approximately 300 million cubic feet of gas per day and our year-end rate at the end of 2013 to be over 500 million cubic feet of gas per day.

New Ventures

Moving to our New Ventures, we have drilled and completed 6 wells in our Lower Smackover Brown Dense play in southern Arkansas and northern Louisiana. As a reminder from our second quarter call, we drilled wells #4 and #5 as vertical tests to see if we would encounter the higher pressure that we saw in our 3rd well, the BML. Both vertical tests encountered the higher pressure.

In our 4th well, we tried several different fracture stimulation recipes, primarily involving different combinations of linear gel. However, in our 5th well we completed 3 vertical stages totaling 12 feet of perforations with white sand and slickwater in the sand stages. Production has stabilized at approximately 200 barrels of oil and 1.25 million cubic feet of gas per day for the last 10 days.

We now are using these wells to obtain additional log data and core samples over the formation and study the effectiveness of different fracture stimulation treatments on the contact area and to learn more about fracture height growth. At a later date, we will re-enter these wells and turn them into horizontal wells sometime in 2013.

Our sixth well, the Doles, located in Union Parish, Louisiana, was drilled in September to a vertical depth of 10,673 feet with a 4,700-foot completed horizontal lateral. This well is being completed and will begin flowing back shortly. We expect to begin selling both oil and gas from the Doles well and the BML well around the end of November with the expectation of learning more about the decline characteristics of both wells before year-end. We remain highly encouraged and look forward to learning more on our path to commerciality.

In our Denver-Julesburg Basin oil play in eastern Colorado we have leased approximately 300,000 net acres and have drilled and completed 2 wells and are permitting additional wells in the area. We are testing multiple intervals in these two wells and evaluation will continue over the next 90 days. We are encouraged by what we have seen so far and hope to have more information about this area in the first quarter of 2013.

Finally, we have drilled and completed a well in Sheridan County, Montana targeting the Bakken/Three Forks objectives. This well has been pumping for over 60 days and we are encouraged and are continuing to lease acreage. However, this is all we are going to say about this area at this time.

In closing, while we have enjoyed the recent gas price run-up, we are not standing still. We are very proud of the efforts of our more than 2,300 people and excited about our positions in two of the best

natural gas plays in the country. As Steve mentioned, we will continue to drive down our costs and innovate to increase production performance in both areas. Our New Venture ideas have the potential to impact our margins and our company in a meaningful way, if successful, and we look forward to learning more about their commerciality over the next few months. I look forward to reporting back to you in February on our progress. I will now turn it over to Craig Owen who will discuss our financial results.

Craig Owen – Senior Vice President and Chief Financial Officer

Thank you, Bill, and good morning. We reported earnings for the third quarter of approximately $132 million, or $0.38 per share, excluding the non-cash ceiling test impairment of our natural gas and oil properties resulting from low gas prices. Our discretionary cash flow was $417 million in the third quarter, which continues to be resilient, as Steve pointed out, and nearly offset our entire capital investment level for the third quarter.

Our average realized gas price was $3.40 per Mcf for the quarter, down 21% from the same period last year. While Nymex settlement prices for the third quarter were 33% lower than they were a year ago, we continue to benefit from our hedging activities, which increased our average gas price by $1.05 per Mcf during the quarter. For the remainder of 2012 we have 67 Bcf of our gas production hedged at a weighted average floor price of $5.16 per Mcf and, for 2013, 186 Bcf hedged at $5.06 per Mcf. We continue to monitor the gas markets and will be looking for opportunities to add to our hedge position over the next several months.

Operating income for our E&P segment was $145 million for the quarter, excluding the ceiling test impairment, compared to $228 million in the same period last year.

To echo Steve’s comments, we continue to see costs moving in the right direction and our cost structure continues to be a key competitive advantage for us, with all-in cash operating costs of $1.14 per Mcfe for the third quarter which includes our LOE, G&A, TOTI and interest.

Operating income from our Midstream Services segment grew 13% in the third quarter to approximately $75 million, primarily due to the increase in gathering revenues from our Fayetteville and Marcellus Shale plays. The cash flow generated by our Midstream Services segment, combined with our strong hedge position, protects approximately 60% of our total expected cash flow for 2012.

Our balance sheet continues to be in good shape with a net debt to book capitalization ratio of 32% and a total debt to trailing EBITDA ratio of about 1.0 times. To remind everyone, we have an unsecured $1.5 billion credit facility which had very little drawn on it at the end of the quarter, and had cash and restricted cash at the end of the quarter of $146 million, so our liquidity continues to be very strong. With our planned total capital investment program for 2012 of $2.1 billion, we expect to end the year with nothing borrowed on our credit facility.

Looking ahead, we remain focused on keeping our costs as low as possible, maintaining a strong balance sheet and being good stewards of our capital investments. That concludes my comments, so now we’ll turn back to the operator who will explain the procedure for asking questions.

Questions and Answers

Operator: Thank you. (Operator Instructions) Our first question is coming from Dave Kistler from Simmons and Company International. Please proceed with your question.

Dave Kistler: 'Morning, guys.

Steve Mueller: Good morning.

Dave Kistler: Real quickly, as we look at kind of a multitude of new venture opportunities and getting more color on those in I guess the fourth quarter call, can you give us maybe some color with respect to spending on those plays between here and there and maybe with respect to '13? As you guys are gathering information, are you considering or pursuing bringing in a partner into any of the plays?

Maybe -- Probably the one you have the most information on and it would be the Brown Dense at this point.

Steve Mueller: As far as '13 goes, and really as you look out into the future, I would just assume that not much more than about 10% to 12% of our capital budget will be going towards new ventures on average. I think the individual year might be a little bit higher. So that's going to be a relatively constant number just depending on what your total capital budget is in any given year.

For the rest of this year, from a pure capital investment, while we're picking up some acreage in some areas, there's not a significant amount of drilling to do between now and the end of the year. So most of our capital is invested at this point in time. And then your other comment about bringing in a partner. We'll look at each of our plays and we've talked about this in the past in New Brunswick. We definitely ultimately will need a partner. It's just a matter of when to bring them in. Some of the other plays may end up needing to have partners for various reasons, whether it's to look at the risk standpoint or whether it's just total capital invested, and we'll just look at that as we go along.

So I think that we just put that in the normal course of business and we just figure out when and if we want to do it in any of those places.

Dave Kistler: And then as a follow-up, IPs -- initial IPs in the Fayetteville based on kind of picking your best quality wells off the charts kind of record number for you guys, but the 30th and 60th day are kind of lagging that same kind of change. Can you walk us through when we would expect to see that reflected into the 30th and 60th day?

Steve Mueller: I'll let Bill handle that one.

Bill Way: The 30, 60 days are in fact lags. Some of our best wells came on in September in our optimization program and they're now just moving into those averages. You'll recall we had a little bit of weather impact in July that we reported last quarter, but the main reason is really just the lag effect of rolling them into the averages, and we expect those averages will come up as we move in through the fourth quarter.

Steve Mueller: And I think if you look at that table, there's like 43 wells is all that's in that 60 day number. Once we get all 100 plus wells into it, it'll come back up.

Operator: Our next question is coming from Brian Singer from Goldman Sachs. Please proceed with your question.

Brian Singer: I apologize if I just missed it, but can you give some color on how you're thinking about 2013? I know there's not necessarily specifics here, but just from a CapEx perspective relative to cash flow, relative to this year's budget, and how you're thinking about balancing between the Fayetteville, and Marcellus, and new ventures?

Steve Mueller: We really haven't given much guidance on 2013. We're still working on that and typically towards the end of the year we normally put out a press release that talks about our 2013. So I would expect something later this year, early next year on actual 2013. Obviously, we talked about in the past that we're increasing rig count in the Marcellus and we'll exit the year with four rigs doing basically the horizontal work there. That will increase the capital budget on Marcellus side. So I can see a weighting that's more Marcellus oriented next year versus the dominant the last few years where the Fayetteville

has been 75% to 80% of the capital. You'll see that more balanced. It may not be balanced, but more balanced.

And then midstream in general, a lot of the work has been done in the Fayetteville Shale, and in the Marcellus we've got another year in the same category we had now where it's $80 million, $90 million. So I'd say midstream is flat or a little bit down as we look toward the future. And then as I said before on the new ventures, expect 10% to 12% of our capital budget to go to new ventures.

Brian Singer: That's helpful. Then a couple questions on the Marcellus. I think you highlighted the backlog or the wells that are uncompleted in your release. Can you just talk to a couple things? One, it really looks like your EURs are at or above the 10 Bcf type. Would you agree with that and does that translate into bookings when it comes to the end of this year?

And then second, how do you expect to meet -- to get up to the 300 million a day? Do your existing wells have a lot of additional production potential? Or did some of that backlog come on to meet the midstream constraints?

Bill Way: Our expectations on wells are meeting or exceeding what we thought they would be. So we have no change really in that. It's looking very good so far. The majority of our production obviously comes out of the Greenzweig area. And so, we've seen some very solid strong performance in that area. That will translate through to reserves bookings. The bigger feature is the commencement of production out of the Range area. The Bluestone pipeline is well under construction. We expect to have that pipeline in service and operating around the end of November. There was no setback except for just days waiting for rain to stop. But we didn't lose any forward progress on that from the storm. So we expect to get that on. And once we can get some production history associated with those wells, we'll be able to move forward.

We are seeing an improvement from compression out of the Greenzweig area, about 25 million to 30 million a day. That combined with some wells waiting to be completed this quarter and the startup of the Bluestone and the Lycoming Area of production also around the end of November is the formula for getting us to 300 million a day exit rate out of Marcellus in total.

Steve Mueller: Let me add something to that. Our PUDs that we booked last year in the Marcellus are about 7.5 Bcf PUDs. Those were all in the Bradford area, what we call Greenzweig area. I expect that we will see some positive revisions on those. When you start looking at that range area that we just now are beginning to open wells up into, a lot of what you can book depends on what you see in those wells; so what could happen to us at year end, we may not get as many PUDs booked as you would normally expect, just because we haven't seen much production from the range area. But I fully expect from all the tests that we've seen that it will be a good area and that will grow as we go out into the future.

Brian Singer: And what are your current drilling completion costs in the Marcellus?

Bill Way: The wells are averaging between $6.4MM and $6.8MM depending on location. The newest Lycoming wells are obviously deeper and longer, but we're in that range.

Operator: Thank you. Our next question is coming from Scott Hanold from RBC Capital. Please proceed with your question.

Scott Hanold: Talking about the Marcellus a little bit, obviously you're infrastructure constrained right now, but you do have plans to get some more online. It seems going forward that's still really the governor on your growth there. What other things can you do or you've got other things you're doing to continually expand that? And is there always the opportunity to pay for other people's firms that they're not using?

Bill Way: Well, there are pipeline infrastructure constraints that are near term and that's represented in the Bluestone discussion, and we are working very closely with the contractor and owner of that pipeline to get that on as quickly as possible. But beyond that, we have been building a portfolio of transportation

capacity out of the Marcellus for some time. And our production growth over time is matched to that transportation capacity.

And the numbers, 300, 500, and then growing beyond that are matched with firm and long-term and short-term firm transport. And we are -- our team continuously looks at adding. We added some additional capacity this last quarter. I think it was 140 million a day through three different transactions. And so we believe that we're solidly covered and we're continuing to look at opportunities to expand that.

Steve Mueller: And let me just add, I know those who follow us closely, we've given out in the past a little spreadsheet that showed our firm and there's a little step jump in 2013. That has been smoothed and if you want a new spreadsheet just shoot Brad an email and he'll shoot you that spreadsheet.

Scott Hanold: Okay, I appreciate that. And my follow-up, looking at your gas price outlook, Steve, obviously it's sub $5 with constraints on the potential for more activity as prices go up, and the power generation switchback. How do you look at the Fayetteville in sort of that light? I don't know what your sort of near term look is, if it's the next day, three years. Where do you see activity there? At 450, do you kind of maintain your activity that you're doing right now in the Fayetteville or would you increase it at a certain price point?

Steve Mueller: I think from just a strategic standpoint, we really started in 2011 trying to keep the Fayetteville Shale within its cash flow with the thought that in the not too distant future it could generate excess cash flow to apply to some other things. And we do have a large backlog of wells to kind of what price we have out there. So I think as we look into the future, we will increase or decrease well count based on basically how much cash flow comes out of the Fayetteville Shale.

This year, we're drilling about 400 wells. We're not quite balanced. As we look into next year, I can tell you we'll start the year running seven or eight rigs and if you ran seven rigs all year that would be in the 350 type number of well range, again, depending on how fast you're drilling those kinds of things. So we will adjust it. As price gets higher and there's more cash flow, we'll drill more wells. On the other side of it, I don't know how much lower we'll go from where we're at right now. That's something we're talking about in our 2013 capital plans.

Scott Hanold: Okay, and it looks like your Fayetteville Shale costs have come down nicely this quarter. Do you anticipate more of that is going to happen and that you have more focused effort? Or where's sort of the bottom on that cost in the basin?

Bill Way: Well, our wells have come down in the quarter a lot due to reduced vendor -- we've gone and consolidated vendors and we're seeing some reductions in costs there. Our completion efficiency is up and we're really improving our work around that. A big change that happened in the quarter was sand, we were using between 80% and 90% of SWN sand across the Fayetteville. We've now done some work and are able to use 100% of our SWN sand across the field. So there are some rather dramatic reductions associated with that.

The next tranche of savings comes from our pumping company that I mentioned earlier. We'll pump a large number of wells next year. The savings is somewhere between $150,000, $160,000 per well that we pump. And so you'll see further reductions there and then we'll continue to chase further optimization. So I don't know -- I wouldn't speculate how far down it can go. We've made some rather dramatic strides in this area and we'll continue to take those down.

Steve Mueller: Let me just add one point. Part of that $2.6 million was cost decreases on the service side and we have locked in our cost for 2013. So we know what the base is and now we're working down from that base.

Operator: Our next question is coming from Hsulin Peng from Robert W. Baird. Please proceed with your question.

Hsulin Peng: So regarding -- I just kind of wanted to understand your total allocation. So one of the things I was trying to understand was the -- your midstream assets. How do you think about monetizing that midstream assets to fund your new ventures play going forward? Or would you rather bring an outside partner if needed?

Steve Mueller: Each play is going to be different. Certainly, we have, besides our current clean balance sheet and the fact that we haven't borrowed any of our borrowing line, we have some other assets that we could monetize in some way and midstream some of those other assets. And then you certainly have whatever you have a discovery on, whatever you're doing something on, you can sell part of it or bring a partner into part of that. It just depends on how big, how fast you're ramping up and what generally you found.

So I can't really say what we do with midstream or what would be first. I think the thinking is whatever the cheapest funding is, that's the one we'll look at doing first and then go from there.

Hsulin Peng: Second question is G&A this quarter was really good, and I was just wondering if you would think, is this quarter run rate a good indication for future G&A expenses? Or is there something unusual this quarter that made it much lower?

Craig Owen: Hi, this is Craig Owen. I'll take that. The G&A, we did have a good quarter for G&A. I wouldn't expect that would be the go-forward run rate. I'd probably look at the year to date G&A, $0.25, $0.26 or a little bit higher. We had some benefits in the quarter and some nonrecurring items. Nothing too substantial, but the $0.21 we experienced in the quarter, probably not a good go-forward rate. More around $0.25, $0.26.

Hsulin Peng: Then last question. The Brown Dense acreage went down a little bit this quarter and I was just wondering if you can help us understand why the acreage number went down?

Steve Mueller: Sure. And what she's referring to, I think we reported a little over 500,000 acres this quarter, versus, I think it was 540,000 or 550,000 last quarter. The main difference there is, in the far Northwest corner of the play, there was some acreage that we'd actually acquired from EOG that we let expire. And then we do have some acreage we double counted. But the biggest thing is we dropped some acreage on the far northwest corner.

Hsulin Peng: Okay. Thank you.

Operator: Thank you. Our next question is coming from Charles Meade, Johnson and Rice Company.

Charles Meade: I had a question on one of the wells that you talked about in your prepared remarks. I think it was the Dean well in the Brown Dense, that you said.

Steve Mueller: Yes.

Charles Meade: Did I get these numbers right? 200 barrels a day, and 1.2 million out of 12 feet of perfs?

Steve Mueller: That's correct.

Charles Meade: I'm curious; did you complete that in a different part of the formation? Is there something -- or did you have a different frac design? I know you talked about using linear gels. But the question is, is there something different you did there, because that looks like a really encouraging rate.

Steve Mueller: There are some things we did different. As Bill mentioned in his comments, the 2 vertical wells that we drilled, the first thing we want to do is determine if there was a extent to the high-pressure area; there was. But the other thing we found, and if you remember back to our very first well, one of the

issues we had was trying to get enough vertical extent on our fracs.

We found as we evaluated the BML well, that we still weren't getting the growth and height on our fracs that we were looking for. So we tried several different kinds of fracs in both the Johnson and the Dean wells. And in some cases they worked and some they didn't. In the Johnson well, I can tell you 2 of the 5, I think we've done so far, we screened out early because the frac that we're trying didn't work. But as we got towards the end of fracking in the Johnson well, we came to what I'll call a new formula. There's nothing magic about it. It just, just kept tweaking. And it looks like we're getting better vertical height.

We tried that on the Dean well. And while there's three intervals we fraced on that well, 3 separate fracs, and the perforations, as he said, weren't much perforations, it was about a 200-foot interval, it wasn't anything unusual over any of the other wells in the area. But when you look at the fracture area that it looks like it's contacted versus even the BML well that has over 4,000 feet, it's got almost 60% of the same fracture area. So it looks like we're starting to learn something on the fracture stimulations. And that well has held up very well. The numbers he quoted were on a 10/64ths choke. And we still have high 6,000 pounds bottom well flowing tubing pressure. So -- bottom well pressure.

So that well gives us encouragement, and we're using a variation of that for the most part. We're trying some things on the horizontal we're fracking right now. But we're using a site variation of what we did on the Dean on this horizontal that we're working on now.

So I can't say it's the answer, but I can say that we're getting closer just by working on the fracture’s stimulation. And it looks like we're getting a little better height than we were in any of the other fracs we've done to date.

Charles Meade: Got it. That's all very helpful, Steve. Thank you. It sounds like, am I right, you guys think that this is just kind of a combination of sand load and pump rate and some chemistry that you --?

Steve Mueller: It's just mix, and when you pour the sand in and how much water you put.

Charles Meade: Got it.

Steve Mueller: There's nothing magical about the fluids themselves.

Charles Meade: Got it. And then it also looks to me like you guys have set up a unit for the Johnson and Dean to be 12-80s. Is that -- are you guys committed to doing long laterals there or is that just an option for you at this point?

Steve Mueller: Just count that as an option right now. I don't know what the ultimate lateral lengths will be. Certainly, if you remember, our general game plan was from the first to the later wells, we were going to go from relatively shallow - 3,000 foot and work our ways up to 9,000 or 12,000 feet. That's somewhere in the game plan. But if we get some encouragement in some other wells like we're seeing in the Dean, it may not need that long lateral. So we just -- we're just going to have to work our way through that.

Charles Meade: Got it. And just to make sure I understand this right. It's the Doles that you're going to complete with this kind of -- with your new frac recipe?

Steve Mueller: Yes, Doles is the one that's completing right now -- is almost done. There's a total -- originally went in, wanted to do about 26 stages of fracs. I think we'll get 22 done and we're almost done with that. In the next couple days, we'll be done.

Charles Meade: And that's using what you've learned from the Dean well?

Bill Way: Yes, that's right.

Steve Mueller: Yes, we've learned from Dean and Johnson, and the other wells before it.

Charles Meade: But the BML is kind of -- is the older version of that frac?

Steve Mueller: The BML's the first well has fracs much more like we did in the first two before it. And there is a significant difference, yes.

Charles Meade: That's great detail. Thank you very much.

Operator: Our next question is coming from Brian Lively from Tudor, Pickering.

Brian Lively: Just on the Marcellus, you talked about having a smoother, I guess infrastructure profile for 2013. On the call, though, could you maybe talk about when do you think you could actually get to 300 million a day? Is that still slated for the end of the year or do you have an opportunity to pull that forward maybe towards mid-year?

Bill Way: We should get to 300 million a day exit rate by the end of this year. We've got the wells in production behind pipe, and the primary driver is waiting on the Bluestone Pipeline to be complete. We have the transportation, the long-haul transportation arranged and committed. So the restriction really is waiting on this piece of pipe. And the segment we're waiting on is 9 miles long, and it's got to connect our business to TGP300, and they're making some very solid progress.

Brian Lively: And then how will that build into 2013?

Bill Way: Into 2013, we should reach -- well, we expect to reach 500 million a day by the end of '13 and, so it will stair-step up in kind of a relatively smooth curve. There's some front-end sort of weather-related questions, but those are just normal for any kind of development in this part of the country. But really, it's expected to be just a pretty steady ramp up. We'll drill -- we expect to drill probably about 100, 103 wells across the field in 2013, based off of the comment Steve made earlier on 4 rigs, and we've built that and their completions into that profile. And we can, like Steve said, we've got a takeaway capacity graphic that we can send you. And if you look at that graphic, you have, the ramp pretty much follows that graphic.

Brian Lively: I guess I was confused. I had thought that you guys were going to be at 300 -- that you were going to be kind of more contained through 2013. But it sounds like you're actually going to --

Steve Mueller: Let me jump in. Again, if you look at our previous spreadsheet that we gave to everyone, there was a step where early in 2013, we jumped about 320 million, a little over 320 million a day and then we had a flat period all the way until November, where that's where we jumped up to 500 million. Today that number is, at the end of third quarter 380 million, at the end of the second quarter, it's 435 million, and then it's 542 million at the end of the year. So we smooth that out. So Brad will be happy to send you that. You can see how that looks.

Brian Lively: That's great. I'll follow up with him. It sounds like there's some biased upside to the numbers. And then just for me the last question, on the Fayetteville, the commentary about the Fayetteville being flat for the next couple of quarters, just wonder if you guys could put some more context around that in the vein of what 2013 might look like. Are you talking about flat through 2013, or are you talking about just flat maybe for the first half of the year?

Steve Mueller: I'm not sure about the flat comment. I think what I said was rig count. Right now we're running 7 rigs, and we'll go into the year running 7 rigs. And if you ran 7 rigs for the entire year, you'd have about 350 wells.

Brian Lively: Okay. Thank you.

Operator: Our next question is coming from Arun Jayaram from Credit Suisse.

Arun Jayaram: Steve, I wanted to ask you a little bit about, obviously you manage the business to the 1.3 kind of PVI target. Obviously you've had a very big hedging tailwind, so-to-speak, where you've had some very attractive hedges. But if you look on a year-over-year basis, the level of hedging games decreases relative to NYMEX. And I think that's a $300 million, $400 million kind of swing factor. You do have, obviously, lower costs in the Fayetteville today, $2.6 million a well, plus you're drilling perhaps at prime locations. So I'm just trying to get a sense of how all that factors in to, you've talked about maybe 350 wells. But what you're thinking about the Fayetteville, given the fact that you won't have as much hedging gains as in '12.

Steve Mueller: I think couple things there. First off, we are hedged, as we talked about. If we had flat production year-over-year, it would be a little over 30% hedged, and those are $5 hedges. I wouldn't assume that those are the only hedges that we have for the year. We're still looking, and I think you may see some other hedges go on.

But really your question is, 2013 budget and what's going to happen in 2013 budget. And we're still working on that all the way to the point of, I'm not ready to say what we think the price will be in 2013, yet - we have to sort that out. So all of that obviously works into the cash flow. Cash flow obviously is partially driven by how much capital you have, and you have to marry the 2 of those together. And we're not quite there yet to say how many wells we're going to drill in each area. The only thing that we've certainly committed to is because of the 2 new rigs that we're adding, one's added already, one will be added in the Marcellus, that have long-term contracts on them, we know the activity will go up in the Marcellus.

Arun Jayaram: That's fair. And, Steve, I want to maybe elaborate on maybe the Marcellus. You guys have commented on the growth on a gross basis. Can you help us, walk us through, net of royalties, where you expect your production to be, because I think you have different working interests thinking about Susquehanna County versus a Bradford County. And just maybe give us a sense of where you expect to be on a net basis.

Steve Mueller: I think if you just think about it in general, the Susquehanna/Bradford area for the foreseeable future will almost be 100% working in just wells. I think we're averaging this year 98% or something. Later on there will be some -- and when I say later on, a few years out there will be some other wells that have some lower interest. I think our average working interest, if you look across all of our acreage, is probably in the low 80% average working interest. But for the next year plus, you're at about 100% on the wells you're drilling. And then in your nets, you're about 82% to 83% nets. So as you look out into 2013, I'd use an 82% number.

Arun Jayaram: And final question, Steve. What are your thoughts, obviously very tight infrastructure in the Marcellus about basis differentials in that marketplace? What are you seeing today?

Steve Mueller: Well, because we have firm capacity, today we're seeing NYMEX pretty much flat. Some months it's a couple cents above, some months a little below. We have not seen anything we've had to do, much of the blowout that you might have seen or heard earlier in the year in some of the other areas. As we look out in the future, we think that the Marcellus will pull away on the basis a little bit. So our long-term planning is actually -- it widens and it's going to be a NYMEX minus some kind of number. But near term NYMEX flat.

Arun Jayaram: Okay. And I have to ask, to be able to get that capacity to smooth out that, what was the consideration that you had to do to get that firm transportation, smooth out the pipeline transportation capacity?

Steve Mueller: It's the same we're paying for all of our other transportation. Actually in some cases, a little bit less. What this is, when you buy firm typically on a pipeline, you're buying long-term firm. In this case, there were operators who can't supply their firm for short periods of time. Some of these contracts we have are 6-month-type contracts. And all we're doing is buying from operators who couldn't use it. So

we're buying at their rate or lower than their rate because they were going to have to pay it one way or the other.

Arun Jayaram: Okay. Fair enough, Steve. Thanks.

Operator: Thank you, our next question is coming from Dan McSpirit from BMO Capital Markets. Please proceed with your question.

Dan McSpirit: Thanks. Good morning. Turning back to the Brown Dense, you speak to a path to commerciality. If you could share with us the determining factors involved and the expected timing, maybe a more definitive answer or color on a go or no-go decision in the Brown Dense? And in answering that if you could share with us the current drilling and complete cost for the latest batch of wells and what’s expected going forward?

Steve Mueller: As you look out into the future there’s – I would put two things that we have to understand, and I think both of those we’ll know a lot about in the next three months. The first one, and we’ve talked about this in the past, we haven’t got a long production life on any of these wells, and so we need to understand the shape of that production curve. We do all of our economics based on an average Eagle Ford because of depth and pressure considerations, but we haven’t got ourselves an average production curve here yet. And we’ll put the two wells that Bill talked about on production this month. We’ll have by January two-and-a-half months of production on those, or two plus months of production, and when we add that to the testing we had earlier we’ll be able to figure the shape of those curves.

The other thing we’ve already talked about, you want to contact as much of the rock as you can, and you’re going to have to have vertical height on your fracs because you’re looking at a 350 to 400-foot integral. And, frankly, our first well we got about 25 to 30-foot height growth and even in this most recent one I talk about we’re looking at about 90 to 100-foot growth. So we still need to do some things on fracking side to get across more of the zone and contact more of the reservoir. So we’ll continue to work on the fracking. Whatever we learn in this horizontal we’re doing now, we’ll apply that and go out in the future. So those are the two main things there.

As far as costs, rather than go into the various costs in each well, we do something internally where we call it pacesetter. We take the wells that we’ve drilled and whatever the best piece of that well was, whether it’s the vertical part up hole, or whether it’s the horizontal, or building in the curve, and we put that together and say we know we can do that. And all we have to do is do it consistently and here’s what it’s going to be. And then from there we improve, and we go from there.

On a pacesetter well, and let me just put it in days to drill, this most recent well, Doles well, took us about 55 days to drill a pacesetter well. Like I said, one where we just did everything the way we’ve done, and had success in the past on each individual portion, would be about a 35-day well for that same well.

And when you start talking about 35 to 40-day well, going back to my comments on the second quarter conference call, you’re talking about $10 million to $12 million type wells. This – the well we’re in today on the Doles is about $12 million, but it’s not significantly above $12 million. So we’re in the range and we can see a way to get our costs down.

Let me also add on the economic side, historically we’ve talked about the fact that we needed a certain rate and we threw out any gas, we didn’t worry about any of those kinds of things. But if we can do a $12 million dollar well to reach our 1.3 PVI, historic economic hurdle, we need about 425 barrels a day of oil and about 4.2 million a day of gas when you count that in. That’s $80 oil, LLS price, and it is a little over $3 NYMEX price, and you put BTUs on that and the well, and that’s the economics for that.

Dan McSpirit: Thank you.

Operator: Thank you. We have reached the end of our question and answer session. I’d like to turn the call back over to Management for any further or closing comments.

Steve Mueller: Thank you. To wrap-up things, again, I want to say how proud we are of the results of the quarter, and I want to thank all of our employees for the hard work they’ve done to achieve the results. And we will continue to keep doing the everyday things that will add value, and I talked about it in all the presentations and I talked about it with our employees – our goal is never just to add value, it’s to add value plus and give you something more. And I think we’ve done that in the third quarter.

I also want you to know we’re not comfortable, we have several ideas on how to improve what we’re doing in the Fayetteville and Marcellus plays, which will translate to better, faster, cheaper and ultimately more wells to drill over the life of the field. It also means that we’re going to keep that focus we talked about and discipline on doing everything with the 1.3 PVI economic objective.

And then when we look, finally, at our New Ventures Team, we’re now generating tangible and new ideas that are needed to significantly impact our Company. We’re going to have some more and expect some more ideas in 2013, but at the same time we’re learning at a rapid rate about what makes each of our current plays work. And we’re very encouraged that in 2013 we’ll provide at least one new development project for SWN so we can apply all those things we’ve learned in the Fayetteville Shale and Marcellus.

And, with that, I thank you again for listening today, and have a wonderful weekend.

Operator: Thank you. This does conclude today’s teleconference. You may disconnect your lines at this time, and have a wonderful day. We thank you for your participation today.

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.

See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the three and nine months ended September 30, 2012 and September 30, 2011. 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.

Explanation and Reconciliation of Non-GAAP Financial Measures

3 Months Ended Sept. 30,

2012

2011

(in thousands)

Net income (loss):

Net income (loss)

$

(144,815)

$

175,173

Add back:

Impairment of natural gas and oil properties (net of taxes)

276,644

--

Net income, excluding impairment of natural gas and oil properties

$

131,829

$

175,173

9 Months Ended Sept. 30,

2012

2011

(in thousands)

Net income (loss):

Net income (loss)

$

(525,211)

$

479,236

Add back:

Impairment of natural gas and oil properties (net of taxes)

855,522

--

Net income, excluding impairment of natural gas and oil properties

$

330,311

$

479,236

3 Months Ended Sept. 30,

2012

2011

Diluted earnings per share:

Net income (loss) per share

$

(0.42)

$

0.50

Add back:

Impairment of natural gas and oil properties (net of taxes)

0.80

--

Net income per share, excluding impairment of natural gas and oil properties

$

0.38

$

0.50

9 Months Ended Sept. 30,

2012

2011

Diluted earnings per share:

Net income (loss) per share

$

(1.51)

$

1.37

Add back:

Impairment of natural gas and oil properties (net of taxes)

2.46

--

Net income per share, excluding impairment of natural gas and oil properties

$

0.95

$

1.37

3 Months Ended Sept. 30,

2012

2011

(in thousands)

Cash flow from operating activities:

Net cash provided by operating activities

$

355,087

$

443,281

Add back (deduct):

Change in operating assets and liabilities

61,523

29,313

Net cash provided by operating activities before changes

in operating assets and liabilities

$

416,610

$

472,594

9 Months Ended Sept. 30,

2012

2011

(in thousands)

Cash flow from operating activities:

Net cash provided by operating activities

$

1,192,477

$

1,300,211

Add back (deduct):

Change in operating assets and liabilities

(50,520)

12,129

Net cash provided by operating activities before changes

in operating assets and liabilities

$

1,141,957

$

1,312,340

3 Months Ended Sept. 30,

2012

2011

(in thousands)

E&P segment operating income:

E&P segment operating income (loss)

$

(296,108)

$

228,476

Add back:

Impairment of natural gas and oil properties

441,465

--

E&P segment operating income excluding impairment

of natural gas and oil properties

$

145,357

$

228,476

9 Months Ended Sept. 30,

2012

2011

(in thousands)

E&P segment operating income:

E&P segment operating income (loss)

$

(1,039,737)

$

629,298

Add back:

Impairment of natural gas and oil properties

1,377,364

--

E&P segment operating income excluding impairment

of natural gas and oil properties

$

337,627

$

629,298

Net Debt Reconciliation

(in thousands)

September 30, 2012

Total Debt

$

1,696,542

Stockholder’s Equity

3,253,279

Total Capitalization

$

4,949,821

Total Debt

$

1,696,542

Less: Cash and Cash Equivalents

(18,560)

Less: Restricted Cash

(127,074)

Net Debt

$

1,550,908

Net Debt

$

1,550,908

Stockholder’s Equity

3,253,279

Total Adjusted Capitalization

$

4,804,187

Total Debt to Total Capitalization Ratio

34.3%

Less: Impact of Cash, Cash Equivalents and

Restricted Cash

(2.0%)

Net Debt to Adjusted Capitalization Ratio

32.3%


1-08246		71-0205415
(Commission File Number)		(IRS Employer Identification No.)

Exhibit Number		Description

99.1		Teleconference transcript for November 2, 2012 telephone conference call for investors and analysts.


	SOUTHWESTERN ENERGY COMPANY

Dated: November 6, 2012	By:	/s/ R. CRAIG OWEN
	Name:	R. Craig Owen
	Title:	Senior Vice President and
		Chief Financial Officer

Exhibit Number		Description

99.1		Teleconference transcript for November 2, 2012 telephone conference call for investors and analysts.


	3 Months Ended Sept. 30,
	2012	2011
	(in thousands)
Net income (loss):
Net income (loss)	$ (144,815)	$ 175,173
Add back:
Impairment of natural gas and oil properties (net of taxes)	276,644	--
Net income, excluding impairment of natural gas and oil properties	$ 131,829	$ 175,173


	9 Months Ended Sept. 30,
	2012	2011
	(in thousands)
Net income (loss):
Net income (loss)	$ (525,211)	$ 479,236
Add back:
Impairment of natural gas and oil properties (net of taxes)	855,522	--
Net income, excluding impairment of natural gas and oil properties	$ 330,311	$ 479,236


Net Debt Reconciliation
(in thousands)
	September 30, 2012

Total Debt	$ 1,696,542
Stockholder’s Equity	3,253,279
Total Capitalization	$ 4,949,821

Total Debt	$ 1,696,542
Less: Cash and Cash Equivalents	(18,560)
Less: Restricted Cash	(127,074)
Net Debt	$ 1,550,908

Net Debt	$ 1,550,908
Stockholder’s Equity	3,253,279
Total Adjusted Capitalization	$ 4,804,187

Total Debt to Total Capitalization Ratio	34.3%
Less: Impact of Cash, Cash Equivalents and
Restricted Cash	(2.0%)
Net Debt to Adjusted Capitalization Ratio	32.3%

EXPLANATORY NOTE