西南能源 (SWN) 2012 Q3 法說會逐字稿

Greetings, and welcome to the Southwestern Energy third-quarter 2012 teleconference call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation.

(Operator Instructions)

As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Steve Mueller, President and CEO of Southwestern Energy. Thank you, Mr. Mueller, you may now begin.

Thank you. Good morning and thank you 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, VP of Investor Relations. If you have 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 in the forward-looking statement section of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

To begin, I would like to say that our thoughts and prayers are with our friends, families, and employees on the East Coast. A storm like this puts everything 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 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 also have several new venture prospects under way 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. US 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 monthly data points. The trends, though, are obvious.

Gas rig count is less than half of what it was a year ago and the US 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 three months almost 11% over 2011 and a combination of flat supply and increasing demand has averted that potential over full storage problem that was a foregone conclusion for many just a few months ago. What does this mean about the future? As this week has shown, weather is still the main variable with a 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. As price rises, both 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 delivering 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.

Thank you, Steve, and good morning, everyone. In the Fayetteville Shale, we replaced 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 a 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 3800 feet, with a drilled lateral length of 3625 feet and was drilled in just under three days.

As a result of our optimization efforts on our drilling portfolio, we expect to see our average production on a per-well basis continue at or around these levels over the next few quarters. Supporting our successful vertical integration strategy, we took delivery on the first of two fracture stimulation fleets in September. Our newest team of employees have already put this equipment to work in the Fayetteville, having successfully fracture stimulated two wells. On the midstream side, our gas gathering businesses in the Fayetteville Shale continue to perform well and at September 30 was gathering approximately 2.2 billion cubic feet of natural gas per day through 1837 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 US who are dealing with the impacts of Hurricane Sandy. 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 will 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 nine wells on production. Our total well count stood at 50 operated producing wells, including 44 wells in Bradford County and six 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 Booster compression enabling the full field to access SWN compression. All wells can now deliver into stage coach 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 six 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 to 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 three vertical stages, totalling 12 feet of perforations 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 sometime in 2013. Our sixth well, the Doles, located in Union Parrish, 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 we 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 two wells and are permitting additional wells in the area. We are testing multiple intervals in these two wells and evaluation will continue over the next 90 days. We are encouraged by what we have seen so far and hope to have more information about this area in the first quarter of 2013.

And finally, we've drilled and completed a well in Sheridan County, Montana, targeting the Bakken Three Forks objective. 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. 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 2300 people and excited about our positions in two 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.

Thank you, Bill, and good morning. We reported earnings in the third quarter of approximately $132 million, or $0.38 per share, excluding the noncash ceiling test impairment of our natural gas and oil properties resulting from low gas prices. Our discretionary cash flow was $417 million in the third quarter, which continues to be resilient, as Steve pointed out, and nearly offset our entire capital investment level for the third quarter. Our average realized gas price was $3.40 per Mcf for the quarter, down 21% from the same period last year.

While NYMEX settlement prices for the third quarter were 33% lower than they were a year ago, we continue to benefit from our hedging activities, which increased our average gas price by $1.05 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 will be looking for opportunities to add to our hedge position over the next several months. Operating income for our E&P segment was $145 million for the quarter, excluding the ceiling test impairment, compared to $228 million in the same period last year. To echo Steve's comments, we continue to see costs moving in the right direction and our cost structure continues to be a key competitive advantage for us, with our all-in cash operating costs 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 the third quarter to approximately $75 million, primarily due to the increase in gathering revenues from our Fayetteville and Marcellus shale plays. The cash flow generated by our Midstream Services segment, combined with our strong hedge position protects approximately 60% of our total expected cash flow in 2012. Our balance sheet continues to be in good shape with a net book-to-capitalization ratio at 32% and total debt-to-trailing-EBITDA ratio of about 1 times. 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. I will now turn it back to the operator, who will explain the procedure for asking questions.

Thank you. We'll now be conducting a question-and-answer session.

(Operator Instructions)

Dave Kistler, Simmons & Company International.

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

As far as '13 goes, and really as you look out in the future, I would just assume that not much more than about 10%, 12% of our capital budget will be going towards new ventures on average. The individual year might be a little bit higher, so that's going to be a relatively constant number, just depending on what the 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. In New Brunswick, we definitely ultimately will need a partner. 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 we just put a normal course of business and we figure out when and if we want to do it in any of those places.

Great. Appreciate that. Then as a follow-up, IPs, initial IPs in the Fayetteville based on picking your best quality wells off the charts, kind of record number for you guys. But the 30 and 60 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 30 and 60 day?

I'll let Bill handle that one.

The 30 to 60-day lags are in fact lags. Some of our best wells came on in September in our optimization program and they are 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 through the fourth quarter.

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

Great, thank you, guys, for that color.

Brian Singer, Goldman Sachs.

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

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

So I could see a weighting that's more Marcellus-oriented next year versus the dominant the last few years, where the Fayetteville has been 75% to 80% of the capital. You'll see that more balanced. May not be balanced, but more balanced. And then Midstream in general, a lot of the work's been done in the Fayetteville Shale and in the Marcellus we've got another year, in the same category we had now, where it's $80 million, $90 million. I'd say Midstream is flat or a little bit down as we look towards the future. Then as I said before, on the New Ventures, expect 10% to 12% of our capital budgets to go to new ventures.

That's helpful. 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 of things? One, it really looks like your EURs 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 ease]?

Our expectations on wells are meeting or exceeding what we thought they would be. So we have no change really in that. It's looking very good so far. The majority of our production obviously comes out of the Greenzweig area and so we've seen some very solid, strong performance in that area. That will translate through to reserves bookings. The bigger feature is the commencement of production out of the Range area. The Bluestone pipeline is well under construction. We expect to have that pipeline in service and operating around the end of November.

There was no setback except for just days waiting for rain to stop. But we didn't lose any forward progress on that from the storm. So we expect to get that on. And once we can get some production history associated with those wells, we will be able to move forward. We are seeing an improvement from compression out of the Greenzweig area, about 25 to 30 million a day. That, combined with some wells waiting to be completed this quarter and the startup of the Bluestone and the Lycoming area of production also around the end of November is the formula for getting us to 300 million a day exit rate out of Marcellus in total.

Great. Thanks. And lastly--

Let me add something to that.

Okay.

Our PUDs that we booked this last year in the Marcellus were about 7.5 Bcf PUDs. Those were all in the Bradford area, what we call Greenzweig area. I expect that we will see some positive revisions on those. When you start looking at that Range area that we're just now, or 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 is at year-end we may not get as many PUDs booked as you would normally expect, just because we haven't seen much production from the Range area, but I fully expect from all the tests we've seen it will be a good area and that will grow as we go out into the future.

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

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.

Thank you.

Scott Hanold, RBC Capital.

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

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

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

Okay, appreciate that. And my follow-up, looking at your gas price outlook, Steve, obviously sub-$5 with constraint on the potential for more activity as prices go up and the par generation switchback. How do you look at the Fayetteville in that light? I don't know what your near-term look is, if it's the next say, three years. Where do you see activity there at, $4, $4.50, do you maintain your activity that you're doing right now in the Fayetteville or would you increase it at a certain price point?

I think from just a strategic standpoint, we really started in 2011 trying to keep the Fayetteville Shale within its cash flow, with the thought that in the not too distant future it could generate excess cash flow to apply to some other things. And we do have a large backlog of wells, depending on 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 drawing about 400 wells. We're not quite balanced.

As we look into next year, I can tell you we'll start the year running seven rigs. And if you ran seven 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 of it, I don't know how much lower we'll go from where we're at right now. That's something we're talking about in our 2013 capital plans.

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

Well, our wells have come down in the quarter a lot due to reduced vendor -- we've gone and consolidated vendors and we're seeing some reductions in costs there. Our completion efficiency is up and we are 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 field. 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. So you'll see further reductions there and then we'll continue to chase further optimization. So 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.

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

Okay, great. Thanks, guys.

Hsulin Peng, from Robert W. Baird.

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

You know, each play is going to be different. Certainly we have, besides our current clean balance sheet and the fact 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. And 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'd 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 go from there.

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

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 would 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.

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

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

Okay, thank you.

Charles Meade, Johnson Rice & Company.

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, 1.2 million out of 12 feet of perfs?

That's correct.

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

There are some things we did different. As Bill mentioned in his comments, the two vertical wells we drilled, the first thing we want to do is determine if there was an 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 extent on our fracks. We found out as we evaluated the BML well that we still weren't getting the growth and height on our fracks that we were looking for. So we tried several different kinds of fracks in both the Johnson and the Dean wells, and in some cases, they worked. In some, they didn't. And the Johnson well, I can tell you two of the five I think we've done so far, we screened out early because the frack we're trying didn't work.

But as we got towards the end of the fracking of 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 while there's three intervals we frack on that well, three separate fracks, and the perforations, as he said, weren't much perforations. It was about a 200-foot interval. It wasn't anything unusual over any of the other wells in the area, but when you look at the fracture area that it looks like it's contacted versus 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 1064 choke. And we still have high 6000 pounds bottom well flowing tubing pressure, bottom well pressure. So that well gives us encouragement and we're using a variation of that for the most part. We're trying some things on the horizontal, we're fracking right now, but we're using a 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 working on the frack, frack stimulation and looks like we're getting a little better height than any of the other fracks we've done to date.

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

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

Got it. And then it also looks to me like you guys have set up a unit for the Johnson and Dean to be 1280. Is that -- are you guys committed to doing long laterals there? Or is that just an option for you at this point?

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 3000-foot and work our way up to 9,000 or 12,000 feet. That's somewhere in the game plan, but if we get some of the encouragement and some other wells like we're seeing in the Dean, it may not need that long lateral. So we are just going to have to work our way through that.

Got it and just to make sure I understand this right. It's the Doles that you're going to complete with your new frack recipe?

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

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

We've learned from Dean and Johnson and any other wells before it.

But the BML is kind of the older version of that frack?

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

That's great detail. Thank you very much.

Brian Lively, Tudor Pickering.

On the Marcellus, you talked about having a smoother infrastructure profile for 2013. On the call though, could you 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 midyear?

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 are making some very solid progress.

And then how will that build into 2013?

Into 2013, we expect to reach 500 million a day by the end of '13. 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.

Okay.

We expect to drill probably about 100, 103 wells across the field in 2013, based off of the comment Steve made earlier on four rigs, and we've built that and their completion into that profile. And we can -- like Steve said, we've got a take-away capacity graphic that we can send you and if you look at that graphic, you have -- the ramp pretty much follows that graphic.

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 sounds like there's -- you're actually--

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

That's great. I'll follow up with him. Sounds like there's some bias upside to the numbers. Then for me, 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 flat maybe just for the first half of the year?

I'm not sure about the flat comment. I think what I said was rig count right now runs seven rigs and we'll go into the year with running seven rigs and if you ran seven rigs for the entire year, you would have about 350 wells.

Okay, thank you.

(Operator Instructions)

Arun Jayaram, Credit Suisse.

Steve, I wanted to ask you about, obviously you managed the business to the 1.3 PVI target. Obviously, you've had a very big hedging tail wind so to speak, where you've had some very attractive hedges. 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 swing factor. You do have obviously lower costs in the Fayetteville today, $2.6 million a well, plus you're drilling perhaps 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 '12.

I think a couple things there. First off, we are hedged, as we talked about. If we had flat production year-over-year, it would be a little over 30% hedge. 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 might see some other hedges go on.

But really, your question is, 2013 budget and what's going to happen in 2013 budget. And we're still working on that all the way to the point of I'm not ready to say what we think the price would 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 two 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 two new rigs that we're adding, one's added already, one will be added in the Marcellus, that have long-term contracts on them, we know the activity will go up in the Marcellus.

That's fair. And Steve, I want 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, where you expect your production to be? Because I think you have different working interests, thinking about Susquehanna County versus Bradford County, and just maybe give us a sense of where you expect to be on a net basis.

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

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

Well, because we have firm capacity, today we're seeing NYMEX pretty much flat. You know, some months, it's a couple cents above, some months a little below. We have not seen anything we've had to do, much of a blowout 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's actually it widens and it's going to be a NYMEX minus some kind of number. But near term, NYMEX flat.

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 pipeline capacity?

It's the same we're paying for all of our transportation. Actually, in some cases a little bit less. What this is, when you buy firm typically on a pipeline, you're buying long-term firm. In this case, there were operators who can't supply their firm for short periods of time. Some of these contracts we have are six-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.

Okay. Fair enough, Steve. Thanks.

Dan Mcspirit, BMO Capital Markets.

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

Okay. As you look out in the future, I would put two things that we have to understand and I think both of those we will know a lot about in the next three months. The first one, and we've talked about this in the past, we haven't got a long production life on any of these wells. And so we need to understand the shape of that production curve. We do all of our economics based on an average Eagle Ford because of depth and pressure considerations, but we haven't got ourselves an average production curve here yet. And we'll put the two wells that Bill talked about on production this month. We'll have by January, 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 ticket 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 fracks, because you're looking at 350- to 400-foot interval. And frankly in our first well, we got about 25- to 30-foot height growth and even in this most recent one I talking about, we're looking at 90 to 100-foot growth. We still need to do some things on the fracking side to get across more of the zone and contact more of the reservoir. We'll continue to work on the fracking. Whatever we learn in this horizontal we're doing now, we'll apply that and go out in the future. Those are the two main things there.

As far as costs, rather than go into the various costs in each well, we do something internally where, we call it Pace Setter. We take the wells that we've drilled and whatever the best piece of that well was, whether it's the vertical part up hole or whether it's the horizontal or the [billing occur], we put that together and say we know we can do that and all we have to do is do it consistently and here's what it's going to be. Then from there, we improve and we go from there. On a Pace Setter well, let me just put it on days to drill -- this most recent well, Doles well, it took us about 55 days to drill. A Pace Setter well, like I say, one where we just did everything the way we've done and had success in the past on each individual portion, would be about a35-day well for that same well. And when you start talking about 35- to 40-day well, going back to my comments on the second quarter conference call, you're talking $10 million to $12 million type wells.

The well we're on today, on the Doles is about $12 million, but it's not significantly above $12 million. So we're in the range and we can see a way to get our costs down. Let me also add on the economics 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 BTUs on that and the oil and that's the economics for that.

Thank you.

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

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 have done to achieve these results. We will continue to keep doing the everyday things that will add value. And I talk about it in all the presentations and 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 the Fayetteville and Marcellus plays, which will translate to better, faster, cheaper and ultimately more wells to drill over the life of the field. It also means that we're going to keep that focus we talked about and discipline on doing everything with a 1.3 PVI economic objective. And then we look finally at our New Ventures team. We're now generating tangible and new ideas at the rate needed to significantly impact our Company. We're going to have some more and expect 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 of 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.

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.