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Southwestern Energy (NYSE:SWN)

Q2 2012 Earnings Call

August 03, 2012 10:00 am ET

Executives

Steven L. Mueller - Chief Executive Officer, President and Director

William J. Way - Chief Operating Officer and Executive Vice President

Gregory D. Kerley - Chief Financial Officer, Executive Vice President and Director

Analysts

Scott Hanold - RBC Capital Markets, LLC, Research Division

David W. Kistler - Simmons & Company International, Research Division

David Snow

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Kevin Kaiser

Michael Kelly - Global Hunter Securities, LLC, Research Division

Operator

Greetings, and welcome to the Southwestern Energy's Second Quarter 2012 Earnings Teleconference Call. [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.

Steven L. Mueller

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've not received a copy of yesterday's press release regarding our second quarter results, you can find a copy on 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 and the forward-looking statement section of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe that 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 second quarter performance and will compare several important numbers. I want to take just 1 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 26% reduction from the year end 2011 price. The swift and rapid decrease in gas price has caused the 49% year-over-year decrease in total industry rigs drilling for gas in United States. SWN has 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 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're encouraged by what we're seeing in our New Ventures projects. Record production, faster times and lower costs are products of the culture of this focus on Value+.

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

William J. Way

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 5 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. 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 continues 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 to 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 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 Greenzweig continue to go very well with 39 producing wells online. We also just placed additional compression on the line at Greenzweig, 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 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've completed and flow tested 3 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 5 days flowback period. Productivity calculations for all 3 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 3.8 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 4 wells in the play to date and we are currently drilling 2 additional wells. Our first 2 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 well's 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 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've installed tubing and have shut in the well in order to perform a pressure buildup 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 receive 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 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 approximately 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 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'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 was 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, excuse me, per day.

We also going to drill 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 as a vertical completion. We'll evaluate the production from these 2 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've 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.

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 TVD for the 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 PVI, driving down our costs 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.

Gregory D. Kerley

Thank you, Bill, and good morning. We reported earnings for the second quarter of approximately $91 million or $0.26 a share, excluding the noncash 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 6 months. Despite significantly lower natural gas prices, our year-to-date discretionary cash flow was down only 14% due to our production growth, strong commodity hedge position and performance to 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 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 noncash 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 cost 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 1. We currently have nothing drawn in our unsecured $1.5 billion credit facility, and also had cash at the end of the quarter of around $41 million and a 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 and production business. Our planned total capital investment program for 2012 remains at $2.1 billion and was front-end loaded in the first 2 quarters by design. So we expect the 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 for 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 cost even further and remain flexible in our decisions on capital investments.

That concludes my comments. And now we'll turn it back to the operator.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is from the line of Scott Hanold of RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Obviously, I think Smackover is going to be an area of focus, and so I guess my question is, can you give us your view on what you think has gone on with the well? It's got 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?

Steven L. Mueller

Scott, we don't know exactly what the overall results is going to be here, that's why we're drilling the 2 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 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 it's 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 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 the 2 vertical wells -- one vertical well with TD to date, and hopefully in the other well, as we get down, has more dolomite in it and actually has a little bit of silt in it as compared to the second and first wells had more carbonate in them. But what that means across the permeability? What that means -- where it goes and how it works? We're still trying to figure that out.

Scott Hanold - RBC Capital Markets, LLC, Research Division

So will this be -- I mean, 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 tends to be more productive? Am I reading in a little bit too much into it?

Steven L. Mueller

No. There could be a little bit of that, but basically, it looks like more than half the zone, somewhere in that range, 40% to 60% of the zone has this different characteristic to it in the third and fourth wells that we didn't see in the first 2 wells. And to remind everyone, the total zones that we're looking at in this third and fourth well is about 450 foot thick. So it's a fairly thick interval as opposed to the Bakken, which is a fairly thin zone with shales on either side of it.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And then maybe moving to the Marcellus. So it sounds like the infrastructures come online, 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? I think you said 41 producing. How many are in backlog and are expected to be brought on production in the second half of the year?

Steven L. 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 jumps 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 we'll continue to put lines on. As we talked about and as Bill talked about, almost all the wells we have online to date are along the Stagecoach pipeline and Greenzweig area. We only have those 2 wells down in Price in the Southern Susquehanna online. And all the wells we're drilling in the Northern Susquehanna block that Bill mentioned, we had 3 wells we tested. Those will all come on right at the end of the year.

Operator

Our next question is from the line of David Kistler of Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Kind of a bit 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 was 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.

Steven L. Mueller

Well, our first hope is we've got 3 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 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 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 our balance sheet is clean, we've got our borrowing line that we can borrow on till 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 you find that, we will figure out a way to fund it and everyone, I think, will be happy with that.

David Snow

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

Steven L. Mueller

We certainly have a group, and Jeff Sherrick who is in the room is part of the -- heads up that group that is looking for ways both to supplement our New Ventures group where they come up with ideas or may be acres that have some kind of held-by production characteristics to it. Or if we want to get into an area, 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.

David W. Kistler - Simmons & Company International, Research Division

Okay, I appreciate that color. And then maybe one micro question. Looking at the Fayetteville specifically and the 60-day IP rate, it looks like over the last year, 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.

Steven L. 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 2 years, a little over 1,000 wells drilled. There were tests, down spacing. And certainly as you get the wells closer together and start seeing interference from them, some point in the 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 will be appropriate for each of the areas and then started drilling pad drilling. And so we always talked about expect in 2012 and beyond that you're going to start seeing interference and you could have 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 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 up the spacing on those wells and we talked about last quarter, expect that the IP will be better in the second half of the year. You're just starting to see that, it was 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 aren't going to see a 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, that you're going to have the same interference issues and you'll start seeing those numbers work back down again.

Operator

[Operator Instructions] Our next question is from Brian Lively of Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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 suggested 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 flown at, at maybe more normalized conditions?

Steven L. Mueller

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 the 16 choke, 16/64 choke, and basically floated through the entire period with 16/64 choke. That 24 choke was only for 2 days, and total of 7 days of 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 happen with gas rates, see what 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 24, we had water rates -- oil rates in the mid-300 range and water rates in a couple hundred barrels 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're going to 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 anyway. We want to see what the reservoir can do. And then once we understand what the reservoir can do, how the frac is 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 of wells, we're trying to learn as much as we can with this well. And you'll see in the 2 verticals we're drilling, we will be trying some different kinds of fracs to learn what we can. And that 6,500-foot lateral we talked about, that'll be drilled basically off the pad that BML well is on, that well will actually frac a little bit different. 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.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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

Steven L. Mueller

Well, you can see, we are moving a lot of fluid. That formation has given up a lot of fluid between the water and the oil. And I just mentioned, the water that we're getting at this point in time, we still believe it's flowback 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.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

That's okay. Just a follow-up is kind of 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?

Steven L. Mueller

The kind of stabilized Btu for that gas is about 1,200 Btu gas, so there's significant NGL 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 4 refineries in the area, about 135,000 barrels a day of refining capacity, 1 is in Arkansas and 3 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.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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

Steven L. Mueller

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

Operator

Our next question is from Hsulin Peng of Robert W. Baird.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

A follow-up question to Brown Dense. Can you comment on the current well cost? And also what you're targeting for the wells to be commercial in terms of well cost, the oil volume, gas volume, IP rates on new wells [ph], that sort of thing.

Steven L. 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 -- 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 have a little longer laterals. So if I have to guess today, the number we're shooting for in the high pressure is somewhere between $10 million and $12 million from a well cost standpoint. When we start looking at how that works out in the economics, I think still that, 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 that gas.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

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

Steven L. Mueller

That excludes the gas.

Hsulin Peng - Robert W. Baird & Co. Incorporated, Research Division

Okay, got it. And second question, just one macro related. I just wanted to get your take on the gas production in the U.S. 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 turnover potentially?

Steven L. Mueller

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 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. 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 started to turn over. And predicting where the core areas are in each one of these areas and what the best wells are, it's 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.

Operator

Our next question is from Marshall Carver of Capital One Southcoast.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Just a question on the Brown Dense. The second well that Garrett 7-23-5H well that you've discussed on the last call, you talked about rates likely increasing as more load was recovered. Did that actually happen into May and potentially in the June, or did you shut it in before that -- it continue to ramp up? If you could just give me any color there, I'd appreciate it.

Steven L. Mueller

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 kind of ties in -- 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. The next time you'll see anything from that well is if we hook that well up and put it online.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Okay. And did...

Steven L. Mueller

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

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Okay. What were the pressures on those first couple of wells versus this much higher pressure third well?

Steven L. Mueller

What were -- do you know those pressures...

William J. Way

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

Operator

Our next question is from the line of Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

In the Marcellus, your exhibit showing your rate history and lack of decline especially in 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 and 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?

Steven L. Mueller

Well, we certainly have some large EURs, and you can see that from the 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 perforation 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 turned the compression on because everything goes straight into the line, which acts like a choke and let's it stay fairly flat. So I think the other way to kind of answer the question is we certainly have some wells in that Greenzweig area and 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 maybe a little different than some of these operators are doing.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. 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?

Steven L. 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 the beginning of the year. And as you look in the future, to monetize it, we're going to have to have some projects to put the dollars into. And those are probably more likely being New Ventures-type projects. Now we've got the capital, we need to do the Fayetteville and the Marcellus. So at this point in time, we're excited about having the Midstream.

Operator

[Operator Instructions] The next question is from the line of Charles Meade of Johnson Rice.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

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

Steven L. Mueller

You need to ask me about Colorado.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

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 holes is really we should be most interested in?

Steven L. 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 where you can see we've started from, and that's something greater than 8,000 pounds. And then, 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 can see how that pressure responded. And that tells you something about permeability, it tells you a little bit about the produce-ability of the formation. So you really need to know both.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Yes. You kind of need all of them because any one in isolation is really the relationship between them that tells the story. On the -- when I look at your wells, the Doles, and the Dean and the BML, and I put them on the map, they're all really close together and it really looks like -- it gives the impression, I think, you guys certainly followed through on that this morning that you guys think you're onto something here. But my question is, how 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 of sections right now, at least is what I see and where your permits are.

Steven L. Mueller

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 had gone into or drilled through the Brown Dense, they haven't seen the high pressure. None of those wells have seen the high pressure. We drilled 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 horizontals 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'd 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 we're drilling is being drilled right next to that original BML well and just a different direction to learn something is going on that way. The other well, the Dean well that we talked about is 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 started 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 2 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 A. Meade - Johnson Rice & Company, L.L.C., Research Division

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 permitted a couple of these 1,280 units just the northwest of you guys. Are you guys going to be in that well -- or in those wells, or are you familiar with those?

Steven L. 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.

Operator

Our next question is from the line of Amir Arif of Stifel, Nicolaus.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

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

Steven L. Mueller

I guess the 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 frac completely across the zone. It's hard to figure out if you've -- what the productivity is as 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 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 turn around and drill some horizontals from those locations. But we think it takes 2 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 turn around and drill that second one as a horizontal without testing it But right now, as it sits today, I think we have to test both of them.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then just a follow-up question, I apologize, I jumped in late, so I apologize if you answer this, the 385,000 disclosed 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...

Steven L. Mueller

It is more than one, and that's all we'll say. And certainly, there's 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.

Kevin Kaiser

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 the New Venture?

Steven L. Mueller

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 have a little bit of acreage in the numbers maybe only 2,000 or 3,000 acreage, but we keep shipping away there. And if the right opportunity came along, we'd certainly like to continue building our position in Marcellus. Gas in general, if there was an idea that economics were as good as the gas economics on the various areas we're drilling today and look like they'd work with 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 the oil price is 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, not the product.

Operator

Our next question is from Mike Kelly of Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

First, I'm hoping you could talk about the status of the first 2 Brown Dense wells. And really, I'm just curious the rationale for shutting them in versus keeping them on production.

Steven L. Mueller

Well, first well from what we saw on it is not economic, and really, at some point in time, might be hooked up that 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. 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 5 or 6 wells that we had out there. The idea was to learn as much as we could. So like in case of the second well, when we saw the high pressures in the third and saw similar type gas and oil, again, the first well had 38-degree gravity, the second and third had 50 and 52 gravity. Now what we wanted to do is figure out the characteristics that made the third different from the second. So we start figuring out how to -- both predict where it could be and predict what its productivity would be. So that was driving us on the second well. It's not hooking it up for 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 will work or will not work.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. And then I think you 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, any color that you can provide there will be great.

Steven L. Mueller

Sure. When you think about our company and step back, say, 4 years ago or 5 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 their slings had fallen between the cracks of those various groups. And that's when Jeff's group came together. And Jeffs' group I would put more as a 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 talked about our strategic exploration side of it. That's the group we just formed about 6 months ago, 7 months ago. So we kind of stepped on New Ventures, then a year ago, the M&A effort and then 6 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 kind of been putting pieces in place, and I think all the pieces are there now.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. Just real quickly, just what are the big initiatives of that group, the strategic exploration?

Steven L. Mueller

They're doing the in between things kind of what you described, I won't go into which areas are going into. But there, were 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 or maybe some other ways you get into the play, and they certainly work with Jeff's group on M&A part of it, too. So they're the geological, geophysical and kind of engineering spot the transitions between those pure M&A and the joint ventures group.

Operator

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.

Steven L. Mueller

Yes, 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 calling and say, "Why in the world would you put those test rigs in the well in Colorado?" And we're -- 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 -- that is flowback water. When we think about the total fluids coming back, very quickly in a 2,000-foot lateral only has 7 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.

Now the other thing I'll just mention about Colorado and both the first and second wells, 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 a point where we can get a well completed in the Bakken, we'll have similar excitement when we got to the Bakken as well.

So let me kind of just close quickly. I started the call today talking about second quarter pricing and said this several times, who would've imagined just 1 year, 6, 8 months ago, that today, we'd be excited about having $3 gas environment. We were above $4 and we were hoping we're 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 that created the short-term natural gas volatility, the price drop 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.

The recent increases in the 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 and demand, the balance have 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 2 things we know as a company. First, near-term gas price is going to remain volatile; and second, the current natural gas price has not created an economic returns from most of the plays in North America. We think that's important. We think knowing both those uncertainties are enough to us -- let us, SWN, navigate a successful course of action for this year and many more years.

We'll continue drilling the wells to meet our 1.3 PVI hurdle, and we'll maintain a strong balance sheet. Our relentless drive to lower costs 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 seeing that in our second quarter numbers. They're down over what we've guided and they're down for the most part of 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 then economically testing new ideas. And that's not just in our New Ventures group but especially out of New Ventures group, but it's 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, our year end extra rate of more than 300 million cubic foot feet per day at 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.

When we 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 everyday challenges. But we're confident Craig Owen is ready to step in and fill in his shoes. The other thing we know is, we 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.

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