西南能源 (SWN) 2014 Q3 法說會逐字稿

Greetings and welcome to the Southwestern Energy Company third quarter 2014 earnings conference call. At this time, all of the participants are in a listen-only mode.

A brief question-and-answer session will follow the formal presentation. In the interest of time, please limit yourself to two questions. Afterwards, you may feel free to requeue for additional questions.

(Operator Instructions)

As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Steve Mueller, Chairman and Chief Executive Officer for Southwestern Energy Company. You may begin, Mr. Mueller.

Thank you. Good morning and thank all of you for joining us today.

With me today are Bill Way, our Chief Operating Officer; Craig Owen, our Chief Financial Officer; Jeff Sherrick, Executive VP of Exploration and Business Development; and Michael Hancock, our Director of Investor Relations. If you've not received a copy of yesterday's press release regarding our first-quarter results, you can find a copy of all of this on our website at www.swn.com.

Also I'd like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the Risk Factors and the Forward-Looking Statements sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.

Now let's begin. In one sense, the recent announcement of our potential new core area for our Company has been very eventful. In the sense of third quarter results, it has been the consistent performance our shareholders expect from our staff and our high-quality assets.

Production continues to increase, well economics improve as we learn how to best drill and then produce the very stratigraphic objectives, and the well inventory increases as we apply what we learn to other zones. Yes, gas price is down relative to earlier in the year, and yes, it will continue to be challenged next summer and fall. But we built that volatility into our 2015 -- our 2014 plan; we built it into the acquisition economics and we'll build it in our 2015 plans.

Some interesting persistent counterpoints are beginning to change that gas price balance. This will be the first winter since 2008 with a total storage less than 3.75 Tcf, and indications are that storage could be as much as 5% less, or approximately 3.5 to 3.6 Tcf.

The ongoing worry is obviously the 12-month average production has grown at just over 4.3%. But it's often forgotten that the demand growth has also kept up, or almost kept up, at 3.9%, and new demand from known projects will increase that base over the next five years. In addition, the current demand increases occurred in a price environment that for the most part has discouraged switching from utilities using coal to gas, and has happened as net imports continue to decrease.

In short, as the storage curve indicates, this is not 2012 from a gas price scenario. And Southwestern Energy is stronger and a better company, poised to take advantage of the better outlook, but also able to deliver top tier results when prices are lower, like we have this quarter.

Before I turn the call over to Craig, let me mention that we have little new information regarding our announced acquisition. But I do want to address one impression. I have heard and read that Southwestern Energy is making a call on natural gas with this acquisition.

While we believe gas fundamentals are improving, the acquisition is not a call on gas. It is a call on quality. Quality wins in every price environment.

That is all I'll say about the acquisition for now, but we have much more to talk about regarding our quarterly performance, and I'll now turn the teleconference over to Craig for an update on our third quarter financial results.

Thank you, Steve, and good morning, everyone. As Steve mentioned, we had another excellent quarter, primarily driven by record production volumes. Excluding certain non-cash items, we reported net income of $178 million, or $0.50 per diluted share for the third quarter, compared to $180 million, or $0.51 per diluted share last year.

Our cash flow from operations before changes in operating assets and liabilities in the third quarter was $504 million, compared to $528 million for the same period last year. Operating income for our exploration production segment was $189 million, compared to $223 million we recorded in third quarter of 2013. This decrease was primarily due to lower realized natural gas prices and higher operating costs and expenses due to increased activity levels, and partially offset by the revenue impact of increased production.

Including hedges, we realized an average gas price of $3.43 per Mcf during the third quarter, compared to $3.61 per Mcf last year. Excluding hedges, our average realized gas price increased to $3.21 per Mcf from $3.06 per Mcf last year. Hedging added about $0.22 per Mcf to our realized gas price in the third quarter, compared to adding about $0.55 per Mcf last year.

Our realized average gas price in the Marcellus was $2.73 per Mcf for the quarter. Our firm sales agreements, along with our financial basis hedging activities, protect 63% of our Marcellus production for the remainder of 2014, at NYMEX plus $0.12 per Mcf, excluding transportation charges. Currently, we also have about 34% of our 2015 Marcellus volumes protected with financial basis hedges and firm sales agreements at a price of NYMEX minus $0.13 per Mcf, excluding transportation charges.

We also have 117 Bcf, or approximately 59%, of our remaining 2014 projected natural gas production hedged through fixed price swaps at an average price of $4.35 per MMBtu. We also have 240 Bcf of natural gas swaps in 2015 at an average price of $4.40 per MMBtu.

On the cost side, our cost structure remains one of the lowest in our industry, with all-in cash operating costs of approximately $1.29 per Mcfe in the third quarter of 2014. That includes our LOE, G&A, net interest expense, and taxes.

Lease operating expenses for our E&P segment were $0.91 per Mcfe in the third quarter, compared to $0.87 per Mcfe in the third quarter of 2013. The increase is due to a combination of higher compression costs in the Fayetteville and the continued growth in Marcellus, which has higher gathering rates than the Fayetteville.

Our G&A expenses were $0.23 per Mcfe, down from $0.24 per Mcfe a year ago. Taxes other than income taxes were $0.10 per Mcfe, compared to $0.09 per Mcfe last year. And the full-cost full amortization rate in our E&P segment was $1.09 per Mcfe, compared to $1.07 per Mcfe last year.

Operating income from our midstream services segment rose 13% to $97 million in the third quarter compared to the same quarter in 2013, primarily due to increases in gas volumes gathered, which resulted from our increase in E&P production volumes. Midstream EBITDA was $111 million for the third quarter in 2014, a Company record, compared to $99 million in the third quarter of 2013.

At September 30, 2014, our debt to total book capitalization ratio was 30%, down from 35% at year-end 2013. The debt balance includes $139 million borrowed on a revolving credit facility at September 30, and that is down from $171 million borrowed at June 30, and $283 million borrowed at December 31.

I am very proud of these strong results we had this quarter and am very excited about what the Company has coming on the horizon. I will now turn it over to Bill Way for an update of our operational results.

Thank you, Craig, and good morning, everyone. As mentioned earlier, we had a great third quarter. Our operating teams impressed once again with strong performance, allowing us to again set production records.

The Marcellus Shale had an impressive 47% growth in production, and we continue to improve our understanding and build additional confidence in our acreage position. In the Fayetteville, where -- we are seeing the benefits from implementing the learnings and efficiencies we have identified to date be translated into record production rates, an increasing number of wells with initial rates in excess of 5 million cubic feet of gas a day, and increasing numbers of future wells to drill, all of which exemplifies the curiosity and innovation that differentiates Southwestern Energy from the pack.

An example of our curiosity and learning during the third quarter is our focus and testing of optimal landing zones, increased profit loading, and frac spacing. In both Fayetteville and Marcellus, we are experimenting with these and other drilling and completion techniques, and early indications appear favorable. If we can confirm this with further testing and analysis, it could result in decreased well costs.

On the exploration front, we have an exciting portfolio of opportunities in the pipeline and are making good progress on testing of the projects that we have publicly announced. I'll walk through the status of some of these projects in a few moments.

Each day, I'm impressed with the dedication and focus that our employees bring to the common goal of working together to find new ways to add value. This teamwork has been instrumental to the strong results that the Company is delivering in 2014.

To begin with the Marcellus Shale, our production in the third quarter grew to a record 66 Bcf, which as I said is an impressive 47% increase over our volumes produced in the third quarter of 2013. We've seen continued improvement in our productivity index in the Marcellus, up 200% since we entered the play, through a combination of optimized lateral placement, stage spacing, and profit loading. In the quarter, we completed a well using as much as 835,000 pounds of sand per stage, and we expect well results on this soon.

We remain committed to growing our production to match our firm transportation capacity, and we continue to look for economic opportunities to add additional capacity to our portfolio. Our strategy of finding the firm capacity, and growing production to those levels, has helped partially insulate the Company from some of the depressed pricing in the region during the summer and shoulder months.

Additionally, our basis hedges provided a benefit of over $9 million during the quarter. We were moving 840 million cubic feet of gas per day in the Marcellus Shale at September 30, and as I said, transporting the gas through our firm transportation capacity to market.

Let me pause here in this discussion of flowing to firm capacity, and say I know there have been some questions regarding the 30 day average rate of our wells in the Marcellus this quarter. While our well mix of 14 wells includes some testing of new areas, we manage the overall Marcellus business on value and not just IP rate. Our marketing and operations teams work very closely together to optimize the value of gas -- we receive for our gas, and in the current pricing environment we've increased production, pulling harder on wells during high demand days of the week, and pulling back on wells on the weekends.

Again, the flexibility of our firm transport allows us to maximize the value of every Mcf we produce. By the end of the year, we currently have firm transportation out of Pennsylvania under contract, which totals more than 1 billion cubic feet of gas per day, and increases to almost 1.2 billion cubic feet of gas per day in 2016. Our current drilling budget allows us to ramp our production to match this increased firm transportation capacity.

Additionally, on the midstream front, the range area in Northeast Susquehanna County now has 600 million cubic feet of gas per day of compression capacity, and this will be a significant benefit to us as the productivity of the field continues to improve. In the most northern part of our Susquehanna County acreage block that we call North Range, we've completed the acquisition of 3D seismic, as we continue to derisk the area. The team is now interpreting the data, and we'll be able to utilize the results as we move forward in our development plan in North Range.

Initial well testing results from North Range area in Susquehanna County continue to be encouraging. We are well under way in extending our gathering system into North Range to gather production from this acreage as well.

In Wyoming County, we've now drilled our first horizontal well, the Dimmig 2H, and we plan to test it in the fourth quarter. Additional locations are planned in both Sullivan and Wyoming Counties, as we progress our delineation efforts in that area.

Additionally, in the upper Marcellus we've drilled three wells during the quarter that are anticipated to be completed during the fourth quarter. A fourth well is also expected to be drilled by year end, with completion planned in the early part of next year.

In the Fayetteville Shale, we again had our best quarter in the Company's history for production volumes, and had our tenth consecutive positive cash flow month. We placed a total of 106 wells online, at an average initial production rate of roughly 4.3 million cubic feet of gas per day. Two of them are in the top 10 ever drilled, at over 10 million a day each.

We also had increasing average 60 day rates of 2.5 million cubic feet of gas per day, reflecting the better wells drilled in the past quarter. We are continuing to monitor well results from higher-rate wells, as we assess whether these wells have higher EURs or if they are accelerating production. Either way, the team's continuing to create value for the Company.

In the Upper Fayetteville formation, the Company has placed 15 Upper Fayetteville wells online through the first nine months of 2014, with an average production rate of 3.4 million cubic feet a day. Three of these wells had an average initial production rate of over 5 million cubic feet of gas per day, with the highest IP rate being 6.6 million cubic feet of gas per day.

We plan to drill five additional Upper Fayetteville wells in the fourth quarter and complete them in early 2015. While it's early, we estimate that the Upper Fayetteville may span over 130,000 acres, or 1,000 well locations, for future development opportunities.

Regarding our vertical integration, we're nearing completion of the upgrading of our drilling rig fleet, where we took possession of our fifth rig of seven rigs during the quarter. The capability of these new rigs continues to impress, as the technological improvements are helping obtain even more efficiencies in the process. We fully expect to reduce the drilling days of Fayetteville wells by one day, allowing us to drill more wells with fewer rigs.

Our gas gathering business was gathering and transporting approximately 2.3 billion cubic feet of natural gas per day on September 30. We have additional firm transportation capacity to deliver any growth from our acreage in the play, and we are positioned very well to supply future long-term demand for our Fayetteville asset.

Moving to exploration, we now have drilled three vertical wells in northwest Colorado, targeting the Niobrara formation, and are drilling our first horizontal well. An additional vertical well is planned for the fourth quarter.

As we mentioned before, we anticipate it will take us 8 to 10 wells before being able to determine the long-term commerciality of this play. As we continue to get more data and make progress in our testing, we'll talk more about well results and what we are finding, but we are encouraged so far.

In closing, we've had a great third quarter and first nine months of 2014, and we are looking forward to finishing the year even stronger. The amazing team of people that I have the privilege to work with every day continues to innovate and find ways to improve performance and capability, which gives me great confidence in our road forward.

This is an exciting time for Southwestern Energy and we look forward to sharing even more terrific results on our next call. This concludes my comments, so we will now turn the call back over to the operator, who will explain the procedure for asking questions.

Thank you. We will now with conducting the question-and-answer session.

(Operator Instructions)

Doug Leggate, Bank of America Merrill Lynch.

Two quick ones if I may. Steve, I'm afraid I missed the call last week. I was traveling, unfortunately, when your call was on.

I wonder if I could risk a question on the acquisition and then one on the quarter, if I may. On the acquisition you did make clear that your investment grade credit rating is very important to you. I don't want to get into specifics, obviously, but I'm just curious if you could frame for us what that means for you in terms of metrics.

I think you did say the midstream was not high up on the list. But just for completeness, if you could give us a tax basis there and just any color around what you think retaining an investment grade credit rating would mean in terms of potential financing structure. And then I'll get a follow-up on the quarter, please.

Okay, I'll mention kind of what it means and each group that's out there has different criteria they look at. We, on a very simplistic basis, and Craig talked about it, we look at that debt ratio.

You talk about 30%. Historically, we like to be in the low to mid-30s. This acquisition will bring us up to something higher than that, and when we talk more about it, we'll show you how we're going to get that debt ratio down, what it will be and how we get it down.

And that's to be discussed at a later date. As far as tax basis on the midstream, I'll let Craig answer that.

Our midstream in general is fairly mature. Most of that investment has occurred over the past 10 years, certainly, but really in the last seven.

So the tax basis is not significant. I won't say exactly what it is, be but we enjoyed the benefit of that tax depreciation over the past couple of years.

Okay. Thank you.

It's basically the capital that we're spending right now.

Right. So in the event of any monetization, then, there would be a fairly hefty tax impact? Is that a good way of thinking about it?

It depends how you monetize, but that is correct.

Okay, my follow-up in the quarter is really more -- you obviously have continued to have substantial success in the Upper Fayetteville. So routinely you've given us an idea what the economic backlog looks like at a range of oil prices.

So I'm just wondering if you could give us an update as to how the Upper Fayetteville is changing things in terms of what you see as economic, let's assume a stressed gas price, call it $3.50 in perpetuity. I don't know what sensitivity you've used but any color as to you how you see that backlog in the current environment would be great. Thanks.

Let me just put the Upper Fayetteville in perspective with the Lower Fayetteville. They're separated at most by 100 feet. It's relatively small interval separation, so cost, lateral length, all those things are almost identical between the two zones.

The Upper Fayetteville is a little bit thinner than the Lower Fayetteville, so where the Lower Fayetteville we're drilling on 60-acre spacing, the Upper will be more just over 100-acre spacing. That's why Bill made the comments about 130,000 acres with 1,000 wells, because it will be wider spacing.

With that wider spacing, EURs, IPs will be very, very similar to the Lower Fayetteville. So that same distribution I talked about in the past where at $3.50 we had something 2,400 or so wells to drill going forward, you can add probably about 250 to 300 wells of Upper into that category and when we had $4 flat forever, that's the 1,000 wells that Bill was talking about.

That's great. Thanks a lot. Appreciate it.

Jeffrey Campbell, Tuohy Brothers Investment.

When you put out the press announcement on the West Virginia acreage acquisition, you also stated that Southwestern was considering dispositions of certain non-strategic assets. I was just wondering if you could he provide some color on what acreage might be behind that statement?

I don't know that we're going to make much comments about that now. Stay tuned and in about three weeks we'll go in a lot of details on that.

Okay, and the other question I wanted to ask was getting back to investment grade, but maybe a little bit different way. You did say you didn't want to threaten your investment grade and you didn't want spending to get uncoupled from cash flow. I was just wondering, how will this affect your development plan for the Colorado Sand Wash if the West Virginia acquisition actually comes through?

It's all about economics and it's all about quality. So any exploration project, not just what we do in the Sand Wash Basin, if we have a discovery it will be what we do with it and how fast we grow, it will depend on the quality of that discovery.

If it's the best economics we have in the Company, a bunch of money is moving in that direction, and something else isn't getting drilled, and if it's in the middle of pack, and it has less to it, and it's on the lower side, maybe we don't keep it. So it really is just the economics, and as Bill said, economics on that won't be known, at least on Sand Wash, won't be known until probably this time next year.

Thanks, Steve. That was very helpful.

Michael Rowe, Tudor, Pickering, Holt & Co.

I was wondering, could you provide just a little bit more detail around just the moving pieces that cause the IP 30-day rates out of the Marcellus to look a little bit lower? I think this has been the lowest kind of since the third quarter of 2013. So just wondered if you could go through that in a little bit more color, please.

Bill's kind of addressed it a little bit in his comments. I'd say he kind of did a political dance around on that.

But basically, what we've been doing, and we've talked about this in the past, if we could buy gas someplace else and make more money than producing our gas, we would shut wells in. And specifically to his comments, weekends are low demand time. The weeks are high demand time.

So what we've been doing is we're not shutting all of our gas in. But we back down on the gas on the weekends. When we don't think there's demand, we get more gas that kicks up during the week.

And on those 14 wells, there were three or four of those that their 30th day rate hit on weekends. So it's just simply that.

Okay, that's helpful, and then I guess you made a comment that in both the Fayetteville and the Marcellus you're sort of testing optimal landing zones, increased proppant loading and tighter frack spacing. And you also mentioned you expect, potentially, some reductions in well costs. So could you talk about, I guess, what are the key drivers of reducing well costs there, just given the fact that you potentially are doing a more enhanced completion than you had previously?

It's really about how much sand per foot we can get into the ground and optimizing that amount of sand. And so if you take a look at the Marcellus wells, for example, where we are -- our objective is to test and increase the sand loading on these wells.

If I can get 800,000 pounds of sand into the ground in 17 stages, or I can get 800,000 pounds of sand into the ground with fewer stages than that by increasing concentration, it affects the cost of completion. We'll test it to make sure that it doesn't impact the overall recovery, but you're trading parts. I can either have 18 stages or I can have fewer.

In the Fayetteville it's the same way. We pay to pump based off stage count, and the more sand we can pump into each stage improves the quality of the frack and lowers the cost overall of the well.

We're doing some other things on well cost as we've talked before. We rest every well in the Fayetteville that we have after we drill it and complete it.

The result of that is that there's less flowback water to no flowback water that comes back. That really impacts us to the tune of about $100,000 a well because we're not moving water around from place to place. If we can -- where we can drill longer lateral's as units allow or we combine units together to do cross-unit wells, we're at the well site one time drilling a longer lateral and enabling us to optimize cost there as well.

On pad drilling, when we go to a pad we drill out the initial acreage capture well, but then when we come back to a pad we work very hard to try to only go back one time and drill all the remaining wells, rather than making multiple trips. Our new rigs certainly are able to drill faster. They're also able to move faster, they're more agile, both on the road and on the pad site.

If we can crack the code of single trip drilling, you have additional cost opportunities that come in both areas. And we're working on that as we speak.

As you can see, we've got a lot of different things that we're doing. Let me just make two kind of general comments.

I know the industry has gone to tighter spacing and you even said in your question tighter spacing. We have certainly tried and are continuing to try some very, very close spacing, 80, 90 type frack intervals in some of our wells. But what we're seeing, if we can put a lot of sand away we actually do less fracks, less stages. So that's part of that savings.

Then the other thing, and it should be obvious from Bill's comment, we're trying just a lot of things and continue to try a lot of things. As we do those, some cost more, some cost less, but we think the end result is less cost.

Okay. Thanks very much.

Dave Kistler, Simmons & Company.

One thing in the Fayetteville, as you guys hit these higher IP rates, can you talk a little bit about how you're optimizing surface infrastructure for those kinds of changes? I would guess you had a standard well design and is that starting to fluctuate a little bit to allow for greater IPs out of the gates and is that changing any of the capital burden?

We've modified facilities in two areas, primarily. First, being how we run tubing and the design of that tubing in the well. At these higher rates, taking tubing down below all the safety equipment and stopping there allows the well to have less restriction to flow to the surface.

One of the things that happens in any kind of very highly efficient business is you tend to go down a path where everything looks the same. You're buying multiples of the same kind of meter run and separator and all that. What we figured out is that in some of the areas we really do have a need for some larger equipment.

So where a two inch meter run might have been standard, now a three or four inch meter run might be there. So we're optimizing all of the midstream gathering facility standards and equipment. In addition, then we look at optimizing flow lines into the main gathering system.

And what we're talking about here is well connection flow lines. The main trunk lines of the field are already invested and so we look at the economics on an integrated basis to determine the optimal pipeline sizes and other facilities. So it's kind of through the -- from the well bore all the way through to the compression point.

We also are working on some new processes or work plans around getting wells back online sooner, which brings in some well side compression, gets those wells unloaded and online faster. So it's kind of an overall logistics and optimization effort and it has a number of components.

I appreciate that. Maybe switching over to the new ventures just for a second. You, in the past had mentioned doing a vertical test in the DJ Basin that was going to be pretty impactful on a go or no go decision for developing that asset going forward.

I didn't see any comment in the release on that this time. Any color you guys can provide us on that?

Let me just say that we drilled that well in the second quarter. We have fracked or tested what we call the Atoka interval and we're getting ready to test the Marmaton, which is shallower intervals. And when we get that all tested we'll talk about it but just haven't got all our testing done yet.

Okay, I appreciate that. Any early indication that's helpful or still we just don't know until we get all final detail?

Atoka is a fairly tight zone, and so -- and it's a fairly thick zone. We tested a couple of intervals in it and it performed like we thought it was going to perform. That's pretty low perm.

And then the Marmaton's a completely different kind of interval. It's a higher [frost], higher permeability, it's not conventional but it's more conventional than it's unconventional in its characteristics. Atoka tested like we thought it was going to test.

Marmaton's what we're about to test. And they're completely different, you can't add or subtract anything, you just have to test them and come to a conclusion.

Great, I appreciate the color, guys. Thank you so much.

Gil Yang, DISCERN Investment Analytics.

You had really tremendous success in a number of wells in the Fayetteville, scattered over a pretty broad part of the play. Can you talk about how predictable those really strong wells are or are they a little bit unpredictable in terms of when -- obviously you tweak a lot of things, but can you predict when those tweaks are going to generate those really good wells?

Then in that context, what proportion of your inventory do you think has the opportunity to be on that really strong result category?

In the Fayetteville Shale, and it really is a comment about most unconventionals. You can get a sense of what's going to happen, but trying to predict whether it's a 10 million a day well, 12 million a day well, or 8 million a day well is difficult but you can tell it should be in that range. And so there is some variability. But you can certainly start figuring out the size, and your real question was is how many of those do we have?

As we said, each area's a little bit different and we're trying different things and so shallow, it's not quite the same as it is in the deeper part of it. But we think about 20% of our 600,000 acres has a potential for some kind of enhancement. And when I say some kind of enhancement, some of that might be reserve, but certainly all of it will have some kind of acceleration component to it, to the economics.

That 20% of the acreage would be -- would that first on the 20% of the remaining locations or a greater percentage or smaller?

We probably won't add any locations if that's what you're asking or add very few locations. The locations we have you now are better.

Okay, so 20% of the remaining locations could be of that extra strong category.

Should have something -- some kind of enhancement to it.

Then my -- sort of the second question is the exit rate of the Fayetteville seemed to be down in the quarter. Was there any commentary around that? Is that significant at all or is it just sort of the day-to-day variability?

I think that was just the way it bounces around.

It's just really well mix and timing of completing fracks. There's nothing there.

If you look on there, you can almost tell when we put a big pad on and not put a big pad on our production curve. It bounces up a little bit and it goes down a little, and you see it bounce back up again.

Thank you very much.

Bob Brackett, Bernstein Research.

Quick question on the final EIS for Constitution Pipeline. Any thoughts on that, and what do you think the next milestones for getting that truly constructed are?

I don't know that we have any thoughts on that too much. We follow it just like everyone else does. You've got -- the big thing that will happen after we get some approvals here, supposed to be happening right now, is get approvals from New York State.

Once you get approvals from New York State, unless there's some kind of misestimate on water crossings or road crossings, it's a relatively short process. We know what that process is, and it's a nine month type build. But just making sure you get all the permits and predicting when and how you're going to get all those permits is the issue.

A quick follow-up. What's your interest in joint ventures in general? Looks like you could potentially be having a partner in this new acquisition in West Virginia.

Is that something you look forward to? Is that something you'd prefer not to do? Would you consider it for other assets?

I think as long as they're quality partners, and certainly in West Virginia that partner brings a lot to the table, both technically and financially, as long as they're quality partners we don't have any problems with partners at all. And especially on the exploration side.

We said in the past that in New Brunswick, that we probably will get a partner some point in time because it's too big of a project for us. So partners are just another one of those things you use and work with when you're there and as long as you make sure you've got high quality, no problems at all.

Okay. And if that partner in West Virginia offered their interest in that acreage, would you be tempted?

You know, I don't know if I want to address that one right now. We'll just have to wait and see if we'd be tempted or not if that ever happens.

Okay. Thanks, Steve.

Charles Meade, Johnson Rice & Company.

Picking up on that point of Bob's, I recognize -- I think I recognize the good reason you have to be reticent about the acreage, but given you tantalized us a little last week talking about the Wetzel County, Utica well coming online. Presumably your working partner is looking at the same well reports as you are. I wonder if there's anything you could add on that.

There's activity going on and drilling and completion and all kinds of well activity going on in that acreage right now. We don't own the acreage so we can't talk about it, frankly.

It's just one of those things. Once we get a little farther down the road and we actually own it I'll be happy to talk about a lot of things on that acreage.

That makes sense, Steve. Thought I'd give it a shot.

If we can go back up to the Northeast Marcellus, the two things I'd like to ask about, that Wyoming well and what you're seeing on that North Range acreage. First, on the Wyoming well, I know you're still testing it but can you talk about maybe what you've seen as far as the pressures you've encountered, and the you drawdown if you proceeded to that far in your testing and how that is fitting versus your expectations?

I'll kind of address both of them right at the same time. Right now we don't want to talk about it.

And whether it's farther North Range and in the case of far North Range, we're just in the early stages of getting production back, so there's nothing to talk about. And in the case of Wyoming County, there's obviously a lot of other competitors around us and there's some advantages to keep all information quiet for a while.

I guess that makes me "O" for two. Good questions, but bad timing maybe.

Ask them in a few months and I'll answer them all.

Thanks a lot.

Joe Allman, JPMorgan.

Bill, could you -- I know you covered this in some of your answers, but could you go through both the Fayetteville and the Marcellus and talk about the standard completion designs you're using now and then what have you changed that you're seeing encouragement on early on? And also could you address these changes you're making, how do you think they compare in an oil reservoir versus a gas reservoir?

In both areas what we're focused on are kind of three things. One, optimizing where we're landing in the interval, and right now in both areas we think we've found a place in the particular interval where you get the best fracture initiation to begin that frack.

The second thing we're looking at and spending a lot of time on is proppant volumes. And so in Marcellus, for example, we've gone in the past couple -- probably 18 months or so from 250,000 to 300,000 pounds of sand per stage, up to, as I said before, we're testing as high as 800,000 pounds of sand per stage and trying to determine -- we believe that the more sand we can get per stage into the -- around the well bore, the better quality flowback we get. We're trying to find, really, the end members on that so that we can optimize it, and then looking, as I said before, about individual stage spacing.

So that range so far, has grown. As I said, early, early on it was 250,000. I think this year we sort of standardized around 350,000 to 500,000 and now we're going from 700,000 on up to 850,000.

In the Fayetteville, we're trying to do the same thing, except the numbers are a bit different, obviously. We were at about 65,000 pounds a stage before, and we're going up to about 100,000 pounds. We've got three tests going on in that right now; we don't have any specific early results yet where we want to land.

As I also mentioned, as part of this whole completion there's flowback in both areas we rest these wells to try to keep the water in the ground. In some parts of the Fayetteville, especially the deeper areas, we do get a bit more gas back than in -- otherwise the rest of the acreage is pretty much -- in the shallow areas, it's pretty much just the water doesn't come back so we save on operating costs.

We'll continue to share that knowledge back and forth between the assets and try to use what is now 4,500 or 4,300 well database to instruct us as well, to just see exactly where that goes. Obviously, we have no real production in the oil side. But I know from our understanding of the industry higher sand loading in some of the oil reservoirs are improving well results in that space as well.

And what Bill is talking, we quickly looked up -- a couple of us quickly looked up what the average is for this year. For the third quarter in the Fayetteville per well, and again, our stages haven't changed much over the last couple years, doing about 115,000 barrels of water, about 4.2 million pounds of sand. When you compare that to the Marcellus, it's 150,000 barrels, so not much difference on the barrels side but about 8.5 million pounds of sand.

So we're putting significantly more sand in the Marcellus. And that just goes back to Bill's comments, both whether it's the liquid in there or the rock itself, you have to design the fracks for that rock.

That's very helpful. And then as a follow-up, just moving just to the Marcellus and production and FT, I'm just curious, what can you do to increase production beyond FT? Besides making a big acquisition in a different area.

I'm specifically asking about the Northeast. What can you do to kind of enable Southwestern to increase production even more than the 1.2 Bcf per day of FT you've got lined up?

I think the answer, at least for the next couple years, is you want to stay within your FT. And so what we said several times between now and the end of the year, you'll see and hear us commit to some other FT that's out there, and as we do that, you'll see how that ramps up and whether it's this year, next year or beyond and how that works in the overall picture. But it's really getting more FT up there, at least for the next few years.

I think by the time you get to 2017, certainly by 2018, that becomes less of an issue. So other than that, from our perspective anyway, we're just going to follow FT.

Great. Thank you very much.

Dan McSpirit, BMO Capital Markets.

Regarding the 1,000 Upper Fayetteville Shale locations, how many of these locations meet the Company's economic hurdle at, say, sub $4 gas, maybe $3.50 NYMEX?

As I was saying before, it's probably in the 250 to 300 range. Maybe a little more than that. That's the range.

And then at $4 flat, that's all 1,000 wells. That's what we usually talk about.

Got it. And as a follow-up, regarding the recent acquisition and your review of the assets and operations, can you sketch for us where, maybe, efficiency or effectiveness gains can quickly be achieved, maybe put differently, what are the easy levers to pull to drive better returns at the field level than maybe what the prior operator achieved?

We certainly have some ideas. But until we get out there and actually get on the ground, they're just ideas. I think the key is we're not going to start out of the box fast and that's why we talked about the fact that we'd start ramping up to five rigs and then work it up to 11 rigs over a two-and-a-half, three year period of time.

We don't know exactly what we can do. As I said, we have ideas.

But what we're concentrating on today is doing all the due diligence to work towards closing and getting answers from the partner on pref rights. That's a question probably to ask towards the end of the first quarter.

Very good. Thank you.

Brian Singer, Goldman Sachs.

This may have been asked earlier, apologies. But can you just talk about how you're thinking about capital commitment to exploration, A, and then B, when you think about non-core opportunities, is there value in any of the historically exploratory areas or are you kind of waiting to create value there?

Let me start with exploration in general. We think that's important to do and we will, today, and continue in the future doing exploration. Now, certainly with the acquisition, we may slow down a little bit from the pace we've been in the last year or two years and invest a little bit less in 2015 and 2016, maybe 2017, but we will do exploration.

Then the question of how that fits in and what you do with the exploration, has to do with the risk on the exploration project early on and then what you find later on. And if it's high risk with significant upfront capital commitments, going back to earlier discussion, we may bring partners in. If we have a discovery and that discovery, depending on the economics of that discovery, we'll slot it in as we need to slot it in.

In some cases that may mean bringing in a partner to help us on that part too. So it's going to depend on the project, the kind of project we have and whatever we discover. But we will continue to do exploration.

Great. Thanks. And then as a follow-up, have you had or engaged any of the potential LNG consumers regarding their interest, either in upstream positions in areas like the Fayetteville or the Marcellus?

We have talked to a lot of different groups. Some of them either have or want to have LNG positions. Others are utilities and others are end users and still others are some kind of industrial.

And there's all kinds of different wants and demands and timings on those things. But we have talked to them, we know generally what the market is. I don't know if there's something else to your question.

More in the context of opportunities beyond funding for the acquisition with just debt and equity. Really trying to identify what the asset sale potential is and whether that's an avenue for you.

We'll talk more about that in the future. Certainly anything that we have, if we can get the right value for it, we're going back to the partner questions and everything else.

We're willing to look at it and talk about it with whoever's out there. It's just that's something to catch or capture as it comes up.

Thank you.

Biju Perincheril, Susquehanna Financial Group.

Steve, a question on your Fayetteville firm transports. Can you give us some idea of the sales contracts you have associated with those firm transports, what the duration of those contracts are?

To kind of put it in a general perspective, Fayetteville Shale's been producing -- this is the tenth year anniversary on it. We have a couple different agreements for transportation. One with Kinder Morgan and one with Boardwalk.

They start expiring in probably three-and-a-half, four years, and the first one would be Boardwalk. These are 10 year terms. And the next -- Kinder Morgan would be another year, year-and-a-half past that.

Actual commitment is just over 2 Bcf a day, it's about where we're at right now. And it's, I think $0.26 or $0.27 is what the transportation fee is, average.

Okay. When you say --

those two pipelines together add up to over 4 Bcf of total takeaway. That was going back to the comments earlier that we have plenty of takeaway. The industry's taken just a small percentage of that and so there's plenty of takeaway if we want to go faster in the Fayetteville.

Got it. And then that three-and-a-half to four years, that's the FT itself, or is that sales contracts under those FTs?

That's the FT.

Okay, got it, and then another question was on the midstream. If you were to monetize it, hypothetically speaking of course, you do already break down -- give a segment breakdown in your reporting. So would there be any impact to the reported cost structure for the upstream business?

We -- in our upstream side of it, we count the gathering fee in our LOE. So when you look at our $0.91 LOE, there's roughly $0.60 of that, that's gathering.

All right. That is being paid to, I would imagine in the South -- in Fayetteville, Southwestern midstream.

Wherever -- whoever's gathering the gas for us is going to pay that, yes.

So if you were to separate the midstream business, there would not be an impact on the upstream cost structure as it is reported today? Is that correct?

On the pure upstream cost structure, no. On the actual reserve life, yes.

Can you give us a little more color why on the actual reserve life?

Well, when you run the -- for instance, if I want to run, whether I keep the well producing or not, as long as it's within my Company I'm going to back out that gathering fee when I do that calculation. If it's not in my Company then it's actually going to be money out the door and the reserve life gets cut off earlier. So yes, we accounted for it, but on any well that's marginal you're going to have to back that back out again.

Okay. Any way to quantify what that would be, if you were to look at your (multiple speakers) --

Lets look at these questions when and if we do something with the midstream. In a few weeks, we'll tell you what we're going to do financing-wise and if midstream's part of that, you can ask all the questions you want.

That's fair. Thank you.

David Heikkinen, Heikkinen Energy Advisors.

On fourth quarter guidance, do you have any update to thoughts on volumes for the quarter?

No, we didn't bother to change that any. As Bill said, we've got the new capacity coming on the Marcellus. So that production will continue to go up and Fayetteville's performing well.

So if I had to guess, we're on the high side of that number. But with a couple months to go, we just didn't bother with it.

And just a couple knits and gnats here. Realized price in the Fayetteville, and I think you said that you're expecting to cut a day from your drilling days in the Fayetteville, you've been 6.8 year-to-date, so you'd be -- is that 5.8 for next year or is that only on the new rigs?

That's really only on the new rigs. It will have a 5 on it, probably.

Okay, cool. And then realized price, just in the quarter for the Fayetteville, you said the Marcellus was $2.73, I believe.

Right, Fayetteville was $3.51.

$3.51. Okay. Thanks, that was it.

Scott Hanold, RBC Capital Markets.

Thanks, good morning. Really quickly, remind me, are you guys still running eight rigs in the -- horizontal rigs in the Fayetteville? And if you did get your well drill times down or your rig days down by one, is the plan still to operate within cash flows so that's reducing the number of rigs in that area?

We are still running eight and the rest of that question's kind of 2015 budget. And we'll talk about that here in a couple months, I hate to say this all the time but unfortunately this quarter's just the wrong time. It needs to be about three or four weeks from now.

Fair enough, guys. I'll leave it at that, thanks.

Thank you. Ladies and gentlemen, we have reached the end of our allotted time for questions. I would like to turn the floor back over to Mr. Mueller for closing comments.

Thank you. You know, I ended up my comments earlier about talking about not being a call on gas but being a call on quality. Certainly, this quarter again shows the quality of our assets and what we've been able to do with those assets. It's not about the growth, it's not about size, but it's about understanding and hopefully -- and I know a lot of the questions were about understanding, understanding what we're doing differently and we're learning and what want to do differently.

That brings me kind of to who we are and what we do. We have three main strategies. The first one is develop our current assets better than anyone else can.

The second one is learn quickly, and then apply that learning rapidly so that we don't just create learning at a linear pace but we create it at an exponential pace. And then the third one is be net positive in how we do our work and how we engage the communities and that has to do with net positive, and what we do with water, net positive what we do with methane emissions and certainly how we work with regulators in the various communities we work in.

When you think about that, each one of those strategies has something that goes up and beyond and we call that value plus, and that's what we try to deliver and whether it's a new acquisition, whether it's exploration or it's our old core assets that have all that strength I talked about, that's what we'll do.

As I said in many ways in the past, our success is not based on growth rates. It's not size. But it's that curiosity that leads to innovation and it's coupled with the disciplined approach to delivering above average economics.

The outcome, and I want to emphasize that, the outcome of doing that every day is the improvement, the quality, the growth, the other things that go with it and you've seen that in what we've done this quarter. Our pledge to you is that we'll continue to learn. We'll continue to be curious and we'll continue to be disciplined and if we do that, we'll have many more quarters just like today.

Thanks for listening today. Have a great weekend and that concludes our teleconference.

Thank you, Mr. Mueller. Yes, this does conclude our teleconference.

You may disconnect your lines at this time. Thank you for your participation. Have a great day.