SWN Q2 2012 Teleconference Transcript

Operator: Greetings, and welcome to the Southwestern Energy's second quarter 2012 earnings teleconference call.

At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. (Operator Instructions)

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

Good morning and thank you for joining us. With me today are Bill Way, our Chief Operating Officer, Greg Kerley, our Chief Financial Officer, Jeff Sherrick, 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 second 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.

Now let’s begin. Bill and Greg will talk about SWN’s second quarter performance and will compare several important numbers. I want to take just a minute and talk about the one number that was foremost in our minds – the average second quarter NYMEX price of $2.22 per mcf. That is a 26% reduction from year-end 2011! The swift and rapid decrease in gas price has caused a 49% year over year decrease in total industry rigs drilling for gas in the US. SWN is also rapidly adjusting to the price changes but rather than retrenching like the rig count our emphasis on Value+ allowed us to continue our strong progress in every investment area in the second quarter. As we mentioned last quarter, investing in the best wells in the Fayetteville Shale has increased the initial production rates and more importantly, the quality of the completed wells. In addition, we continued to decrease days to drill below our recent

year-end 2011 estimates. The Marcellus production is ramping up and we are encouraged about what we are seeing in our New Ventures projects. Record production, faster times and lower costs are a product of a culture that is focused on Value+. I will now turn the call over to Bill for more details on the results of that focus in the second quarter.

Bill Way, Executive Vice President and Chief Operating Officer: Thank you Steve and good morning everyone. In the Fayetteville Shale, we placed 131 operated wells on production in the second quarter, resulting in net production of 121 Bcf, up from 116 Bcf in the first quarter and 107 Bcf a year ago, which was a new quarterly record for us. Our operated horizontal wells had an average initial production rate of 3.5 million cubic feet of gas per day, up from 3.3 million cubic feet of gas per day in the first quarter, an average completed well cost of $2.8 million per well and an average drilling time of 6.9 days during the quarter, which is the fastest quarterly drill time in the history of the play. We also placed 30 wells on production during the quarter that were drilled in 5 days or less. As you may recall, we have optimized our portfolio in the Fayetteville and are targeting the highest-return wells in the field. Going forward, we expect to see our average production on a per well basis improve over the next few quarters.

On the midstream side, our gas gathering business in the Fayetteville Shale continued its strong performance and at June 30th was gathering approximately 2.1 billion cubic feet of natural gas per day through 1,829 miles of gathering lines, compared to gathering approximately 2.0 billion cubic feet per day a year ago. Lately, our production in the Fayetteville has been affected by the recent extremely high temperatures in central Arkansas and, year-to-date, we estimate that production from the field has been impacted by almost 1.0 Bcf due to the extreme heat. Since June 30, however, our gross production rate has returned to approximately 2 Bcf per day, however we still continue to manage the effects of the heat on our compressors and dehydration facilities.

In Bradford and Susquehanna Counties in Pennsylvania, we had 41 operated Marcellus Shale wells on production at the end of the quarter resulting in net production of 9.9 Bcf, which is up from 5.1 Bcf in the same quarter in 2011. Gross operated production was approximately 166 million cubic feet of gas per day at June 30. Since that time, our gross production rate from the area has surpassed 200 million cubic feet of gas per day.

Our operations at Greenzweig continue to go very well, with 39 producing wells on line. We also just placed additional compression on line at Greenzweig which already allowed us to increase our rate from the area.

We began selling gas from our Price area in Susquehanna County in May and we had 2 wells producing at a combined rate of 10 million cubic feet of gas per day at June 30 without the aid of compression into TGP 300.

In our Range Trust area, which is approximately 70,000 net acres in Susquehanna County, we have completed and flow tested 3 wells to date before they were shut-in waiting on pipelines. The wells were only flowed for a short time period to avoid flaring of gas and showed strong performance in the initial 5-day flowback period. Productivity calculations for all three wells indicate that Greenzweig-type performance should be expected once the wells are turned to sales in the fourth quarter.

In New Ventures, we hold approximately 3.7 million net undeveloped acres, of which 2.5 million net acres are located in New Brunswick, Canada.

In our Lower Smackover Brown Dense play in southern Arkansas and northern Louisiana, we have over 560,000 net acres leased, we have drilled four wells in the play to date and we are currently drilling two additional wells. Our first two wells were completed earlier this year and are currently shut-in for testing. Our third well, the BML located in Union Parish, Louisiana, was drilled to a vertical depth of approximately 10,400 feet with a 4,300-foot horizontal lateral and was completed with 19 successful fracture stimulation stages in June. After 41 days of flowing up casing and after approximately 43% of the load recovered, this well’s highest 24-hour producing rate to date was 421 barrels of 50o API oil per day, 3.9 million cubic feet of gas per day and 836 barrels of water per day with a calculated flowing bottom hole pressure of 5,700 psi on a 24/64-inch choke. The BML well also averaged 353 barrels of oil per day and 3.3 million cubic feet of gas per day for more than 30 days during the test period.

We have installed tubing and we have shut the well in order to perform a pressure build-up test and wait on pipeline connections. Once pipeline connections can be completed, we expect to begin selling both oil and gas from the well in the fourth quarter of 2012. The oil pricing we are receiving from this area is at a premium to WTI and analysis of the gas shows a high Btu content of around 1,220, so we would receive a premium to Nymex due to the richer gas liquids. We are encouraged by the BML’s results, however we also know that we have more to learn in order to make the play economic.

Our fourth well, the Johnson located in Union Parish, Louisiana, was drilled to a vertical depth of 10,507 feet in July. Like the BML well, this well also encountered unusually high pressure within the target formation. We will complete this well vertically in order to test the effects of fracturing fluid and sand type on reservoir performance, however it will be able to be re-entered as a horizontal well in the future. We also commenced drilling on the Dean well located in Union Parish, Louisiana, which is currently drilling at approximately 8,325 feet. This well is planned to be drilled to approximately 10,450 feet and be completed vertically. Finally, we are also drilling the Doles well located in Union Parish, Louisiana, which is currently drilling at approximately 6,375 feet to a planned measured depth of approximately 17,300 feet with a 6,000-foot horizontal lateral.

In our Denver-Julesburg Basin oil play in eastern Colorado we have leased approximately 290,000 net acres and completed our first well in July, the Ewertz Farms located in Adams County. This well was drilled to a total vertical depth of 8,550 feet with a 2,000-foot horizontal lateral targeting the Marmaton formation. We are in the early days on this well with less than a quarter of flowback having been recovered, but we are encouraged as oil production began on Day 3 after flowback commenced. The highest 24-hour producing rate to date for the Ewertz Farms well was 65 barrels of oil per day on a pump, 40 Mcf of gas per day and 740 barrels of water per day. We have also drilled the Staner 5-58 #1-8 well located 20 miles away in Arapahoe County to a total vertical depth of 9,650 feet. This well is planned to be completed in August as a vertical completion. We will evaluate the production from these two wells over the next 90 days and additional drilling in the area is planned near the end of the year.

In New Brunswick, we have deferred our planned 2012 exploration program until 2013 to provide additional time for public engagement and completion of the permitting process. The Department of Natural Resources and other key government officials support this decision and we will continue to work together with the appropriate parties to be able to accomplish the work we would like to do in 2013.

Finally, we spud our Bedwell horizontal well in Sheridan County, Montana on July 10 targeting the Bakken/Three Forks objectives. This well drilled through the objective section and reached a total vertical depth of 8,619 feet. We are currently drilling the curve at approximately 7,600 feet TVD with a planned 3,200-foot horizontal lateral. At this time, this is all we are going to say about this area.

In closing, we continue to do the Right Things – which is focusing on PVI, driving down our costs and continuing the innovation process across all our existing assets and new plays. We also are encouraged about our New Venture ideas and have additional exciting ideas that will come to the surface at a later date. I look forward to reporting back to you next quarter on our progress. I will now turn it over to Greg Kerley, our Chief Financial Officer, who will discuss our financial results.

Greg Kerley – Executive Vice President and Chief Financial Officer: Thank you, Bill, and good morning. We reported earnings for the second quarter of approximately $91 million, or $0.26 per share, excluding the non-cash ceiling test impairment of the company’s natural gas and oil properties which resulted from low gas prices.

Our discretionary cash flow was $355 million in the second quarter and $725 million for the first six months. Despite significantly lower natural gas prices our year-to-date discretionary cash flow is down only 14%, due to our production growth, strong commodity hedge position and performance of our Midstream business and our low cost structure.

Our average realized gas price of $3.12 per Mcf for the quarter, was down 27% from the same period last year, while Nymex settlement prices for the second quarter were approximately half of what they were a year ago. Our realized gas price included gains from our commodity hedging activities which increased our average gas price by $1.36 per Mcf during the quarter. For the remainder of 2012 we have 134 Bcf of our gas production hedged at a

weighted average floor price of $5.16 per Mcf. This strong commodity hedge position, along with the cash flow generated by our Midstream Services business protects approximately 60% of our expected cash flow for 2012.

Operating income for our E&P segment was $76 million during the quarter, excluding the non-cash impairment, compared to $222 million in the same period last year.

Our cost structure continues to be one of the key drivers of our financial results and is one of the lowest in the industry, with all-in cash operating costs of $1.20 per Mcfe for the second quarter which includes our LOE, TOTI, G&A and interest.

Operating income from our Midstream Services segment grew by 20% in the second quarter to approximately $72 million. The increase in operating income was primarily due to the increase in gathering revenues from our Fayetteville and Marcellus Shale plays.

Our balance sheet continues to be in good shape with a net debt to book capital ratio of a little less than 30% and a total debt to EBITDA ratio of about 1.0. We currently have nothing drawn on our unsecured $1.5 billion credit facility and also had cash at the end of the quarter of around $41 million and restricted cash from the sale of our Overton properties of approximately $144 million, which further strengthens our liquidity position.

Year to date, we have invested $1.2 billion, including $1.1 billion in our E&P business. Our planned total capital investment program for 2012 remains at $2.1 billion and was front-end loaded in the first two quarters by design, so we expect a decline in our capital investing during the third and fourth quarters of the year and as a result we expect to end the year with no additional increase in our total debt level from where we are today and also expect to hit our production targets.

Looking ahead, we are focused on keeping our balance sheet in good shape and will remain vigilant in reducing our costs even further and remain flexible in our decisions on capital investments. That concludes my comments, so now we’ll turn back to the operator who will explain the procedure for asking questions.

Operator: Thank you. We will now be conducting a question-and-answer session. (Operator Instructions) Our first question is from the line of Scott Hanold of RBC Capital Markets. Please proceed with your question.

Scott Hanold: Obviously, I think Smackover would be an area of focus and so I guess my question is would you give us your view on what you think is going to go on with the well? It's got a lot more gas relative to some of the other ones and that bottom-hole pressure seems incredibly high. I mean, what is your interpretation of what's going on and what does that portend potentially to like EUR and longer term productivity?

Steve Mueller: Scott, we don't know exactly what the overall result is going to be here. That's why we're drilling the two vertical wells and doing some testing on those, but as we discussed last quarter, that BML well did hit some pressure that's significantly higher that we've seen in the other wells. And you're seeing that in the bottom-hole pressure, you're seeing that in the rates, and it's giving us a lot of encouragement.

As far as the gas and the oil, when you go back and look at the second well, the second well had similar ratios of gas to oil. It didn't have quite as high rates, so this one looks a lot more like the second well than it does the first well, but with the high pressures, we're still trying to sort out exactly what the meaning of that is. We won't know probably for another 45 to 60 days, actually seeing the details and all the numbers from the core data, but in looking at it through just visual inspection, it looks like the zone that we have in the BML well and in the two vertical wells, the one vertical well in TD to date, and hopefully, in the other wells we get down, it has more dolomite in it and

actually has a little bit of silt in it as compared to the second and first wells that had more carbonate in them, but what that means to porosity permeability, what that means -- where it goes and how it works, we're still trying to figure that out,

Scott Hanold: So would this be -- and obviously, just broadly speaking -- kind of analogous to what you have in the Bakken where you've got like a dolomitic sandstone near a shale that tend to be more productive? Am I reading in a little bit too much into it?

Steve Mueller: No. There could be a little bit of that, but basically, it looks like more than half the zone is somewhere in that range. 40% to 60% of the zone has this different characteristic to it in that third and fourth well, though we didn't see it in the first two wells.

Steve Mueller: And to remind everyone, the total zones that we're looking at in these third and fourth wells is about 450-foot thick, so it's a fairly thick interval as opposed to Bakken which is a fairly thin zone with shales on either side of it.

Scott Hanold: Okay. And then maybe moving to the Marcellus, so it sounds like the infrastructure has come on line, so we're going to see a pretty good step-function now that you've got some of the firm, and how many wells do you have, I guess, in backlog inside? I think you said 41 producing. How many are in backlog and are expected to be bought on production in the second half of the year?

Steve Mueller: I think in the second part of the year, we're looking at between -- probably around 60 or so wells, 60-plus wells, that we'll have to put on production. Let me also clarify. While we are -- our production is increasing, the key step-jump that you're talking about is the Bluestone line. That Bluestone line is not operational yet, and it looks like it will not be operational until sometime in the fourth quarter. We will continue to have an increase in production, but the Bluestone by itself should be almost 100 million a day production late in the year. So that's still to come and then we'll continue to put lines on.

As we talked about, and as Bill talked about, almost all the wells we have on line to date are along the Stagecoach pipeline in the Greenzweig area. We only have those two wells down in Price and the southern Susquehanna on line, and all the wells are drilling in that northern Susquehanna block that Bill mentioned had -- we had three wells we tested. Those will all come on right at the end of the year.

Operator: Thank you. Our next question is from the line of Dave Kistler of Simmons & Company. Please proceed with your question.

Dave Kistler: Good morning, guys. Kind of a bit of a big-picture question here -- as we start thinking about 2013, and looking at your New Ventures program, you've got a number of more visible efforts than you have in the past. It looks like we're focusing on a period of continued weak gas prices. Most of the Fayetteville is held by production. How do we think about how spending looks for next year? Do you maybe shift down activity in the Fayetteville, take up New Ventures more than you have in the past? Do you even consider for New Ventures doing some acquisition-type activity? So a very big-picture, but would love to get any color you can give us in that direction.

Steve Mueller: Well, our first hope is we've got three discoveries and we really have an issue that we have to figure out how to fund all of them. Now, from a practical standpoint, I don't know that we'll have that in 2013. We'll just have to look at it. When we talked about it in the past, we're driven on present-value index and if we find something in New Venture, and it's better than anything we have, then anything is potentially on the table to fund that better project. If, for instance, it's better than the Fayetteville, and not quite as good as the Marcellus, then you have a different way to fund and you start moving dollars around.

And certainly, we have capacity. As Greg mentioned, we've got a balance sheet that's clean, we've got our borrowing line that we can borrow on until we start any kind of New Venture program, and we've got other ways that we can access capital. So I think the big key is find something that's good, figure out how good it is, and once we find that, we'll figure out a way to fund it and everyone, I think, will be happy with that.

Dave Kistler: Does that include though maybe looking at acquisitions a little different than in the past where things have been organically driven?

Steve Mueller: We certainly have a group – and Jeff Sherrick, who's in the room, is part of -- heads up that group that is looking for ways both to supplement our New Ventures group, where they come up with ideas and there may be acreage that has some kind of held by production characteristic to it, or if we want to get into an area and the best way to get in the area is acquisitions -- and I don't think that slows down or speeds up based on what we find in New Ventures. I think if anything, it's just part of the overall plan. We really don't care how we do it. It's just a matter of finding those good projects and going on down the road from there.

Dave Kistler: Okay. I appreciate that color. And then maybe one micro question -- looking at the Fayetteville specifically and the 60-day IP rates, it looks like over the last year or certainly since 3Q '11, the 60-day rates have tended to trend down. Can you talk a little bit about maybe what's happening there? Obviously, we're seeing the initial IP start to go up as you are high-grading your portfolio, but looking at the 60, they seem to be slipping a little.

Steve Mueller: If you remember, in 2010 and the first half of 2011, we drilled a significant number of wells. It ended up to be almost 600 wells basically over those two years, a little over 1,000 wells drilled. Now, we test down-spacing and certainly, as you get the wells closer together and start seeing the interference from them, at some point -- out past the initial rate, you'll start seeing the effects of that.

And then in the second half of 2011, we started actually doing the drilling, picked our space that we thought would be appropriate for each of these and then started drilling, pad drilling. And so we always talked about expect in 2012 and beyond that you're going to start seeing that interference and you could see it in the 60-day numbers, and then you'll certainly see it in the overall numbers when we talked about 10% to 15% type interference.

What's actually happened, and what you're seeing in the IPs, is at the beginning of this year, when the drop in the gas prices there, we went to drilling the best wells, not worrying about drilling pad wells. We widened out the spacing on those wells and we talked about last quarter expect that the IPs would be better in the second half of the year. You're just starting to see that with our second quarter production.

And if you think about the 60-day rates, the 60-day rates are reflecting the very beginning of this quarter with the numbers. You don't have the June data in there. You're not going to see the June data for another 45 days or so. And so you should see that whole curve move up as it goes in the future, but again, it's going to move up because we're drilling the very best wells. Once we get back to pad drilling, whenever that is, then you're going to have the same interference issues and you'll start seeing those numbers work back down again.

Operator: Thank you. (Operator Instructions) Our next question is from Brian Lively of Tudor, Pickering, Holt. Please state your question.

Brian Lively: Hi, just a couple of follow-ups, one on the Brown Dense well -- the fact that the well had 5,700 pounds of flow in bottom hole pressure and a 24-inch choke, that suggests that there was a lot more productive capacity in this well. At least, that's my assumption. I'm just wondering, maybe you guys can provide some color on what you think the well could have flowed at, at maybe more normalized conditions.

Steve Mueller: I don't know if we want to make a guess at that. Let me tell you what generally what we do with the well. We put the well on with a 16 choke, 16/64 choke, and basically flowed it through the entire period with a 16/64 choke. That 24 choke was only for two days and a total of seven days, our total flow period was something different than 16 choke.

What we were trying to do is a step-change to see what would happen with water rates, see what would happen with gas rates, see what would happen with oil rates. And while we got our best oil rate during that period of time, I can tell you that the water rate also increased. Right before we went from the step-up from the 16 to the 24, we had water rates -- oil rates in the mid-300 range and water rates in a couple of hundred barrel a day range, and as we stepped up, we started seeing higher water rates. And the whole idea here is to see what would happen, and really, I think that's what you need to think about the entire well.

We put it on a 16 or keep it on low rates even when we first put it on production later, or on low chokes, because we don't want to damage the reservoir in anyway, and we want to see what the reservoir can do. And then once we understand both what the reservoir can do and how the frac is working, later wells, we'll worry about what the rate or best rates could have been on them.

So again, just like the first couple of wells, we're trying to learn as much as we can with this well and you'll see in the two verticals we're drilling, we'll be trying some different kind of fracks to learn what we can, and then in that 6,500-foot lateral we talked about, that'll be drilled basically off the pad that the BML well is on, that well, we'll actually frac a little bit different and we'll have a whole different set of learnings. So we're continuing doing that learning path and at the same time, being very encouraged with what we're seeing.

Brian Lively: Okay. That's great. And so it sounds like the rates could have been better if you had opened the well up a little more, but that would be on kind of a total fluid basis. My follow-up is more --

Steve Mueller: Well, you can see we are moving a lot of fluid. That formation is giving up a lot of fluid between the water and the oil, and I'll just mention, the water that we're getting at this point in time, we still believe it's flow-back water. We're not seeing anything that hints that it's formation water. Certainly, that's one of the risks. As we go down the road, there could be some formation water there and we won't know that until we get longer tests, which on this well, will be later in the year. Sorry for interrupting.

Brian Lively: That's okay. Just a follow-up is kind on the actual stream itself. Assuming the gas is pretty high BTU gas, can you break out what you think the NGL volume would be for that gas stream?

Steve Mueller: The kind of stabilized BTU for that gas is about 1,200 BTU gas, so there is significant NGLs in it, and then we talked about on the oil that we should get a premium price. We did sell some oil at WTI plus $10 off of the lease, and the reason for that is there's four refineries in the area and about 135,000 barrels a day of refining capacity. One is in Arkansas and three in northern Louisiana and they really would like to have the oil condensate that comes off of it. So both the gas is going to be rich and we'll have some NGLs with it and the oil has a premium price to it.

Brian Lively: It's not unreasonable then to assume a couple hundred barrels a day of NGL volume barrels from this stream then, right?

Steve Mueller: Yes, we're still working on the analysis to figure out if it's a couple hundred or 150, or what that number is.

Hsulin Peng: Good morning gentlemen. A follow-up question to Brown Dense. Can you comment on the current well cost and also what you will like to -- what you are targeting for, for the wells to be commercial in terms of well cost, the oil volume, gas volume, IP rates, and EUR, that sort of thing?

Steve Mueller: We talked about in the past that we thought we could drill roughly $8 million wells here, assuming 4,000-foot laterals. That was at the assumption of the lower pressures. Today, and this may not stay this way, but today we're thinking we have to run at least one other string of pipe for the higher pressures, and probably will have a little longer lateral.

So if I had to guess today the number we're shooting for on the high pressure is somewhere between $10 million and $12 million from a well cost standpoint. When you start looking at how that works out on the economics, I think still that that 500-barrel-a-day range on the oil-only side still makes that work. It may have been 550 versus 475 before on the other, but it's still in that general range, especially when you start talking about the Btu that's on that gas.

Hsulin Peng: Okay. So the 500 barrel for oil -- so what -- does that include or exclude the gas, the NGO component?

Hsulin Peng: Okay. Got it. And then, and second question, just more macro-related, I just wanted to get your take on the gas production in the US overall, because we have seen that, production has been holding fairly steady, not really, hasn't really gone down. What is your -- what do you think when the gas production could turn over, potentially?

Steve Mueller: That's one of those, I wish I knew the exact answer to that. We could do a lot of things with it. But we expect that the gas is going to be slow in turning over. I think it's flattened out right now and will stay fairly flat for the next several months. The reason we believe it's going to stay flat for the next several months is that every area, while rigs are dropping, everyone's doing the same thing we're doing to the Fayetteville Shale - they're drilling their best wells. And so I think it's going to follow not the same shape, but the same general concept that happened to Barnett, where as the rigs dropped off, the Barnett production held fairly stubborn, flat for a while and now is starting to turn over. And predicting where the core areas are in each one of these areas and what the best wells are is difficult to do. And that's why I say, we're comfortable for the next several months that you're not going to see a strong turnover in production, but when and how, that's the real question.

Marshall Carver: Yes, good morning. Just a question on the Brown Dense. The second well, that Garrett 723-5/8ths well that you discussed on the last call, you talked about rates likely increasing as more load was recovered. Did that actually happen into May and potentially into June or did you shut it in before that and continued the ramp up? If you could give me any color there, I'd appreciate it.

Steve Mueller: We shut that well in a few days after the last conference call, have done an extended period trying to figure out the pressure on it. And this kind of ties into trying to understand the BML well as well and trying to tie core data pressures and everything together. And again, it had a fairly high gas rate and it -- the next time you'll see anything from that well is if we hook that well up and put it online.

Steve Mueller: We may do some work in the well, but you're not going to see much production from it for a while.

Marshall Carver: Okay. And what were the pressures on those first couple wells versus this much higher pressure third well?

Bill Way: Yes. Roberson well had 2,750 bottom-hole pressure. The Garrett was up to 4,100 bottom-hole pressure. And then the BML, as we said before, was at 5,700 flow in bottom-hole pressure.

Brian Singer: Thanks, good morning. In the Marcellus here, your exhibit showing your rate history and lack of decline, especially on some of the recent wells, makes it look like the wells could be producing more, and then you highlighted the lack of compression on some of your recent wells. In the absence of compression and midstream constraints, what do you think the Greenzweig range in price wells could be producing at? And what's the implication from the data that you're seeing on what the right EURs are from those wells?

Steve Mueller: Well, we certainly have some large EURs, and you can see that from that graph that we put in our investors play and put in the press release. I don't think you'll ever see a high rate from us, high being I've seen some numbers in the general area, 20 million to 30 million-a-day numbers. The reason for that is we're keeping the draw down across the perforations at a certain level. And that will limit the total rate of the wells and will make them look flat. And then, as you said, we've also got the other part of it that just some of these wells are so strong either we haven't had to put compression out there yet or we haven't turned the compression on because then it goes straight into the line, which acts like a choke and lets it stay pretty fairly flat.

So I think the other way to kind of answer the question is, we certainly have some wells in that Greenzweig area in Bradford County that match up with anyone else's wells that are out there from a productivity standpoint. It's just the way we're producing them may be a little different than some of the other operators are doing it.

Brian Singer: Okay, thanks. That's helpful. And then as a follow-up, have you seen anything in the portfolio that makes you want to reconsider monetizing some or all of your midstream business?

Steve Mueller: Not yet. The midstream business is there. It's continuing to grow. It's performing better than we had budgeted and kind of guided at the beginning of the year. And as you look out in the future, to monetize it, we're going to have to have some projects to put the dollars into. And those would probably, more than likely, be ventures-type projects. We've got the capital we need to do Fayetteville and the Marcellus. So at this point in time we're excited about having the midstream.

Charles Meade: Good morning gentlemen. Back to the Brown Dense, I know you guys have fielded a lot of questions on that this morning. I'm sorry to follow on this well-worn path, but maybe I'll ask something just a little bit different.

Relative to the earlier things about the flowing pressures, isn't really bottom hole, shut-in bottom hole's really what we should be most interested in?

Steve Mueller: I think you want to be interested in both, probably. You want the initial -- you always like to have an initial bottom-hole pressure that you can see where you started from, and that's something greater than 8,000 pounds. And then the -- basically, part of the science that we're doing is trying to understand how that pressure changes with certain rates as you go through. And one of the reasons we left it on a 16/64ths choke for that whole period, so we could see how that pressure responded. And that tells you something about permeability and talks a little bit -- tells you a little bit about the produce-ability of the formation. So you really need to need both.

Charles Meade: Yes, you kind of need all of them, because any one kind of in isolation, it's really the relationship between them that tells the story.

Charles Meade: On the -- when I look at your wells, the Doles and the Dean and the BML, and I put them on a map, they're all really close together and it really looks like, it kind of -- it gives the impression I think you guys certainly followed through on that this morning, that you guys think you're on to something here. But my question is, what kind of aerial extent, in terms of aerial extent, how large do you think this high-pressure area of the Smackover is? I mean, how large, how many kind of -- because it's all within a couple sections right now, at least is what I see and where your permits are.

Steve Mueller: Yes, we're trying to understand that. And since it was completely unexpected and then, just to remind everyone, there have been over 30 wells drilled previously to us going out and drilling that had gone into or drilled through the Brown Dense. They hadn't seen the high pressure. None of those wells have seen the high pressure. We drill our BML well. The first vertical part of the BML well did not see the high pressure. And then in the lateral, about 300 feet out in that horizontal's where you actually saw the high pressure, it took a kick, and so

So as you said, we stake the next few wells around the BML, so we've got something to compare back to. And so the first vertical well is only about 2 miles north. The 6,500-foot lateral where we're drilling is being drilled right next to that original BML well, and it's just a different direction to learn something that's going on that way. The other well, that Dean well that we talked about that's a vertical, that's about 6 miles due east.

And then if you look at the press release we had, and you'll see in our investor data, we have permitted some other wells, and those other wells start stepping out. Some of those wells could very well be high pressure, and there's probably some of those permitted wells that are back trying to test what we saw in the first two wells.

But we're just stepping out from what we know and trying to learn, just because it's kind of caught us off guard in our general overall thought process out there.

Charles Meade: Got it. And then I guess the follow-up to that step-out, it looks to me like one of your least -- one of your competitors, at least under their name, has it looks like permeated a couple of these 1,280 units just to the northwest of you guys. Are you guys going to be in that well or in those wells? Or are you familiar with those?

Steve Mueller: Yes, I know there's been some wells permitted around us. I do not -- I personally don't know if we have any interest in those wells.

Amir Arif: Good morning guys. The first question I had is just curious why you're doing -- I mean, an initial vertical I understand is a step out to see if the over pressure zone. But why the second vertical beyond that instead of just going ahead and testing horizontally?

Steve Mueller: I guess that second one, the easiest way to explain that is we just don't have enough information at this point. And when you think about having a 450-foot-thick zone, it's hard in a horizontal to make sure that you fracked completely across the zone. It's hard to figure out if you've -- what the productivity is, there's various parts of that. So we have a program worked out between the 2 verticals to test the things that we want to test. And that's just it -- that's the whole story there.

I wouldn't be surprised at all, once we get the test here on both the wells done, like Bill said, we will turn around and drill some horizontals from those locations. But we think it takes to wells to get all the things we want to learn. There is a slim chance that that first well, vertical, we can learn almost everything we wanted and we turn around and drill that second one as a horizontal without testing it. But right now, the way it sits today, I think we have to test both of them.

Amir Arif: Okay. And just a follow-up question. I apologize, I jumped in late, so I apologize if you answered this. But that 385,000 undisclosed acres in new ventures, do you know how much of that is in Montana or how many different plays that is spread over in terms of the remaining --

Steve Mueller: It is more than one, and that's all we'll say. And, certainly, there is some Montana acreage in there, because we haven't talked about Montana.

Operator: Our next question is from the line of Kevin Kaiser of Hedgeye Risk Management. Please state your question.

Kevin Kaiser: Hey guys. How do you think about picking up more natural gas acreage given the commodity price environment and maybe it's a bit of a buyer market there? Are you interested in acquiring more acreage either in the Marcellus or Fayetteville, or in a new venture?

Steven Mueller: There's not a lot of acreage in the Fayetteville, at least not available right now. Certainly, in the Marcellus you see each quarter we had a little bit of acreage. The numbers mainly only 2,000 or 3,000 acres, but we keep chipping away there. And if the right opportunity came along, we'd certainly like to continue building our position in the Marcellus. Gas in general, if there was an idea that economics were as good as the gas economics in the various areas we're drilling today and looked like they'd work was what we thought the forward curve was at, we'd certainly look at gas. We're not disposed to look for oil or look for gas today. With oil prices, it's a lot easier to find good oil projects, but ultimately we just want good 1.3 present value index projects. So that's what drives us. It's not the product.

Operator: Our next question is from Mike Kelly of Global Hunter Securities. Please proceed with your question.

Mike Kelly: Good morning guys. I was hoping you could talk about the status of the first two brown dense wells, and really I'm just curious the rationale for shutting them in versus keeping them on production.

Steven Mueller: Well, the first well, from what we saw in it is non-economic and really probably, at some point in time might be hooked up but would need some other encouragement in the area to lay the gas lines and do all the things to hook that well up. So the first well, just consider it an experimental well. The second well may get hooked up and we're looking at that right now, but again, the idea wasn't necessarily to make money off any of the first five or six wells that we had out there. The idea was to learn as much as we could. So, like in the case of the second well, when we saw the high pressures in the third, but saw similar type gas and oil, again, the first well had 38-degree gravity. The second and third had 50 and 52 gravity. What we wanted to do was figure out the characteristics that made the third different from the second, so we could start figuring out how to both predict where it could be and predict where its productivity would be.

So that's what's driving us on the second well. It's not hooking it up or producing along or any of those other things. We're just trying to do the most we can to learn as fast as we can, so we can figure out the play we're working on.

Mike Kelly: Ok thanks. And then I think it took a number of us by surprise to learn last quarter that you were drilling a well in the Bakken. And I'm wondering if this was a prospect that was generated under the new ventures group, or this was really an idea that was generated by the group you mentioned here on the call that was formed to complement or supplement the new ventures group. I think I've heard it called the Strategic Exploration Group, and if we could see that their influence have you guys drilling wells in some of these other new oil basins, like maybe a Tuscaloosa Marine Shale Well, the Utica, and any color that you could provide there would be great.

Steven Mueller: Sure. When you think about our Company and step back, oh, say four years ago or five years ago, we were concentrating completely on the Fayetteville Shale. We were picking up some acreage in the Marcellus, but did not have a concentrated effort on looking for new projects. So we started a new ventures group, got it up and running, and then about a year ago said, you've got new entries, you've got Fayetteville and Marcellus, but there's things that fall in between the cracks of those various groups. And that's when Jeff's group came together and Jeff's group I would put more as an M&A type group. They're out there looking at something that may have production on it, that may have upside to it, and it can supplement what the new venture is doing.

And then you talked about our Strategic Exploration side of it. That's a group we just formed about six months ago, seven months ago. So we kind of started doing new ventures and a year ago the M&A effort and then six months ago the Strategic, and the Bakken play was developed in that group. So I think now we've got the full contingency out there from being able to do development and do it very well, all the way to look for rank exploration. And that was our plan that we put together a few years ago. We've been putting the pieces in place and I think all the pieces are in now.

Mike Kelly: Just real quickly, just what are the big initiatives of that group, the Strategic Exploration?

Steven Mueller: They're doing the in-between things kind of like you described. I won't go into which areas they're going into, but they're where there's more data. There are places where the way you get in may not be just go out and lease a bunch of acreage. There may be some other ways you get into the play, and they certainly work with Jeff's group on the M&A part of it too. So they're the geological, geophysical, and kind of engineering spot that transitions between those pure M&A and the joint ventures group.

Operator: Thank you. Ladies and gentlemen, at this time we've come to the end of our Q&A session. I will now turn the floor back to management for closing comments.

Steven Mueller: I really did hope someone was going to ask about Colorado. Let me make a comment about Colorado before I make my closing comments. We've had several people call and say, why in the world would you put those test rates in the well in Colorado, and I can tell you we're excited about Colorado. One of the issues that could come up in the zone we're in is it may end up having a lot of water in it. To date, we've only seen water come back from the -- that is flow back water.

When we think about the total footage coming back, very quickly on a 2,000-foot lateral only has seven frac stages in it. We're very encouraged by that. It looks like the marmaton there has a got a lot of natural fracturing. It's definitely got oil in it and with a little more production, who knows what might happen there. The other thing I'll just mention about Colorado, in both the first and second well we did see other zones. And so, you will see us test a little bit different zones in the second well. But even in the first well, down the road either that well or some offset to it, you'll see us testing some other things. So Colorado right now, we're encouraged that even though those rates may not impress people out there, we're very excited to have the total volume of fluids moving the way they are and to get a little bit of oil after the first little bit there.

And hopefully when we get down to the point where we can get a well completed in the Bakken, we'll have similar excitement when we get to the Bakken as well.

So let me kind of just close quickly. I started the call today talking about second quarter pricing and I said this several times, who would have imagined just one year, six to eight months ago that today we'd be excited about having a $3 gas environment. We were about $4 and we were hoping it would go higher at that time, and that just confirms to us what we already knew. The unconventional gas discoveries that we have in North America have created short-term natural gas volatility. The price dropped because of convergence of the rapidly increasing supply and a winter that was the warmest we've had in many, many years. What they had it on here is 80 and I'm not sure that's right, but certainly over 40 years.

Recent increases in natural gas price are a response to flattening production, and we talked about that a little bit in the call, and a very hot summer. That's helped the supply-demand to balance and decrease more than 350 Bcf, but we still need to decrease another almost 500 Bcf to be in balance. And there's a lot of us trying to guess what's going to happen with that as we look into the future. But there's two things we know as a Company. First, near term gas price is going to remain volatile and second, the current natural gas price did not create economic returns for most of the plays in North America.

We think that's important. We think knowing both those uncertainties are enough to have let us win -- navigate a successful course of action for this year and many more years. We'll continue to drill only wells that meet our 1.3 PBI hurdle, and we'll maintain a strong balance sheet. Our relentless drive to lower cost in all projects will continue. Some of those reductions will come from old-fashioned hard work, and I want to thank all the employees for their old-fashioned hard work, and you've seen that in our second quarter numbers. They're down overall with guidance and they're down for the most part over the first quarter.

And then some of them are going to come from creative ideas like our further vertical integration in our pumping services. We're also going to build on our future by continuing to search for and economically testing new ideas, and that's not just in our new ventures group. It's especially in our new ventures group, but it's in every corner of the

Company. The only thing I want to emphasize is, these are not long-term hopes. Expect short-term results from SWN. Better and faster wells drilled in the Fayetteville Shale, a year-end exit rate of more than 300 million cubic foot per day in the Marcellus, and significantly more information about our new ventures plays by the end of the year. Our expectations are based on the belief that we're the right people doing the right things and that combination will create tremendous value for us and for our shareholders in any price environment.

And when you think about the right person doing the right thing, certainly Greg Kerley must come to mind and being near the top of that list. He's been an integral part of SWN's success for more than 20 years and he just announced his retirement as CFO effective October 1st. We'll miss him and I personally will miss him, as we attack our everyday challenges. But our competent Craig Owen is ready to step in and fill in his shoes. The other thing we know is, we'll still have his wisdom since he'll remain on the Board of Southwestern Energy. Thank you, again, Greg, for your friendship, your leadership, and your passion.

And I also want to thank all of you for listening today and have a great weekend. That ends our call.

Operator: This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.

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 months ended June 30, 2012. 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.


	3 Months Ended June 30,
	2012	2011
	(in thousands)
Net income (loss):
Net income (loss)	$ (488,100)	$ 167,454
Add back:
Impairment of natural gas and oil properties (net of taxes)	578,879	--
Net income, excluding impairment of natural gas and oil properties	$ 90,779	$ 167,454


	3 Months Ended June 30,
	2012	2011

Diluted earnings per share:
Net income (loss) per share	$ (1.40)	$ 0.48
Add back:
Impairment of natural gas and oil properties (net of taxes)	1.66	--
Net income per share, excluding impairment of natural gas and oil properties	$ 0.26	$ 0.48


	3 Months Ended June 30,
	2012	2011
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$ 392,727	$ 460,451
Add back (deduct):
Change in operating assets and liabilities	(38,200)	(12,237)
Net cash provided by operating activities before changes in operating assets and liabilities	$ 354,527	$ 448,214


	6 Months Ended June 30,
	2012	2011
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$ 837,390	$ 856,930
Add back (deduct):
Change in operating assets and liabilities	(112,043)	(17,184)
Net cash provided by operating activities before changes in operating assets and liabilities	$ 725,347	$ 839,746


	3 Months Ended June 30,
	2012	2011
	(in thousands)
E&P segment operating income:
E&P segment operating income (loss)	$ (859,872)	$ 222,539
Add back:
Impairment of natural gas and oil properties	935,899	--
E&P segment operating income excluding impairment of natural gas and oil properties	$ 76,027	$ 222,539


Net Debt Reconciliation
(in thousands)
	June 30, 2012

Total Debt	$ 1,670,011
Stockholder’s Equity	3,515,877
Total Capitalization	$ 5,185,888

Total Debt	$ 1,670,011
Less: Cash and Cash Equivalents	(41,499)
Less: Restricted Cash	(144,384)
Net Debt	$ 1,484,128

Net Debt	$ 1,484,128
Stockholder’s Equity	3,515,877
Total Adjusted Capitalization	$ 5,000,005

Total Debt to Total Capitalization Ratio	32.2%
Less: Impact of Cash, Cash Equivalents and
Restricted Cash	(2.5%)
Net Debt to Adjusted Capitalization Ratio	29.7%