西南能源 (SWN) 2016 Q3 法說會逐字稿

Greetings, and welcome to Southwestern Energy Company third-quarter 2016 earnings teleconference call.

(Operator Instructions)

As a reminder, this conference is being recorded.

It is now my pleasure to introduce Michael Hancock, Director of Investor Relations for Southwestern Energy Company.

Thank you, Doug. Good morning and thank you for joining us today. With me today are Bill Way, our President and Chief Executive Officer; Craig Owen, our Chief Financial Officer; Randy Curry, our Senior Vice President of Midstream; Jack Bergeron, our Senior Vice President of Operations; and Paul Geiger, Senior Vice President of Corporate Development.

If you've not received a copy of last night's press release regarding our third-quarter 2016 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 that involve risks and uncertainties affecting outcome. Many of these are beyond our control and are discussed in more detail in the risk factors and the forward-looking statements sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers. For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release available on our website.

I'll now turn the call over to Bill Way to discuss our recent activity and results.

Thanks, Michael, and good morning everyone. Thank you for joining us on our call today.

This year has been one of unwavering focus in SWN and that focus is on our commitments that we laid out in February, namely to strengthen our balance sheet, aggressively improve margin, optimize the portfolio, and remain agile, enabling us to be ready to capture opportunities to add value as the commodity price environment improves. We're delighted to be here today to talk with you about this and to talk about another quarter in which we've delivered on those commitments. I'd like to start by thanking the Southwestern team for all that has been accomplished to far this year. We've tackled a number of different challenges and set the Company up for significant value creation as we finish up 2016 and prepare to move on to 2017. This year's accomplishments are a direct reflection of the commitment and dedication that each employee brings to the work every day and I commend you for all that you do and all that you've done.

When we spoke last quarter we discussed our plans to reinitiate investment in drilling and completion activities as a result of our strengthened balance sheet, the improving commodity price environment, and our ability to assure solid returns provided by our commitment to prudent hedging and disciplined risk management. We'll provide more details about this in a few minutes. However, I can tell you that the learning, planning, and preparation that each of the teams focused on during the pause in drilling and completions activity resulted in an extremely successful reinitiation of our drilling and completion operations. As expected, we now have five rigs running Company-wide: two in Northeast Appalachia, two in Southwest Appalachia, and one in Fayetteville.

The drilling results have been better than expected, as we've seen record performance in drilling times that are even better than when we halted activity at the end of 2015. However, speed is only part of the story. We've also been able to stay within our targeted zone over 95% of the time, which can be as narrow as 10 feet. Steering the well fully in zone supports the completion optimization by placing the entire length of the lateral in the interval that is most favorable for fracture stimulation and initiation. These impressive results have been driven by the learnings we captured from drilling and completing wells on paper during the first half of the year and applying these learnings now as we resume activity. Additionally, the utilization of technology such as rotary steerable tools and other technologies are now standard on many of our wells. The activity in the second half of this year primes the portfolio for a robust 2017.

Regarding 2017, while we have not approved next year's capital program, at current strip prices we expect cash flow to be in excess of $1 billion. We've had some questions on maintenance capital for next year, so let me reconfirm that the maintenance capital required to hold 2017 annual volumes flat at 2016 levels is only $700 million, given our improved capital efficiency and the benefits flowing from our recent restart activity of approximately 150 Bcf equivalent of incremental 2017 production, from the wells that we are drilling and completing during the second half of this year. With this quarter's impressive restart of activity, we also fully expect to arrest our production decline by the end of the year, this year, 2016, after which we will be back on the growth trajectory.

Reduced overall decline and resumption of value-added growth are both the results of our work to improve the performance of our vast portfolio. This $700 million in maintenance capital is an all-in capital number, including capitalized interest and expenses. Closing this part of the discussion, while the maintenance capital is approximately $700 million, this is well below the expected more than $1 billion in cash flow for 2017 that I mentioned earlier at current strip prices. We plan to watch the impacts of the winter weather on 2017 prices and issue public guidance in February.

Let me now move on to our marketing and commercial activities. As is historically the case, we experienced our widest differentials for the year in the third quarter. Our overall discount, inclusive of differentials and transport costs, was $1.03 per Mcf lower than average NYMEX settlement pricing, compared to $1 per Mcf lower than average NYMEX settlement pricing during the third quarter of 2015. This slight widening of the 2016 quarter was influenced largely by regional storage levels being at or near capacity and the percentage of total production from our Northeast assets increasing versus guidance.

Factoring in the forecasted gains of approximately $0.03 per Mcf on basis hedges currently in place, the Company anticipates its total Company discount to NYMEX for the year will be at the high end of guidance range or about $0.83 per Mcf. We do believe that the current challenges facing the Appalachian basin are a short-term issue and that the quality and quantity of our transportation portfolio in our Appalachian basin businesses is robust and allows us both strong access to markets and growth opportunities this year and beyond. Over the long term, our view on improving regional basis differentials has not changed and we expect the projected capacity additions out of the greater Appalachian region to come on line over the next few years. These pipeline projects have robust economics and are of high quality and we remain confident that the capacity from these pipeline projects gets overbuilt, albeit not without some scheduling challenges on individual projects.

Lastly, we're encouraged by the strengthening of NGL pricing for 2016 and how the NGL demand picture, particularly ethane, seems to be shaping up over the next few years. Given SWN's capacity on ATEX, we are in a strong position to capitalize on rising ethane prices at Mont Belvieu, as projects making up the estimated 620,000 barrels a day of new demand begin to come on line between now and 2019. With our vast resource position and the optionality provided by the wet gas window of Southwest Appalachia, increased NGL prices materially enhance the margins provided from that area.

With that, let me turn over to Craig to discuss some of our financial highlights from the third quarter and then we'll have Jack talk a bit more about some operations.

Thanks, Bill, and good morning, everyone.

I thought I would start this morning by summarizing the steps we have taken to strengthen the balance sheet this year since many of them were in progress at the end of the second quarter. In the third quarter we completed the equity offering for $1.25 billion, of which a portion was used to retire $700 million in 2018 debt maturities, with $500 million earmarked for resumption of drilling and completion activities. Additionally in the third quarter, we closed the previously announced acreage divestiture in Southwest Appalachia.

As you saw in last night's release, net debt as of September 30 was $3.2 billion, down from $4.8 billion at the end of the second quarter. As a reminder, when we amended the bank agreement, its structure changed from our historical revolving credit facility. The new credit facility is supplemented by the fully drawn, $1.2 billion secured term loan, which we expect to utilize for liquidity purposes and results in large cash balances going forward, compared to our historical amounts.

We have made great strides strengthening the balance sheet this year and expect net debt to EBITDA for 2017 to be in the high 2s, assuming current price levels. With these actions and the improved commodity price environment, we are confident in our trajectory, and therefore have no other asset sale plans imminent or of a material nature. In the normal course, we will continue to evaluate options and opportunities, but are confident with our portfolio and balance sheet where it stands today.

In the third quarter, we continued to add to our hedge position. We have now hedged 535 Bcf of 2017 production, of which approximately half of these positions are collars providing upside exposure to improving prices. On these 2017 hedges, we have a weighted average strike price for the swaps and purchase puts of $3 per Mcf. We have also been actively adding financial and physical basis hedges to the portfolio, where we currently have 75 Bcf protected in the fourth quarter and 196 Bcf protected in 2017. These hedging activities will help us achieve our expected returns, providing downside protection while also retaining upside potential as prices improve.

With the financial strengthening steps taken in 2016, we are now positioned to drive value generation with our premier assets. I will now turn it over to Jack to discuss some of the details of our operational results in the third quarter.

Thanks, Craig. Good morning, everyone.

As Bill mentioned earlier, we've successfully reinitiated our drilling and completion activities, which was a primary focus of the third quarter for operations. It's not often that you completely halt drilling and completion work for six months and then ramp up to five rigs in such a short period of time, as we have this year. The success of this resumption demonstrates our differentiating agility as a Company.

While returning to drilling and completions, we did not lose sight of the importance of our 2016 strategic initiatives, evidenced by once again hitting the top end of our production guidance at 211 Bcfe while continuing our focus on improving margins. In particular, we reduced our lease operating expenses on a unit of production basis for the fifth quarter in a row.

In each of our areas, we continue to push the boundaries of our completion design. We are experimenting with increased proppant volumes, with tests in Southwest Appalachia reaching up to 5,000 pounds per foot. We are also challenging ourselves to find the technical limits of these solutions. With such a vast number of drilling locations in the area, determining the optimal proppant loading will significant increase the value of this play. Our proppant testing is not just limited to Southwest Appalachia. We are also testing this in each of our other operating areas. In Fayetteville, we are testing over two times as much proppant as our historical averages were. We expect to have some preliminary results on our next call, but the early indications are promising.

In Southwest Appalachia, we completed eight wells in the third quarter and plan to connect nine wells to sales prior to the end of the year. While we did not turn on any wells to sales in the third quarter, we continue to see strong well performance from our Ridgetop Land Ventures pad in Wetzel County, which came online in the fourth quarter of 2015. As a result, we've increased our lean gas type curve for the second time this year to approximately 25 Bcfe based on 7,500-foot laterals. The wells that we have drilled and completed there continue to outperform the offset wells drilled by the previous operator by as much as 40%. As we look forward, this asset provides substantial optionality where capital could be allocated to the wet or dry gas targets, depending on commodity prices.

Moving to Northeast Appalachia, we currently have two rigs running, which were the first two rigs to be mobilized. As Bill mentioned, the preparation for the reinitiation of activity resulted in some exceptional accomplishments. For the quarter, we have achieved a record total drill depth time of less than eight days from reentry to reentry, which is 5% faster than the fourth quarter of 2015. Included in these results was one well that drilled over 4,700-foot of lateral in just 24 hours, a Company record in the area.

On the completion side, we have tested reduced cluster spacing to increase well performance. This, when coupled with the optimized flow techniques we're using, expect to materially improve the flow rates. For example, the Racine pad we brought on in Susquehanna County this quarter came online at greater than 50 million cubic feet a day from just three wells. We plan to continue testing these techniques in the fourth quarter and will discuss further as we get more information.

Moving to Fayetteville, we hit a very big milestone there during the third quarter, where we surpassed 5 trillion cubic feet of production since our inception in 2004. Even with the recent reduction in rig count, this play still produces approximately 2% of the nation's gas supply and contributed over $60 million to the Company in cash flow in the third quarter. We continue our testing efforts in Fayetteville during the quarter on the Moorefield Shale, which lies just below the Fayetteville Shale. We brought on line one Moorefield well at the end of June that had an initial production rate of 6.2 million cubic feet of gas per day, a lateral length of approximately 7,300 feet, and an estimated EUR of over 4 Bcf.

This continues the encouraging results we've seen since the beginning of 2015. The seven Moorefield wells brought on line since the beginning of the year in 2015 averaged an initial production rate of 7.2 million cubic feet a day, a lateral length of approximately 6,950 feet, and an estimated EUR of over 5 Bcfe. We will continue watching the long-term performance of these wells and determine the aerial extent of the acreage perspective for this interval.

With the potential of the Moorefield and the impact of increased proppant loading in the Fayetteville that we discussed earlier, we are encouraged that these, along with other initiatives being tested in the play, could significantly lower the breakeven price for the play and help it compete with opportunities available in our Appalachia portion of the portfolio.

This concludes today's prepared comments. We'll now turn it back to the operator, who will explain the procedure for asking questions.

Thank you.

(Operator Instructions)

Our first question comes from the line of Scott Hanold from RBC Capital Markets. Please proceed with your question.

Thanks. Good morning, guys.

Good morning.

Hey, Scott.

Hey. You all talked about the $700 million to maintain production in 2016 to 2017. Could you give us a sense of what rig count cadence is that? Is that currently the five rigs you're at or would that require additional activity? I guess the follow-up question to that is based on the hedges you all have in place, which gives you I guess a fair, decent certainty in terms of pricing next year, what is your view on adding to your current rig count and when could that occur?

This is Jack. Thanks for the question. As far as rig counts for the $700 million of maintenance capital, that would be less rigs than we're running today. That would be right around three rigs, maybe 3.5 rigs for the year.

Capital efficiency's gone up as we've drilled more and more in the Northeast, so we're able to do more and more with fewer rigs. Our, I think, well count becomes probably the key question. As you look at our hedges and, Randy, you can talk a little about it, but as you look at our hedge positions, as we look at our capital program, we feel very assured on delivering the value that we need. As our capital -- as we look at gas prices and we see if they increase further than they are, then we will make some adjustments to our plans at that time. Our objective is to invest within cash flow and as that cash flow changes or rises, it gives us options to move forward.

The rigs are our rigs. We're very flexible in terms of what we can turn on and turn off. We can be very agile in that view as we get closer to February.

Okay. I appreciate the not trying to front run your guidance. Maybe the better question I should ask more specific to that is, at the current five rig count, what does that imply for annualized CapEx then?

About $900 million, give or take.

Okay. Okay. So just a bit under the $1 billion-plus cash flow number you talked about for next year.

Well, again, we haven't set our 2017 plan. My only reason for bringing up the $700 million, two points, one, just to make sure people understood that point and there's a good amount of upside we're returning back to flat production using that just maintenance capital. Then we'll analyze and look at the markets as we approve our budget and again look for opportunities to either go faster or drill more as economics and cash flow afford.

Appreciate the color. Thanks, guys.

Sure.

Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Please proceed with your question.

Thank you. Good morning, everybody. Good morning, Bill.

Hey, Doug, how are you?

Good, thank you. I appreciate all the information this morning. On the cash flow breakeven, I wonder if I could just asked you, you talked about a strip. What's your outlook for differentials that's baked into that number?

This is Randy Curry. The differential outlook, we remain very positive on the structural improvement in differentials over the long term, in spite of the recent headwinds some of the projects that were going to be coming online in 2017 are facing. We do believe it's a question of when, not if. Right now our differentials for 2017 are at the strip levels and the strip is also indicating out in the future, 2018 and 2019, some structural improvement and that's consistent with what we're modeling.

I appreciate that. I guess my follow-up may not be too easy to answer, I guess. I'm going to have a go anyway. There's been a lot of changes for things, obviously your proppant loading, your efficiency gains, your cost reduction, everything else. Is it possible to give us kind of an update as to where you see break evens across your three core plays at this point, just to help us a little bit as to how the economics look? I'll leave it there. Thanks.

I think if you look at Marcellus, and these numbers probably don't have all of the improvements in them yet. We're working on that. Marcellus economic wells are [260, 263] kind of range on pricing. That's a 10% kind of return. West Virginia is probably -- dry is probably [250].

I don't have a wet one with the newer kind of outlook on gas pricing. We can get that to you. Not gas pricing, but ethane improvements. The portfolio looks pretty -- very positive for opportunities to invest and make the returns we need in that range. You look at 1.3 PVI numbers and they're probably in [280s to 290s] for each of those two areas.

And Fayetteville?

Doug, this is Craig. In Fayetteville, kind of just follow up on Bill's note or Bill's comments, Fayetteville certainly at current prices with the high of [17], certainly looks good. What we're seeing in these early results we talked about these IPs and certainly testing Moorefield, continues to push that breakeven down. As we've kind of seen, kind of lay out based on historical results in our IR deck, Fayetteville at $3 flat gives you about 500 well locations. You can maybe push that a little bit lower.

Certainly with new results can continue to push. That really kind of goes with all locations. As we continue to drive costs out of the system and improve production rates or EURs, that helps. The numbers Bill quoted on our Appalachian assets is fair.

That's great. Really helpful, guys. Thank you.

I'll comment. We have -- just one more thing on that. In the Fayetteville, we're doing some Moorefield drilling right now. We don't have -- the results are kind of early days, but those wells are coming on quite strong. They have -- their economics are very solid. We're not doing anything that doesn't meet our 1.3 PVI investment hurdle at strip pricing and that's excluding any hedge benefit. You can kind of see that in each of the three areas, there's some depth and some good depth in terms of well locations available to pursue.

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

Good morning, Bill, and to the rest of your team there.

Good morning.

I wanted to ask a question about your completion pace here in Q4. One of the things I was struck by was the uptick in planned completions to 52 in Q4 from 9 in Q3. Can you talk about what the pattern of that, of those completions will be over the fourth quarter? Is it going to be kind of flat over -- across the months and weeks of the quarter or are you more perhaps weighted towards the back end with the aim of capturing better local pricing? What does that mean for your -- do you have an estimate you can share with us for your 2016 exit rate?

Let me talk a little about the pace of what we're doing and then I'll do some exit rate stuff, or Jack can. There's a combination of things at work here. We've restarted the activity. We want to be as efficient as we can. Really most of the completions in the fourth quarter will come across fairly ratably.

We expect that we will do -- our objective is to complete all the DUCs, or as many DUCs as we can, out of Fayetteville and then in each of the other two assets retain a level of DUCs only for efficiency. We don't -- when we halted activities at the end of the year, first part of this year, we had a DUC inventory. We then restarted. That's all going fine and we're just working them off. Since we don't anticipate a large amount of drilling in Fayetteville, we don't need a large amount of inventory in Fayetteville, so you get those to market and begin to get returns on those.

In the other two areas, you're going to be focused on capturing those that we can get to market in an efficient and timely manner to capitalize on those rising prices, while retaining enough that we can be efficient with our plan. I think at the end of the day, you'll see it ratably across the year. On volume, what was your question on volume?

Just what implication that's would have for exit rate on 2016.

We're looking at about 2.2 to 2.3 Bcf a day equivalent exit rate. As far as the fracture, the level of completions, we're currently running five completion frac crews. We may pick up a sixth, but it's -- we're very smooth and just continuous operations. The only thing that impacts it, the reason we don't have a little faster pace is water availability in Pennsylvania and it comes and goes. They've been getting a lot of rain up there right now, so we don't foresee a problem.

Got it. Thank you. My follow-up question, and Bill, I apologize if this is pushing too far into your 2017, so feel free to deflect a part of the question. As you look ahead to 2017, I know you're going to work down your DUC inventory it looks like by 16 in Q4 and then you say you'll be back to your target of that 60% inventory that you need for efficiency in 2017. That implies you're going to work down your DUC inventory by another roughly 25 over the course of the year. Compared to the 52 completions you're going to have in 2014, what do you think your completion rate per quarter is going to look like in 2017?

Well, you're right, we will get those inventories to where they're efficient. The completion inventory in 2017 will be directly related to what our capital budget looks like. We haven't done that yet, so we're doing scenario planning around that now. We want to remain flexible between the two divisions up in the Northeast. As our DUC inventory, our rate of burn off DUCs, our timing of wells and completions, the underlying theme will be -- it will be as efficient as we can to drive higher margin through lower cost and improved well performance and it will be, the makeup of that will be part of our capital plan.

Thank you for that color.

Our next question comes from the line of Holly Stewart with Scotia Howard Weil. Please proceed with your question.

Thank you. Good morning, gentlemen.

Hi, Holly.

Just quickly maybe following up on Charles' question a little bit. Could you just talk you through how you're viewing the ramp process so far versus your expectations? It looks like DUC count now versus, I guess, the slide deck is a little higher and the wells turn to sales projection for the year is a little bit -- I guess year-to-date is not right on par with the forecast. Just trying to get a good sense for how you think it's going and maybe just the expectations here as you work through the fourth quarter.

Sure. Yes. The headline is, it's going terrific. Remember, there's two components to this. First component on the fracture stimulation side is we want to be as efficient as we can and we want to get the count to where it optimally suits our budget.

The second thing that we talked about, and this is critical, is the frac intensity or the testing that's going on, on some of these wells. We're l ramping sand loading in a couple cases from 1,000 to 2,000 pounds a foot from 2,000 to 5,000 pounds a foot. That testing impacts some of these wells and to put that much more sand and that many more stages into a well takes longer to do. The only issue that we have right now, and it's not really an issue, I miscalled it, it's an opportunity, is we're doing some testing related to higher sand loading, which will have positive effects, we expect, on our wells. We've already seen that in West Virginia, where we've gone up above 2,000 to almost 3,000 pounds in wells that are already online. That combined with how we're landing them and how we're flowing them and all that is improving their individual performance. We expect that to be the case elsewhere.

A nuance to all that statement is, we're right now focused on technical limit. We've already proved to ourselves that we can get a whole lot more sand in and they make a whole lot better wells, which makes them more economic. We want to know how much can you do. We focused the folks on that. We'll do those wells and get them online and see and then we'll bring them. If we go to the place where much higher sand content and stage spacing, et cetera, becomes more of the norm after we test it, then we'll readjust our schedule, let you know what that look like and go from there. That's the real big piece of that whole calendar issue.

Okay. That's helpful. Maybe just following up on the sand comment, you mentioned in the prepared remarks the 5,000 well -- or the 5,000-pound per allowable foot test and then you just mentioned 3,000. I guess, is that well online? Is there anything to think through there? Was that a wet versus dry well?

Just trying to think through, I guess historically you said you'd been at 2,000 pounds. Just trying to think through how that could potentially impact the results.

Holly, this is Jack. We have not brought any of our current tests online yet. They'll be coming on this quarter. We do have some higher -- greater than 3,000-pound tests that we did last year that are part of the better performance I mentioned on the Ridgeland land ventures pad.

We're building on that, actually stretching, again, as Bill said the technical limits to do that. We have brought on in Northeast PA some of our -- the Racine pad I mentioned was one that we went to tighter cluster spacing, more stages. That contributes to the time but we're definitely seeing the performance there. It's there with high sand already at the 2,000 pounds that we adopted last year.

As you walk through these, you've got a couple things going on. You've got three different areas of production in the three divisions we have. They're all in various stages of ramping up. You take Fayetteville going from 500 or 800 pounds to 2,000 pounds, that doesn't mean we're stopping there. That's a big leap for them.

In Northeast -- the Northeast assets we've already have proof that in certain areas that you can go up past 3,000 pounds and get materially better wells. Now we want to figure out, okay, how do we step that up and in what increment. I've got engineers that would like to do a whole lot more than even the numbers we've been talking about. We want to be prudent about it as well. Then we'll figure out where that economic threshold crosses that technical limit and optimizes that point and go forward. We'll -- we've got a lot of moving parts here and the early indications, both from late last year and early now with some of the Racine work in Northeast Pennsylvania and some of these is very encouraging and we'll continue to pursue that.

Great. Thanks, guys.

Our next question comes from the line of Arun Jayaram with JPMorgan. Please proceed with your question.

Good morning. Bill, I was wondering if you could comment on the potential delays on Atlantic Sunrise. I think you do have some modest volumes on that project and what that means to SWN as we think about 2017, 2018 and how you're thinking about capital allocation.

Just in general, our exposure to Atlantic Sunrise and the Constitution pipeline, quite frankly, on a relative basis to our portfolio is small. We are watching both of those. We're very aware and trying to be more aware every day of the different twists and turns that are going on with those projects. We think they're both robust projects and should happen.

We've known for some time that we needed to manage our overall portfolio in that area by adding additional capacity. Last year we added some additional capacity around what we already had, anticipating that you could have some scheduling challenges. I think further, probably the greatest near-term impact becomes the seasonal differential challenge, especially as production and pricing resumes and if you get production come back online you get the differential challenge. We're trying to manage that through basis hedging.

Our overall transportation portfolio pricing is very low in that area. Managing that to the markets we serve, managing any kind of basis challenge with further hedging, we certainly are doing and we'll watch it closely. Randy may have some other comments for you, but we feel pretty good about where we sit relative to that right now.

I agree with everything Bill said, obviously. The only thing, color I'd add is everybody, I think, is aware the FERC did issue a new deadline for the EIS, which is the end of the year yesterday and then there's a 90 day period after that. The project has been certainly pushed back a little bit, but as Bill said, we feel really good about our overall portfolio out of Northeast PA and Southwest Virginia. What we had was a 44K -- 44,000-a-day volume on Atlantic Sunrise.

Just a quick follow-up on that. Can you give us an update on Rover as well, where you did have more the significant from transportation exposure?

Yes, Rover has received their final EIS and there's actually an expectation, I believe, by the industry and the market that they'll receive some notification here very soon at the expiration of the 90-day period. To date I think all the feedback that we're getting from the pipeline is they remain confident on that and will be able to start construction fairly soon.

Okay. My second question would be just on NGLs. Bill, you highlighted how you're quite optimistic on NGLs and ethane. How could you, as you think about 2017, could we see more activity in your Southern Marcellus, or Southern Appalachia acreage, take advantage of that?

Yes, I think the way we're doing this, as I said earlier, we've got economic projects in all three of our operating areas. What we do in putting together the portfolio of projects is that we force rank them all and we look at the PBI contribution to the Company from each of the areas and we rank them. As we're working through that planning process and we see further and further signs of some clear strengthening of NGLs, you get some of the wells move around in that positioning.

So yes, it's entirely likely as you look at where that mix falls out by the time we issue guidance that you see it move around. We are -- I'm a firm believer in leveraging every strength you have and because we have our -- we're vertically integrated, have our own rigs, we have our flexibility to move around, we have capacity in each of the areas, we need to take advantage of that and be able to be agile in working through that.

Okay. Thanks a lot.

Our next question comes from the line of Marshall Carver from Heikkinen Energy Advisors. Please proceed with your question.

Yes. What are your wells costing by area now for a typical well and how much more expensive are the wells with the larger completions?

Well, typically in Northeast PA, we're looking at about -- still around $5 million, $5.5 million. We have not seen an increase in costs overall with our testing of the completions because of the service prices right now are very favorable. We've now in the very large jobs we're pumping in West Virginia and Southwest Appalachia, we are adding $1 million to $2 million generally to our well cost. They're up to $8 million on the well cost, $8 million to $8.5 million.

But we're getting a great return. I believe the work we did at the end of 2015, we think on that $2 million we invested extra on those, we got 2 PBI on that $2 million. The return is very healthy on the incremental sand and cluster spacing. Fayetteville is still right around $3 million on our wells. We have our own sand mine and so sand is very cheap there.

In West Virginia, $7 million on a 7,500 -- or 7,800-foot lateral in rich gas and about $6.5 million on a 6,000-foot lateral in the lean gas.

All right. Very good. Thank you very much.

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

Thank you. Good morning.

Hi, Brian.

Can you talk about capital allocation to the Fayetteville beyond completing the DUCs? How aggressive should we expect you to ramp up activity if we're in a, say, [325 versus 350] gas price environment for 2017?

Yes. I kind of mentioned this a bit earlier. Certainly as we look at the Moorefield testing that's going on, we want to understand the aerial extent of that. We want to understand how the changes to our completion technology -- our completion practices, flow-back practices and drilling practices, what impact that has on the Fayetteville.

I remain in the same place that I spoke about earlier, though, is that you have some targeted testing and if that opens up new frontiers then we put that into the mix. You have some land capture in the two other division, not Fayetteville. Absent those and maybe one or two other things, then you start looking at relative economics to the Northeast. A big piece of our capital productivity improvement, a big piece of really our overall performance improvement, is allocating capital to the highest, best use of that capital and today, with current technology and current commercial terms and all the other things that go into that, our two Northeast assets by and large have that advantage.

In the first pile-up of projects, the majority of it obviously goes to the Northeast. As you're seeing right now, we have a rig in Fayetteville. It's focusing on Moorefield. It's focusing on some other testing and we've got some other things we're working on. Then the rest of the activity is in the other two places.

We challenge the teams all the time and they take this challenge on very well and as you can see from our results, it shows through. Each group, while they're working for the whole of the Company, they're driving in their own backyard, driving margin improvements, driving productivity of well improvements. You make major in-roads into the water management of any of these divisions and you move the needle. There's a lot of very exciting testing going on around water management and around different techniques. It can move the dial.

As we work through the remainder of this year and continue the planning for 2017, all of that will be taken into account. The headline for you is really it's all about economic value and driving economic value out of what we have. The bias at the current view at this 10 seconds obviously goes to the capturing that value in the Northeast.

Thanks. Just a follow-up on the Moorefield point that you mentioned a couple times, obviously that's base load because you're doing that now with the one rig that you've added. Is it also the next -- is it also on the margin? In other words, if you do want to add more activity to the Fayetteville, would you actually do more Moorefield test first with another rig over a wider aerial extent or would you actually go to doing more development drilling for the Fayetteville zone? I know you mentioned that would have to come only if the returns are better than Appalachia, but let's just say they are.

If they are, then certainly they would compete in the investment stack and you'd go from there. I'm going to do capital allocation based off of proof and so the teams are working those out and certainly we will -- we'll go from there. I don't know whether at this 10 seconds whether we'll do more Moorefield testing next year or we'll gain enough to be able to sort of lay that all out and put it again in the priority stack.

Brian, this is Craig. Let me just add, as Bill indicated, Moorefield is certainly something that we like. We like what we've seen. All of Fayetteville continues as the teams continue to work and spent the six months doing a lot of work on paper and a lot of challenge across divisions, in divisions, it has kind of stepped up and we like the early results we've seen. It continues to compete and it continues to claw back.

If you were to ask us that question nine months ago, I think $3 flat environment our bias would have been most of the economics would have been in the north. I think we're seeing some positive things that may be changing that.

You challenge a team with thousands of well location that are sitting there on the price curve and they rise to that occasion. We look forward to talking more about that as we learn more.

Thank you so much.

Our next question comes from the line of Kashi Harisingh with Simmons.

Good morning. Thanks for taking my question.

Good morning.

On the Racine pad with the really impressive initial results, could you give us some idea of what your expectations are for year-one cumulative production on an individual well? Could you also give us some idea as to what extent this optimized flow-back technique would be incorporated into future wells being brought online?

Yes, I think the headline for you -- Jack may have some comments to go with it. The headline for you is it's just too early to tell. When we -- as a matter of practice, just now and going forward and even in the past, when we have some very high rate performance out of some wells, given advancing sand loading or given advancing anything, we're going to study them, understand them, are we accelerating EURs, are we opening up new recovery percentages, all that. These have not been on all that long and so I would guard against adding to EUR at this time.

What is clear is when they -- as they come on and they flow at this rate, you're accelerating value. That is a -- that's our driver is trying to figure out how do we maximize value. As soon as we get a bit more of those under our belt -- we're in a kind of a fun but awkward time right now. We've been offline in the drilling and completions area for six months. We've come back with just an aggressively strong performance, but it's too early. I don't want to lead you down a path that we can't confirm.

Thank you. That's it from me.

Our next question comes from the line of Dan McSpirit from BMO Capital Markets. Please proceed with your question.

Thank you and good morning.

Good morning.

Circling back on a previous answer regarding capital spending in 2017, what would five rigs running in $900 million in capital spending mean for production growth in 2017?

I don't have that yet. It depends on where you allocate those, that capital and where you allocate those rigs and how many -- how the completions go and -- the divisions are all very different and so I'll ask you to stay tuned on that.

Very good. As a follow-up, relatively heavy use of swaps in 2017 as part of the hedging program. Just curious as to why swaps versus greater use of collars.

Our program's one where we just -- we try to find the right balance and we want to have a portfolio of both swaps and collars to give us both some floor certainty and then also some opportunity for the upside. It's really just a balanced approach.

Very good. Great. Thank you. Have a great day.

Thanks.

Our next question comes from the line of David Tameron with Wells Fargo. Please proceed with your question.

Good morning. A couple questions. One, I think, Bill, it was you that referenced ethane. Can you just talk about what type of leverage you have to that and what that could mean as far as margins and pricing and -- I know I obviously have your NGL volume, but can you expand on that a little more?

Sure. Randy?

This is Randy. Yes, the -- we have a nice exposure to Mont Belvieu pricing via our ATEX capacity. That is really one of the primary drivers. Also, ethane represents a little over 60% of our NGL barrel. Those two factors combined really do start impacting kind of the wet versus dry economics when we start seeing some significant shift in ethane.

The longer term outlook, given the crackers that are under construction as we speak for demand in the Mont Belvieu area, is fairly significant. We're looking at over 600,000, 700,000 barrels a day of demand on top of a base that is 1.2. You couple that with some export capacity and that's why you see a rather strong outlook for ethane, which we have some -- certainly have some good exposure to.

Export capacity is nearly 300,000 barrels a day. You've got some material demand happening.

Okay. That's helpful. As relates to -- remind me, how should we think about 2017, 2018 as far as framework? What are you putting up as, I guess I'll call them governors, as far as debt to EBITDA levels, within cash flow (inaudible) cash flow a little bit, how should we -- we can plan on prices, but how should we be thinking about that?

At this point I think that what you are to think about is you look at the forward curve and depending on what that -- your you view of that is, you look at our -- the cash flow that our assets can generate and then you look at the capital that investing within cash flow would add up to and that's how we intend to be thinking about setting these budgets and plans. You look at assurance of that. We have a three-year rolling hedging program that the front year's hedged about where you see we're at for 2017.

Then you look at the two following years and we want to have a rigor and discipline around rolling those in, taking into account market forces and economics of the program and the investments. I think right now it would be prudent for you to look at that from the standpoint of hedging within -- not hedging but investing within cash flow, because that's what we think is prudent.

All right. Thank you.

Thanks, David.

Thank you.

Our next question comes from the line of David Deckelbaum with KeyBanc. Please proceed with your question.

Hey, good morning, everyone. Thanks for taking my questions.

David.

Just curious, I know on the -- there was the illustrative $700 million of CapEx planned to hold things flat. I know a lot of things are dynamic. You haven't given your 2017 plans. In that original illustration, did that assume that just the Northeast region was growing and that Fayetteville was still in decline in 2017?

I would expect that to be the case. You've got to drill -- you've got to put a number of rigs in there to keep -- to arrest decline in Fayetteville (technical difficulty).

Okay. Moorefield shale, can you give us -- I wasn't sure if I heard it or not, but what do those wells cost right now relative to the Fayetteville wells?

They run about $3.5 million to $4 million.

Okay. You opened up your remarks, Bill, by talking about how you've basically been 95% within zone or target of where you want to land these laterals. You also talked about improvements with proppant loading. Are you seeing the biggest step change from that lateral landing from rotary steerables or is the performance that you see this year more a function of sand loading? Where would you have said that you were in terms of percentage of hitting zone in 2015?

This is Jack. The rotary steerables have helped us in getting the laterals in place and speed. Those are where they are. We were getting them in zone before. They were taking longer. We were drilling slower. The performance of the wells is that we -- is a combination of landing in the proper zone and the completion techniques. The more sand is definitely making better wells but if you don't get them in zone, doesn't matter how much sand you put in.

The other thing we're looking at, and we do this all the time, but as wells get better and you need to go back and look at your -- at the surface facilities and the gathering systems, are they sized appropriately for improving well performance. You up size meter runs or up size production facilities, and I'm not talking about massive up sizing. You go from 2- to 3-inch and you get a huge benefit. Looking at tubing design. In history we've done some modified tubing design. We've done some tubing-less wells in different parts of the Company and we're applying all of those learnings back towards these assets as well.

You'll continue to see the components improve the overall performance and as we can triangulate around, well, we think sand is contributing this much and better, different flow-back regimes or different surface facilities contribute to that much, we can share that with you. We're getting solid performance out of each component.

Thanks for the answers, guys.

Our next question comes from the line of Drew Venker with Morgan Stanley. Please proceed with your question.

Hi, everyone. Just want to circle back on the earlier question about your expectation for differentials next year. Just wanted to clarify. Are you thinking pricing is better on an absolute basis in Appalachia or you're thinking differentials are actually narrower than for 2016?

Differentials for this quarter compared to 2015 in Northeast Appalachia were actually slightly better. Our forecast and our outlook and planning is kind of what the current strip is right now for calendar 2017.

Sorry, just to clarify. You're saying in line with strip. Is that -- so is that better than, narrower than this year or is it actually a little bit wider?

It's greatly influenced by the seasonal effects. I would say there's probably right now about the same as this past year.

Okay. And then --

-- that I'm talking about.

Okay. This quarter Northeast PA production was down I think more than the prior quarter. Just curious if you had shut in any volumes and just wondering on your typical operational plan. As you said in your remarks earlier, 3Q is typically your weakest pricing year, weakest pricing quarter of the year. Do you typically try to constrain volumes when prices are low or is it mitigated by some other basis swaps or other measures?

We don't normally constrain volumes unless prices get very low, which in the quarter they were actually not that -- at that point. There was a lot of maintenance went on, on different pipelines during the quarter that did hurt our production in the Northeast a little and we brought on -- the wells came on later in the quarter, the new wells that we did bring on. It was normal decline generally.

When we -- the investments that we did make early in the year, the benefit of that showed up in Q2. Then you go six months without much activity, that will do Q3. As I said earlier, when you get to -- when you include the activity that we've got going on now and the improvement of the overall business, setting aside the activity we have going on now, but just the overall improvement, we arrest decline by the end of Q4 and you're actually building back volume. It was -- it probably mostly related to just sequencing and timing.

The other thing that just pointed out to me, when we started, restarted our drilling, you usually have simultaneous operations. You have some shut-in on the pads that you do actually curtail production but it's really from a HS&E standpoint that we do it and so that goes in the second quarter. We had no operations going on. Third quarter we did have some that contributed somewhat.

We have minimal volume in the dailies. Most of our volume is under contracts. You have some just minimal volume. If we don't cover cash cost, we won't produce them. But it doesn't show up on the radar. It's not material.

Thanks for all the color.

Sure.

Our next question comes from the line of Ray Deacon from Coker Palmer. Please proceed with your question.

Yes. Thanks for taking the question. I was wondering if you could talk about your attempts to lock in additional firm transportation, if you were to make the decision to ramp in the Southwest at this point, looking out to 2017 and keep the current rig count in place.

Yes, kind of a high level view. I would like Randy to give you whatever color we can on that. When we went into Southwest Appalachia, we saw the very high priced, very -- up close to $1 long 20-year agreements. We got in there early.

We acquired as much transportation as we needed to do two things. One, get an early ramp on the business. Assuming the pipes come in when they're supposed to come in we can ramp that thing at 35% a year for the next three years, comfortably. We then wanted to look at where the pipes get built. Committing to the right pipes at the right place to access our acreage was really important.

Then we stepped back. 16 Bcf a day of pipeline capacity, excluding expansion capacity being built all in one area, is a lot of capacity. Taking on long-term commitments that you end up having to drill into or whatever didn't make any sense to us at all. We said we'll wait, because we do believe, and I think the industry shares this with us, that there will come an inflection point in all of this expansion where the cost of those and especially if you get into any expansion type capacity, the cost of that comes down. We will leg into that at a later date as that cost does come down and the terms get more rationalized.

We also have the opportunity to enter and we have into firm sales capacity, where we are making sales into other consuming side, demand side capacity. We'll continue to work that. Randy may have some additional color he wants to put on that, but high level, that's kind of our philosophy.

Yes, Bill, the only thing I would add to that, and Bill touched on it is, we're going to have a portfolio of options out of really all the basins we operate. There will be a mix of FT, a mix of firm sales, a mix of daily exposure to local indices. The outlook, again, is one that we think structurally over time improves and we'll continue that. What we have today in FT we're very comfortable with, with commitments that we have made on some pipes that will be coming online and so we're -- we'll continue to watch that but feel very confident about our position as it stands today.

Great. Thank you. I guess just one more follow-up on that is it seems as though some have noticed that you have less exposure to the Midwest relative the to others and is that something you see as critical to price realizations going forward?

We want to have exposure, a balanced portfolio and a broad portfolio. There will be some Midwest exposure in some of the capacity that we have that's to be built. We also are very oriented towards the Gulf Coast as that really is -- if you look at kind of Gulf Coast and southeast where the demand growth expectations are, that's certainly a value to us as well.

Thank you.

We have time for one last question. Our last question comes from the line of Jeffrey Campbell from Tuohy Brothers. Please proceed with your question.

Thanks for taking my call and congratulations on the ramp-up. First thing I wanted to ask was this call we've had more discussion around completions rather than lateral length. I think most E&Ps are pretty unified around lateral lengths improving economics. I was just curious, are you also increasing lateral lengths in your Fayetteville and Moorefield tests as well as in the two Appalachian areas?

Yes, where we can. In some places lateral length is limited to -- by unit size or how that is made up. We've done lateral length testing up past 12,500 feet. We are analyzing the -- and we were up near to virtually 100% in zone and all the things we've talked about.

What we're doing is analyzing that flow back. We have four of those wells, I believe, in two different areas are some of our longest that we have. You want -- the trick is making sure that you're getting the contribution out of the full lateral length and that when you rerun economics, it's not just -- it's not about flow rate or IP or any of that. It's about well economics. You make sure that these extended-reach laterals, you're getting the contribution out of the whole thing for the investment that you're making and it's a risk/reward balance.

We do -- as we look the to block up land, we are consistently -- so for example, in the range, we started out in West Virginia the 7,500-foot kind of target lateral. I think some of our latest averages are like 7,800. We'll tip of to block up acreage and trade and exchange so that you can get those out there while we're testing these longer-reach ones. The Moorefield laterals are longer. The Fayetteville well laterals are longer as well. The trend is longer, but we will make sure that value per risked foot and all of that makes sense.

Thank you. Just a little higher level question on the Fayetteville to close. Looking at it longer term, is there an argument for high grading and downsizing the assets or sales or acreage release? In other words, the more challenged locations? I'm also wondering how the Fayetteville's midstream might affect any thinking on that point.

I think you look at the Fayetteville from a number of different dimensions. We do. First of all, it's just a massive cash flow generation machine and the opportunity that, that affords the Company is certainly a bright one. We're seeing the application of commercial and technical and operating expertise be applied at an even greater pace that is unlocking additional opportunities.

Certainly, our midstream business is integral to that. The agility that we have, the ability to move back and forth, the ability to be flexible as a corporation, again, not drilling into somebody else's midstream contract or not drilling into the firm transportation that you've over committed to, any of those kind of things. It's a balance. I think we see the Fayetteville as a vast resource that continues to generate cash flow.

Any of these assets are certainly assets that you look at, say can I get greater value doing something different than I'm doing now? We work that routinely. Where are they on their cost curve? Or you take a subset of it. We did a transaction in West Virginia on some acreage we weren't even going to get to until 2023. It wasn't that it was not economic. It's just so long dated that why, if we're able to accelerate that value at a good value, then it makes sense to do it.

I think we continue to look at it as the answer. We don't want to put ourselves in the place where we do A because we've done B. We want them to be economically synchronized and we think that you add more value in the long run.

Okay. Thanks very much. I appreciate that.

Okay. Thank you.

We are out of time for questions. I'd like to turn the call back over to Management for closing comments.

Thank you, and thank you all for being here today and taking an interest in what we're doing. You've heard a lot of impressive accomplishments throughout the call this morning. The good news is that we've positioned each of these assets well and we think that they're each set up so where you can expect to have even more results and even better results as we go forward in time. With the stability that we've recaptured in the Company this year, we've got a clearer path to capturing and delivering value, creating growth and we're doing all of that in a rising gas price environment. Positioning yourself to capitalize on a rising gas price environment is a big piece of that objective.

Our portfolio's primed to deliver impressive well results as we learn from all the things we've talked about today and our firm transportation portfolio allows us the flexibility to maneuver, navigate, and work through an ever-changing basis environment, an ever-changing regulatory environment and an ever-changing pricing environment. We'll continue to device and implement innovative drilling and operating techniques and efficiencies. We have what we call around here an aggressive assault on improving margin.

Every individual in this Company is driven by, incentivized by, the quest to reduce cost, improve the operating results of every part of the business. You have it on the revenue side. You have it on the cost side. We are committed to continuing to increase that margin. Finally, we will maintain the rigor of capital allocation, capital discipline, financial responsibility, that we've demonstrated so far this year and is a hallmark of our Company.

I want to thank each of you for joining us on the call today. Thanks for all the questions. We look forward to seeing you along the road and hope you all have a great weekend.

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