Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Southwestern Energy (NYSE:SWN)

Q3 2012 Earnings Call

November 02, 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

Robert Craig Owen - Chief Financial Officer, Senior Vice President and Chief Accounting Officer

Analysts

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

Brian Singer - Goldman Sachs Group Inc., Research Division

Scott Hanold - RBC Capital Markets, LLC, Research Division

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

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

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

Arun Jayaram - Crédit Suisse AG, Research Division

Dan McSpirit - BMO Capital Markets U.S.

Operator

Greetings, and welcome to the Southwestern Energy Third 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, Southwestern Energy. Thank you. Mr. Mueller, you may now begin.

Steven L. Mueller

Thank you. Good morning and thank you for joining us. With me today are Bill Way, our Chief Operating Officer; Craig Owen, our Chief Financial Officer; Jeff Sherrick, 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 the third quarter 2012 results, you can find a copy at our website at www.swn.com.

Also, I would like to point out that many of the comments during the 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 the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.

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

With that being said, I want to take a moment to express how proud I am of the third quarter results. We continue to make meaningful progress in lowering our costs. This, along with our growing production, growing cash flow from our midstream and our hedge position continue to help our earnings and cash flow move higher. Our wells in Fayetteville Shale have improved and our Marcellus production is growing and is expected to ramp up dramatically later in the fourth quarter.

We've also -- we also have several debenture prospects underway that I personally am excited about and especially knowing more with the Brown Dense later this year and added results from our Colorado and Montana plays in the first quarter of 2013. Plus, we have some other ideas we're working on we hope to unveil soon.

Let me take a few moments to talk about the macro picture regarding gas price. U.S. demand and production data for August are scheduled to be released today, and everyone who follows those numbers knows how difficult it is to predict individual monthly data points. The trends though are obvious. Rig gas -- gas rig count is less than 1/2 of what it was a year ago, and the U.S. Lower 48 gas production has been nearly flat since the beginning of the year, and that only reflects part of that decrease in rig count. The lower gas price this year has increased demand, the past 3 months, almost 11% over 2011, and a combination of flat supply and increasing demand has averted that potential overfull storage problem, so as the foregoing conclusion for many just a few months ago.

What does this mean about the future? As this week has shown, weather still remains variable with the continuing narrowing of the supply, demand and balance, gives cause to be more constructive about 2013 gas prices and a strong case to be made for 2014 yearly average gas price above $4, as the many new gas power plant projects start coming online to help maintain healthy demand.

As shown this past year, demand does change with change in price. And as price rises, both the possibility of some rig count returning and less coal to gas fuel switching is very real. This will have the tendency to keep average yearly prices below $5 for the foreseeable future.

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

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

William J. Way

Thank you, Steve, and good morning, everyone. In the Fayetteville Shale, we placed 105 operated wells on production in the third quarter, resulting in net production of 123.6 Bcf, which is up 10% from a year ago. Our operated horizontal wells achieved a record quarterly average initial production rate of 3.8 million cubic feet a day, up from 3.5 million cubic feet per day in the second quarter.

Our average completed well cost was $2.6 million per well with an average drilling time of 6.8 days during the quarter. We also set new company record for drilling time of a well that reached total depth in late September. This well had a total vertical depth of approximately 3,800 feet with a drilled lateral length of 3,625 feet and was drilled in just under 3 days. As a result of our optimization efforts on our drilling portfolio, we expect to see our average production on a per well basis continue at or around these levels over the next few quarters.

Supporting our success for vertical integration strategy, we took delivery on the first of 2 fracture stimulation fleets in September. Our newest team of employees have already put this equipment to work in the Fayetteville, having successfully fracture stimulated 2 wells.

On the Midstream side, our gas gathering businesses in the Fayetteville Shale continued to perform well and at September 30 was gathering approximately 2.2 billion cubic feet of natural gas per day through 1,837 miles of gathering lines compared to gathering 2 Bcf per day a year ago.

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

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

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

In our Range Trust area in Northern Susquehanna County, we have 25 wells currently either waiting on fracture stimulation or on the completion of the Bluestone pipeline, the southern portion of which is estimated to be placed in service into TGP 300 around the end of November. We expect our production to increase dramatically from our Marcellus properties over the next 14 months. From today's current gross operated rate of over 200 million cubic feet per day, we expect our year-end rate to be approximately 300 million cubic feet per day and our year-end rate at the end of 2013 to be over 500 million cubic feet per day.

Moving on to New Ventures. We've drilled and completed 6 wells in our Lower Smackover Brown Dense play in Southern Arkansas and Northern Louisiana. And as a reminder, from our second quarter call, we drilled Wells 4 and 5 as vertical tests to see if we would encounter the same high pressure that we saw in our third well, the BML. Both vertical tests did encounter this high pressure.

In our fourth well, we tried several different fracture stimulation recipes, primarily involving different combinations of linear gel. And in our fifth well, we completed 3 vertical stages totaling 12 feet of preparations with white sand and slick water in the sand stages. Production from this well has stabilized at approximately 200 barrels a day and 1.2 million cubic feet of gas for the last 10 days. We're now using these wells to obtain additional log data and core samples over the formation and study the effectiveness of different fracture stimulation treatments on the contact area and to learn more about the fracture height growth. At a later date, we'll reenter these wells and turn them into horizontal wells some time in 2013.

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

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

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

So in closing, while we have enjoyed the recent gas price run up, we are not standing still. We're very proud of the efforts of our more than 2,300 people and excited about our positions in 2 of the best natural gas plays in the country. And as Steve mentioned, we'll continue to drive down our costs and continue to innovate to increase production performance in both areas. Our New Venture ideas have some potential to impact our margins and our company in a very meaningful way, if successful, and we look forward to learning more about their commerciality over the next few months.

I look forward to reporting back to you in February on our progress. Now let me turn the call over to Craig Owen, who will discuss our financial results.

Robert Craig Owen

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

Our average realized gas price was $3.40 per Mcf for the quarter, down 21% from the same period last year. While NYMEX settlement prices for the third quarter were 33% lower than they were a year ago, we continue to benefit from our hedging activities, which increased our average gas price by $1.05 during the quarter.

For the remainder of 2012, we have 67 Bcf of gas production hedged at a weighted average floor price of $5.16 per Mcf and for 2013 186 Bcf hedged at $5.06. We continue to monitor the gas markets and we'll be looking for opportunities to add to our hedge position over the next several months.

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

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

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

Our balance sheet continues to be in good shape, with a net debt to book capitalization ratio of 32% and total debt to trailing EBITDA ratio of about 1x. To remind everyone, we have a $1.5 billion credit facility, which had very little drawn on it at the end of the quarter and had cash and restricted cash at the end of the quarter of $146 million.

So our liquidity continues to be very strong. With our planned total capital investment program for 2012 of $2.1 billion, we expect to end the year with nothing borrowed on our credit facility.

Looking ahead, we remain focused on keeping our costs as low as possible, maintaining a strong balance sheet and being good stewards of our capital investments.

That concludes my comments. So we'll now turn it back to the operator, who will explain the procedure for asking questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is coming from Dave Kistler from Simmons & Company International.

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

Real quickly, as we look at kind of a multitude of new venture opportunities and getting more color on those in, I guess, the fourth quarter call, can you give us maybe some color with respect to spending on those plays between here and there and maybe with respect to '13? As you guys are gathering information, are you considering or pursuing bringing in a partner into any of the plays? Maybe -- probably the one you have the more information on would be the Brown Dense at this point.

Steven L. Mueller

As far as '13 goes, and really, as you look out into the future, I would just assume that not much more than about 10% to 12% of our capital budget will be going towards New Ventures on average. Now I think the individual year might be a little bit higher, so that's going to be a relatively constant number just to kind of what’s our total capital budget is in any given year. For the rest of this year, from a pure capital investment, while we're picking up some acreage in some areas, there's not a significant amount of drilling to do between now and the end of the year so most of our capital’s invested at this point in time. And then, your other comment about bringing in a partner. We'll look at each of our plays. And we’ve talked about this in the past, New Brunswick, we definitely ultimately will need a partner. It's just a matter of when to bring them in. Some of the other plays may end up needing to have partners for various reasons, whether it's to look at the risk standpoint or whether it's just total capital invested, and we'll just look at that as we go along. So I think that we'll just put a normal course of business, and we'll just figure out when and if we want to do it in any of those places.

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

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

Steven L. Mueller

I'll let Bill handle that one.

William J. Way

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

Steven L. Mueller

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

Operator

Our next question is coming from Brian Singer from Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

I don't know if I just missed it, but can you give some color how you're thinking about 2013? I know there's not -- they're not fairly specific here but just from a CapEx perspective relative to cash flow relative to this year's budget and how you're thinking about balancing between the Fayetteville and the Marcellus and New Ventures.

Steven L. Mueller

We really haven't given much guidance on 2013. We're still working on that. And typically towards the end of the year, we normally put out a press release that talks about our 2013. So I'd expect something later this year or early next year on actual 2013. Obviously, we talked about in the past that we're increasing rig count in the Marcellus, and we'll exit the year with 4 rigs doing basically the horizontal work there. That will increase the capital budget on the Marcellus side, so I could see a weighting that's more Marcellus-oriented next year versus the dominant last few years where the Fayetteville has been 75% to 80% of the capital. You'll see that more balanced, may not be balanced, but more balanced. And then Midstream, in general, a lot of the work's been done on the Fayetteville Shale. And in the Marcellus, we've got another year in the same category we had now where it's $80 million, $90 million. So I'd say Midstream is flat or a little bit down is really towards the future. And then as I said before on the New Ventures, expect 10% to 12% of our capital budget to go to New Ventures.

Brian Singer - Goldman Sachs Group Inc., Research Division

That's helpful. And then a couple of questions on the Marcellus. I think you highlighted the backlog or the wells that are uncompleted in your release. Can you just talk to a couple things? One, it really looks like your Ewertz are at or above the 10 Bcf-type group. Would you agree with that? And does that translate into bookings when it comes to the end of this year? And then second, how do you expect to meet the – to get up to the 300 million a day? Do your existing wells have a lot of additional production potential, or does some of that backlog come on to meet the Midstream constraints at East?

William J. Way

Our expectations on wells are meeting or exceeding what we thought they would be. So we have no change really in that. It's looking very good so far. The majority of our production obviously comes out of the Greenzweig area, and so we've seen some very solid, strong performance in that area. That will translate through to reserves bookings. The bigger feature is the commencement of production out of the range area. The Bluestone pipeline is well under construction. We expect to have that pipeline in service and operating around the end of November. There was no setback except for just days waiting for rain to stop. We didn't lose any forward progress on that from the storm. So we expect to get that on, and once we can get some production history associated with those wells, we will be able to move forward. We are seeing an improvement from compression out of the Greenzweig area, about 25 million to 30 million a day. That, combined with some wells waiting to be completed this quarter and the startup of the Bluestone and the Lycoming area of production also around the end of November, is the formula for getting us to 300 million a day out of -- exit rate out of Marcellus in total.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And lastly...

Steven L. Mueller

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

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And what are your current drilling completion costs in the Marcellus?

William J. Way

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

Operator

Our next question is coming from Scott Hanold from RBC Capital.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Talk about the Marcellus a little bit. Obviously, your infrastructure is constrained right now, but you do have plans to get some more online. And it seems going forward, I mean, that's still really the governor on your growth there. Is -- what other things can you do or you got other things you're doing to continually expand that? And is there always the opportunity to pay for other people's firm that they're not using?

William J. Way

Well, there's pipeline infrastructure constraints that are near term and that's represented in the Bluestone discussion, and we are working very closely with the contractor and owner of that pipeline to get that on as quickly as possible. But beyond that, we have been building a portfolio of transportation capacity out of the Marcellus for some time. And our production growth over time is matched to that transportation capacity. And the numbers, 300, 500 and then growing beyond that are matched with firm and long-term and short-term firm transport, and we are -- our team continuously looks at adding. We added some additional capacity this last quarter. I think it was 140 million a day through 3 different transactions. And so we believe that we're solidly covered, and we're continuing to look at opportunities to expand that.

Steven L. Mueller

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

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. I appreciate that. And my follow-up, looking at your gas price outlook, Steve, obviously sub-$5 with constraints on even the potential for more activity as prices go up and the power generation switchback. I mean, how do you look at the Fayetteville in sort of that light if -- I don't know what your sort of near-term look is the next, say, 3 years? Where do you see activity there at the 400, 450? Do you kind of maintain your activity that you're doing right now on the Fayetteville, or would you increase that at a certain price point?

Steven L. Mueller

I think from just a strategic standpoint, we really started in 2011, trying to keep the Fayetteville Shale within its cash flow with a thought that in the not too distant future it could generate excess cash flow to apply to some other things. And we do have a large backlog of wells to kind of what price we have out there. So I think as you look into the future, we will increase or decrease well count based on basically how much cash flow comes out of the Fayetteville Shale. This year, we're drilling about 400 wells. We're not quite balanced. As we look into the next year, I can tell you we'll start the year running 7 rigs. And if you ran 7 rigs all year that would be in the 350-type number well range, again, depending on how fast you're drilling those kinds of things. So we will adjust it. As price gets higher and there's more cash flow, we'll drill more wells on the other side, but I don't know how much lower we'll go from where we're at right now. That's something we're talking about in our 2013 capital plans.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And it looks like your Fayetteville Shale costs have come down nicely this quarter. I mean, do you anticipate more of that's going to happen with your more focused effort or where’s sort of the bottom on that cost in the basin?

William J. Way

Well, our wells have come down in the quarter a lot due to reduced vendor. We've gone and consolidated vendors, and we're seeing some reductions in cost there. Our completion efficiency is up, and we're really improving our work around that. A big change that happened in the quarter was SWN sand. We were using about between 80% and 90% of SWN sand across the Fayetteville. We've now done some work and are able to use 100% of our SWN sand across the fields. So there's some rather dramatic reductions associated with that. The next tranche of savings comes from our pumping company that I mentioned earlier. We'll pump a large number of wells next year. The savings is somewhere between 150,000, 160,000 per well that we pump. And so you'll see further reductions there, and then we'll continue to chase further optimization. So I don't know -- I wouldn't speculate how far down it can go. We've made some rather dramatic strides in this area, and we'll continue to take those down.

Steven L. Mueller

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

Operator

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

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

So regarding -- just kind of wanted to understand your capital allocation. So one of the things I was trying to understand is the -- for your midstream assets, would you -- how do you think about monetizing that midstream assets to find your New Ventures play going forward, or would you rather bring an outside partner if needed?

Steven L. Mueller

You know, each play’s going to be different. Certainly, we have, besides our current balance sheet, and the fact that we haven't borrowed in our borrowing line, we have some other assets that we could monetize in some way and midstream some of those other assets. And then you certainly have whatever you have a discovery on, whatever you're doing something on, you can sell part of it or bring a partner in part of that in. It just depends on how big, how fast you're ramping up and what generally you found. So I can't really say what we do with midstream or what would be first. I think the big key is whatever the cheapest funding is, that's the one we'll look at doing first and then we'll go from there.

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

Okay. And second question is G&A this quarter was really good. And I'm just wondering if you would think if this quarter run rate a good indication for future G&A expenses, or if there's something unusual this quarter that made it much lower.

Robert Craig Owen

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

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

Okay. Got it. And then last question, the Brown Dense acreage went down a little bit this quarter, and I'm just wondering if you can help us understand why the acreage number went down.

Steven L. Mueller

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

Operator

Our next question is coming from Charles Meade from Johnson Rice & Company.

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

I had a question on one of the wells that you talked about in your prepared remarks. I think it was the Dean well in the Brown Dense that you said. Did I get these numbers right? 200 barrels a day, and 1.2 million out of 12 feet of perfs?

Steven L. Mueller

That's correct.

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

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

Steven L. Mueller

There are some things we did different. As Bill mentioned in his comments, the 2 vertical wells we drilled, the first thing we want to do is determine if there was extent to the high pressure area; there was. But the other thing we found in -- and if you remember back to our very first well, one of the issues we had was trying to get enough vertical to extend our fracs. We found as we evaluated the BML well that we still weren't getting the growth and height on our fracs that we were looking for. So we tried several different kinds of fracs on both the Johnson and the Dean wells. And in some cases, they worked; in some, they didn't. In the Johnson well, I can tell you 2 of the 5 I think we've done so far, we screened out early because the frac that we're trying didn't work but as we got towards the end of frac-ing in the Johnson well, we came to what I'll call a new formula. There's nothing magic about it; just kept tweaking. And it looks like we're getting better vertical height. We tried that on the Dean well and well, there's 3 intervals, we frac-ed -- on that well 3 separate fracs, and the perforations, as we said weren't much perforation. There's about a 200-foot interval. It wasn't anything unusual over any of the other wells in the area. But when you look at the fracture area that it looks like it's contacted versus in the BML well that has over 4,000 feet, it's got almost 60% of the same fracture area. So it looks like we're starting to learn something on the fracture stimulations. And that well has held up very well. The numbers he quoted were on a 10/64 choke, and we still have high 6,000 pounds bottom-well floating tubing pressure -- of bottom-hole pressure. So that well gives us encouragement and we're using a variation of that. For the most part, we're trying some things on the horizontal we're frac-ing right now. But we're using a slight variation of what we did on the Dean on this horizontal that we're working on now. So I can't say it's the answer, but I can say that we're getting closer just by working on the fracture simulation. And it looks like we're getting a little better height than we were in any of the other fracs we've done today.

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

Got it. That's all very helpful, Steve. It sounds like -- am I right in guessing that this is just a kind of a combination of sand load and pump rate and some chemistry that you...

Steven L. Mueller

It's just mix. And when you put the sand in and how much water you put, there's nothing magical about the fluids themselves.

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

Got it. And then it also looks to me like you guys have set up a unit for the Johnson and Dean to be 1,280. Is that -- are you guys committed to doing long laterals there? Or is that just an option for you at this point?

Steven L. Mueller

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

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

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

Steven L. Mueller

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

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

And that's using what you've learned from the Dean wells?

Steven L. Mueller

Yes, what we’ve learned regard from Dean and Johnson and any other wells before.

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

But the BML is the older version of that frac?

Steven L. Mueller

The BML is the first well; has fracs much more like we did in the first 2 before it, and there is a significant difference, yes.

Operator

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

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

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

William J. Way

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

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

And then how will that build into 2013?

William J. Way

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

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

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

Steven L. Mueller

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

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

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

Steven L. Mueller

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

Operator

[Operator Instructions] Our next question is coming from Arun Jayaram from Credit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

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

Steven L. Mueller

I think a couple of things there. First off, we are hedged, as we talked about. If we had flat production year-over-year, it would be a little over 30% hedged, and those are $5 hedges. I wouldn't assume that those are the only hedges that we have for the year. We're still looking, and I think you may see some other hedges go on. But really your question is 2013 budget and what's going to happen in 2013 budget, and we're still working on that all the way to the point -- I'm not ready to say what we think the price will be in 2013 yet. We have to sort that out. So all of that obviously works into cash flow. Cash flow obviously is partially driven by how much capital you have and you have to marry the 2 of those together, and we're not quite there yet to say how many wells we're going to drill in each area. The only thing that we've certainly committed to is because of the 2 new rigs we're adding. One’s added already, one will be added in the Marcellus that have long-term contracts on them. We know the activity will go up in the Marcellus.

Arun Jayaram - Crédit Suisse AG, Research Division

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

Steven L. Mueller

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

Arun Jayaram - Crédit Suisse AG, Research Division

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

Steven L. Mueller

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

Arun Jayaram - Crédit Suisse AG, Research Division

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

Steven L. Mueller

It's the same we're paying for all of our transportation, actually in some cases, a little bit less. What this is, we buy firm. Typically on a pipeline, you're buying long-term firm. In this case, there were operators who can't supply their firm. And for short periods of time, some of these contracts we have are 6-month type contracts. And all we're doing is buying from operators who couldn't use it. So we're buying at their rate or lower than their rate because they were going to have to pay it one way or the other.

Operator

Our next question is coming from Dan McSpirit from BMO Capital Markets.

Dan McSpirit - BMO Capital Markets U.S.

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

Steven L. Mueller

As you look out into the future, there's -- I would put 2 things that we have to understand. I think both of those, we'll know a lot about in the next 3 months. The first one and we talked about this in the past, we haven't got a long production line on any of these wells. And so we need to understand the shape of that production curve. We do all of our economics based on an average Eagle Ford because of depth and pressure considerations, but we haven't got ourselves an average production curve here yet. And we'll put the 2 wells that Bill talked about on production this month. We'll have, by January, 2.5 months of production on those or 2-plus months of production. And when we add that to the testing we had earlier, we'll be able to figure the shape of those curves. The other thing we've already talked about, you want to contact as much of the rock as you can, and you're going to have to have vertical height on your fracs because you're looking at 350 foot to 400 foot interval. And frankly, on our first well, we got about 25 foot to 30 foot height growth. And even in this most recent one I talk about, we're looking about 90 foot to 100 foot growth. So we still need to do some things in the frac-ing side to get across more of the zone and contact more of the reservoir. So we'll continue to work on the frac-ing. Whatever we learn in this horizontal we're doing now, we'll apply that and go out in the future. So those are the 2 main things there. As far as cost, rather than go into the various costs in each well, we do something internally where -- we call it the pacesetter. We take the wells that we've drilled and whatever the best piece of that well was, whether it’s the vertical part up whole, or whether it's the horizontal, or building the curve, and we put that together and say we know we can do that. And all we have to do is do it consistently and here's what’s going to be. And then from there, we improve and we go from there. On a pacesetter well, let me just put it on days to drill, this most recent well, Doles well, took us about 55 days to drill a pacesetter well. Like I said, one where we just did everything the way we've done and had success in the past on each of individual portion would be about a 35-day well for that same well. And when you start talking about a 35- to 40-day well, going back to my comments on the second quarter conference call, you're talking about $10 million to $12 million-type wells. The well we're on today on the Doles is above $12 million, but it's not significantly above $12 million. So we're in the range, and we can see a way to get our costs down. Let me also add, on the economic side, historically, we've talked about the fact that we needed a certain rate and we threw out any gas. We didn't worry about any of those kinds of things. But if we can do a $12 million well -- to reach our 1.3 PVI, that's our economic hurdle, we need about 425 barrels a day of oil and about 4.2 million a day of gas when you count that in. That's $80 oil LLS price, and it is a little over $3 NYMEX price. And you put the BTUs on that and the oil, and that's the economics for that.

Operator

We have reached the end of our question-and-answer session. I'd like to turn the floor back over to management for any further or closing comments.

Steven L. Mueller

Thank you. To wrap up things, again, I want to say how proud we are of the results of the quarter. And I want to thank all of our employees for the hard work they've done to achieve these results. Now we will continue to keep doing the everyday things that will add value, and I talk about it on all the presentations. I talk about it with our employees. Our goal is never just to add value, it's to add value-plus and give you something more. And I think we've done that in the third quarter. I also want you to know we're not comfortable. We have several ideas on how to improve what we're doing in Fayetteville and Marcellus plays, which will translate to better, faster, cheaper and ultimately, more wells to drill over the life of the field. It also means that we're going to keep that focus we talked about on the -- and discipline on doing everything with a 1.3 PVI economic objective. And then when we look, finally, at our New Ventures team, we're now generating tangible and new ideas that are needed to significantly impact our company. We're going to have some more and expect some more ideas in 2013 but at the same time, we're learning at a rapid rate about what makes each of our current plays work, and we're very encouraged that in 2013, we'll provide at least one new development project for SWN so we can apply all those things we've learned in the Fayetteville Shale and Marcellus.

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

Operator

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Southwestern Energy Management Discusses Q3 2012 Results - Earnings Call Transcript
This Transcript
All Transcripts