Southwestern Energy Company Q3 2013 Earnings Conference Call

Friday, November 1, 2013

 

Executives

Steve Mueller; Southwestern Energy; CEO

Bill Way; Southwestern Energy; COO

Craig Owen; Southwestern Energy; CFO

Jeff Sherrick; Southwestern Energy; SVP-Corporate Development

Brad Sylvester; Southwestern Energy; VP, IR

 

Analysts

Doug Leggate; Bank of America; Analyst

Will Green; Stephens, Inc.; Analyst

Gil Yang; Discern Group; Analyst

Charles Meade; Johnson Rice & Co.; Analyst

Brian Singer; Goldman Sachs; Analyst

Hsulin Peng; Baird Equity Research; Analyst

 Joe Allman; J.P.  Morgan Securities, Inc.; Analyst

Matt Portillo; Tudor, Pickering, Holt & Co. Securities; Analyst

Arun Jayaram; Credit Suisse; Analyst

Amir Arif; Stifel, Nicolaus & Company; Analyst

Biju Perincheril; Jefferies & Company; Analyst

Bob Christensen; Canaccord Genuity; Analyst

Ray Deacon; Brean Capital; Analyst

Dan McSpirit; BMO Capital Markets Corp.; Analyst

 

Presentation

 

Operator:  Greetings, and welcome to the Southwestern Energy Third Quarter 2013 Earnings Conference Call.  (Operator Instructions)

 

As a reminder, this conference is being recorded.

 

It is now my pleasure to introduce your host, Steve Mueller, Chief Executive Officer for Southwestern Energy.  Thank you, sir.  You may begin.

 

Steve 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 have not received a copy of yesterday's press release regarding our third quarter 2013 results, you can find a copy of all of this on our website at SWN.com. 

 

Also, I'd like to point out that many of the comments during this teleconference are forward-looking statements and involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the Risk Factors and the Forward-looking Statements sections of our annual and quarterly filings with the Security 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, we posted record results in the third quarter.  Not only did we set new records for production, EBITDA, and cash flow, but each of our operating teams achieved new milestones, as well.

 

I will let Bill and Craig recap how we achieved these strong results, but before we do that, I'd like to address a few questions that you might have.

 

First question -- Did SWN curtail any gas from Marcellus in the third quarter, and do we expect any curtailments in the fourth quarter?

 

Answer -- Both of those are no.  We put our system in place to purchase firm and follow that firm curve just like we had in the Fayetteville.  It's worked well in the Fayetteville, and it worked well for us in the third quarter in the Marcellus.  We'll talk more about that takeaway later in the call.

 

One of the things I do want to note, though, is on the marketing side, we had little bit of extra firm burn in the quarter, and we were actually able to buy some gas at less than $1 and sell it at $3.60 at another point.  I don't know if we'll be able to do that in the future, but it just shows you that having firmed several points is valuable.

 

Second question that you might have out there -- Some of the numbers aren't growing perfectly upwards, and sometimes those are 30-day rates, sometimes those are 60-day rates, sometimes those are the fourth quarter guidance, but does this mean we should expect bad things in the fourth quarter or next year or three years or five years down the road?

 

We'll be happy later on to talk about all the details you want as far as the numbers and which way they're trending and how important those numbers are.  You'll see a lot of the answers are some of the ones you've seen in the past, where we're in a slightly different area or we've got slightly different pressures going against other kinds of line pressures. 

 

But the key question is, should we expect something bad in the future?  Your expectations should be the same as ours, and our expectations are high, and we think things will be great in the future.

 

Third, Brown Dense.  I really struggled with how to describe where we are in the Brown Dense.  You know, we drilled our first commercial well and plan to drill three more wells by the end of the year, and that's where I start to struggle.  What do I tell you?  We're almost ready to declare commercial.  We're getting close to knowing the key things needed to make it commercial.  The text that Brad prepared and all the senior management agreed to says not ready to call the play economic but encouraged. 

 

For now, I'd like to tell you where I’m at on it.  Where I’m at today is that I believe we have a new discovery, and our task for our Company is to figure out how big.  Today if you ask me the size, maybe a township.  Could be much, much bigger when it's all done.  And our second task once we figure out how big is how fast we can get it into the pipeline and get it to the bottom line.

 

Those are the three questions I wanted to address to begin with.  Now, I'll turn it over to Bill for more details on our operations and then to Craig for a recap of our financial results.

 

Bill Way:  Thank you, Steve.  Good morning, everyone.  To echo Steve's comments, we had a terrific quarter which was again driven by our proven industry-leading operating capability and really underpinned by our curiosity and constant focus on delivering more to our shareholders.

 

Our Marcellus properties continued on our planned path of significant growth by reaching a gross operated production rate of over 600 million cubic feet per day of gas in August.  We also added firm transportation, as Steve mentioned, enabling this growth to continue.

 

In our Fayetteville, our focus on constantly improving the value of this huge asset continues to produce results as we placed two of the highest-rate wells ever drilled and completed on production during the quarter, with IP rates near 10 million cubic feet per day of gas. 

 

In addition, we continued testing the Upper Fayetteville formation, and in October, we brought on two wells, producing at the highest rates we've seen to date from Upper Fayetteville wells.

 

As Steve mentioned briefly, in our Brown Dense play, we have drilled and completed our first economic well, the Sharp vertical well located in Union Parish, Louisiana.  This well reached a peak rate of 600 barrels per day of 52 API gravity oil and 1.3 million cubic feet per day of 1240 Btu gas.  After 88 days on production, this well continues to flow at 530 barrels of oil per day and 1.1 million cubic feet per day on a 16/64th-inch choke.  We'll speak more about this and our plans in a few minutes. 

 

But I must say, overall, we completed the third quarter with a 19% growth in our total production and have made a third upward revision to our production guidance for the year.  This is testimony to the creativity, hard work, dedication, and focus of all of our teams on delivering more value in all they do.

 

Let me begin in the Marcellus, where we placed 22 wells on production during the quarter, which led to net production that was almost 200% greater than compared to a year ago, rising to approximately 45 billion cubic feet per day of gas, up from 15 billion cubic feet per day of gas in the third quarter of 2012. 

 

We continue to be pleased with our results as we delineate our acreage in Susquehanna County.  We placed 12 wells on production in this area during the third quarter, and gross operating production was 267 million cubic feet per day at September 30 from a total of 61 wells, up from 184 million cubic feet per day of gas at July 1.

 

We added another phase of compression in Northern Susquehanna County last week, which now allows over two-thirds of our wells in that area to produce at higher rates.  Additional compression is planned to be in service in the area in the first quarter of 2014.  We are planning on testing more of the acreage in the County as you move north and east towards the New York border, which will begin in 2014.

 

In December, we will drill our first well in Sullivan County on the acreage we acquired earlier this year, and we'll be drilling in Wyoming and Tioga counties in early 2014.

 

On the gathering side, our Midstream gathering company was gathering 344 million cubic feet per day from 89 miles of owned gathering lines across all of our Marcellus acreage out of a total of 611 million cubic feet of gas per day being produced at September 30.

 

It's well known that basis differentials in the Marcellus area widened dramatically at certain points beginning in June and during the entire quarter.  And as Steve mentioned, our gas marketing team did an outstanding job of getting the majority of our gas to high-value sales points with better prices during the quarter.

 

Our ability to move our Marcellus gas to better priced and more liquid markets is built on our strategy of securing firm transportation capacity to move our gas out of the area. 

 

In fact, we've just executed an agreement to secure additional firm transportation capacity on Millennium subject to completing a new interconnect project beginning in November of 2014 for an additional 150 million cubic feet of gas per day.  This increases our total firm capacity out of the basin to approximately 872 million cubic feet per day by the end of 2014 and over 1 billion cubic feet of gas per day by the end of 2015.  And we won't stop there.  We'll keep you updated as we are able to obtain more firm transportation capacity in order to move our gas to the best-priced areas in the country.

 

We expect to have another year of very strong results in Marcellus in 2014, and we'll be giving you more information in our plans for Marcellus in our capital program update in December.

 

In the Fayetteville Shale, we placed 89 operated horizontal wells on production in the third quarter at a record initial production rate of 5 million cubic feet of gas per day, and this rate was bolstered by an extremely good September, where we placed on production 31 wells at an average initial rate of 5.4 million cubic feet of gas per day.  Results during the quarter included two of the strongest wells we've drilled and completed since we announced the play in 2004, the Sneed and the Ledbetter wells, which achieved peak 24-hour production rates of 10.1 and 9.2 million cubic feet of gas per day, respectively.

 

As I mentioned earlier, we also had encouraging results from a couple of Upper Fayetteville tests placed on production in early October that achieved a peak 24-hour production rate of 6.6 and 6.7 million cubic feet per day of gas, respectively.  We're continuing to evaluate this reservoir and believe that it could provide material additional gas resource to capture over time.

 

Not only did we put online some of the largest wells in the play during the quarter, which contributed to our highest-ever quarterly IP rate in the Fayetteville, but we're also seeing tangible benefits from changes we are making in our completion and flowback procedures in certain parts of the play that are enhancing early well productivity. 

 

We began a procedure of resting wells for a short period of time, only 10 to 20 days, before we placed them on production.  Our results to date have shown that by resting these wells before we place them on production, we're seeing lower produced water volumes and, therefore, lower water handling costs and higher initial gas volumes in some areas.  We've completed a total of 55 tests to date and plan to have around additional 20 wells to place on production in the fourth quarter.

 

It now is a standard procedure in two pilots, our Pike and Sturgeon areas, where historically wells are relatively deeper and exhibited higher initial water production rates.  Those areas have shown the greatest benefit to date.

 

Our completed well costs were $2.6 million in the quarter, up from $2.3 million in the second quarter due to longer laterals and deeper average vertical depths.  Through the first nine months, our average well cost has been $2.3 million per well.

 

Our vertically integrated services continue to be a significant benefit in lowering our well costs, and that has resulted in an estimated $380,000 per well savings so far in 2013.

 

Let me move on to new ventures, where we remain encouraged -- I'll change that to excited -- about the work that's going on in the Brown Dense exploration program, where we're seeing it pay off and believe that the potential value creation from this project could be substantial for us over time. 

 

As I mentioned briefly, we have recently drilled and completed our first economic well, the Sharp, which is a vertical well located in Union Parish, Louisiana.  This well was completed in three stages with resin-coated proppant and crosslinked gel and accessed the entire Brown Dense interval, which is about 450 feet thick in this well.  The Sharp well has since shown a flattening production profile, which is promising, and we're encouraged about this result and will continue to watch the shape of its production profile over time.

 

Our next vertical well, the Hollis, was completed with three stages and, again, accessed the entire Brown Dense interval.  The well commenced flowback last week and is still unloading.  We'll keep you abreast of that in the future. 

 

Our McMahon well located in Columbia County, Arkansas reached a total depth last week, and we expect to complete this well with three to four stages in late November.

 

We also spud our Plum Creek vertical test well in Union Parish last week with a target vertical depth of 9,500 feet.

 

As we capture and understand the learnings from various technical studies underway and our recent wells in the near term, we will drill a series of vertical wells and apply what we're learning from these vertical wells to see if we can unlock more contactable reservoir volume with horizontal wells in the future.  We continue to test not only different completion techniques but also different theories in each of these wells.

 

While I realize the results we are reporting to you are only on a few wells with short production histories, we're excited about the potential in the Brown Dense.  We're learning more with each well we drill and making solid progress on best practices for drilling and completing these wells.  We believe we've moved our understanding and our performance in the play forward, and we'll keep working to unlock this resource and further improve our results.

 

In the Denver-Julesburg Basin in Colorado, our oil play there, the Staner well, which included a 3,400-foot lateral with 10 stages completed, was placed on production in July and reached a peak rate of 146 barrels of oil per day.  We'll continue to test the Marmaton and Atoka with additional wells to be spud in the first quarter.

 

In Paradox Basin in Utah, we'll continue to test our acreage with additional wells to be drilled in 2014, and we continue to lease acreage in this area and will update everyone on our activity by the next quarter.

 

To close, I'm very proud of the results we've had in the third quarter, but more importantly, I'm proud of the hard work and commitment that all of our teams have exhibited throughout the year. 

 

We know that there's more work to be done to keep driving our costs down, while increasing the innovation and the successful execution of every aspect of the projects we have before us.  And we remain really excited about our New Ventures projects and also are focusing on more exploration ideas to initiate next year.  We have much more to look forward to as we enter 2014. 

 

I will now turn it over to Craig Owen who will discuss our financial results. 

 

Craig Owen:  Thank you, Bill, and good morning, everyone. Our results in the third quarter were excellent, driven by higher production volumes and higher gas prices.  Excluding non-cash items, we reported record net income of approximately $180 million or $0.51 per share in the third quarter compared to net income of $132 million or $0.38 per share last year. 

 

Cash flow from operations, before changes in operating assets and liabilities, was a record $527 million, up 7% sequentially and up 26% compared to the third quarter of 2012, and also within $15 million of our capital investments for the quarter. 

 

Operating income for our Exploration & Production segment was $223 million, up 51% compared to $148 million in the third quarter of 2012.

 

We realized an average gas price of $3.60 per Mcf during the third quarter compared to $3.41 per Mcf last year, and have 84 Bcf of our remaining 2013 projected natural gas production hedged through fixed price swaps at a weighted average price of $4.68 per MMbtu.  We also have 233 Bcf of natural gas swaps in 2014 at an average price of $4.41 per MMBtu.

 

As for field differentials, we currently have protected approximately 74 Bcf of our remaining 2013 projected natural gas production from the potential widening basis differentials through hedging activities and sales arrangements at an average basis differential to NYMEX gas prices of approximately $0.06 per Mcf. This includes approximately 20 Bcf of our expected Marcellus volumes at $0.08 per Mcf. In total, we expect a $0.55 discount to NYMEX for the fourth quarter of 2013, which includes transportation and fuel charges.      

 

Our cash operating costs of approximately $1.25 per Mcfe in the third quarter continue to be a competitive advantage for us. 

 

Lease operating expenses for our E&P Segment were $0.87 per Mcfe in the third quarter, up from $0.79 per Mcfe last year, primarily due to higher third-party compression and gathering costs in the Marcellus shale, partially offset by lower saltwater disposal costs in the Fayetteville shale.

 

Our G&A expenses were $0.24 per Mcfe, up from $0.21 per Mcfe a year ago due to higher personnel costs.

 

Taxes, other than income taxes, were at $0.09 per Mcfe for both periods and our full cost pool amortization rate fell to $1.07 per Mcfe, compared to $1.30 per Mcfe last year.

 

Operating income for our Midstream Services Segment for the quarter was up 15% to approximately $87 million compared to last year. 

 

At September 30, our debt to total book capitalization ratio was 35%, which is flat compared to year-end 2012 and our liquidity continues to be in excellent shape.  We currently expect our debt to total book capitalization ratio at the end of 2013 to be approximately 34% to 36%. 

 

Looking ahead to the fourth quarter, the combination of another quarter of strong production and higher gas prices compared to last year points toward more records to be achieved by year-end. In addition, we expect to provide our initial outlook for our 2014 capital program, production and expenses in early to mid-December. 

 

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

 

Questions-and-Answers

 

 

Operator:  Thank you.  (Operator Instructions)  Thank you.  Our first question comes from the line of Doug Leggate with Bank of America Merrill Lynch. Please proceed with your question. 

 

Doug Leggate:  Thank you.  Good morning, everybody.  Steve, I'm not sure who wants to take this one, but if I could try two, one on the Brown Dense and one on the Fayetteville.  On the Brown Dense, I understand clearly, you're quite enthusiastic about the potential new discovery you're calling this morning. But can you give us some idea of scale, repeatability, location, or at least an idea of what's changed here for this latest vertical well that now gives you greater confidence that this thing is going to work? 

 

Steve Mueller:  There are several things that go into it.  Certainly, how we are fracing and what we're seeing on the fracing side has given a little encouragement, but really, it just goes back to historically what we've found to date.  If you go back to our third well that we drilled, that's the first well that we drilled in the high-pressure area.  That well has continued to produce fairly well and it looks like cash-on-cash, we will get our money back on that well. 

 

I think it was the fifth well that we drilled was called the Dean well. It's a vertical well and again, it won't make much greater return, but it will make a little bit of rate of return.  And then you've got this well that we just drilled, and to put this well in perspective with what we think the production curve is going to be going forward, this well actually cost us $10 million to drill.  It had some issues that we had on the drilling side and we also had a lot of science, but at $10 million, this well still is above our 1.3 PVI that's our economic hurdle. 

 

The Hollis well, the well that we just finished and just put on production, had a little bit of troubles up hole all over the zone getting through it. It was basically a clean well.  That well today, after we've done all the fracs on it, is less than $7 million and we think we can get that down to $6 million.  Well, a $6 million well with any rates anywhere near this is a high -- like 1.8 to 1.9 PVI, which is high, high, 80%, 90% rate of return type numbers. 

 

And when you look at the map where those three wells are across the area, that covers well over a township and that's why I said early on that we're fairly comfortable in that general area of the high pressure.  We've got more of these to go after.  We'll just work on the costs a little bit and the little bit we've learned on the fracing side. 

 

Doug Leggate:  Just to be clear, Steve, is this isolated to the high-pressure area?  And what proportion of your acreage does that represent at this point, at least what you think is prospective?

 

Steve Mueller:  We don't know if it's an isolated high-pressure area.  Almost all the wells we've drilled recently have been in the high pressure.  When I say almost all of them, the wells we're drilling right now, we internally call corner posts.  The 9th well that we drilled is the farthest south and west step-out we've done.  The 10th well is back on the Arkansas side of the border for what we're doing.  The 11th well is due north 8 or 9 miles.

 

So I can answer that question a lot better in another quarter or two quarters, but if you just take the high-pressure area, we're looking at somewhere in the 150-plus thousand acre range.

 

Doug Leggate:  That's really helpful.  And maybe -- I hate to labor the point, but you're now thinking about this as a vertical program, not a horizontal program? 

 

Steve Mueller:  We don't know.  In the Fayetteville early on, in the, I think, in the Eagle Ford early on, a lot of these other plays early on, they were vertical wells, and then later, went back to horizontal.  Theoretically, horizontal has ultimately out to be the right answer, but it's a lot cheaper to do it today with the verticals and we can learn faster doing verticals.  So we will continue doing that for a while.

 

Doug Leggate:  Thank you.  My follow-up, Steve, is just a quick one on the Fayetteville -- you've routinely given us an idea of what your economic backlog looks like at different gas prices.  Obviously, it sounds like things have changed quite dramatically with this difference in your completion technique, the resting and so on.

 

So I'm just wondering if you could help us -- you've previously talked about $4.50 was a kind of bogey for stepping up spending.  Could you just frame for us how your backlog changes with these better well results, and when you might start to think about getting a little bit more -- putting more money toward the Bakken and the Fayetteville?  And I will leave it there, thanks. 

 

Steve Mueller:  I don't know that we have a good answer on any changes to what I've talked about in the past as far as the number of wells yet, and the reason for that is when you look at the Upper Fayetteville, for instance, the Upper Fayetteville historically, we just kind of lumped those together and said we had so much in place, it was such a recovery factor. 

 

Now that we've got an area -- and again, it's over 100,000 acres -- it doesn't look like it's communicated to the lower.  You've got to go back and re-look at your gas in place across the whole field and make sure that you weren't conservative on that part.  Well, to the extent that you might be conservative, there could be a lot of locations that go into it and we're in early stages of understanding that. 

 

And then the completion techniques and the resting the wells and the changes we've done in fracs with a little more sand, the best way I can characterize that is we're learning each individual part of the field, how to do it better.  And so the northern part of the field, putting more sand, a little less water; it seems to be working fairly good, but the resting, frankly, isn't worth the effort.  Statistically, if you look at it, you get a little bit extra early on, but it's just not worth it. 

 

The southern parts of the field, that water gave us a lot of trouble before.  We weren't getting high enough initial rates to give us that first cash flow that we needed and there were a lot of wells that we put in a marginal category. And we're still trying to figure out how that works, but the theme here is after 3,000 wells, we're getting to the point where we are fine-tuning the individual parts of the field and we're seeing good things as we do that.  

 

Doug Leggate:  Terrific.  Well, congrats on a great quarter, Steve.  Thanks. 

 

Steve Mueller:  Thank you. 

 

Operator:  Our next question comes from the line of Will Green with Stephens.  Please proceed with your question.

 

Will Green:  Good morning, guys. 

 

Steve Mueller:  Good morning. 

 

Will Green:  Steve, you mentioned in your prepared remarks being a lot closer to knowing what it takes to make commercial oil in the Brown Dense.  We kind of just went through the high-pressure obviously being one of them.  Is there any kind of other things that, in hindsight, look to be obvious characteristics of making this work beyond just being in the high-pressure zone?

 

Steve Mueller:  Again, I need to caution you there.  We're in the high-pressure, but I'm not sure that is a criteria you have to have to make it work.  Certainly, the higher pressure, the higher initial rates, those kinds of things, so you always want higher pressure.  But we just don't know enough about the whole area yet to know what works and doesn't work.

 

There are some things we're learning.  Frankly, I don't want to discuss those right now.  I think that gives us some competitive advantage maybe in some other plays.  So I will just kind of leave it there.  We are learning some things. 

 

Will Green:  Got you. And you guys mentioned the thickness on the Sharp well was about 450 feet thick.  How does that compare to previous tests you guys have done in the play, and how does that compare to the McMahon and the Hollis? 

 

Steve Mueller:  In general, the thickness is a little bit thinner to the north in Arkansas and then thickens as you go into Louisiana.  So up by our first well, the Roberson well, if I remember right, that was a little under 400 feet, 350 feet or so.  And when you get to, say, the Hollis, the Hollis is a little bit thicker and starts approaching 500 feet, but the intervals between 350 in the very shallow part of the area down to 500.

 

Will Green:  Great, I appreciate the color, guys. 

 

Operator:  Our next question comes from the line of Gil Yang with Discern. Please proceed with your question.  

 

Gil Yang:  Good morning, everyone.  A great quarter -- can you talk about the -- it looks like the Fayetteville is throwing out a fair amount of free cash.  Can you talk about that and how you plan to allocate capital there going forward?  And is the goal to maintain production flat there, you think, or with these new well results, do you think that might be  a more growth area going forward?    

 

Steve Mueller:  We'll give our 2014 guidance here probably sometime in mid-December, but we've talked about in the past that we want to get the Fayetteville shale and we'd like to get the Marcellus as concluded as we can into the cash flow positive arena, and then make decisions about what you want to do with that excess cash flow. As you said, we are generating cash flow now and we'll continue to generate it, I think, into 2014.

 

And, the real question we have now is we've got 8 rigs running in the Fayetteville. If you add a rig and keep those 8 rigs running, how do you do it into 2014? And we'll talk about that later in the year. I don’t think you'll see us significantly increase the rigs, by that, I mean double the rigs or go 4 or 5 more rigs, but certainly, we'll tweak that a little bit.

 

And kind of a back way to get into your question about holding production flat, it takes about 7 rigs drilling with 6 to 8 average wells to hold the production flat. So if all you're doing is 8 to 9 rigs, it'll grow at single-digit numbers.

 

Gil Yang:  But that 7 rigs is based on the historical well results, right?

 

Steve Mueller:  Yes, right, right. And I don’t have enough information now to tell you what might happen if you had a little bit better wells.

 

Gil Yang: Right. And can you just detail the specific versus -- as specific as you're willing to talk about, the completion changes that contributed to the better well results in the Fayetteville?

 

Bill Way:  Yes, there were a couple of things that we did.  First of all, in the areas where we -- that 10 million-a-day well, for example, it's relatively deeper in the area.  It's probably more like 5,200 feet in vertical depth.  We had longer laterals.  So we're at about 8,500 completed lateral length with 18 frac stages.  We're trying to get more and more proppant in and we put about 7 million pounds of proppant in that well and 200,000 barrels of fluid. 

 

The other side of this has been looking at how we flow them back.  And certainly there's some efficiencies in getting pressure reductions out by removing tubing strings and replacing them with some shorter pup laterals that can allow for wellhead pressure drop -- pressure losses to be improved and improve friction pressure losses as well.  And we've made some changes in how we flow back to the midstream company in terms of de-bottlenecking pressure constraints there as well. 

 

So the result of all of that let us see quite a bit of improvement in the overall performance, and we're testing that across the piece.  I think the 10 million-a-day well IP was very focused on trying to test productivity from that particular area, but we're seeing higher IPs across the space.

 

Steve Mueller:  Early on, we'll be kind of boring on some of our responses on there.  But --

 

Bill Way:  Sorry.

 

Steve Mueller:  It's not that it means that Bill's boring.  But I think that the thing is, we've looked at the system wherever we're at and we look at every little point where there might be a bottleneck, and we're trying to get rid of those bottlenecks plus give you something to it.  And we went specifically with a couple of these wells and said, okay, do all the things you think you could to make it the best you can.  And now you're seeing what that best-you-can is.

 

Gil Yang:  And how much did that well cost?

 

Bill Way:  The 10 million-a-day well was $4.6 million, including some science and some additional costs for the testing itself.

 

Gil Yang:  Great, thanks very much for your help.

 

Operator:  Our next question comes from the line of Charles Meade, Johnson Rice. Please proceed with your question.

 

Charles Meade:  Good morning and thanks for taking my question. Steve, you anticipated one of my questions in your prepared comments about fourth quarter volumes.  And looking at it, especially relative to the beat versus your guidance that you put up in 3Q for volumes, it looks like there's just, I look at it as a percent and a half sequential growth for Q4 versus about 6.6% for 3Q over 2Q.  So it looks like that's going to be an anomalously low quarter-over-quarter growth that you're guiding to.  And so am I looking at it the right way?  And can you talk about some of the factors that may be a play there?

 

Steve Mueller:  There are kind of 2 things in general.  In the Marcellus, we won't have quite as many completions in the fourth quarter as we did in the third quarter.  And, frankly, the first quarter's going to have a lot more completions the way it looks.  And you say why is that happening?  We are drilling on pad for the most part, and depends on which pad comes up.  So if a couple of those pads move in early, earlier than we thought, you might see a bump in the fourth quarter.  If they stay where they're at today, the first quarter gets to see that bump. 

 

The other thing is, Millennium has said that they're going to have their pipeline down for 8 days, and we do have quite a bit of our capacity going down that Millennium line.  And that's a scheduled maintenance.  So when they do that though, we factored that into our fourth-quarter guidance.

 

Charles Meade:  Got it. That's exactly what kind of color I was looking for.  And then the second thing, if I could ask, the upper Fayetteville, I think -- I believe I heard you say that you have 100,000 acres perspective for that.  But what I'm really curious about is with 2 of those wells that came on over 6 million a day, I think my question is along the lines of, A, are those representative of what you think the upper Fayetteville can do?  And, B, if it is representative, how much of that is reflective of a better reservoir and how much of it is reflective of better improved completion designs?

 

Steve Mueller:  Again, I don't know that we want to go in a lot of details there.  We think we're learning some things that we can use in other places, and so I don't want to go to a lot of detail.  But we've got now 30, roughly 30 wells in the upper Fayetteville.  We've had some wells in the past that were very good wells, just not this good.  We've got at least one well over 5 Bcf that we drilled a couple years ago. 

 

So we spent the last year, year and a half delineating the area.  And just like I talked about earlier, now it's time to fine tune.  And as we're fine tuning, we're getting better wells.  Will all the wells in that 100,000 acres be that?  No.  But we're kind of learning the formula about the upper Fayetteville as well.  And again, there are some things there in that formula we think we can apply in some other areas.  So we'll just kind of leave it at that.

 

Charles Mead:  Thank you for the color, Steve.

 

Operator:  Our next question comes from the line of Brian Singer, Goldman Sachs. Please proceed with your question.    

 

Brian Singer:  Thank you. Good morning. Going to the Marcellus, production looked very strong during the quarter.  IPs, which I think you kind of highlighted in your opening comments, were down quarter-on-quarter.  Sometimes it can be difficult to draw conclusions when we look at the charts that it shows on one hand low IPs in the earlier days, but then performance that seems to be trending above your type curve. 

 

So I wondered if you could add some color as to, A, how the performance of recently drilled wells compares to past Marcellus wells, particularly those that are greater than 13 stages?  B, the degree to which midstream-related delays may impact the first couple hundred days of production.  And then, C, what you're seeing from wells drilled in northeast Susquehanna County after you've reached critical mass there.

 

Bill Way:  To address sort of the IPs up front, you'll know that in the Range area Susquehanna County, where we're doing a lot of drilling and completing, we also have a series of compressor stations and midstream gathering that is required to get those wells online.  And in the quarter, we were completing the compressor station to get another tranche of the wells.  So now we have two-thirds of the wells that we have gathered in that Susquehanna County area in the Range Trust now on compression.  So you'll see those IPs, as those pressures come down, improve. 

 

We've got solid performance.  We're very confident that as we move through the delineation of the Range area, wells are performing as we've expected.  And you get a bit of pressure difference between one end of the acreage to the other.  But all in all, we've now got quite a bit of confidence to go ahead and raise our overall gathering capacity, get additional compression in and then move that forward. 

 

So midstream is really just building out infrastructure, nothing to do with our long-haul capacity, which is solidly locked up. 

 

Steve Mueller:  And kind of -- you didn't quite ask this question.  But where are we comfortable?  How do we feel about the wells and how much acreage is it that go into it?  If you think about our Susquehanna total acreage, we've got about 130,000 acres, we're very comfortable that 60,000 of that acres, plus, is as good as anything that anyone's got out there.  And I think Bill mentioned in his comments going to what we call north range, which is right along the New York border.  We're heading that direction and we're still getting very good wells.

 

Now, we do produce our wells a little different than some of the industry does.  Bill mentioned some of the backpressure because of the compression.  We don't have near the choke size that some others do.  And so there's a lot of details that go into that.  And part of that goes to your question about 30- and 60-day numbers.  Some of our wells peak rates are actually past the 30-day mark, because of some of those issues, and we want to be consistent and give 30-day numbers.  So some of that's just how we're doing what we're doing out there.

 

Brian Singer:  And then I guess in getting the new midstream capacity there, the gathering capacity, is there an implied EUR-type curve improvement relative to your expectations?

 

Steve Mueller:  I think there's partially the fact that we're seeing wells get unrisked.  And whether you call that better wells or not, we had risked wells before.  And partially has to do with the new acreage, the Chesapeake acreage.  And we talked about that I think on last conference call where our ultimate target is to get up at least to 1.2 Bcf a day.  So it's a combination of both of those.

 

Brian Singer:  And then lastly, it looks like at least based on the cash flow statement, you spent a little bit more than $1.6 billion in the first 9 months.  Can you just talk to the CapEx trajectory in the fourth quarter?  And then, any early thoughts on next year?

 

Steve Mueller:  I think we've guided to $2.2 billion total, and I think we're pretty much on that for the capital for the year.  So we'll have borrowed a little bit of money this year.  And depending what you want to use on the pricing next year and what you want to guess about capital next year, if you did $2.2 billion again next year and you're in a $4 price range, we're basically close to neutral on our cash flow.

 

Operator:  (Operator Instructions) Hsulin Peng, Baird Equity Research.  

 

Hsulin Peng:  So I was wondering if you can talk about your target well design in Marcellus?  Just wanted to get a better understanding for the number of stages, lateral lengths in your standard well, as well as well cost and also EUR expectation and whether that varies across the different parts in Marcellus.

 

Bill Way:  We have an overall average on frac design for Greensweig at about 240-foot stage spacing.  That means about 17 frac stages per well.  We're inching that up a bit.  We do have right now 32 wells at 18 frac stages.  And, but we're pretty comfortable that 240 in the Greensweig range, which represents Susquehanna and Bradford Counties, makes sense. 

 

Probably over in the Lycoming area, we think that you're more likely optimized around 500-foot stage spacing, and we're doing some tests to determine that.  I think our lateral length numbers are really probably more directed -- or influenced -- sorry -- by the shape of the units and the geography.  As we do longer laterals in this area, we'll adjust spacing accordingly. 

 

Our well costs are running about $6.4 million on an average CLAT well.  And we think that we've got some opportunities to improve on cost associated with those, as we increase our activity and activity increases and there's more competition for services.  We are seeing completion costs come down, partly due to competition in the area and partly due to the fact that we have our own completion company, which is helping us get additional competitive pricing in that arena, as well.

 

The acreage varies, and so we won't -- just like we do in the Fayetteville, we won't lock in on one average stage spacing or completion recipe.  But we're being very targeted in how we go about that so we learn the most in the particular area.

 

Steve Mueller:  And let me just add, it's a very similar story to the Fayetteville or to the Brown Dense.  To the north, you're a little shallower, little lower pressure.  To the south and as you go in this case, off to the south and west, you're deeper and higher pressure.  And so the mix is going to be a little bit different from quarter to quarter.  And there are going to be different EURs.  We're still trying to understand what those EURs are right now.

 

I can tell you that, in general, the wells that we currently have on our books for the end of last year, going to this year, have an upward pressure on the ultimate recovery on those wells.  We'll talk more about that when we talk about year-end numbers.

 

Hsulin Peng:  That was exactly what I was trying to get at in terms of, it seems like -- it sounds like there will be improvement in your EUR currently versus where you were the end of 2012.

 

Bill Way:  Yes.

 

Hsulin Peng:  And then I guess if I can ask my follow-up question.  Just in terms of the improvements in Fayetteville, I was wondering how much testing or production history do you need to see before you could revise your EUR assumption?

 

Steve Mueller:  I think the answer to that is the same as almost any area.  You’ve got two general issues, the quality of a well and how big an area the quality of that well is over.  And the quality well takes several months of production to figure out the quality.  And then you have to do it in other places to figure out how much that's going to be.  So, for instance, in the upper Fayetteville, we had a lot of wells.  We've been working on it for almost 2 years now, so we feel better about it.  When you think about Marcellus or you think about the Brown Dense or something, we don't have near the wells, and we're still learning a lot.  So each one of them is going to be a little bit different on size and how fast you change your reserves.

 

I'll just remind everyone, when you do reserves, SEC says you have to be 90% certain.  So there ought to be always kind of an upward pressure on your reserves if you're doing it right.

 

Operator:  Joe Allman; JP Morgan.

 

Joe Allman:  Steve, back to the Upper Fayetteville.  So could you just give us the implications in terms of number of possible locations or resource size, given what you've done so far?  I think you said you've drilled I think over 30 wells, I think you said, and you've got over 100,000 acres.  And talk about your plan, too, in terms of mixing up the Lower Fayetteville with the Upper Fayetteville drilling over the next year.

 

Steve Mueller:  The Upper Fayetteville is between 40% and 50% of the thickness of the Lower Fayetteville.  So you're going to put in a wider spacing.  And we've talked about in the past that typical spacing for the Lower Fayetteville is 60 acres, in some places maybe a little tighter than that.

 

This is going to be wider.  This is going to be 80- to 100-acre spacing.  And we'll drill it just like any other of the plays, where you've got an upper, lower, or however you've done it, where, when we're there on the pad, we'll space out wells both in the lower and the upper at the same time.  So it's just when you're in that part of the field.

 

And for the most part, the acreage is on the northern part of our acreage block in some of the areas where we've done a lot of drilling in the past.  So as rigs move in there, you'll see us drill more.  So each quarter it's going to swing a little bit.

 

Joe Allman:  Okay, that's helpful.  And then, back to the tables that you put in the press release, so first with the Marcellus.  So if I look at that Marcellus table and I see in the third quarter you drilled the wells at the longest lateral length, the highest cost. But the 30-day average rate is not as high.  It's actually on the lower end of the prior quarters you list there.  So (multiple speakers) --

 

Steve Mueller:  I can give you the easy answer right there.  The mix changed a lot.  The other quarters were all Bradford County.  It's a little deeper and it's certainly higher pressure.  The pressure's what counts.

 

We flowed -- this quarter we had a lot of wells in the range area and we're flowing the whole thing, as Bill said before, against 1,100 pounds of pressure.  Well, 600 or 700 pounds difference in bottom hole pressure translates, if everything else is constant, to the lower rate.  Doesn't mean the quality of the reservoir is any different.  Doesn't mean anything more than now I've got a different differential between my surface pressure and bottom hole pressure.  And that's what you're really seeing what we're doing here.

 

On a per-foot, drilled per-stage shot, per-cluster, we're very comfortable with what we've done so far in that range, Northern Susquehanna area, that it's every bit as good as what we're seeing in Bradford County.

 

Joe Allman:  Okay, so it would not be a correct interpretation if we were to say that what you're doing in Susquehanna County is going to be less productive than what you've done in Bradford County.

 

Steve Mueller:  That would be a wrong interpretation.

 

Joe Allman:  Got you.  Okay.  And then, moving over to that Fayetteville table, so you've got the longest laterals, the highest IP rates, and you've increased the 30-day and 60-day from the last two quarters.  But the 30- and 60-day are lower than a bunch of the other quarters.  So what's the interpretation there?

 

Steve Mueller:  In some of the cases -- there's two pieces of this, and it's kind of like I said in the beginning.  Some of it's location, location, location.  So the rigs are working the southern part of the field now.  That is deeper.  There are some places where you can do longer laterals there versus some of the shallow portions of the field.  So you're getting a little longer lateral.

 

But it's also different characteristics.  And if you think about it, what Bill talked about on the rest of these wells you didn't change your EUR at all.  What you had was a low initial rate before that stayed low for a long period of time and you still got the EUR ultimately.  And all we've done is figure out a way not to have the water come to the surface.  But you need to get a higher IP and you get the whole thing back faster. 

And that's not really interpreted much in the 30-day rates, but as you get into the 60-, 90-, 120-day rates you start catching back up with that curve. 

 

So the curve does change a little bit in shape.  But it's really just a variance that you see going across there from the various locations and the things that we're trying to do in those locations.

 

Joe Allman:  But the EURs are not necessarily be less -- lower going forward?

 

Steve Mueller:  Not anything we're seeing.

 

Joe Allman:  Okay.  All right.  Very helpful.  Thank you, guys.

 

Operator:  Matt Portillo; Tudor, Pickering & Holt.

 

Matt Portillo:  Just a couple quick questions on the Marcellus.  Historically you guys have talked about kind of running a four rig count to get to your growth expectations.  With the incremental capacity you have today, in combination with the improved well results, should we expect any material change in your rig count?  Or with the better wells versus your previous expectation you may be able to still hit that higher capacity with the same amount of CapEx?

 

And then, just a second question in regards to the take-away capacity.  I was wondering if you could give us any color in terms of how much the incremental take-away capacity is going to cost on a transportation basis?    

 

And then, finally, as you guys think about the overall Northeast market, as the pipes get connected into New York, I was wondering if you could comment a little bit about how you think about basis in the New York market in 2014 and 2015?

 

Steve Mueller:  You had more than two questions there.  I forgot your first one, but we'll start backwards and we'll get back to your first one.  The whole basis as we look out into the future and then what do we pay for whatever we had in the newest announcement -- the 150 million a day actually is going to be relatively cheap.  We're paying about $0.10 for that.  So that's one of our cheaper rights that we're paying on any of it.

 

If you think about all of our firm that we've got, the high side on it, if we do back to back where you tie to one liquid point and then tie to another liquid point it can get as high as $0.50.  But most of it's in that $0.20 to $0.25 range.  And this is the low side of that.

 

As far as what's going on in the Northeast, we've been talking about it for over a year now, that as the Northeast trails you basically balance the country and you're going to have a minus in your long term, have a minus to the current plus that you had over the last couple of years.  And we think that minus is something, $0.20-plus, ultimately.

 

Now, over the short term it's going to be dynamic and I don't know that we can pick a point and say, well, this point's going to be bad this day and this point's going to be bad another day.  You can still move gas around, just like the example I use of where we bought from one and took it to another point and made some money.  There's a lot of dynamics there you can move in fixed points.

 

But certainly over the next year to year and a half, there's going to be times where a point has got issues.  And I think we should, for the most part, be in good shape where we can send to different points within the -- wherever has the issue.  That's been our goal for whatever we're doing as it goes through.  So that's kind of just a general statement there.

 

And what was your very first --

 

Bill Way:  The first part was on rigs.

 

Steve Mueller:  Yes, on rigs.  Especially on rigs, just say just stay tuned.  We're learning daily.  And the theory that you put together, as you get better wells and you don't have any firm, then yes, you can drill it with fewer rigs and you go with it.  But we're looking for more firm.  We're continuing to learn about our areas.  And we already talked about that starting the end of this quarter, we'll drill some wells in some new areas and start to learn from that.

 

Expect in 2014 we're going to have a series of wells that won't give much production in 2014, because we'll just be learning about what we need to do and what size systems we need to put in in some of these newer areas we have. 

 

So that's all going to play into whatever 2014 and 2015 look like.  And, as I said, just stay tuned and we'll talk about it as we go through.

 

Bill Way:  And I would add one further comment.  Just like our teams in the Fayetteville, the Marcellus team's doing a great job of lowering the number of days to drill and becoming more and more efficient.  So following rigs versus following well count -- we're already seeing some rather dramatic reductions in time to drill.

 

Matt Portillo:  Great.  Thank you very much.

 

Operator:  Arun Jayaram; Credit Suisse.

 

Arun Jayaram:  I wanted to see if you could elaborate on the well cost.  I  know you talked about bringing 19 wells on in the Fayetteville, which had strong IPs in excess of 6 million a day.  I just wanted to see what the average well cost, or how many of those wells would have been drilled at your average $2.5 million range versus the higher well cost?

 

Steve Mueller:  You mean the $4 million number that (multiple speakers) --

 

Arun Jayaram:  Exactly.  I'm trying to parse out --

 

Steve Mueller:  There were -- I don't even know if there's another well at $4 million, but there's maybe one or two at $3.6 million range, $3.8 million range.  But almost all of those were $2.5 million, $2.6 million, and $2.4 million.

 

Arun Jayaram:  Okay.  So the bulk of those are at the lower well cost.

 

Bill Way:  That's right.  And we purposely did this test.  And as I said before, we did a number of things in terms of testing and extending the lateral lengths and quite far, a number of things that added to that well cost.

 

Steve Mueller:  If you think about the general increase in well costs this quarter, if you average the lateral length goes up a couple hundred feet, we space our fracs about 300 feet apart.  So you're getting half to two-thirds more frac space per well.  And that's really the whole cost.

 

Arun Jayaram:  Okay.  And Steve as you think about looking at your Fayetteville EURs, generally we've been running around the bulk of your inventory being spaced around 600 feet, or just under 70 acres.  Is that still a pretty good assumption?

 

Steve Mueller:  That's fine.  Each area's a little bit different but that's fine.

 

Arun Jayaram:  Okay.  And then my follow-up question is just looking at the Midstream segment, obviously Devon announced a transaction with Crosstex, which was warmly received by Wall Street.  I'm just wondering, Steve, as you think about potentially financing the Brown Dense, where your head's at in terms of Midstream?

 

Steve Mueller:   Well, we will -- as far as financing Brown Dense, as we need the dollars, we've got a lot of different ways we can finance that.  And we haven't hardly used any of our borrowing base.  We've got some other assets we can do things with.  So I wouldn't just assume that we're going to scale up -- if and when we scale up the Brown Dense, that something's going to happen in Midstream.

 

Midstream, we think about that -- it's truly a very good asset.  It generates a lot of money for us.  As we look at it, it makes a lot more sense today for it to be inside our company than outside our company.  When you think about that LOE, when we talk about some $0.80 of LOE, $0.60 of that is the Midstream part, in both areas, both Fayetteville and Marcellus, actually a little bit more in the Marcellus. 

 

And so having it internal, especially when I know some of the people are a little bit worried about gas prices going forward.  And we need to be prepared if gas price goes down.  It's a big difference if you set up your own MLP and you've got $0.60 going cash out the door versus having an internal team.  So we like where it's at today.  And we'll make decisions about what we want to do with Midstream in the future.  But I wouldn't make the assumption that if the Brown Dense takes off and SWN needs capital we're just going to do something with the Midstream, or anything else, or the sand company or anything else.

 

Arun Jayaram:  Sounds like it's a core part of the business that you plan to keep for the time being.

 

Steve Mueller:  For the foreseeable future it's a core part of our business.

 

Arun Jayaram:  All right.  Thanks, guys.  Appreciate it.

 

Operator:  Amir Arif; Stifel.

 

Amir Arif:  Initial question is on the 55 wells that you've done the resting period on, if you can just give us a sense of what the IP was on those 55 wells, and if you have a 30-day rate on any of those, if you can provide that as well?    

 

And the follow up question is on the Brown Dense, on the verticals.  I know you've been -- done three or maximum first stage and I'm just curious that, given the thickness, what do you think the potential is for number of stages on vertical?

 

Steve Mueller:  I'll let Bill talk about Brown Dense and frac stages.  But as far as the resting and where it was beforehand and what it is in the future and what the 30-day rates, I don't have any of that numbers sitting in front of me.  I can tell you that, in general, the wells we drill in the areas we're drilling now, were 2 million type numbers.  And we're probably in the high 2's, low 3's on the numbers that we have.  So we've added 30% to 40% to the IP rates.  But I don't have any other details.

 

Bill Way:  And on the Brown Dense verticals, when we planned these series of vertical wells we were looking at numbers of stages being somewhere between 3 and 5.  And as we complete these wells, we began this process with the Sharp well, completing each particular stage separately so that we can run some logs and try to determine we're getting frac height or not, which would dictate how many stages we needed.

 

So we planned for 4 and evidence in the completion told us that we were getting greater frac height than we'd originally planned for.  So we backed it off to 3.  And we're using that sort of 3 to 4 frac stages as the planning and adjusting on the fly as we work through these.

 

Steve Mueller:  I want to remind everyone, we're not even close to understanding how many frac stages we need or whether it's horizontal or vertical.  So our best guess today may not be our best guess six months from now or three months from now, wherever that is.

 

Amir Arif:  Sounds great.  Thank you.

 

Operator:  Our next question comes from the line of Biju Perincheril with Jefferies.  Please proceed with your question.

 

Biju Perincheril:  Hi, good morning.  Following up on that Brown Dense question -- the number of stages that you're completing the verticals in, is that a function of simply the thickness of the formation or are you trying to access maybe different zones within the Brown Dense formation?

 

Steve Mueller:  It's both, it's both.  The eighth well, that's the good well.  We, for the first time, fraced the very bottom part of the Brown Dense, and we announced and we talked about that last quarter where we were getting I think a peak rate of about 170 barrels a day out of that.  And so in that case that fracs was set just for that zone, and then some of the fracs are just to get us across all intervals, as well, and that goes back to Bill's comments about each one we flowed back separately.  We did a lot of diagnostics on it, that's why it was a $10 million well, not a $6 million or $7 million well.  So we're still learning those things, but we're doing both.

 

Biju Perincheril:  Okay, and so when you're then drilling horizontally do you know if you're able to access all those different zones with one lateral or if that is the issue that you're having with the horizontal wells?

 

Steve Mueller:  Well, certainly, any of the horizontals we've done in the past we have not been able to frac across the entire interval, and so as we go into the future that will be one of the things we'll have to figure out, but I don't know, don't have an answer there that whether we can or can't yet.  Part of what we're trying to learn about the verticals is how to do it optimally so when we do try it horizontally we get a shot at it.

 

Biju Perincheril:  Got it.  And my follow-up is the upper Fayetteville wells that you drilled, the 30 plus, are those in areas where you have existing wells in the lower Fayetteville or Fayetteville areas?

 

Steve Mueller:  Yes, we drill the lower Fayetteville throughout the entire area.

 

Biju Perincheril:   Got it.  And then is the -- you're comfortable at this point that over that 120,000 or so acres you were talking about two separate reservoirs?

 

Steve Mueller:  Yes, there is an upper and lower almost across the entire field, not quite the entire field.  Some of it doesn't have much of a barrier and we know we're getting the upper and lower with what we're doing, and it's 120,000.  We're very comfortable that we're getting almost no contribution from the Upper.

 

Biju Perincheril:  Great.  Thank you.

 

Operator:  Our next question comes from the line of Bob Christensen with Canaccord Genuity.  Please proceed with your question.

 

Bob Christensen:  Yes, thank you.  Steve, on the Paradox Basin, the first well, what depth were you taking that to?  Because I saw a second permit, so my curiosity is up in the Paradox, can you tell us a little bit about it?

 

Steve Mueller:  Well, we were going for the Cane Creek, I think that was just under 10,000 feet is where we landed our lateral.  I believe it was about 9,800, 9,600 to 9,800 feet.  I'll tell you on this, that well we're still doing the completion stages of it, but the first couple stages that we've done and completion have not given us the results we were hoping for, and that doesn't give us any discouragement.  This play is going to take some wells to figure out if it's going to work or not. 

 

We're certainly permitting some other wells, but there's several industry players around us that are drilling and permitting wells, also.  So that's one of the reason Bill didn't say much about it, and I won't say much more about it.  There are other zones, though, in the Cane Creek that are shallower and some of the permits you may see that are shallower that some of the other people are out there.  And we'll be testing some of those zones in this well.  So that's why he said stay tuned and wait a quarter, so and we'll talk in a lot more detail.

 

Bob Christensen:  And then my follow-up comes back to the Lower Smack, when do you think you might drill the next horizontal well?  And the follow-up on that is can you go back to two or three of your horizontals and refrac them and maybe learn by that?

 

Steve Mueller:  Well, our seventh well has -- is a horizontal, it has one or two stages in it right now, but it's ready, as we learn from the verticals to go do some experimentation on, and really that could happen anytime.  Once we get to a point where we want to try that.  As far as drilling another horizontal, not in our immediate plans right now.  As I said, what we're trying to do now is do what we call corner posts, what's going on towards the edge, and work back towards the middle with some of the vertical wells that we're doing. 

 

And then as far as reentering a well, we're looking at that.  Probably not, maybe on one of them you could do something, but unless you've fraced it there's -- trying to get science from it, fracing them and then trying to learn from what you just did is very, very difficult, and there's some mechanical issues all the time going back in a well.  So we've got one well we can do some experiments on, and we will do those, and then future horizontal wells are down the road.

 

Bob Christensen:  Thanks.

 

Operator:  Our next question comes from the line of Ray Deacon with Brean Capital.  Please proceed with your question.

 

Ray Deacon:   Yes, hey, good morning.  Thanks for taking my call.  I'm just wondering, Steve, if you could expand a little bit on your response on the differential issue because it seemed as though you did much better than any of your competitors relative to NYMEX this quarter, and I was wondering if you could be a little bit more specific about how you had the options to take gas to different pricing points, I guess, from the Marcellus?

 

Steve Mueller:  We set-up our system to -- I need to start with the two big lines that we can take gas to is Tennessee Gas Pipeline and Millennium Line, that's where -- that kind of brackets most of our acreage.  So I'll just start right off the bat and say if both of those have severe problems at some point in time, then we're going to have some problems.  So I can't tell you we're never going to have a problem, but we have enough flexibility that we can bounce between Millennium and Tennessee Gas fairly easily, and that's because of our north, south ties between the Stagecoach Line and that DTE Line, and that's one of the reasons we've waited so long to start developing.  We needed to have a redundant and dynamic system before we wanted to get out there and do it.

 

And, basically, those lines, I think there's five or six different places you can sell on those lines by themselves.  The Constitution Line will come in 2015.  It didn't help us this quarter, but that goes north, jumps over those lines and gets us to another point.  We can take gas today to the Midcontinent markets, and take some of our gas to the Southern markets.  And I won't go into a lot of details about that, but it's the same strategy we had in the Fayetteville Shale, where in the Fayetteville Shale we can do anything west of the Mississippi or I mean east of the Mississippi and get gas to it.  Our ultimate goal in the Marcellus is to be able to do the exact same thing.

 

And the thought process isn't about this year or next year.  We're going to be there for 20 or 30 years.  I can't tell you even five years from now exactly where you need gas.  I know you'll need it, and I know the major population areas of the Marcellus, so I know it'll always be priced better than the rest of the country, but that doesn't mean that you're not going to have some bumps along the way.  And so our purchasing is thinking down the road and trying to be prepared for anything that might come up down the road, and it's worked well for us this quarter as we go through it.

 

Ray Deacon:  Great. Thank you.  And, just one more quick one, are you willing to talk about the breakdown of spending on new ventures, the $133 million between drilling and acreage, 3D, I guess?

 

Steve Mueller:  This year I think it's just under $50 million, that's the land part of that.  There's probably less than $10 million of science in it, and that number could change a little bit depending on what happens in New Brunswick, but it's basically in the $10 million range, and the rest of that is drilling for 2015.

 

Ray Deacon:  Okay, got it.  Thank you.

 

Operator:  And due to time constraints, our final question comes from the line of Dan McSpirit with BMO Capital Markets.  Please proceed with your question.

 

Dan McSpirit:  Thank you, and good morning, folks.  Is there an asset in the new ventures portfolio that could rival the Brown Dense in resource potential and maybe value creation, whether it's the -- that found in the Paradox Basin or elsewhere?

 

Steve Mueller:  That's one of those trick questions, Dan.  We've got some acreage we haven't talked about.  We would hope that we have acreage that would rival the Brown Dense in our portfolio, and certainly whenever we go into any of these plays we think about them as potentially being significant. 

 

Now after you learn from them, and I'll use the Bakken in Montana, where we talked earlier about the fact that we were there and decided it just didn't quite make it to what we needed.  There may be something in the Bakken in Montana, but it doesn't have the scale after we did our first couple tests there. 

 

And so it could happen that whether it's Colorado or Paradox or something we haven't talked about, doesn't -- after we drill a couple of wells starts getting smaller and it gets too small for what you're doing, but today the Colorado and Paradox both in our minds have the potential to be significant to our Company.  Now certainly the Brown Dense is 500,000 acres, the Colorado is 300,000 acres, and we haven't talked about Paradox, but there's a little bit of scale in acreage, but we still think there's significant and can be significant to the Company.

 

Dan McSpirit:  Understand.  And then quickly as a follow-up, on the Brown Dense, to confirm in your view the play doesn't necessarily need to work on a horizontal basis for it to be declared a repeatable commercial success, correct?

 

Steve Mueller:  Not, at all.  As a matter of fact, the three best wells drilled to date are vertical wells.

 

Dan McSpirit:  Right.  Very good.  Thank you.

 

Steve Mueller:  Thank you.

 

Operator:  Thank you.  Mr. Mueller, I'd now like to turn the floor back over to you for closing comments.

 

Steve Mueller:  Thank you.  Over the years we have attended several investment conference, and I was asked recently by one of the new people to our story, what makes you excited about Southwestern Energy?  And, you know, for any CEO that's a question we love to get, and we're always excited to get it.  And I just wanted to end this with what makes me excited about Southwestern Energy.

 

And, first and foremost, it's our formula, the right people doing the right thing, wisely investing the cash flow from underlying assets, creating value plus.  And I think this quarter shows the value plus.  But the reason I started with the formula, it defines our culture and that's the culture that Bill talked about before, about the relentless curiosity that leads to innovation, that leads to records that we saw in this quarter.  The other thing about that formula is it drives our values, and you can't be successful without having the right kind of values, and so that's the number one thing I'm excited about. 

 

I'm certainly excited about the Marcellus.  We've talked a lot about it today, the well results, the northeast corner, talked about growing production, and then we talked about the fact that what we've seen to date I think our acreage matches with almost anyone else's acreage out there on a productivity per foot or on a productivity for lateral length or frac stage or however you want to do that.

 

I'm also excited, and we talked about it in one of the last questions, about the firm capacity we have.  It took us a little longer to get started because we thought it was very important to have that firm capacity in place.  We're continuing to add to that firm capacity.  We saw the benefits of it in the third quarter.  I think we'll see some benefits of it in the near term, and I know we'll see some benefits of it in the long term as we go through.

 

And then I'm really excited in starting the fourth quarter, and you'll see as we start in 2014 you're going to see us move into some of the other counties on the new acquisitions that we had and you'll start seeing tests in Wyoming, Sullivan, Tioga Counties, and we'll talk about that starting early next year.

 

And then the Fayetteville Shale, I'm excited, the fact that we keep learning to unlock more of the resource potential.  We keep -- that learning has allowed us to understand more about the Fayetteville Shale, and I'm excited about that. 

 

And then I'm excited on the exploration effort, and the first thing, the exploration effort obviously comes up is Brown Dense, but I'll just remind everyone Brown Dense is only part of our 1.3 million acres, remember we had in that last question, there's some good things I think that can come out of that acreage, as well.  And we'll continue to have that million plus acres as we look out into the future that we'll have as upside to what we're doing.

 

And then I'm excited obviously about our performance and the records we've set, and I'm especially excited about the fact that a lot of our peers have given up on natural gas and, most importantly for us, we haven't given up on natural gas, but we're actually and very easily able to deliver more value per dollar invested, and that's what makes value plus, value plus.

 

And then, finally, I'm excited about the future.  I think we have a transparent growth path and some great project areas, and the one key thing I want to leave you with is that we've got one of the few teams in the entire industry that understands what it takes to drill more than 3,000 wells, produce 3 Tcf of gas in nine years out of a single field, and I think that's going to do a lot for us in the future.  I think what we're learning, as I said in some of the calls, we’ll probably set-up for some of the things we're thinking about in the future, and I think that gives us an advantage.

 

So, with that, thank you for joining us today.  We'll look forward to a great fourth quarter, and I wish you the best weekend possible.

 

Operator:  Ladies and gentlemen, this does conclude today's teleconference.  You may disconnect your lines at this time.  Thank you for your participation, and have a wonderful day.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Explanation and Reconciliation of Non-GAAP Financial Measures   

    

We report our financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However, management believes certain non-GAAP performance measures may provide users of this financial information with additional meaningful comparisons between current results and the results of our peers and of prior periods.     

    

One such non-GAAP financial measure is net cash provided by operating activities before changes in operating assets and liabilities. Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.   

    

See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the three months ended September 30, 2013 and 2012, and 3 months ended June 30, 2013. Non-GAAP financial measures should not be considered in isolation or as a substitute for the company's reported results prepared in accordance with GAAP.