西南能源 (SWN) 2016 Q2 法說會逐字稿

Greetings and welcome to the Southwestern Energy Company second-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, Melissa. Good morning and thank all 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 have not received a copy of last night's press release regarding our second-quarter 2016 update, 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 outcomes, many of which are beyond our control and are discussed in more detail in the risk factors and the forward-looking statements sections of our annual and quarterly filings with the Securities and Exchange Commission. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

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

Thank you, Michael. Good morning, everyone. Thanks for joining you on the call today and your continued interest in Southwestern Energy Company. Earlier this year we set out on a mission and articulated a clear set of objectives committing to reinforce our Company, restore confidence and strengthen our bridge to resuming value-adding growth as commodity prices and the economics improved. We have delivered on these commitments.

As you've seen over the past few months, we have been keenly focused on strengthening our balance sheet, including managing near-term maturities, by pushing out a material amount of 2018 maturities to 2020, and have taken specific actions to he reduce approximately $1.2 billion of debt through the sale of a portion of our long-dated undeveloped acreage and our very successful equity offering. Craig's going to discuss the details of this very successful deleveraging activity in a few minutes.

In addition, we have continued to do what we do best, aggressively improve margin, both cost and performance, from our premier asset portfolio. We continue to drive cost out of the system and optimize our base production. The results of these efforts were evident in last night's release, where you saw our strong quarterly results, including production beating the top end of guidance by 10 BCF equivalent, while the cost metrics came in below guidance. These achievements position the Company to capture the benefits of a strengthening commodity price that appears to be in process.

Based on this strong operational performance and our high-quality assets, improved commodity prices, a stronger balance sheet, including the preservation of our strong liquidity position, and funds earmarked from our equity offering, we are reinitiating economic drilling and completion activities in each of our operating areas. These activities include completion of drilled but uncompleted wells and drilling of new wells, all meeting or exceeding our rigorous economic criteria. In fact, given our vertically integrated business model and only after the funds were secured, we have already resumed drilling activities much faster than we anticipated.

Our first well, which was spud last weekend, reached TD in less than four days, which is comparable to what we were doing seven months ago when he we halted drilling activities. We plan to add one to two rigs per month across the Company during the third quarter, demonstrating the speed and agility with which we can adjust our activity. Our well costs will also see the benefit of this vertical integration as the industry increases activity over time in response to the improved commodity prices.

However, we plan to continue to evaluate and utilize both internal and external services as we ramp up activity and as economics dictate. Jack will walk through the detailed plan for Southwestern for the second half of 2016 in a moment, which will have a material beneficial impact on 2017 and beyond. While we've not communicated our 2017 plans, early indications show that we can invest in value-adding economic projects resulting in production volumes flat year-over-year with a capital program of just $700 million in 2017, given the optimization work under way and the higher capital efficiency in our go-forward plans.

Let me be clear. We will not chase uneconomic production growth. Each well we drill, each well we complete, must meet our economic threshold of 1.3 PVI at current pricing before we drill. In line with our intent to invest within cash flow and drive continued improvement in the balance sheet, we will remain flexible and adjust activities accordingly as prices move.

A critical aspect of our commitment to financial discipline and an essential part of our forward investment plan is to take steps to assure our commodity price projections used in our economics for projects are realized. Consistent with our strategy to protect returns on our investment, to date we have hedged just over 225 BCF of our 2017 production, locking in a portion of our 2017 cash flow.

With that, let me turn over to Craig to discuss some of our financial highlights from the second quarter.

Thanks, Bill. Good morning, everyone. As Bill mentioned, we had a very strong quarter and successfully delivered on our commitments. Since the beginning of the year we have consistently noted that strengthening the balance sheet is a core focus. We took significant steps and deliberate steps in this area during the second quarter.

The first step announced was the divestiture of long-dated acreage in West Virginia for $450 million. This acreage was scheduled to be developed in or after 2023, providing us with the opportunity to realize a strong purchase price with no appreciable near-term production or cash flow loss. The due diligence is progressing well and the transaction is expected to close in the third quarter.

Additionally, we announced the amendment and extension of our bank agreements, which ensures significant liquidity availability through 2020. Our portfolio of premier assets and strong bank relationships made this amendment process possible despite the challenging lending environment currently facing the banks.

Combining the impact of our bank transactions with $1.25 billion equity offering and successful debt repurchase in July, we currently have approximately $1.5 billion in cash in addition to the undrawn $800 million from the revolving credit facilities. Pro forma for these transactions, our net debt balance was reduced to $3.2 billion, with debt maturities prior to 2020 reduced from $2 billion to $300 million. This is a very positive development for our credit and liquidity profile, as it positions our balance sheet well to drive value from our outstanding assets.

As we strengthen our balance sheet with these proactive steps, we're also taking steps to resume value-adding growth as we resume drilling and completion activity in the second half of 2016. We are committed to maintaining a healthy balance sheet and protecting our returns and have been actively hedging our remaining 2016 production as well as 2017. We have now hedged 93 BCF of our remaining 2016 production at an average floor price of $2.57 per Mcf and approximately 228 BCF of expected 2017 production at an average floor price of $3.01 per Mcf. These positions provide, and our hedging program in general will provide, protection on cash flows and include options that allow exposure to upside price movements.

I will now turn it over to Jack to discuss some of the details of our operational results and increased capital program for the second half of the year.

Thanks, Craig, and good morning, everyone. As you saw in last night's release, in addition to the great financial achievements that Craig mentioned that we made in the second quarter, we also delivered excellent operational results. The quality of our acreage and the strength of our well performance continue to show as demonstrated by the second quarter production exceeding the top end of guidance by 10 BCF while investing less than $15 million of drilling and completion capital during the quarter.

With this strong portfolio performance, we are raising our 2016 production guidance by 45 Bcfe, or 5% using midpoints. Almost three-quarters of this improvement is attributable to our team's efforts to increase production from our existing wells.

Along with this impressive production performance, our aggressive assault on margin is continuing to reap benefits as our E&P costs, which include lease operating expenses, general and administrative and taxes other than income taxes, decreased to $1.17 per Mcfe in the second quarter of 2016, compared to $1.24 per Mcfe in the second quarter of 2015. LOE costs for the quarter were again lower than our guidance range as the team's progress -- as the teams progress their efforts to identify efficiencies in the field. Our identified LOE cost savings for 2016 is now over $50 million, an increase of $10 million from savings that we discussed in our last call.

These savings are in addition to the $35 million annual impact of the amended Williams agreement we previously discussed. The incremental $10 million was primarily driven by efficiencies implemented around salt water disposal and contracted services. We expect to leverage this focus on margin enhancement as we reinitiate our drilling and completion activities.

As Bill mentioned earlier, we have already started our drilling and completion activities and we anticipate five rigs running by the end of the third quarter, two in Northeast Appalachia, two in Southwest Appalachia, and one in the Fayetteville. We expect to drill approximately 60 wells and place approximately 100 wells to sales in the second half of this year, which includes our Utica well which we drilled in late 2015. While this additional activity will impact 2016 slightly with increased production, the real benefit of this comes in 2017 as we build the momentum of the portfolio and return to value-added growth.

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

Thank you. We will now be conducting a question-and-answer session.

(Operator Instructions)

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

Morning, guys, and great turnaround. Say, Bill, maybe a question for you, one of the guys, just on the rigs now that are coming out. Could you talk about on the two for Southwest Appalachia, is that going to continue just to focus primarily on Marcellus there or now bringing that first Utica well on from 2015, will that -- you start focusing on some of those as well?

I'll have Jack take that.

Okay. Currently, the initial wells will be Marcellus wells. We do plan to complete the Utica well and do plan Utica wells in our program going forward.

Okay. Maybe just a follow-up to that, or my second question, Bill, for the midstream maybe, could you talk about just midstream take-away as it pertains down to that Southwest area? I know, again, you guys have built up down there but I'm just wondering, as you get a little bit further down into West Virginia, any plans to build that out? Or if you could talk about sort of the infrastructure around that Southwest Appalachia area?

Randy can talk a little bit of detail on infrastructure. As we've said before, we took on some early transportation commitments and some gathering commitments as we did the acquisition. We've added to that portfolio through fixed sales where the buyer has the transport or transport of our own. We can grow this asset over the next three years at about 35% per year and not have -- run into constraints associated with take-away.

Gathering, the areas where we will drill have existing gathering agreements and gathering infrastructure in place and it's really a model for what we do everywhere. The time from spud all the way to sales needs to include is there available capacity, is there available take-away, is there available gathering processing and we assure ourselves that we have that route all the way to the market before we drill. Randy's got some -- probably some further details on the latest activity that we've been doing.

Thanks, Bill. I think the only thing I'd add to your comments are on the gathering side. As Bill mentioned, we do feel confident in the existing service providers and their ability to add needed infrastructure where we do need it and the time we need it. On the export capacity, the interstate capacity out of the region, again, we don't anticipate having any constraints when we get to levels that are beyond currently contracted levels in our portfolio.

We still have a good excess position forecasted right now. With the market where it is and the anticipated build-out of that area in 2017 and 2018 respectively, we feel very confident in being able to get what we need out of there.

One of our benefits of the renegotiation of the Williams deal, and we brought to the table, was the opportunity for them to be our gatherer for dry Utica gas in the same region. That's provided us quite a bit of flexibility. Our gatherers do a great job. We contract there to enable us, for example even the Utica well that Jack mentioned, we will be able to test that well in a wet gas system for a while, just to -- because it's available and the great support we get out of our gatherers. As we test there and then test other areas that dry gas gathering system for Utica gets built out. We just see a seamless progression from testing through to production.

One last one if I could, quick, maybe for Craig. Just that $700 million you said of D&C for CapEx for 2017, is that flat year over year or exit to exit?

What we moved to -- this is Bill again -- what we've moved to is prior our guidance was flat exit to exit. Now that is -- we believe that we will have a flat total production all-in for 2017 based off that number. As prices move around and we do our budgets, the opportunity -- gas prices, $0.25 gas price moves to cash flow $185 million. The opportunity to kind of evaluate that we go forward is what we're up to now. We won't do -- we'll do more work on our budget for 2017 later this year.

Perfect. Thanks for all the details.

It's an improvement.

Thank you. 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. I'm sure it feels good for you all to get back to drilling. I want to pick up on that last thread, which follows up on your comments from your prepared remarks. Two questions in this. Is the $700 million that you refer to, is that just D&C CapEx or is that total CapEx? If you could drill in a little bit more on the comment of being flat year over year, the way I look at it, if you were going to be flat year over year you would actually probably have to resume growth quarter over quarter, sequential growth, sometime in early 2017. Is that the right read on that?

Total capital number that I talk about and we do -- internally we look at out it this way, that is all-in. That's got CI&E in it as well as the activity capital that makes that happen. Our previous guidance was that for about that much capital, again, all-in, we could achieve a year-end 2016 to year-end 2017, you'd end up in the same -- where you started. But that had a decline built into it because it's a U-shaped kind of production profile.

With this, with us reinitiating drilling and completions and remember, we're doing a number of our DUCs and we can talk about that later, number of our DUCs and drilling new wells, we accelerate that progression, or another way to look at it, you flatten out the trough of declines. So yes, you're going to have -- we have to turn it. We'll turn it early in the year, probably, rather than waiting until sometime mid to late year to do that. And so we wanted to kind of compare something that we put out before which was at about $700 million instead of it being exit to exit is now full year on full year, flat.

You are correct. As we enter the second half of next year, you get on that growth ramp, assuming that we -- again, assuming that's the number. We haven't done our capital budget. We guided on that before so we just wanted to make it connect the dots for you.

Right. Thank you. That's helpful detail, Bill. If I could ask another question about what you're seeing in pricing in your local price points up in Appalachia. Depending on which price point you look at, you could make the case that there's been a Henry Hub rally, but there hasn't been as much of a rally up in Appalachia. How do you guys see that progressing, your local pricing in the back half of the year? Are there any particular sensitivities we should be thinking about with respect to that?

This is Randy. I'll take that one. We have seen an improvement in basis. We saw it obviously in the first quarter with prices falling. We saw basis come in. And then we've seen actually, as prices have risen, if you haven't seen necessarily the same widening, we still have a view that we'll have an improving basis over time in Southwest Appalachia, have a bias that the incremental capacity that's coming on, as I mentioned earlier, particularly in 2017 and 2018. Right now we've got that at around 13 BCF. Between the two years, will be adequate to continue to show some improvement and differentials over that time frame.

That's helpful. Thank you.

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

Good morning, gentlemen. Just two quick ones. Bill, I know last quarter you mentioned drilling wells on paper, so I guess the question is what will be done differently with this ramp in activity?

We've done and what we'll do is probably talk about a couple things. We've both drilled wells on paper and we're completing wells on paper. I'm going to have Jack talk to you about what we found in the studies, but certainly position our landing zone, frac loads, all that will come into play. Let me get Jack to give you some specifics.

Thank you, Bill. We went through, during the time we've been not drilling, we've gone through and we've reviewed all the drilling wells that we have done, especially recently. We've done a lot of collaboration within our Company and have shared a lot of ideas, things that have worked in West Virginia last year, are now being utilized in Appalachia.

One -- we've come up with ideas. One thing on this well we just recently drilled, we used a rotary steerable in Northeast PA, which we use regularly in Southwest Appalachia last year. That's one of the reasons we were able to get immediately back on curve. Everything didn't go perfect on that well but still we're right on pace with what we did in the past.

We've also looked add every one of our completions and have basically have gone to engineered completions as far as looking at how much is in the zone, completing it, completing the work that's in zone and have spent a lot of time looking at how we could -- more sand placement, we've gone that pretty much across the way. Our flow-back techniques of our wells we've evaluated what has worked best and what has not worked so well and we're going to implement those. That has been a focus for the last six months and we're already seeing results of it on our very first well we TDed Wednesday morning.

Great. My follow-up just maybe on 2017, Bill, and just the previous thought on staying kind of within cash flow or cash flow neutrality, is that still the goal as we think about how we should be forecasting CapEx for next year?

Yes.

Okay. Thank you.

Thank you.

Thank you. Our next question comes from the line of Subash Chandra with Guggenheim Securities. Please proceed with your question.

Good morning. When I think about how you're allocating capital with the big Northeast Marcellus emphasis, I'm trying to reconcile that with the PV10 values in the reserve report. It seems to rank Fayetteville at the highest and Northeast Marcellus second or third. Is it because the F&Ds are so much better in Northeast Marcellus that you earn your PVI threshold there versus Fayetteville?

Yes.

So when I think of the Fayetteville then, your leverage is in location is in the Fayetteville, whereas if we look at the price deck, you don't have that much leverage in terms of location in Northeast Marcellus. How do you think about -- what are the gating factors to really ramping up in the Fayetteville and why not -- and I'll leave it there.

This is Craig. I think the biggest gating factor, as Bill mentioned, certainly we're going to look at economics. Northeast, no secret, get bigger wells. Certainly Fayetteville continues to improve and we've got some things that we continue to test there in the second half of this year.

The pricing, that's one component. The size of the well and then just how we're driving cost through the system and Randy mentioned earlier. One thing he didn't specifically reference, but West Virginia as we get into Southwest Appalachia we had that liquids profile coming in as well. That certainly helps the economics and we've seen what pricing has done this year so far as well. We get it improved on the NGL side.

Okay. My follow-up, just on the CapEx, is so $700 million all-in including C&I for flat year over year. This might be an unfair question, but is there a way to sort of illustrate for every $100 million more in CapEx what kind of growth you might get?

Not yet. What we -- as we put together our budget later this year, we'll be able to talk about that. If you look at our guidance from last time, we've got sort of indicative numbers on production per rig making some assumptions on where they are and the speed at the time and we're back to kind of that speed or better. If you look back there, you can find it or Michael can get it for you.

We have that sort of benchmark data that we want to put together 2017. I wanted to connect a dot which was 2017 where we were three, six months ago and 2017 where we are now so that you could see the benefits rolling in from the investment we're making now when a large percentage of that production happens in 2017. It was appropriate for us to do that, but we're not far enough down the road on budget, and certainly our view of gas price, to set numbers for that in detail yet, but it will be forthcoming.

Great. Thank you.

You bet.

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

Thank you. Good morning.

Morning.

Good morning, Brian.

As to your PVI calculations, is there a base level of fixed costs in each of your three core areas in which the hurdle rates for, say, adding a rig or two are temporarily lower, or is the message that your hurdle rates to meet your PVI threshold are $2.70 to $2.80 gas?

Let me try to answer that. Craig may help me. When we do our economics for our wells, for drilling wells going forward, that perspective, we put all the costs in there. If you look at completing of wells that we're doing in this sort of reinitiation of completions, since those wells are already drilled and waiting on completions, those economics are point forward.

What we do is we take a look at the total cost in each of the three areas. We take a view, in this case, it's forward strip pricing, exclusive of any hedge benefits and then we run the economics straight up in the three areas and the wells -- when you're investing within cash flow and you have more projects than you can fund within cash flow, then you prioritize them from top to bottom and with the flexibility of our vertical integration, we can move that investment around.

If you see some kind of a change develop, obviously it's longer than a change in one day, but as you begin to see a trend, NGL prices begin to recover and stay there based on fundamentals you shift to liquids-rich drilling, that kind of thing. But yes, just compared straight up, heads up, all-in.

Brian, you mentioned $2.70, $2.80. That's true. That turns on -- a large part of our portfolio doesn't turn on every last well location we have at those price levels, so don't want to lead you down that path. But obviously depends on the production profile of the well and those wells as you go north are just stronger in general. Across the portfolio, $2.70 to $2.80 does turn on economic locations.

Great. Thanks. The follow-up is on the earlier question with regard to some of the paper drilling, the efficiency improvements on the completion front. Can you speak to what your expectations are for productivity gains, how much better well performance would look like in each of the areas you're applying some of the enhanced completions or other targeting technologies.

Let me try something on you from a fact base and then whether the projections forward apply to the whole Company or not, I think we're still working on that. If you go and look at wells that we drilled in the last 12 months in the West Virginia -- or excuse me, Southwest Appalachia area, and expertly managed prior to us coming there, a lot of focus on good operatorship, we came in with a different concept and we drilled and completed wells, a number of them, across the acreage.

We increased the sand loading substantially. We optimized where we landed the wells. In fact, we took the wells that were already drilled and drilled them on paper to figure out if you were going to redo it, how would you steer it. We used tools that weren't used on the first wells. We upped the sand loading considerably. We managed the flow back on those wells to increase condensate yield and the ultimate EURs. And we drilled those wells nearly or virtually 100% in the 15-foot targeted interval we had.

Long way of saying we had a different concept and the wells are 40% or more, more productive and better EURs than the ones that were there when we got there. So much so that when we could go back to our reserve auditors and explain to them what we were doing, that was a -- we wanted to test it all the way through the system. We are taking those learnings, applying them back into Pennsylvania and even into Fayetteville. There's no condensate yield or NGL yield in the other two divisions, so that part doesn't apply.

But hitting -- putting stronger metrics in for being in zone 100% of the time, changes in our sand loading, changes in our flow-back regime, elimination and debottlenecking of both the downhole equipment and surface facilities are producing better wells and those kind of learnings are what we've learned. Then we project those into our going-forward estimates where we can substantiate them.

Great. Thank you.

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

Good morning, guys, and thanks for taking my questions. You all have definitely a vertically integrated program on the services side. Listening to Schlumberger today on the services side, there's a lot of higher pricing going forward. What are your thoughts of cost per well per area, back half of the year. I know the $700 million budget is just an indication but whenever you think about that, do you have any sort of cost escalation in your concept?

Jack can kind of go into a couple of percentages. Let me just touch on a couple of things. As I said in my prepared remarks, we're going to economically evaluate our equipment and third parties, but directionally when I look at the drilling rigs, for example, our drilling rigs are hand built by us, in terms of picking all the pieces.

We've got extraordinary employees that are compensated as employees that are drilling these wells and doing an incredible job, so the likelihood of us using our own rigs to do that versus the cost of external rigs and the flexibility advantage we have by using our own, you put all that into economics and our costs on drilling should stay right where they are or continue to improve just because of our performance. On the completion side, there's a part of the equation that's really huge here and it's utilization and it is utilization in a place so that it becomes hyper efficient.

As we ramp up, and we're still working on this concept, by the way. As we ramp up at this first initial pace, the numbers of wells, the numbers of completions to keep something -- keep a team and a frac fleet, et cetera, fully utilized weigh heavily on the economic side. If you're using them half time, you've got to charge yourself quite a bit more. If you're not, if you're using them full-time, you can compete.

We can compete with anyone and we have. This transitional phase, we're working on it. I don't see any changes in our drilling side costs in terms of moving them up. We've worked with a lot of our suppliers and have put in place agreements for as long as 18 months to try to enable them to get back to work but enable us to save cost and keep our costs in check. Jack may have some specifics around completion but potential risk to it but --

Okay. Hello, David.

Morning.

The costs we're doing the work for, for the rest of this year is actually lower than it was when we were -- we suspended operations at the end of last year. But comparing back to when times were busy and we all expect as commodity prices get better we're going to get busier, last year we were doing work for about a third of -- 33% less than what the peak was. It is considerably less right now.

One of the reasons vertically integrated as Bill said about drilling rigs, we expect to use our drilling rigs with -- mainly, but on a pumping services side, that is something we consider is protection against those higher prices if they come that will be utilized in ours, again, with the utilization Bill mentioned as that goes. Our pumping services will be able to supplant if prices get out of hand. We think that's a little bit of a hedge that we're protected.

(Multiple speakers) flat to slightly lower near term.

Yes, sir.

Through 2017, so not a significant risk to us at this point.

What are the millions of dollars, Fayetteville, Northeast, Southwest, in your third-quarter expectations per well?

Well cost?

Yes, millions of dollars per well, just to put the benchmark of this is our expectation. You're down 33% from peak.

Total well costs for 7,500-foot lateral in Southwest Appalachia is right around $7.5 million, $8 million. Northeast is about $5.5 million. It's about a 5,500-foot lateral well. Fayetteville is right around $3 million.

Perfect. That's great.

Sure.

That's all I needed. Thanks, guys.

Sure.

Thank you. Our next question comes from the line of Jeffrey Campbell with Tuohy Brothers Investment Research. Please proceed with your question.

Can you hear me?

We can.

Okay. Great. Thank you. Sorry for the fumble there. First question I wanted to ask was just having taken out $700 million of debt recently, does debt reduction take a back seat to EBITDA growth in 2017 or is debt reduction still a significant concern in the shorter term?

Well, two things on that. Balance sheet is always a focus of ours and we'll continue to do so. The second part of that is we've addressed what he we wanted to address with 2018. The significant pay down, you mentioned the $700 million through the tender offer, takes that wall away from us. That's a significant accomplishment. Nothing that we feel like we have to do something immediately but we'll continue to look at the balance sheet, whether it's 2018 or any other debt that we have for pay down potentially.

A follow-on to that. It's part of our capital discussion and our 2017 budget discussion. We can have gas prices. We can hedge those gas prices. They can generate a set of cash flow.

The further dialogue that we want to have and will have is, out of that cash flow is that all drilling and completion? Is it part drilling and completion, part debt reduction? We know where we've just been, so we're going to look at the full dimension of that, and so a bit more time on the guidance for 2017 beyond the comparison of the $700 million that we put out. Part of it is looking at that balance sheet and continuing to evaluate that. Once we figure that out we'll put it out.

Thank you, I appreciate that. I'd like to approach some of the questions regarding the rigs in a slightly different way, but one that you've always been pretty consistent about. Slide 17 of the current corporate presentation shows that Southwest Appalachia has far more economic locations at $3 nat gas than the Fayetteville or Northeast Appalachia combined. I was wondering what are the drivers that are putting 60% of your rigs in those plays instead of more rigs into Southwest Appalachia?

One of the key drivers -- there's kind of a couple. One of the key drivers is the variability on liquids pricing and the assumptions that we make and then where we see the market. NGL pricing has been under quite a bit of pressure for the last many months. We are seeing fundamentals show us that there are more -- an uphill trend buoyed by specific fundamentals in each of the NGLs that enable us to see the opportunities to shift even on the fly from Northeast to West Virginia to capture that is available to us.

We had to have a starting point. We're seeing some of the available or the fundamentals that may shift that as we go through these drilling projects. The second part of it is our available wells to be able to be drilled in -- from a permit perspective. You keep an inventory of permitted wells in each area. You watch acreage expirations. You watch a number of things and so those are qualitative issues around the shift in economic -- or the specific economics.

I believe that when you look at the longer term drilling profile and you look at the pricing that we see, et cetera, more and more of our capital will go to the West Virginia area. Again, assuming that there's superior economics, which when as NGL pricing returns to some more -- a more market fundamentally based pricing regime, we expect that, that will happen. (Multiple speakers) all of that is there, so it's just really a matter of where do we get started and how do he we get started.

Another piece of this economics are, again, a big piece of this, we positioned rigs back in December, January in place much less some even on pads and so the initial drilling to complement the permits and the plans that were already there are the most efficient things to do as well.

The last point that you were making there late in that was that Southwest Appalachia has no infrastructure constraints. It's based on the permitting and the efficiencies and all that sort of thing.

That's correct.

Okay. Thanks very much. I appreciate it.

You bet.

Thank you. Our next question comes from the line of Jeoffrey Lambujon with Tudor, Pickering, Holt. Please proceed with your question.

Thanks. Good morning. Just a few on your DUC backlog here. In contrast to the allocation for rig adds, it looks like the Fayetteville is actually seeing the biggest blow down of DUCs, at least through the end of this year, just looking at the guidance for drilled wells versus completions. The Northeast in comparison looks to be building a bit potentially, or at least staying flat. Does that speak to your view on Northeast basis entering next year and can you talk about what that I have been other drivers for that DUC blow down allocation?

The key driver for DUCs, they're all economic, is the fact that unless something changes in our view in the Fayetteville, we're not going to put a number of rigs in Fayetteville. We're biased to the Northeast. Those are investments we've made that are waiting to capture the revenue associated with them. Bringing that inventory down as low as we can makes economic sense and it makes practical sense.

In the Northeast -- let me stop for a second and make one other comment relative to DUCs in general. We don't drill -- we don't have a DUC inventory for any other reason than to be efficient. We don't drill wells and hold them and wait on price or do any of that kind of stuff. So as we built this restart plan and we're looking towards the Northeast, we need a certain inventory of DUCs to be efficient.

The initial view was let's go to the Northeast. Let's do work there. In West Virginia we weren't going to do as many wells and so we could burn off some of our DUC inventory because we didn't need as many to be as efficient. And that is -- that variable moves around all the time. So it's an efficiency issue. It's a straight up economic issue.

In this case at this moment in time, with clearing up excess inventory, you'll recall we came to a very abrupt halt. As you work off that inventory and get it down to where it needs to be, that's why they came out the way they did and we've got about 100 across the Company and most of Fayetteville's will be done and many more West Virginias will be done and we'll have Fayettevilles' or excuse me, Appalachia's toward the end of the year. We end up at 60 or so by the end of the year.

Keep in mind, from an operational perspective, calendar years are only to do budgets. Operationally, we keep the machine flowing through the year. Part of our plan of this restart had 2017 in mind and, again, a continuous efficient, hyper efficient operating regime.

Understood. I know you guys just raised capital Here for the second part of the year but thinking beyond that, if commodity prices merited even more acceleration going into next year, mid next year, would that lead you to a similarly balanced approach in terms of blowing down a portion of your DUCs but also adding rigs?

Our plan next year as we get in the middle of next year if prices recover?

Exactly.

I think the flavor -- the flavor of -- a couple things, as I try to dissect the question. One, the statement I made before, DUCs are an efficiency improvement tool for us, more than a pile of a bunch of DUCs and wait for price to get better and then move them off. This initial phase of restart related to DUCs is just putting the house from an abrupt start into an efficient mode again. If we're not drilling a bunch of wells in a particular area, we don't need a bunch of DUCs and we can monetize those and get cash flow coming back quickly.

As we go into 2017, my guess from a drilling and completions kind of overall priority, it will be more what I would call normal. First of all, highly instructed by economics and differentials and cash flow. We'll invest within cash flow, as I said earlier. We'll prioritize where we go and you how we do it based off of a reasonably smooth development plan but one that is driven by economics and we will shore up our confidence in that you through a hedging program.

So you won't see some kind of opening like we're starting over in 2017 and doing a bunch of completions. You'll just see us trend through the rest of this year. They'll ebb and flow, but not by much and minus [30s] because we'll have cleaned that up by now.

Thank you.

Thank you. Our next question comes from the line of [Kashi Harisingh] with Simmons & Company. Please proceed with your question.

Good morning and thanks for taking my questions.

Good morning.

I was wondering if you could just provide some latest thoughts on the nat gas macro?

Sure. Randy?

Yes. I can give you a few thoughts. I think it's the fundamentals continue to show improvement. If you look at year-over-year changes on the demand side, we've seen just July year-over-year changes of plus 2.1 BCF a day. If you look at exports, combined LNG and exports to Mexico, up roughly 1.2 BCF a day. We see lower dry gas production year-over-year decline of about 1.5 BCF a day.

The macro fundamental outlook is certainly improving. We've certainly got less gas available to go into the ground. I think we'll see some very low injection numbers over the course of the next two to three weeks. The weather at least balance of the summer is looking like the heat is going to stay with us. I think overall from a macro standpoint balance of the year into 2017, it's a positive outlook.

Just one more from me. When we look at the presentation that shows the gross drilling locations of various commodity prices, so the economic hurdle rate embedded into that table in the presentation assumes the 1.3 times PVI, is that fair?

No, it's kind of a combination. I wouldn't say it's 1.3 across the board. Those are economics for the industry. Obviously, as Bill mentioned we use more stringent than 1.3 at current pricing. Especially as you get into across the board and the dynamics of Southwest Appalachia with NGL pricing, it is economic. It's economic 1.3 in most cases, just kind of depends on what the you view of the price is when that was run and when that table was put together.

NGL side, yes.

Well, thank you. That's it from me.

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

Good morning. I apologize if -- I don't think you've answered this yet. A lot has been asked, though. The comments specifically you put in the press release about the well performance in 2016, can you just give us more color on that as far as what's driving that versus your prior expectations? I'm talking about the guidance raise.

This is Jack. The primary driver between -- for our increased guidance and our increased performance of our production is we've worked very hard this year and last year at debottlenecking our gathering systems and working on compression and line loops and things like that. That's been a significant part in all of our fields.

The other thing we've done is it's, frankly, better well performance on wells drilled in late 2015. Part of the thing that Bill mentioned earlier about our managed drawdown of our West Virginia assets and those wells are just a shallower decline than what the previous wells have been and better performing at this point.

All right. That's helpful. That's all I've got. Thank you.

Thank you. Our next question comes from the line of Mike Kelly with Seaport Global. Please proceed with your question.

Hi, guys. Good morning. I was hoping to dive a little bit deeper into the depth of your Southwest Marcellus inventory, especially post the sale to Antero here. Your slide deck shows both 12 and 20 BCF type curves here. Really, I'm just curious if you could quantify how much of your acreage is truly core of the core here in your opinion and has this 20 BCF-plus potential. Thank you.

This is Paul. From the standpoint of the West Virginia land, while we were -- we were very pleased with that sale from a metrics standpoint at the time. We've got quite a bit of that inventory left. The way we think about that from an inventory standpoint is up in the Panhandle of West Virginia we've got very liquids-rich inventory that gives us an opportunity to access those in the case of positive NGL pricing.

From a portfolio standpoint over there on the Eastern side of that position, as you get into Marion/Mon type area, we've got the opportunity to develop dry Marcellus over there as a natural offset, as our Northeast PA is to NGL prices. Then across both of those positions you see that industry is aggressively proving that up for a very strong Utica development. That's the basis of those type curves.

Okay. In terms of if you had to break it down, though, is there a rule of thumb that you've got 200,000 net acres that could be 20-plus type? Really I guess I'm trying to get a sense of how much do you believe is probably as good as it gets in this portion of the play?

Both of those, like I mentioned, the Panhandle and that Eastern portion of that play are very strong as we see -- as you see by the IR materials on Southwest in the deck, as you move toward the very south of that position and toward the southeast of that position, they're lower recovery type curves and as to the Marcellus and as to the Utica, still a developing play within the industry.

Got it. Do you have an acreage number that you kind of peg to that or a location count? Maybe I'm missing a presentation here too. I'm going back to what's on the website. Just shows kind of the overall aggregate position there still --

I don't -- if you look from a May IR deck standpoint, probably the best source that you can get for that is we've got a solid [ogif] map there for the entirety of the position that I think you can use to scale that.

Yes, so about 200,000 roughly is in the core and we're derisking more of it as we continue to evaluate it, so that number is going up, not down.

Okay. Appreciate that. Then just wanted to follow up from me. This year the guidance for capitalized interest is $240 million to $250 million. What's a decent number to use for next year, just kind of ballpark as we try to back in to really kind of what's a D&C number versus that capitalized interest number as part of that $700 million all-in? Thanks.

Mike, this is Craig. I think you just kind of use that number as a starting point and take off the deleveraging that we've done and the interest impact. It's a little bit lower. Still a significant number is part of that D&C, or overall capital.

All right, appreciate it. Great update, guys.

Mike, that 200,000 is surface acres and remember it's a stacked play so there's opportunity for additional locations.

Understood. Thanks.

Thank you.

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

Morning. Thanks for taking my questions, guys.

Sure.

Was hoping if you have it handy, could you provide color on how you think your PDP decline's performing in 2016 on a percentage basis and how you see that evolving into 2017?

Yes, right now it's kind of running in the low 20%. It will be 19%, 18% next year if we didn't -- yes, for PDP.

Thank you. To your comment earlier now that you finished most of your goals for balance sheet clean-up, should we think about that then going forward? I know you said earlier that now sort of EBITDA growth is definitely a priority and the returns are compelling to do. If you were successful in any of the non-core divestitures that you still have pending, one, can you give us an update on how that process is going, and two, should we think of that incremental capital going towards some more rig activity?

First, activity. We've had some additional interest in some of that. Certainly as pricing continues to look strong, our view of -- and the Company's position continues to look strong, our view of what is attractive to us changes. I think as we -- should we get interest and as we get to a place where we are ready to transact or do transact, we'll put that out in the marketplace.

I don't have a specific goal that I'm -- to go and sell a certain number more. I think the market dictates that. As far as the if we transact one and sell anything, right now my position is that those funds go to pay down debt.

Probably -- this is Craig. As you know, our term loan that we have left, it's now pushed out to 2020, but it's wired such that asset sale proceeds go to that term loan. That's the term loan that went into effect in November of 2015.

Thanks for the color, guys.

Sure.

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

I want to say thank you to all of you for all the questions. I really appreciate it and the dialogue is good. We set out this year, as I said earlier, committed to strengthening our balance sheet, enhancing our margins, optimizing our portfolio. As you can see, and as we have demonstrated, we delivered on those commitments. I really believe we accomplished a tremendous amount in the first half of this year and we're all thrilled and excited to continue to do what we do best and that's create value plus for our shareholders.

We've got a premier quality set of assets, some very, very strong operational proficiency and we marry that with a disciplined capital approach and a focus on returns and so we're able to create tremendous value and deliver -- really deliver differentiating value. We've been through a lot in the first quarter and I'll express to my employees and our whole team our thanks because without them building that base, we wouldn't have been able to do all of the things that we've been able to do.

Our investors and banks and bond holders and all the other folks supported us along the way because we were in an early spot that was difficult in a terrible commodity price environment and they let us -- or supported us as we navigated forward, so I'm quite confident in a going-forward view. I'm looking forward to talking with you again about the different ways we continue to find to strengthen our Company and to take us forward in that value-adding growth. I want to thank each of you again and I hope you all have a great weekend. Thanks for your time.

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.