Southwestern Energy Company Third Quarter 2015 Earnings Teleconference October 23, 2015

Transcription

1 Officers Steve Mueller Chairman, CEO Craig Owen CFO Bill Way President, COO Southwestern Energy Company Third Quarter 2015 Earnings Teleconference October 23, 2015 Analysts Neal Dingmann; SunTrust Doug Leggate; Bank of America Holly Steward; Howard Weil Scott Hanold; RBC Capital Markets Dan McSpirit; BMO Capital Markets Dave Kistler; Simmons & Co. David Heikkinen; Heikkinen Energy Advisors Bob Brackett; Sanford Bernstein David Tameron; Wells Fargo Brian Singer; Goldman Sachs Jeff Campbell; Tuohy Brothers Presentation Operator: Greetings, and welcome to the Southwestern Energy Company third quarter 2015 earnings teleconference call. At this time all 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. Afterward, you may feel free to re-queue for any 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. Thank you, sir. You may begin. Steve Mueller: 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 have 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 forwardlooking statements that involve risks and uncertainties affecting outcomes, many of which are 1 P a g e

2 beyond our control, and are discussed in more detail in the risk factors of the forward-looking statement 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. These are challenging times in our industry. Whenever I see fellow industry 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 will 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're going to do. And as you will 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 post 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 Third, while we may have an opinion about the direction of oil and gas prices, we will manage if prices are lower for longer for both commodities. Like many management teams, we are wrestling with several uncertainties in 2016, and probably will not give 2016 guidance until after the first of the year. 2 P a g e

3 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 that significant upside has been added to each of the Southwestern Energy's three assets during the quarter. Bill 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 with our West Virginia assets, our estimate of the recoverable resources have 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 he can begin the more detailed discussion of our quarterly results. Craig Owen: Thank you, Steve, and good morning everyone. We met or exceeded each of our guidance metrics provided to The Street, as we continued 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 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 At September 30th, 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 and our commercial paper program. We remain committed to flexing our capital investment program in 2016, to keep debt at or 3 P a g e

4 below its current level. We have no plan 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 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 I will now turn it over to Bill Way for an update of our operational results. Bill Way: 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 continue 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 and 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 in 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. 4 P a g e

5 For the third quarter, we had net production of 37 billion cubic feet of gas equivalent and the 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 Frye Pad, which has three Southwestern drilled and completed wells online, outperformed its offset wells by 54%, with an average EUR per 1,000 foot of CLAT 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 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 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 5 P a g e

6 firm takeaway, which continues to be available, and identifying other potential cost-saving methods to reduce operating cost 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 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 continue to improve. The drilling days for the third quarter were down to eight days, which compares to over 10 days for the area in 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 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 five million cubic feet per day during a two-week flow test. With this performance, the northern and southern part of our Tioga County 6 P a g e

7 acreage appear de-risked, and we're 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 the 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 four million cubic feet per day was observed against a 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 the 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 7 P a g e

8 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 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 our 2015 strong and sharing more exciting updates with you on our next call. That concludes my comments, so I'll turn it back over to the operator who will explain the procedure for asking questions. Operator: Thank you, ladies and gentleman. We will now be conducting a question-andanswer session. (Operator Instructions) As a reminder, Q&A is restricted to approved market analysts only for today, and there is a two question limit. One moment, please, while we poll for questions. Neal Dingmann: Steve, just a question on your comments for you or Jeff. In your comments about maybe assuming the lower for longer and you did go through, obviously, the details of Southwest App, Fayetteville, the Northeast App - just your thoughts about maybe different capital allocation if we are in fact in that lower for longer scenario well into next year. Steve Mueller: Yes. I think you're talking about where the capital will go between those various regions. Is that how --? Neal Dingmann: Correct. Correct, Steve. Steve Mueller: I don't know that we have an answer there. We've talked about in the past and Bill mentioned it, that the Fayetteville has been a swing area for us, and it 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'll 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 or the best markets and those kind of things. Neal Dingmann: 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 8 P a g e

9 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 or 12-month period. Bill Way: Yes. This is Bill. The wells that we've just brought on and continue to bring on, are part of a philosophy change 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 re-steered the old wells to determine that. If you look at when -- 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. Neal Dingmann: Got it. Thanks, Bill and Steve. Steve Mueller: One other thing I'll just remind everybody. On all the charts that we have, the well count's 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 through. So keep that in mind as you're analyzing charts. Neal Dingmann: Good point. Thanks. Thanks, Steve. Operator: Thank you. Doug Leggate with Bank of America. Doug Leggate: Steve, on the $600 million of carry or upfront bonus that you're looking for on the development acreage, is there -- 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 upfront spending? And I've got a follow-up please. Steve Mueller: Yes. There isn't really a limit on the $600 million, except it looked like that was something we could physically do, and we thought there was potentially a market for that value. The $600 million is a total capital that's talked about being invested out there. It's not the carry. It's what would be the total piece of that. What we're asking for someone to do is pay our 50%. 9 P a g e

10 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, and it would just work in to our normal scheme. In this case, if someone helps us, we would accelerate and get it done faster and you'd have more production in 2017, and we invested less capital. But that's the consequence. It's just trying to bring some things that are long dated forward into our overall portfolio. Doug Leggate: 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 on what you're saying this morning, I'm wondering is there, given the market doesn't really seem to be rewarding growth in gas right now, is there a scenario that we could see in 2016 where you actually go toward generating free cash and all of your production to flatten out? Or is that not something that you're thinking about at this point? I'll leave it there. Thanks. Steve Mueller: We never worry too much about production growth. I said this in the past. We invest at 1.3 PVI. As long as we do that, production will be fine, our economics will be fine, all the parameters will be fine. So we're focused even more on that 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. So 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. Doug Leggate: 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 forgo all the 1.3 PVI opportunities, I guess, to invest at a level that would generate free cash flow. I'm looking at the billion dollars 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 you 10 P a g e

11 could generate free cash. I'm just wondering why you wouldn't do that. Steve Mueller: Yes. 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's going to be better, you 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 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. Doug Leggate: Got it. Thanks for the color, Steve. Operator: Thank you. Holly Stewart with Howard Weil. Holly Stewart: I have a follow-up on Neal'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. Bill Way: Yes. We've moved a rig from northeast Pennsylvania to Southeast Appalachia in West Virginia to drill our Point Pleasant well. That'll drill here for the next several weeks and then 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 two other rigs in northeast Pennsylvania that are drilling at this time. And then in the Fayetteville, we have four rigs at the moment. Steve Mueller: Now, let me caution you. Bill said at the end of the year we're going to move one back to northeast Pennsylvania. All 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, six months from now. So he gave you what's happening today. Holly Stewart: Okay. Okay, helpful. And then, I know you mentioned the 80% of takeaway 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 kind of curious to how this, the dry gas gathering solution sort of plays into all of this. 11 P a g e

12 Steve Mueller: Yes. 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. And what that mix is, we're still working on it. I will say that one of the problems the entire industry has in 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 takeaway, but the gathering part within the various areas is not well developed. And so I don't think any company can go very fast for the next six to eight months. I think everyone's 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's more like 2016, and maybe into 2017, as that gathering system gets put in that area. Holly Stewart: Okay. Thank you, gentlemen. Operator: Thank you. Scott Hanold with RBC Capital Markets. Scott Hanold: Steve, got a question. 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 assets you still have or real estate or any other plans for potential monetizations? And if so, any kind of net cash proceeds you would receive, would you look to spend that over and above cash flow in 2016, or is your view regardless of any kind of proceeds we receive, we're still spending at cash flow levels next year? Steve Mueller: 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, and 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 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. Scott Hanold: 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 kind of discuss what changes you made and what got you to adjust those? Steve Mueller: Yes. I think the overarching thing was is the curves we're using, really up until 12 P a g e

13 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 also the shapes of them. So it's truly just an update. Scott Hanold: Okay. Thank you. Operator: Thank you. Dan McSpirit with BMO Capital Markets. Dan McSpirit: Is maintenance level spending still in the billion dollar 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? Steve Mueller: Yes. Again, you're way ahead of us. I haven't even gotten 2016 even near figured out, let alone what 2017's going to look like. But I think the best way to answer the question is, 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 matter much to go into that now. We just need to give you some guidance after the first of the year on what we're going to do in And then you'll ask me about I'll tell you I'm not quite there yet on that one, too. But expect whatever you're using for your pricing, we will stay within cash flow. And if it goes up, it goes up. If it goes down, it goes down. If it goes sideways, it goes sideways. Dan McSpirit: Okay, great. I understand. And then just any thoughts on hedging here as we get closer to 2016? Steve Mueller: 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 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, but 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 13 P a g e

14 opposed to just going to the financial markets. Now, that's the physical hedges on gas. Similar on the basis hedge side, we have basis hedges for between 30% and 50% of our production all the way out through 2016, and we continue to do that hedging. Dan McSpirit: Very good. Have a great day. Thank you. Operator: Thank you. Dave Kistler with Simmons and Company. Dave Kistler: Following up on kind of the rig allocation question. In the 2Q call when you talked about the possibility of a billion dollar 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, etc? Just any color you could give on that would be great. Steve Mueller: That certainly is not optimal from a lot of different angles. And when we gave those numbers in that 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 that 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 the northeast is better, you'll do less. And to the extent that something in West Virginia's better, you'll do more there and less someplace else. So we're not married to just drilling in each area. We're going to drill the very best. Dave Kistler: Great. Appreciate that. And then maybe kind of 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. Steve Mueller: I kind of figured out that's what you were trying to basically ask. I think you've seen a little bit this quarter already where the overall average pricing, that's 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 14 P a g e

15 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 the present forward curve. Dave Kistler: Okay. Greatly appreciate the added detail. Thanks so much, guys. Operator: Thank you. David Heikkinen with Heikkinen Energy Advisors. David Heikkinen: 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? Steve Mueller: Well, 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, but 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. But I don't see anything on the near-term horizon at all that puts us in that. David Heikkinen: That make sense. And then 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, I mean does that automatically move it to number one in your portfolio? It just did in our fast math. But wanted to make sure we were aligning. Steve Mueller: It certainly makes it competitive. Again, you've got a lot less information there than you do other places. David Heikkinen: Yes. Steve Mueller: In general, the area we feel most comfortable about is northwest 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. And that's part of this whole, we're not ready to talk about 2016 yet. We want to see a little bit more and 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, 15 P a g e

16 we're putting capital in the best place to put it. David Heikkinen: Thanks, Steve. Operator: Thank you. Bob Brackett with Sanford Bernstein. Bob Brackett: Had a question on how important is investment grade to you guys? Steve Mueller: 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. Bob Brackett: What's more important? Steve Mueller: Well, I think investing in the best possible wells, keeping driving improvements, if not more important, they're certainly as important. Bob Brackett: Okay. Great. And 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 sort of improve efficiencies forever. Do you have an estimate of what that might be? Steve Mueller: I'm going to give you some just general comments. We have been surprised. And 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 always estimate it 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 that are out there on the dry gas side can get into the 50-plus percent 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 had 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 our spacing 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 kind of 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 it's a 20 Bcf well and you drill five wells per section, that means you recover 100 Bcf. 16 P a g e

17 The best spot we map in the 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's some other funny math going on out there and everyone just needs to watch out for that. Bob Brackett: Great. I appreciate that. Thanks, Steve. Operator: Thank you. David Tameron with Wells Fargo. David Tameron: Most have been asked. But thanks for the color on the Utica, Steve. One just follow-up. If I look at the well costs, that $6.8 down to $5.6 quarter over quarter what's -- can you just talk about what's the different components of that, just big picture? Bill Way: Yes. Big picture, faster drilling times, better or reduced stage spacing as a result of higher sand loading. So under our contracts, they're putting fewer stages in a well, that drives down the cost. If you're more efficient, less downtime, that drives the cost down. Put 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, etc, and those numbers have come down significantly as well due to where we are in the gas price cycle. David Tameron: Okay. And just are we talking service cost efficiencies? Or what's -- I'm just trying to figure out -- Steve Mueller: By far, the biggest one is if you take a couple frac stages out, that's by far your biggest. David Tameron: Okay. So in theory, a very large portion of that should be sustainable, right? Steve Mueller: Yes, it is. Bill Way: Right. Steve Mueller: Most of it's sustainable. David Tameron: Okay. Thank you. That's all I got. 17 P a g e

18 Operator: Thank you. Brian Singer with Goldman Sachs. Brian Singer: 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? Steve Mueller: 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 will 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 we'll have come to a conclusion on by the time we get to 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's going on in the macro market. And 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, you're staying lower for longer or what may happen on the macro. So 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. Brian Singer: 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 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? Steve Mueller: 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 why we're doing that. And 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 EBITDA there, you can see in the numbers that we have this quarter had a little bit lower production in the Fayetteville Shale. Our midstream's driven by the Fayetteville Shale. 18 P a g e

19 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 continues just proportionately with that. Brian Singer: Great. That's very helpful. Thank you. Operator: Thank you. Jeffrey Campbell with Tuohy Brothers. Jeff Campbell: Going back to the JV real quick. I just wondered is, and let's assume that it does happen, is there an order of development priority within the proposed package? Steve Mueller: There's two pieces to the package. There's the basically development that's in northeast Pennsylvania, in the Tioga area mainly. That will start immediately and will go all through 2016 and 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 and have drilled in the past, and that would be Sand Wash and Brown Dense. But the program just lays out over two years. And we've shown anyone who goes to the data room kind of a calendar they would expect to go on. So that's kind of the two pieces of it. Jeff Campbell: Okay. Thanks. That's helpful. My other question is, in the past you talked about how trying to spend within cash flow can be tricky and some overspend may be required just because of commodity price movement. 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? Steve Mueller: It'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 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 you go with, I expect to have less adjustments during the year. So you should be tighter on cash flow in that direction. And then sort of 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 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 kind of one of those theoretical questions. 19 P a g e

20 Jeff Campbell: Okay, great. Thanks very much. Operator: 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. Steve Mueller: Thank you. And thank you for all your questions. And 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. So I think all the industry will have that. And I hope that at least the responses I gave you were as best and were taken in the light that it's 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? And I can just come to two points. And very simply, the first one is, we have a track record of consistent 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 the industry hasn't been there yet and won't be there for a while. And it'll take them some time to arrive there. So I think that gives us an advantage in how we're thinking and what we're doing. And I talked earlier about the fact that learning from Fayetteville Shale have helped us understand recovery factors, as well as Bill talking about learning how to frack wells better and drill wells faster. And I think people are catching up, not necessarily us having to catch up with them. So 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 exceed at any price environment, but especially this price environment. These are challenging times, that's the way 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. Operator: Thank you, ladies and gentleman. 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. 20 P a g e