西南能源 (SWN) 2015 Q3 法說會逐字稿

Greetings and welcome to the Southwestern Energy Company's third-quarter 2015 earnings teleconference call.

(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. Thank you, sir, you may begin.

Thank you. And good morning and thank all of you for joining us today. With me today are Bill Way, our President and Chief Operating Officer; Craig Owen, our Chief Financial Officer; Jeff Sherrick, Executive Vice President of Exploration and Business Development; and Michael Hancock, our Director of Investor Relations.

If you've not received a copy of this morning's press release regarding third-quarter 2015 financial and operating results, you can find a copy 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 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 vary or differ materially. Now let's begin.

These are challenging times in our industry. Whenever I see a fellow with a history in management we always begin the discussion with comments about how we've seen tough times in the past and how we'll make it through these tough times as well. What is understood, but not said, is that we also received many scars in the past tough times, and we'll have many more before the cycle is finished. An even deeper but unspoken understanding is that not all of our organizations will actually survive these times.

So why start a quarterly call with this conversation when Southwestern Energy's results were strong compared to consensus expectations? Very simply, we have designed the Company and will continue to evolve what we do to make sure we are not just a survivor, but one of the winners who have been toughened rather than weakened by these current times. You might be thinking that many other companies say similar things, so what is our evidence that Southwestern has the right characteristics to flourish? First, look at the quarterly results and our results from the past many quarters. We have delivered on what we said we were going to do, and as you'll hear in this call we are positioned to keep delivering.

Second, those results could not have been accomplished without discipline. Our low cost structure is part of the evidence combined with our focus on investing every dollar wisely. It is easy to track that discipline if you have the data, and that is the reason we publish tables every quarter in investor relations materials following our progress with actual production and cost information. We began reporting the first iteration of that data in the Fayetteville shale almost 10 years ago, and we'll continue that transparency in the future.

Discipline also relates to the capital budget. Last quarter we guided our 2015 budget down from approximately $2 billion to $1.875 billion. And even though drilling times are improving, we will not exceed that guidance in 2015.

Third, while we may have an opinion about the direction of oil and gas prices, we will manage as if prices are lower for longer for both commodities. Like many management teams we're wrestling with several uncertainties in 2016 and probably will not give 2016 guidance until after the first of the year. The one thing I can confirm about 2016 is our absolute focus on investing within cash flow.

Finally, and probably the most important point, is the significant upside that has been added to each of Southwestern Energy's three assets during the quarter. We will go into more details, but we drilled economic extensions in Northeast Pennsylvania that have added both quantity and quality to our well inventory. In addition, the best wells ever drilled in the Fayetteville shale area were completed in third quarter, and in our West Virginia assets our estimate of the recoverable resources has increased more than 5% in roughly 10 months since the acquisitions. Times are difficult, but Southwestern is up to the challenge.

Let me now turn the call over to Craig Owen so we can begin the more detailed discussion of our quarterly results.

Thank you, Steve. Good morning, everyone.

We met or exceeded each of our guidance metrics provided to the street as we continue to deliver operationally and focus on improving margins in this challenging commodity price environment excluding certain non-cash items, the most significant of which was a $1.7 billion net of tax ceiling test impairment. We reported net income attributable to common stock of $3 million, or $0.01 per diluted share, for the third quarter compared to $178 million, or $0.50 per diluted share, for the third quarter of 2014. The mandatory convertible shares issued earlier in the year had the impact of reducing our current quarter earnings by $0.07 per share due to the dividend.

Our cash flow from operations before changes in operating assets and liabilities in the third quarter was $330 million compared to $504 million in the same period last year. We realized an average gas price of $2.21 per Mcf during the third quarter, including hedges, and $1.77 per Mcf excluding hedges. As a reminder, all of our realized prices include the impact of transportation costs. We have been diligent on our cost control focus, which has always been a differentiator for the Company. Our all-in cash operating costs were approximately $1.22 per Mcfe in the third quarter of 2015.

At September 30, 2015, our total debt was approximately $4.7 billion with over $1.2 billion in liquidity available. Our debt balance included a combined $800 million borrowed under the revolving credit facility in our commercial paper program. We remain committed to flexing our capital investment program in 2016 to keep debt at or below its current level. We have no plans to issue additional equity, and expect to manage through this cycle by flexing our capital investment program and potentially utilizing non-core asset sales.

When meeting with investors we often receive questions related to our investment-grade rating. Based on recent feedback from the rating agencies and our intent to flex our capital program with cash flow, within cash flow, we are comfortable with both our rating and rating outlook. That wraps up the financial update for the third quarter. We are in a challenging environment and are extremely focused on improving our financial performance as we close 2015 and prepare for 2016.

I'll now turn it over to Bill Way for an update of our operational results.

Thank you, Craig, and good morning, everyone. Once again we had a strong operational performance in the third quarter. In addition to delivering another quarter of record production, we continued to find ways to benefit from our curiosity and innovation and cut costs across the business while improving well performance.

Our teams remain concentrated on identifying efficiencies and finding ways to deliver more with less as we focus on margin management and rapidly applying learnings from industry and between our teams to generate even better well results. There are multiple examples that demonstrate this in action throughout our Company, with one of the biggest being the pace in which our Southwest Appalachia asset has achieved its impressive results from applying learnings from Fayetteville in Northeast Pennsylvania and implementing those as we ramp up that business.

Let me recap some of the results and some of the other highlights for the quarter from each of our divisions. In Southwest Appalachia we have taken the momentum that we discussed on last quarter's call and built on it, further demonstrating the potential of the rock and our ability to maximize the value of this acreage, resulting from the smooth integration of this new asset and the pace that the team has sprinted up the learning curve to realize these results.

We set a number of drilling and completion Company records and achieved pace setter performance during the third quarter. An example of this is the work done on the Alice Edge pad in Ohio County, West Virginia where nine wells are expected to begin production during the fourth quarter. One well on this pad had the longest measured depth the Company has ever drilled on a single well at over 19,000 feet. The lateral length alone on this well is over 12,000 feet.

This pad also had the Company's longest combined total completed lateral length on a single pad at over 86,000 feet, and utilized more than 200 million pounds of sand in the completion operations, a new single pad record. We look forward to bringing these wells online and updating you on their performance going forward.

For the third quarter we had net production of 37 billion cubic feet of gas equivalent, and a net exit rate for the Southwest Appalachia business was 407 million cubic feet of gas equivalent per day with 40% of the 2015 wells anticipated to be drilled and completed this year remaining to be brought online during the fourth quarter.

Included in the third quarter results were five wells that were drilled and completed by Southwestern. These wells, similar to the wells that were brought online during the second quarter, are materially outperforming their offset wells that were drilled and completed by the previous operator. For example, the Charles Fry pad, which has three Southwestern drilled and completed wells online, outperformed its offset wells by 54% with an average AUR per 1,000-foot of sea lat of 2.1 Bcf equivalent.

In fact, when you look at all six Marcellus wells that have been drilled and completed by Southwestern and brought online, these wells are producing at rates 60% higher than the type curve that was used for the acquisition analysis. The wells in this area are being drilled nearly 100% within a tighter landing zone where we have determined that productivity is greatly enhanced. In addition to the drilling accuracy, completion activities are being optimized and we are seeing improved results as well. The wells are being completed with tighter stage spacing of about 260 feet and increased sand volumes of more than 2,000 pounds to as much as 3,000 pounds per foot.

As the team advances its learnings and gathers more data in this area, we anticipate these results will potentially get even better. In addition to productivity of the wells being better than we anticipated, we are also seeing industry-leading cost in this area where our total well D&C costs have recently gone below $1,000 per completed lateral foot. This compares to over $1,200 per completed lateral foot that was assumed for the acquisition economics.

Our delineation efforts also took a big step forward with our first Company drilled upper Point Pleasant well being spud in early October in Marshall County, West Virginia. In preparation for this well we did a rigorous review of industry well costs to date and took extra precautions to avoid repeating some of those costly challenges. With these extra precautions and some additional science to enhance the learnings, the AFE for this well is $16 million. This well is expected to have a vertical depth of 12,000 feet and a completed lateral length of 8,000 feet. This is our first well in the zone so there's plenty to learn, but so far the drilling operations have progressed as planned without issues and we look forward to confirming how the strong results of the third party wells surrounding our more than 400,000 net acres apply to our acreage here as well.

We anticipate having this well completed by the end of the year and bringing it online in early 2016. The marketing and midstream teams continue to work on a number of fronts as well, each with an opportunity to materially improve the returns generated by this asset. The team continues to work on determining an optimal dry gas gathering solution, securing additional future economic firm take away which continues to be available, and identifying other potential cost saving methods to reduce operating costs in the area. We'll continue to update you as any of these materialize and are finalized.

As a reminder from our last call we have over 80% of our firm takeaway needs already committed for 2016 and 2017 if this asset grows by 35% in each year. We'll continue to monitor rig count and pipeline builds, but we continue to believe pipeline capacity will not be a constraint. When you look at the progress made with costs, well productivity, and midstream alternatives it's easy to see that this asset has tremendous upside, even more than we anticipated when making the deal last year.

In Northeast Appalachia production for the third quarter was 93 Bcf which represents a 41% increase from third quarter of 2014. Our gross operated production was just over 1.2 billion cubic feet per day, allowing sizable growth before approaching the more than 1.4 billion cubic feet per day of firm transport that's currently locked in under contract. Additionally, the team continues to monitor the market for opportunities to add to this firm portfolio to support the growth outlook for this asset going forward.

So once again, transportation capacity is not a constraint for Southwestern here or anywhere else in our operations. Utilizing the new rigs that were constructed last year, using a customized design from Southwestern, the drilling results continued to improve. The drilling days for the third quarter were down near to eight days which compares to over 10 days for the area in 2014. As with our Southwest Appalachia asset, a number of Company drilling records were set in the third quarter in the Northeast Appalachia area.

Included in these Company records were the fastest pad mobilization at 1.5 days, the most wells drilled by a single rig at 11, and record footage per rig for the quarter at 133,000 feet. As a result of our continually improving drilling performance, the team realized 9% reduction in the cost per foot compared to the second quarter.

Completions also saw improvements, cost improvements due to the optimization work we've discussed on previous calls by reducing the number of stages and water used and by increasing the sand content in each stage of the well. We are also realizing lower costs from the service company price reductions that we have under contract.

Drilling and completion costs are now approximately $5 million per well, a significant decrease from the $6.1 million average in 2014. The third quarter also saw additional successful delineation efforts. In Tioga County, a well was tested to the north of a fault line with a test rate of over 5 million cubic feet per day during a two-week flow test. With this performance the Northern and Southern part of our Tioga County acreage appear derisked, and we are excited about the anticipated first production from this area coming in late 2016 after infrastructure is installed.

In Susquehanna County the installation of infrastructure was completed ahead of schedule, and first production was achieved on the acreage in the northern part of our county near the New York border. Additionally, the furthest most east well was drilled in the northern acreage with promising results, where a rate of more than 4 million cubic feet per day was observed against the line pressure of 1,200 Psi. This rate is expected to increase as compression is started during the fourth quarter. This well delineates additional acreage in that northern acreage block of the county and additional wells are planned to be drilled. This asset is well positioned to achieve strong growth over the next couple of years as further development activities progress. Our firm capacity portfolio allows us both delivery point flexibility and the opportunity to access markets which provide higher netbacks than the constrained market outlets in the northeast.

As we've mentioned previously, the Fayetteville asset provides a great deal of value and flexibility in the portfolio. As demonstrated this year when prices fell, activity can be adjusted very quickly.

The same is true of increasing activity as prices recover. This flexibility is made possible by our vertical integration which is also saving us $475,000 per well. It allows us to move rigs, deliver sand, and optimize the drilling and completion schedule real time without a long period of delay.

Fayetteville, which sometimes can be overlooked, still produces nearly 3% of the country's natural gas. The value of the Fayetteville shale was demonstrated again in the third quarter with this asset generating positive cash flow despite the current price environment. While this asset has a successful 12-year history, the team has not stood still when it comes to learning new things.

This quarter the Company drilled two wells that are outperforming any wells drilled in the Fayetteville region. We'll talk more about these once we learn more, but there is real excitement amongst the team about this legacy asset.

Many in the industry discuss their plans of future production growth, but few have done it already to a level of the Fayetteville shale. The experience in growing this asset over the past decade along with the stable cash flow that it generates for the Company, are very valuable to the future development plans of the Company's assets. Additionally this asset's proximity to the growing demand centers along the gulf coast over the next few years provide tremendous opportunity to capture even more value from this asset.

Regarding our new ventures portfolio, we are currently marketing a package that includes our acreage in Tioga, Sullivan, and Wyoming Counties in Northeast Pennsylvania; the Brown Dense play in Southern Arkansas and Northern Louisiana; the Sand Wash Basin play in Colorado; and our acreage in New Brunswick along with three other undisclosed exploration plays to potentially find a joint venture partner. We are looking for cash bids plus a commitment to carry SWN's 50% portion of a $600 million capital program planned for calendar years 2016 and 2017 to further develop these plays. There's currently an active data room, and we anticipate receiving bids later in the fourth quarter.

In closing, the operational results this quarter were impressive, and we will build on this momentum as we end the year and forge ahead into 2016. While prices are not where any of us would choose to have them, it's times like these that differentiate those that can operate economically and efficiently along with improving well results and those that can't.

We've been through this before and we have done it in the past. We continue to demonstrate to the market that we are one of those companies that can.

We look forward to closing out 2015 strong and sharing more exciting updates with you on our next call. That concludes my comments, so I'll turn back over to the operator who will explain the procedure for asking questions.

Thank you, ladies and gentlemen.

(Operator Instructions)

Our first question comes from the line of Neal Dingmann with SunTrust. Please go ahead with your question.

Good morning, guys. Say, Steve, just a question, in your comments for you or Jeff, your comments about maybe assuming the lower for longer and you did go through obviously the details of Southwest App, Fayetteville, and the Northeast App. Just your thoughts about maybe different capital allocation if we are in fact lower for longer scenario well into next year.

I think you're talking about where the capital will go between those various regions?

Correct, correct.

I don't know that we have an answer there. We've talked about it in the past and Bill mentioned it that the Fayetteville has been a swing area for us and will probably be a swing area in the future.

But I think the key is we will invest in the very best wells wherever those are at, and so that will be the way the capital will fall out. And we're still working on exactly where those best wells are and how we get the product and what's the best markets, those kind of things.

Okay. And then just my second question, just looking at that slide 21 that shows the Northeast Appalachian performance most recently and then versus your second quarter, certainly looks like the newer wells, the wells on less than 18 months, have seen some uplift or possible higher EURs.

I'm just wondering if you could comment, have you thought about or have you changed the EURs, are you seeing an uplift? It does certainly seem like you're seeing some improvement not only how they're necessarily coming on but how they're holding on around that 9-month period or 12-month period.

This is Bill. The wells that we've just brought on and continue to bring on are part of a philosophy that changed that we applied to this acreage where we are getting much better drilling in zone, landing in a much narrower window where we believe we get much better frac initiation, increasing sand content as I said in my comments, and the results of that as direct offsets to wells that were previously drilled are, as I said, as much as 50% better.

And we've actually gone and resteered the old wells to determine that. If you look at -- your question is on this chart. We are seeing better results.

We are managing flow across all of our assets, our wet wells, to manage condensate yield, and we have yet to produce long enough to know whether they fall off. But we do see improving EURs and we do see the opportunity to go back and look at our original assumptions on those and perhaps raise those performance in the future.

Got I thanks, Bill and Steve.

One other thing I'll just remind everybody. On all the charts that we have, the well count is different across those charts.

So for instance, there's a spike on that one chart that pops up in the very last bit there, and it gets kind of ratty at the end. You've got a lot fewer wells farther out on the 18-month chart or any of these charts as you go you through, so keep that in mind as you're analyzing charts.

Good point. Thanks, Steve.

Our next question comes from the line of Doug Leggate with Bank of America. Please go ahead with your question.

Thanks. Good morning everyone. Steve, on the $600 million of carry or upfront bonus that you're looking for on the development acreage, is there a -- I'm just curious as to what the consequences are if you don't get the kind of transactions that you're looking for.

Is it an acreage expiry issue, or what's setting the kind of limit on that $600 million planned spending? And I've got a follow up please.

There really isn't a limit on the $600 million except that it will looked like that was something we could physically do, and we thought there was potentially market for that value. The $600 million is a total capital that's talking about being invested out there.

It's not the carry. It's what would be the total piece of that. And what we're asking for someone to do is pay our 50%.

So that's where the $300 million comes from. When you think about what's the consequences if we don't do it, it's not an acreage exploration issue. It's really trying to bring things forward.

In the case of the exploration, we would have drilled those in any circumstance over the next three to five years, and we're trying to get that all drilled quickly and figure out what's good and what's not good on it. In the case of Tioga County, Bill mentioned before we're building a pipeline. We were going to drill Tioga one way or the other.

It would just work into our normal scheme. In this case if someone helps us we would accelerate and get it done faster, and you would have more production in 2017 and we invested less capital.

That's the consequence. It's just trying to bring some things that are long dated forward into our overall portfolio.

Okay. I appreciate that. My follow up is I wanted to go back to, if I may, some of the comments you made on the second quarter call about the flexibility in your capital spending for next year.

Just kind of reading between the lines in what you're saying this morning, I'm wondering is there -- given the market doesn't really seem to be rewarding [good oil fin] and gas right now, is there a scenario that we could see in 2016 where you actually go towards generating free cash and allow your production to flatten out?

Or is that not something that you're thinking about at this point. And I'll leave it there. Thanks.

We never worry too much about production growth. I've said this in the past, we invest at that 1.3 PVI.

As long as we do that production will be fine, economics will be fine, all the parameters will be fine. So we're focused even more on the 1.3 PVI.

And so if production declines, if it stays flat or grows isn't an issue with us. The big issue is planning as if it's going to be lower for longer and living within cash flow.

The other part of your question, would we generate free cash flow, I don't know. But if we don't have the wells with lower longer to get our 1.3 PVI, that could happen.

I guess not to belabor the point, Steve, I guess what I'm saying is that clearly more gas, particularly in the northeast, is compounding the problem so to speak. So I'm just curious if it would have to be a choice on your part I guess to forego all the 1.3 PVI opportunities to invest at a level that would generate free cash flow.

I'm looking at the $1 billion for 4% growth that you talked about last time. So I'm just curious, if you left your production flat in a $2.50 gas price environment, not unreasonable that you could generate free cash. Just wondering why you wouldn't do that.

And again, we do not try to predict the future, per se. We're not telling you we think gas price is going to be anything. What we're saying is we're going to work as if it's lower for longer.

When you start not drilling wells that are economic because the future is going to be better, you've said two things. One, you know when it's going to get better and two, you know how much better it's going to get.

And historically we just haven't done that. So it doesn't mean that we might not think about it down the road, but historically what we've said is if it works in today's environment, whatever today's environment is, and it ranks out high on our list of the wells that we have so you've got the capital to do it, we'd probably drill it.

Got it. Thanks for the color, Steve.

Thank you. Our next question comes from the line of Holly Stewart with Howard Weil. Please go ahead with your question.

A follow-up on Neil's question on capital allocation and thinking about it more from a rig perspective, can you just give us an update on where the rigs are in the Appalachian Basin right now? Just kind of totals by the two areas. I think last quarter you mentioned a fourth rig was scheduled to be added to the southwest.

We've most a rig from Northeast Pennsylvania to Southwest Appalachia in West Virginia to drill our Point Pleasant well. That will drill here for the next several weeks and then it will be -- it will go back after the first of the year to the northeast.

So three rigs plus this one there is four, and then we have three other rigs in Northeast Pennsylvania that are drilling at this time. And then in the Fayetteville we have four rigs at the moment.

Let me caution you. Bill said at the end of the year we're going to move one back to Northeast Pennsylvania. All the rigs that are operating are our rigs.

We have laid down rigs in the past and we will lay down some other rigs with what we're doing. So that mix that we have today my guess doesn't look anything like what it does today even five months, six months from now. So he gave you what's happening today.

Okay. Okay. Helpful. And then I know you mentioned the 80% of take-away capacity to cover 35% growth for the next couple years in the southwest region.

Does that assume continued liquids drilling or is there a shift to dry gas? I'm just curious as to how the dry gas gathering solution plays into all of this.

You're way ahead of us. We didn't assume or haven't assumed that that's actually our growth that we're going to have. It just says we have that capacity.

What that mix is we're still working on it. I will say that one of the problems the entire industry has whether you talk about dry gas Marcellus, dry gas Utica, is that it's spent the last five or six years working on the liquid side.

And so the gathering part, not the firm, large pipe take-away, but the gathering part within the various areas is not well developed. So I don't think any company can go very fast for the next six to eight months. I think everyone is working on how to get dry gas gathering system in and then the dry gas decision, except for maybe one or two wells that you put in the wet gas system, the dry gas decision is more like 2016 and maybe even into 2017 as our gathering system gets put in in that area.

Okay. Thank you, gentlemen.

Thank you. Our next question comes from the line of Scott Hanold with RBC Capital Markets. Please go ahead with your question.

Thanks, good morning, guys.

Good morning.

Steve, I have questions. So you all have that asset package up for sale. Is there anything else that you all are looking at? Is there any kind of storage asset you still have or real estate or any other plans for potential monetizations?

And if so, any kind of net cash proceed you would receive, would you look to spend that over and above cash flow in 2016? Or is your you view regardless of any kind of proceeds we have received, we're still spending at cash flow levels next year?

There are things we're looking at and contemplating. We had mentioned in the past that we were selling a small storage field and we're still on pace to do that.

And we've mentioned some conventional assets that we were looking at selling. We're working on those things as well. So there are things we're looking at and we'll head down that path and as those come up and we get closer to either having answers or having done them, you'll hear about them.

As far as what you do with those -- whatever that is that you bring in, that's still a big discussion. But I would say the safe thing to assume today is that we live within cash flow and what we're assuming today is we have nothing coming in the door until it comes in the door. So everything we're doing is living within cash flow.

Okay. Understood. And as my follow up, on those northeast type curves that you all have out there, it looks like you changed the shape of the curve a little bit, the B factors and terminal decline rates. Can you discuss what changes you've made and what got you to adjust those?

I think the overarching thing was is the curves we were using really up until sometime during this quarter had the assumption that you didn't have the managed production that we talked about. And they went at a much higher initial rate, and that would put back into the system the managed production, flatten out the curve, and it changed slightly the -- also the shapes of them. So it's truly just an update.

Okay. Thank you.

Thank you. Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Please go ahead with your question.

Folks, good morning. Is maintenance level spending still in the $1 billion range, appreciating the cost structure continues to shift in your favor? And what might that level of spending in 2016 mean for growth or no growth in 2017?

Again, you're way ahead of us. I haven't even gotten 2016 even near figured out let alone what 2017 is going to look like.

I think the best way to answer the question is what I'd said before. Production is not what we're worried about. We're worried about wisely investing the capital.

And so I've got some things that -- here's what it takes to keep maintenance or some of those things. But it really doesn't go -- doesn't matter much to go into that. We just need to give you some guidance after the first of the year and what we're going to do in 2016 and then you'll ask me about 2017.

I'll tell you I'm not quite there yet on that one too. But expect whatever you're using for your pricing where it will stay within cash flow.

If it goes up, it goes up. If it goes down, it goes down. If it goes sideways, it goes sideways.

I understand. Any thoughts on hedging here as we get closer to 2016?

There's always thoughts on how you hedge and how you work through it. Kind of two general things. I said earlier we don't make a call on prices, but we can't figure out how they can get much lower.

So hedging right now at this point we're having a hard time doing that. And really we don't see much value in locking in that price where it is today.

The other side of it is when trying to think about creative ways to basically hedge, and it's not in the financial markets but other activities to do that, and if you think about this package that we talk about, if someone can carry us for activity that creates production, not much next year but significant production in 2017 and 2018 and we didn't have to put any capital into it, we basically put on a long-dated hedge into our portfolio by doing that. So we think about hedging all the time and we're also thinking about very creative ways to do that hedging.

And I think that's more what you're going to see in the near term from us as opposed to just going to the financial markets. Now, that's the physical hedges on gas. Certainly on the basis hedge side, we have basis hedges between 30% and 50% of our production all the way out through 2016 and we continue to do that hedging.

Very good. Have a great day. Thank you.

Thank you. Our next question comes from the line of Dave Kistler with Simmons & Company. Please go ahead with your question.

Good morning, guys. Following up on the rig allocation question, in the 2Q call when you talked about the possibility of the $1 billion CapEx, I believe you indicated that would equate to running one rig in the northeast, one in the southwest, and one in the Fayetteville.

Thinking about your PVI focus, would that be the most optimal operating plan? Or would it make more sense to maybe have several of those rigs in one area and no rigs in another just to optimize the actual returns, efficiencies, et cetera? Just any color you can give on that would be great.

That certainly is not optimal from a lot of different angles. And when we gave those numbers in the second quarter I literally just went to the group and said put one rig in each area and see what happens, and that's what happened.

That certainly is not a plan nor is it a capital budget. So again, expect that we will put the rigs to work where the best wells are. Now, Fayetteville shale, we just talked about the fact and we've got some very, very good wells.

We will drill some of the Fayetteville shale for those very, very good wells. But to the extent that northeast is better, you'll do less.

To the extent that something in West Virginia is better you'll do more there and less someplace else. We're not married to just drilling in each area. We're going to drill the very best.

Great, appreciate that. And then maybe looking at your PVI comments and looking at the uplift you're seeing in EURs in the Southwest Appalachia, the leading edge well cost, can you give us any specific color on what that's doing as far as cash on cash payback periods on those wells? And obviously as part of that, that would be asking a question of what you guys are using as your forward price deck on that.

I kind of figured out that's what you were trying to basically ask. You know, I think you've seen a little bit this quarter already where the overall average pricing is the best way I can describe this, looks a little bit better than it did last quarter in the West Virginia assets.

And certainly part of that is the mix, part of that is the quality of the wells that you're just starting to see affect the overall area there. So the best I can say right now, and again you're a little bit ahead of us, we're working those numbers.

We're getting the data in daily, and as we get that data in we figure out what the quality of those wells are and then we can figure out where we're going to put our capital to drill the best quality. So I don't have a real answer there.

But going back to the other thing you're trying to get out of me, what's our cost curve look like. Again, I don't have a final, final here's what we're going to do for the budget. But assume it's somewhere around present forward curve.

Okay. Greatly appreciate the added detail. Thanks so much, guys.

Thank you. Our next question comes from the line of David Heikkinen with Heikkinen Energy Advisors. Please go ahead with your question.

Good morning, Steve. And just thinking about prior cycles and your comments around stronger and weaker companies, traditionally the stronger companies have been able to consolidate quality assets and companies. How do you think about Southwestern's role in that potential future?

I think near term there's probably not a whole lot in that. We've got a lot of good assets and we're worrying about making our new acquisition better and worrying about the assets that we have.

And as we look out, this is a lower for longer cycle. I can see as it evolves certainly we could be one of the players in it. I don't think anything -- I don't see anything on the near term horizon at all that puts us in that.

That makes sense. People have tried to get to the capital efficiency thoughts, and really I guess the question is with the new results in Southwest PA, how much -- and 20% lower cost and 50% better wells, does that automatically move it to number one in your portfolio? I just did it in our fast math, but wanted to make sure we are aligning.

It certainly makes it competitive. Again, you've got a lot less information there than you do in other places. In general, the area we feel most comfortable about is Northeast PA.

But again, we've got a lot more experience and a lot more information there than we do in the very newest wells we're drilling in West Virginia. That's part of this whole we're not ready to talk about 2016 yet.

We want to see a little bit more. Want to make sure it holds up.

We want to understand a little bit more about pricing. We want to understand when gathering systems can be in and all of those things so that, again, we're putting the capital in the best place to put it.

Thanks, Steve.

Thank you. Our next question comes from the line of Bob Brackett with Sanford Bernstein. Please go ahead with your question.

Good morning. Had a question on how important is investment grade to you guys?

You know, it's definitely important. It takes a lot of work to get to investment grade.

It's something that we talk about on a fairly regular basis. So it's important. I'm not going to tell you it's the most important thing out there, but it's important.

What's more important?

I think investing in the best possible wells, keeping driving improvements, if not more important or certainly as important.

A follow up on a different tack. Where do you think you are in terms of recovery factors in the stimulated rock zone in some of these Marcellus wells?

We can't improve efficiencies forever. Do you have an estimate of what that might be?

I'm going to give you some just general comments. We have been surprised. I'm going to go all the way back to the Fayetteville shale.

We have been surprised that we have some areas that are up around 50% recovery factor in the Fayetteville shale. We'd always estimate at 35% to 40% range. And all the numbers when we talk about it is still assuming those kinds of recoveries.

But we have seen wells that are slightly above 50%. Certainly I think over a long period of time, over 20 years, the better rock in the various plays are out there on the dry gas side can get into the 50% or 50% plus range.

But you just don't have the history yet to be able to say that that's happening. One of the things that we have learned in the Fayetteville shale is that because we're getting a little bit better recovery factors than we thought, we've widened out a little bit on our space in our wells.

We've actually widened out a little bit on the fracking, how many fracs we put in the wells. And I've sent hints for several quarters that I think everyone needs to watch out on their well counts.

Those first wells drilled to hold acreage are not going to be what the wells ultimately are, and there is a limit. And I'll just give a quick example.

I've heard a couple of statements recently that the Utica will be 20 plus Bcf wells, and you're going to drill between five and six wells per section. Well, if the 20 Bcf well you drill five wells per section that means you recover 100 Bcf.

The best spot we map in Utica may have 150 Bcf per section. The average certainly is not 150 Bcf per section. So something's wrong with the way that math works.

And I think there's a lot of that that's happening in a lot of different areas. And so you're seeing us and what we do generally put our wells farther apart than the rest of the industry.

We put our fracs farther apart than the rest of the industry because we think it's going to creep up towards 50% as opposed to staying at 35% to 40%. But there is some other funny math going on out there and everyone needs to watch out for that.

I appreciate that. Thanks, Steve.

Thank you. Our next question comes from the line of David Tameron with Wells Fargo. Please go ahead with your question.

Most of them have been asked, but thanks for the color on the Utica, Steve. One just follow up. If I look at the well cost, that's 6.8 down to 5.6 quarter over quarter, can you just talk about what different components of that, just big picture?

Big picture, faster drilling times, better or reduced stage spacing as a result of higher sand loading. So under our contracts you're putting fewer stages in a well. That drives down the cost.

If you're more efficient, less down time, that drives the cost down. But a bit more sand in it, so that offsets it a bit. And then we've done a significant amount of work on industry rebidding of contracts, et cetera, and those numbers have come down significantly as well due to where we are in the gas price cycle.

Are we talking 50/50 service cost/efficiencies? Or what -- I'm just trying to figure out.

By far the biggest one is if you take a couple frac stages out, that's by far your biggest.

Okay. So in theory, a large portion of that should be sustainable.

Yes.

Correct.

Most of it's sustainable.

Okay. Thank you. That's all I've got.

Thank you. Our next question comes from the line of Brian Singer with Goldman Sachs. Please go ahead with your question.

Thank you. Good morning.

Good morning.

You mentioned if the PVI meets your hurdle rates or threshold rates you would look to allocate capital. Can you provide, and I apologize if you already did, specific color on what local gas price or effective realization net of firm transportation you would need to achieve your PVI targets based on your current or projected cost structure in Northeast versus Southwest PA?

That's one of those questions that has a huge amount of detail in that I'm not sure is completely good for this entire group or would be valuable for the entire group. I think the simple answer is today's prices are very, very challenging for the entire industry.

And one of the things that we are debating and working on and will have come to the conclusion on by the time we get to the 2016 budget, we don't have it yet, if it's going to be lower for longer do the differentials stay the same? Or do the differentials narrow just based on that, lower for longer, and then you have the macro market and what you think is going on in the macro market.

At this point in time I certainly have some numbers for if this, this, and this happens. But we don't have a good feel nor do we even have a consensus in our Company about what those changes are either staying lower for longer or what may happen on the macro.

I'll kind of defer that. Ask me that as we get towards the 2016 capital budget discussion a little bit farther and I'll be happy to go through that with you.

Okay. Great. Thanks. And then a couple of non-direct E&P questions.

Can you talk about the outlook for midstream EBITDA, how that's impacted by and/or influences your growth rate in the Fayetteville? And then if your asset sale program either takes longer or doesn't work out the way you expect, how does that impact how you're thinking about capital allocation?

Well, I'll start with the second one. The capital allocation portion of it is just about wells. So I don't know that it matters at all on what happens on what we're selling or not selling or how we're doing that.

I think it goes back to an earlier question. Are you going to allocate some of those dollars to the budget or are you going to use that to pay down debt? And for now I'd assume we're paying down debt.

I don't know that there's any reason that we need to use that for drilling the wells. Then the second question on midstream and what's happening in the EBITDA there, you can see in the numbers that we have, this quarter has a little bit lower production in the Fayetteville shale.

Our midstream is driven by the Fayetteville shale. If you wanted to hold production flat in Fayetteville shale we'd have to drill about 350 wells a year.

We're drilling significantly less than that this year, and we haven't decided what we're going to do next year. But assume that the production in the Fayetteville shale continues to decline so that EBITDA declines just proportionately with that.

That's very helpful. Thank you.

Our next question comes from the line of Jeffrey Campbell with Tuohy Brothers. Please go ahead with your question.

Going back to the JV real quick, I just wondered -- let's assume that it does happen. Is there an order of development priority within the proposed package?

There's two pieces to the package. There's the basically development that's in Northeast Pennsylvania and the Tioga area mainly.

That will start immediately and will go all through 2016 and 2017. And that's a development program building into a pipeline that gets put in later next year.

The other part of that package is your exploration, and the first parts of that exploration is where we drilled, have drilled in the past, and that would be Sand Wash/Brown Dense. The program just lays out over two years and we've shown you when it goes to the date around kind of a calendar that they would expect to go on. So that's kind of the two pieces of it.

Thanks. That's helpful. My other question is in the past you've talked about how trying to spend within cash flow can be tricky, and some overspend may be required just because of commodity price movements.

So I was wondering is there still some overspend buffer to consider in 2016 on that basis, or will you hedge at higher than historical levels in 2016 to protect more cash flow? How will that work?

That's kind of a two part question. Assume we're tight on cash flow. I've talked about in the past, it's hard to adjust as you get a falling price during the year.

If you start in the year lower for longer and you're looking at the forward curve around the forward curve type numbers to go with, I expect to have less adjustments during the year. So you should be tighter on cash flow in that direction.

And then, like I said earlier on hedging questions, we will certainly look at creative ways to hedge. We will look at hedging at the appropriate time. And when you start to talk about historical numbers, typically we're somewhere between 40% and 60% hedged in any given year.

I would love to have some good hedges on in that range, and if I can put those on maybe we do go a little bit higher. But right now we're not hedging, so that's one of those theoretical questions.

Thanks very much.

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

Thank you. Thank you for all your questions. I know a couple of them I was a little bit vague in answering, but again, we are like you, struggling with what's going on and we're early in the process.

It doesn't mean we haven't done a lot of work, but every time we do something, something changes and we're having to redo a lot of things again. And I expect that's going to happen and I expect that every quarter as we go into 2016, end this year and go into 2016, we will have a lot of dynamics that go with that.

I think all the industry will have that and I hope that at least the responses I gave you were as best -- were taken in the light that is best of what we knew today. And as we know more we'll certainly talk about that.

I kind of want to end here with just that question. Why in the world invest in Southwestern Energy? I can just come to two points.

Very simply, the first one is we have a track record of consistently high performance. Whether it's the amount of production, the low cost, our focus on capital efficiency, our culture of continual improvement, we've shown you the data. You've seen the data.

And we're leaders in each one of those categories. And then those learnings that we have today, in a lot of ways the rest of industry hasn't been there yet and won't be there for a while. And it will take them some time to arrive there.

So I think that gives us an advantage in how we're thinking of what we're doing. And I talked earlier about the fact that learnings from Fayetteville shale have helped us understand recovery factors, as well as Bill talking about learning how to frac wells better and drill wells faster.

And I think people are catching up, not necessarily us having to catch up with them. So if we combine that performance with our high quality assets, I think what you come with is a very formidable company that really has one of the best opportunities to succeed in any price environment, but especially this price environment.

These are challenging times. That's why I started. But they remain for us exciting times at Southwestern Energy. So thank you for taking your time to be part of the call today, and have a great weekend.

Thank you, ladies and gentlemen. This does conclude our teleconference for today.

You may now disconnect your lines at this time. Thank you for your participation, and have a wonderful day.