西南能源 (SWN) 2012 Q2 法說會逐字稿

Greetings, and welcome to the Southwestern Energy 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)

As a reminder, this conference is being recorded. 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.

Thank you. Good morning, and thank you all 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 yesterdays press release regarding our second quarter results, you can find a copy at our website www.swn.com. Also, I'd 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 in the forward-looking statement section 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 during the quarter, the average second quarter NYMEX price of $2.22 per Mcf. That is a 26% reduction from the year-end 2011 price. 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 United States. SWN is also rapidly adjusting to the price changes. But, rather than retrenching like the recount, our emphasis on value plus 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 initial rates and more importantly the quality of the completed wells. In addition, we continue 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're seeing in our new ventures projects. Record production, faster times, and lower costs are product of the culture that's focused on value plus.

I'll will now turn the call over to Bill for more details on the results of that focus in the second quarter.

Thank you, Steve. 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 which is 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 five days or less. As you may recall, we've optimized our portfolio in the Fayetteville, and are targeting the highest return wells in the field. And, 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 30 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 billion cubic feet a day a year ago. Lately, our production in the Fayetteville has been affected by recent extremely high temperatures in Central Arkansas. And, year-to-date, we estimate that production from the field has been impacted by 0.5 Bcf to a 1 Bcf due to the extreme heat.

However, since June 30, our gross production rate has returned to approximately 2 Bcf per day. However, we are still managing the impact of extreme heat on our compressors and dehydration facilities.

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

Our operations at Greenswig continue to go very well with 39 producing wells online. We also just placed additional compression on the line at Greenswig which has 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 two 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 arranged trust area, which is approximately 70,000 net acres in Susquehanna County, we've completed and flow tested three wells to date before they were shut in waiting on pipelines. The wells were only flowed for a short period of time to avoid flaring of gas and showed strong performance in the initial five day flowback period. Productivity calculations for all three wells indicate that Greenswig-type performance should be expected once the wells are turned to sales in the fourth quarter.

In new ventures, we hold approximately 3.8 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 was recovered, the wells highest 24 hour producing rate to date was 421-barrels of 50-degree 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 hold pressure of 5,700 PSI on a 24/64 cinch 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've installed tubing and have shut in the well in order to perform a pressure build up test and wait for pipeline connections. Once pipeline connections can be completed, we expect to begin flowing -- selling both oil and gas from the well in the fourth quarter of 2012.

The oil pricing we received from this area is at a premium to WTI, and analysis of the gas shows high BTU content of around 1,220 BTU. So, we should receive a premium to NYMEX due to the richer gas liquids. We're encouraged by the BML's results. However, we also know that we have more work to do and 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 reentered 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 completed vertically. And, finally, we are drilling the Doles well located in Union Parish, Louisiana, which is currently drilling at 6,375 feet to a planned measure depth of approximately 17,300 feet with a 6,000 foot horizontal lateral.

In our Denver Julesburg Basin oil play in Eastern Colorado we've leased approximately 290,000 net acres and completed our first well in July. The Ewertz farm's 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're in the early days on this well with less than a quarter of the flowback having been recovered. But, we're encouraged as oil production began on day 3 after flowback commenced. The highest 24 hour producing rate to date for the Ewertz well with 65-barrels of oil per day on a pump, 40,000 cubic feet of gas, and 740-barrels of oil -- I mean barrels of water per day.

We also have drilled the Staner 58 well located 20 miles away in Arapahoe County, Colorado, to a total vertical depth of 9,650 feet. This well is planned to be completed in August and has a vertical completion. We'll 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, Canada, we have deferred our Plan 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.

And, finally, we spud our Bedwell horizontal well in Sheridan County, Montana, on July 10 targeting the Bakken and Three Forks objectives. This well drilled the objective section and reached total vertical depth of 8,619 feet.

We're currently drilling at the curve at approximately 7,600 feet TBD with a planned 3,200-foot horizontal lateral. At this time, this is all we're going to say about this particular area.

In closing, we continue to do the right things which is focusing on PBI, driving down our cost, and continuing the innovation process across all of our existing assets and new plays. We're also encouraged about our new ventures 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.

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

Thank you, Bill, and good morning.

We reported earnings for the second quarter of approximately $91 million, or $0.26 a 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 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 an 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 ENP 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 Mcf for the second quarter which includes our LOE, taxes, 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 one.

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've invested $1.2 billion including $1.1 billion in our exploration production 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. Now, I'll turn it back to the operator who will explain the procedure for asking questions.

Thank you.

(Operator Instructions)

Scott Hanold, RBC Capital Markets.

Thanks, good morning guys.

Good morning.

Obviously, I think, Smackover is going to be an area of focus so my question is could you give us your view on what you think has gone 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. What is your interpretation of what is going on and what does that portend potentially to EUR and longer term productivity?

Scott, we don't know exactly what the overall results 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, and that BML well did hit some pressure that's significantly higher than 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 its given 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, didn't have as 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 starting 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 of 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 -- one vertical well with TD to date and hopefully in the other wells as we get down, has more Dolomine 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 pricing permeability, what that means where it goes and how it works, we're still trying to figure that out.

So, would this be, obviously just broadly speaking, analogous to what you have in the Bakken where you have got a dolomitic sandstone near a shale that tends to be more productive? Am I reading in a little bit too much into it?

No. There could be a little bit of that. But, basically it looks like more than 50% of the zone, 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.

Okay, understood.

And, to remind everyone, the total zones we're looking at in these third and fourth wells are 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.

Okay, and then, maybe moving to the Marcellus. So, it sounds like the infrastructure has come on line so we'll see a pretty good step function now that you've got some of the firm in. 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 expect to be brought on production in the second half of the year?

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 Blue Stone line. That Blue Stone line is not operational yet.

And, it looks like it will not be operational until some time in the fourth quarter. We will continue to have an increase in production. But, the Blue Stone 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 of the wells we have online to date are along the Stagecoach pipeline in the Greenswig area. We only have those two wells down in Price in the Southern Susquehanna online. And, all of the wells we're drilling in that northern Susquehanna block that Bill mentioned we had three wells we tested. Those will all come on right at the end of the year.

Dave Kistler, Simmons & Company.

Good morning, guys. A bit of 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. 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 consider, for new ventures, doing some acquisition type activity? So, very big picture but would love to get any color you can give us in that direction.

Well, our first hope is we've got three discoveries and we really have an issue, 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. We talked about 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 have got our balance sheet is clean, we've got our borrowing line that we can borrow on to at least start any new venture program. And, we've got other ways 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.

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

We certainly have a group, and Jeff Sherrick who is in the room, 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 acres that have some held by production characteristic to it. Or if we want to get into an area and the best way to get into 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.

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 60s they seem to be slipping a little.

If you remember, 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 that were test down spacing. And, certainly as you get wells closer together and start seeing interference from them, some point in the out, past the initial rate you'll start seeing 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 the areas, and then started drilling pad drilling. And so, we always talked about expect in 2012 and beyond you're going to start seeing an interference and could see it in the 60 day numbers.

And then, you'll certainly see it in the overall numbers. And, 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, with 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 date in there. You aren't going to see a June date 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.

Thank you.

(Operator Instructions)

Brian Lively, Tudor, Pickering, Holt.

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 there was a lot more productive capacity in this well, at least that's my assumption. I'm just wondering, maybe you could provide some color on what you think the well could have flown at, at maybe more normalized conditions?

I don't know if we want to make a guess at that. Let me tell you, generally, what we do with the well. We put the well on with a 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, total of seven days, total flow period was something different than 16 choke.

What we're 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 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 200 barrel a day range.

And, as we stepped up you start seeing some higher water rates. 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, we'll 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 any way.

And, we want to see what the reservoir can do. And then, once we understand both what the reservoir can do, how the fracs working, later wells we'll worry about what the right, or best rates, could have been on them. So, again, just like the first couple 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 kinds of fracs to learn what we can. And then, in that 6,500-foot lateral we talked about that will be drilled basically off the pad that the BML well is on, that well will actually frac a little bit different. And, we'll have a whole different set of learning. So, we're continuing down that learning path and at the same time being very encouraged with what we're seeing.

Okay, that's great. So, it sounds like the rates could have been better if you had opened the well up a little more but that would have been on a total fluid basis. My follow-up is more --.

And, 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 flowback water. We aren't 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.

Okay.

Sorry, for interrupting.

That's okay. Just a follow-up is on the actual stream itself. I'm assuming the gas is pretty high BTU gas. Can you break out what you think the NGL volume would be for that gas stream?

The 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 full refineries in the area and about 135,000-barrels a day of refining capacity.

One's in Arkansas and three in northern Louisiana. And, they really would like to have the oil condensate that comes off of this. 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.

It's not unreasonable then to assume 200 barrels a day of NGL volume barrels from the stream then, right?

We're still working on the analysis to figure out if it's 200 or 150 or what that number is.

Thanks, Steve.

Hsulin Peng, Robert W. Baird.

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

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 laterals.

So, if I had to guess today the number we're shooting for in the high pressure area 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 500-barrel a day range on the oil only side still makes that work. It may be 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 the gas.

Okay, so the 500-barrels for oil, so does that include or exclude the gas, the NGL component?

That excludes the gas.

Okay, got it. And then, second question, just more macro related. 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 do you think when the gas production could turnover, potentially?

Yes, 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 is doing the same thing we're doing in the Fayetteville Shale. They're drilling their best wells.

So, I think it's going to follow, not the same shape but the same general concept that happened in the Barnett. Where, as the rigs dropped off, the Barnett production held fairly stubborn flat for awhile. And, now it's starting to turnover. 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 aren't going to see a strong turnover in production. But, when and how, that's the real question.

Right, okay. That's fair. Thank you, very much.

Marshall Carver, Capital One Southcoast.

Yes, good morning. Just a question on the Brown Dense. The second well, that Garrett 723-5H 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 continued the ramp up? If you could give me any color there I'd appreciate it.

We shut that well in a few days after last conference call, have done an extended period trying to figure out the pressure on it. And, this ties into I'm 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, the next time you'll see anything from that well is if we hook that well up and put it online.

Okay, thank you. And, did --.

We may do some work in the well. But, you're not going to see much production from it for awhile.

And, what were the pressures on those first couple wells versus this much high pressure third well?

Do you know those pressures?

Robertson well had 2,750, bottom hole pressure at the Garrett was up to 4,100 bottom hole pressure. And, the BML, as we said before, was at 5,700, flowing bottom hole pressure.

Okay, thank you, very much.

Brian Singer, Goldman Sachs.

Thanks, good morning.

Good morning.

In the Marcellus, your exhibit is showing your rate history and lack of declines 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 Greenswig 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?

Well, we certainly have some large EURs and you can see that from a graph that we put in our investor's data 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. And, the reason for that is we're keeping the drawdown 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 some of these wells are so strong either we haven't had to put compression out there yet or we haven't had to turn the completion on.

Because they can go straight into the line which acts like a choke and let's it stay fairly flat. So, I think the other way to answer the question is we certainly have some wells in that Greenswig area in Bradford County that match up with anyone else's wells that are out there from a productivity standpoint. Just the way we're producing them may be a little different than some of the other operators are doing.

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?

Not yet. The Midstream business is there. It's continuing to grow. It's performing better than we had budgeted at the beginning of the year. And, as you look down the future, to monetize it we'll have to have projects to put the dollars into. And, those would probably more than likely be new 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.

Great, thank you.

Thank you.

(Operator Instructions)

Charles Meade, Johnson Rice.

Good morning, gentlemen. Back to the Brown Dense, I know you guys have fielded a lot of questions on that at this point.

You need to ask me about Colorado. No, go ahead.

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 is really what we should be most interested?

I think you want to be interested in both probably.

Okay.

You want the initial -- you always like to have an initial bottom hole pressure where 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 16/64 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 know both.

Yes, you need all of them because any one in isolation is -- its really the relationship between them that tells you the story.

Right.

On the -- when I look at your wells, the Doles, and the Dean, and the BML, and I put them on a map, they are all really close together. And, really looks like -- it gives the impression that, 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 how aerial extent, in terms of aerial extent how large do you think this high pressure area of the Smackover is? And, how large, how many -- because it's all within a couple of sections right now, at least is what I see on where your permits are.

Yes, we're trying to understand that. And, since it was completely unexpected, and 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 had 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 is where we actually saw the high pressure took a kick. And so, now we're trying to figure out what that means, what the rock looks like. So, as you said, we staked 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 two miles North. The 6,500-foot lateral where we're drilling is being drilled right next to that original BML well in 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 six 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 pressured. 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 caught us off guard in our general overall thought process out there.

Got it. And, I guess the follow-up to that step out, it looks to me like one of your competitors at least under their name has, looks like, permitted a couple of 1280 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?

I know there's been some wells permitted around us. I personally don't know if we have any interest in those wells.

Got it. Thank you, very much for that detail.

Thank you.

Amir Arif, Stifel Nicolaus.

Good morning guys.

Good morning.

First question I had is just curious why you're doing -- I mean on the initial vertical I understand is a step out to see about the overpressure zone. But, why the second vertical beyond that instead of just going ahead and testing horizontally?

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 you fracked completely across the zone. It's hard to figure out what the productivity is of the various parts of that. So, we have a program worked out between the two 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 testing of both wells done, like Bill said, we will turnaround and drill some horizontals from those locations. But, we think it takes two wells to get all the things we want to learn. If there is a slim chance that that first well vertical we could learn almost everything we wanted and we would turnaround and drill the second one as a horizontal without testing it. But, right now, as it sits today, I think we have to test both of them.

Okay. And then, just a follow-up question. I apologize, I jumped in late, so I apologize if you've answered this. But, the 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 --.

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 the Montana.

Okay, thank you. And, Greg, congratulations on your retirement.

Thanks, very much, Amir.

Kevin Kaiser, Hedgeye Risk Management.

Hi, 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 acquiring more acreage either in the Marcellus or Fayetteville or in a new venture?

There's not a lot of acreage in the Fayetteville, at least not available right now. Certainly in the Marcellus, you see that each quarter we add a little bit of acreage. The numbers maybe only 2,000 or 3,000 acres. But, we keep chipping away there. And, if the right opportunity came along, we would 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 look like they would work with what we thought the forward curve was at, we would certainly look at gas. We're not disposed to look for oil or look for gas. Today, with the oil price 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.

Great, thanks. That's all I had.

Mike Kelly, Global Hunter Securities.

Good morning, guys.

Good morning.

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.

Well, first well, from what we saw in it, is non-economic. And, really, at some point in time might be hooked up. But, would need some other encouragement in the area to lay the gas line 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 of any of the first five or six wells that we had out there. The idea was to learn as much as we could. So, in 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. And, 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 what its productivity would be. So, that's what's driving us on the second well. It's not hooking it up or producing longer and 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, it'll work or not work.

Okay, 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 if this was really an idea that was generated by the group you mentioned here on the call that was formed to complement or supplement that 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, any color there you could provide would be great.

Sure. When you think about our company and step back say four years ago, or five years ago, we were concentrating completely on the Fayetteville Shale. We were picking out some acreage in the Marcellus. But, did not have a concentrated effort on looking for new projects. So, we started new ventures group, got it up and running. And then, about a year ago said, you've got new ventures, 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 ventures is doing. And then, you talk about our Strategic Exploration side of it. That's a group we just formed about six months ago, seven months ago. So, we did step one, new ventures, and then a year ago the M&A effort, and 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 of the pieces are there now.

Okay, just real quickly, what are the big initiatives of that group, the Strategic Exploration?

They're doing the in between things like you described. I won't go into which areas they're going into. But, there, 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 engineering spot that transitions between those pure M&A and the joint ventures group.

Very interesting, thank you.

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

Yes, and I really did hope someone was going to ask about Colorado. And, 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 flowback water. But, when we think about the total fluids coming back very quickly in a 2,000-foot lateral that only has seven frac stages in it, we're very encouraged by that. It looks like the Marmaton there has 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 that 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 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 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 or eight months ago that today, we would be excited about having $3 gas environment? We were above $4 and we were hoping we 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 rapidly increasing supply and a winter that was the warmest we've had in many, many years. What they have on here is 80 and I'm not sure that's right, but certainly over 40 years. Recent increases in natural gas price are response of flattening production and we talked about that a little bit in the call and a very hot Summer. That's helped the supply to demand to balance. It's decreased 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 does not create an 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 SWN, navigate a successful course of action for this year and many more years.

We'll continue to drill only the wells that meet our 1.3 TBI 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 of the employees for their old fashioned hard work and you're seeing that in our second quarter numbers. They're down over what we've guided and they're down for the most part over the first quarter.

And then, some of them will 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 then economically testing new ideas. And, that's not just in our new ventures group. It's especially in our new ventures group, but in every corner of the company. The one 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 index rate of more than 300 million cubic foot per day on 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 be 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 1. We'll miss him, and I personally will miss him, as we attack our every day challenges. While we are confident 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 will 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.

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