Jul 22, 2016
Executives
Michael Hancock - Director-Investor Relations William J. Way - President and Chief Executive Officer Robert Craig Owen - Senior Vice President and Chief Financial Officer John E.
Bergeron - Senior Vice President-E&P Operations Randy L. Curry - Senior Vice President, Midstream Paul W.
Geiger - Senior Vice President - Corporate Development
Analysts
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Charles A. Meade - Johnson Rice & Co.
LLC Holly Barrett Stewart - Scotia Howard Weil Subash Chandra - Guggenheim Securities LLC Brian Singer - Goldman Sachs & Co. David Martin Heikkinen - Heikkinen Energy Advisors LLC Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Kashy Harrison - Simmons & Company International David R. Tameron - Wells Fargo Securities LLC Michael Dugan Kelly - Seaport Global Securities LLC David A.
Deckelbaum - KeyBanc Capital Markets, Inc.
Operator
Greetings, and welcome to the Southwestern Energy Company Second Quarter 2016 Earnings Teleconference Call. At this time, all participants are in a listen-only mode.
A brief question-and-answer session will follow the formal presentation. In the interest of time, please limit yourself to two questions.
Afterwards, you may feel free to re-queue for additional questions. 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.
Michael Hancock - Director-Investor Relations
Thank you, Mellisa. Good morning, and thank all of 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 releases 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.
William J. Way - President and Chief Executive Officer
Thank you, Michael. Good morning, everyone.
Thanks for joining us 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 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 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 the 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 we halted drilling activities. We plan to add one to two rigs per month in the – across the company during the third quarter, demonstrating the speed and agility with which we can adjust our activity.
Our well costs will also 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 underway and the higher capital efficiency in our go-forward plans.
Let me be clear. We will not chase an economic 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'll 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.
Robert Craig Owen - Senior Vice President and Chief Financial Officer
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 ensure 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 impacts of our bank transactions with our $1.25 billion equity offering and successful debt repurchases 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've strengthened our balance sheet with these proactive steps, we are 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.
John E. Bergeron - Senior Vice President-E&P Operations
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 teams progressed 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.
Operator
Thank you. We will now be conducting a question-and-answer session.
Our first question comes from the line of Neal Dingmann with SunTrust. Please proceed with your question.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Morning, guys, and great turnaround. Say – Bill, maybe a question for you or 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?
William J. Way - President and Chief Executive Officer
I'll let Jack take that.
John E. Bergeron - Senior Vice President-E&P Operations
Okay. Well, we will – 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.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Okay. And then, just maybe just a follow up to that and my second question.
Just, Bill, for the Midstream maybe, just could you talk about just Midstream takeaway as it pertains down in that Southwest area? I know – again, you guys have built up down there, but I'm just wondering I guess as you get a little bit further down into West Virginia, any plans to build that out?
Or just if you could talk about sort of the infrastructure around that Southwest Appalachia area.
William J. Way - President and Chief Executive Officer
Yeah. And Randy can talk a little bit of detail on infrastructure, but as we said before, we took on some – our 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 run into constraints associated with takeaway. 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 takeaways, is there available gathering processing. And we assure ourselves that we have that route, all the way to the market before we drill.
But Randy's got some – probably some further details on the latest activity that we've been doing.
Randy L. Curry - Senior Vice President, Midstream
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.
And then 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 on our portfolio. We still have a good excess position forecasted right now, and just with the market where it is, and the anticipated build-out of that area in 2017 and 2018 respectively, we feel very confident of being able to get what we need out of there.
William J. Way - President and Chief Executive Officer
One of our benefits of the renegotiation of the Williams deal and we brought to the table was opportunity for them to be our gatherer for dry Utica gas in the same region. And that's provided us quite a bit of flexibility.
Our gatherers do a great job, are confident that 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. So as we test there and then test other areas that dry gas gathering system for Utica gets build out, we see a seamless progression from testing through to production.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
And just one last one if I could quick, maybe for Craig. Just that $700 million you said of D&C for CapEx for 2017, was that – is that flat year-over-year or flat exit-to-exit?
William J. Way - President and Chief Executive Officer
What we've 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.
And so as prices move around and we do our budgets, the opportunity – gas prices – $0.25 gas price moves cash flow $185 million. And so the opportunity to kind of evaluate that as we go forward is what we're up to now.
But we won't do – we'll do more work on our budget for 2017 later this year.
Neal D. Dingmann - SunTrust Robinson Humphrey, Inc.
Perfect. Thanks for all the details.
William J. Way - President and Chief Executive Officer
There's an improvement.
Operator
Thank you. Our next question comes from the line of Charles Meade with Johnson Rice.
Please proceed with your question.
Charles A. Meade - Johnson Rice & Co. LLC
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.
But 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? And then 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're going to be flat year-over-year, you'd actually probably have to resume growth quarter-over-quarter sequential growth sometime in early 2017.
Is that the right read on that?
William J. Way - President and Chief Executive Officer
Total capital number that I talk about and we do – internally, we look at it this way. That is all-in – all-in, so that's got C&I 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, a number of our DUCs and drilling new wells, we accelerate that progression or – or another way to look at it, you flatten out the trough of decline.
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've put out before which was at about $700 million instead of it being exit-to-exit is now full year-on-full year flat.
And so, you are correct as we enter the second half of next year, you get on that growth trend assuming that we – again, assuming that's – remember we haven't done our capital budget and we guided on that before, so we just wanted to make it – connect the dots for you.
Charles A. Meade - Johnson Rice & Co. LLC
Right. Thank you.
That's helpful detail, Bill. And then, can I 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 a case that – there's been 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, and are there any particular sensitivities we should be thinking about with respect to that?
Randy L. Curry - Senior Vice President, Midstream
Yeah, 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, we'll be adequate to continue to show some improvement in differentials over that timeframe.
Charles A. Meade - Johnson Rice & Co. LLC
That's helpful. Thank you.
Operator
Thank you. Our next question comes from the line of Holly Stewart with Scotia Howard Weil.
Please proceed with your question.
Holly Barrett Stewart - Scotia Howard Weil
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?
William J. Way - President and Chief Executive Officer
And we've done – and what we'll do is probably talk about a couple of things. We both drilled wells on paper and we're completing wells on paper.
And 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.
But let me get Jack to give you some specifics.
John E. Bergeron - Senior Vice President-E&P Operations
Thank you, Bill. We went further down 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 at – in West Virginia last year are now being utilized in Appalachia.
But 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 used regularly in Southwest Appalachia last year. That's one of the reasons we were able to immediately get back on curve.
Everything didn't go perfect on that well, but yet we still were right on pace with what we did in the past. We've also looked at every one of our completions that are 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 spend a lot of time looking 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. But we've – that has been a focus for the last six months and we're already seeing results of it on our very first well we TD'd Wednesday morning.
Holly Barrett Stewart - Scotia Howard Weil
Okay, great. And then 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?
William J. Way - President and Chief Executive Officer
Yes.
Holly Barrett Stewart - Scotia Howard Weil
Okay. Thank you.
William J. Way - President and Chief Executive Officer
Yeah. Thank you.
Operator
Thank you. Our next question comes from the line of Subash Chandra with Guggenheim Securities.
Please proceed with your question.
Subash Chandra - Guggenheim Securities LLC
Yeah, good morning. So when I think about how you're allocating capital with the big Northeast Marcellus emphasis, I'm trying to reconcile that with the PV-10 value over several quarters (24:02).
And it seems to rank Fayetteville at the highest and Northeast Marcellus second or third. Is it because the F&Ds are just so much better in Northeast Marcellus that you earn your PVI threshold there versus Fayetteville?
William J. Way - President and Chief Executive Officer
Yes.
Subash Chandra - Guggenheim Securities LLC
Okay. So when I think of the Fayetteville then, your leverage is in locations is in the Fayetteville, whereas if we look at the price tag, you don't have that much leverage in terms of location in Northeast Marcellus.
How do you think about – so what are the gating factors to really ramping up in the Fayetteville and why not – and I'll leave it there?
Robert Craig Owen - Senior Vice President and Chief Financial Officer
This is Craig. I think the biggest gating factor, as Bill mentioned, certainly, we look at economics.
Northeast, no secret, get bigger wells. Certainly, Fayetteville continues to improve and we've got some things that we – we will continue to test the second half this year.
But 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 the 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've improved on the NGL side.
Subash Chandra - Guggenheim Securities LLC
Okay. And 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?
William J. Way - President and Chief Executive Officer
Not yet. But 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. So if you look back there, you can find it or Michael can get it for you.
But we have that sort of benchmark data that we want to put together 2017. And I wanted to connect the dot which was 2017 where we were three months, 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 the 2017.
So it's 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'll be forthcoming.
Subash Chandra - Guggenheim Securities LLC
Great. Thank you.
William J. Way - President and Chief Executive Officer
You bet.
Operator
Thank you. Our next question comes from the line of Brian Singer with Goldman Sachs.
Please proceed with your question.
Brian Singer - Goldman Sachs & Co.
Thank you. Good morning.
William J. Way - President and Chief Executive Officer
Good morning.
Robert Craig Owen - Senior Vice President and Chief Financial Officer
Good morning, Brian.
Brian Singer - Goldman Sachs & Co.
I see your PVI calculations, is there a base level of fixed cost 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 $2.72 to $2.80 gas?
William J. Way - President and Chief Executive Officer
Let me try to answer that and Craig may help me. When we do our economics for our wells, for drilling wells going forward, that perspective, we put all the cost in there.
If you look at completing of wells that we're doing in this sort of re-initiation of completions, since those wells are already drilled and waiting on completion, those economics are pulling forward. But 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. So if you see some kind of a change develop, obviously, it's longer than a change of one day.
But as you begin to see a trend, NGL prices begin to recover and stay there based on fundamentals, you shift to liquid-rich drilling, that kind of thing. But yeah, it's compared straight up, heads up, all-in.
Robert Craig Owen - Senior Vice President and Chief Financial Officer
Yeah. And 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 it obviously depends on the production profile of the well. And those wells, as you go north, are just stronger in general.
But across the portfolio, $2.70 to $2.80 does turn on economic locations.
Brian Singer - Goldman Sachs & Co.
Great. Great, thanks.
And the follow-up is on the earlier question with regard to some of the paper drilling and 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?
William J. Way - President and Chief Executive Officer
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. But if you go and look at wells that we've 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've managed the flow-back on to 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. So a 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 reserves auditors and explain to them what we were doing, that was a – we wanted to test it all the way through the system. So we are taking those learnings, applying them back into Pennsylvania and even into Fayetteville.
There is 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 down-hole equipment and the surface facilities, are producing better wells.
And those kind of learnings are what we've learned. And then we project those into our going-forward estimates where we can substantiate them.
Brian Singer - Goldman Sachs & Co.
Great. Thank you.
Operator
Thank you. Our next question comes from the line of David Heikkinen with Heikkinen Energy Advisors.
Please proceed with your question.
David Martin Heikkinen - Heikkinen Energy Advisors LLC
Good morning, guys, and thanks for taking my questions. You all have definitely a vertically integrated program on the services side.
And listening to Schlumberger today in the services side, there is a thought of higher pricing going forward. What are your thoughts of kind of cost per well, per area, like back of the year?
And then 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?
William J. Way - President and Chief Executive Officer
Yeah, 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.
I mean, we – 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. And 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 in the economics, and our costs on drilling should stay right where they are or continue to improve just because of our own 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.
And as we ramp up – and we're still working on this concept, by the way – as we ramp up at this first initial phase, 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 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, so 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 further 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 cost in check.
Jack may have some specifics around completion and potential risk to it, but...
John E. Bergeron - Senior Vice President-E&P Operations
Okay. Hello, David.
David Martin Heikkinen - Heikkinen Energy Advisors LLC
Good morning.
John E. Bergeron - Senior Vice President-E&P Operations
The cost 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 those – 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 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 on ours, again with utilization Bill mentioned.
As that goes, our pumping services will be able to supplant if prices get out of hand, so we think that's a little bit of a hedge that we're protected. Currently...
William J. Way - President and Chief Executive Officer
So flat to slightly lower near term.
John E. Bergeron - Senior Vice President-E&P Operations
Yes, sir.
William J. Way - President and Chief Executive Officer
(36:25). So not a significant risk to us at this point.
David Martin Heikkinen - Heikkinen Energy Advisors LLC
What are the millions of dollars, Fayetteville, Northeast, Southwest in your third quarter expectations per well?
William J. Way - President and Chief Executive Officer
A well cost?
David Martin Heikkinen - Heikkinen Energy Advisors LLC
Yeah, just like millions of dollars per well, just to put the benchmark of like this is our expectation, you're down 33% from peak, just...
William J. Way - President and Chief Executive Officer
Yeah. Total well cost for a 7,500 foot lateral in Southwest Appalachia is right around $7.5 million, $8 million.
Northeast is about $5.5 million. It's quite a – it's about a 5,500 foot lateral well.
And Fayetteville is right around $3 million.
David Martin Heikkinen - Heikkinen Energy Advisors LLC
Perfect. That's great.
William J. Way - President and Chief Executive Officer
Sure.
David Martin Heikkinen - Heikkinen Energy Advisors LLC
That's all I needed. Thanks, guys.
William J. Way - President and Chief Executive Officer
Sure.
Operator
Thank you. Our next question comes from the line of Jeffrey Campbell with Tuohy Brothers Investment Research.
Please proceed with your question.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
Can you hear me?
William J. Way - President and Chief Executive Officer
Now we can.
Robert Craig Owen - Senior Vice President and Chief Financial Officer
Yeah.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
Okay, great. Thank you.
Sorry for the fumble there. The first question I wanted to ask was just having taken out $700 million of debt recently, does debt reduction take a backseat to EBITDA growth in 2017, or is debt reduction still a significant concern in the shorter term?
William J. Way - President and Chief Executive Officer
Well, two things on that. Balance sheet is always a focus of ours and will continue to do so.
But the second part of that is, we've addressed what 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. So 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.
Robert Craig Owen - Senior Vice President and Chief Financial Officer
And 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 that 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 whole dimension of that, and so a bit more time on the guidance for 2017 beyond the comparison of the $700 million that we've put out, part of it is looking at that balance sheet and continuing to evaluate them.
William J. Way - President and Chief Executive Officer
And once we've figured that out we'll put that out.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
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 your current Corporate Presentation shows that Southwest Appalachia is far more economic locations at $3 nat gas than the Fayetteville or Northeast Appalachia combined.
So I was wondering what are the drivers that are putting 60% of your rigs in those places instead of more rigs into Southwest Appalachia.
William J. Way - President and Chief Executive Officer
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.
And NGL pricing has been under quite a bit of pressure for the last any months. And 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.
So, we had to have a starting point. We're seeing some of the available – or the fundamentals that may shift at as we go through these drilling projects.
The second part of it is our available wells to be able to be drilled from a permit perspective. So, you keep an inventory of permitted wells in each area, you watch acreage explorations, 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 their superior economics when as NGL pricing returns to a more market fundamentally-based pricing regime, we expect that that will happen.
(41:35) all of that is there, so, it's just really a matter of where we get started and how we get started. Another piece of this, economics are, again, a big piece of this.
We positioned rigs back in December-January in place, left some even on pads. And so, the initial drilling to complement the permits and the plans that are already (42:06) are the most efficient things to do as well.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
Right. And the last point that you're 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 things.
William J. Way - President and Chief Executive Officer
That's correct.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc.
Okay. Thanks very much.
Appreciate it.
William J. Way - President and Chief Executive Officer
You bet.
Operator
Thank you. Our next question comes from the line of Jeoffrey Lambujon with Tudor, Pickering, Holt.
Please proceed with your question.
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Thanks. Good morning.
Just a few on your DUC backlog here. In contrast to the allocation for rig adds, it looks like the Fayetteville has actually seen the biggest blow down of DUCs at least at the end of this year, just looking at the guidance for drilled wells versus completions.
And Northeast, in comparison, looks to be building a bit potentially or at least staying flat. Does that features your Northeast base is entering next year, and can you talk about what may have been other drivers for that DUC blow down allocation?
William J. Way - President and Chief Executive Officer
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 in the Northeast.
Those are investments we've made that are waiting to capture the revenue associated with them. And so, 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 have a DUC inventory for any other reason than to be efficient.
We don't drill wells and hold them and wait on price for doing 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 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 variable moves around all the time.
And so, it's an efficiency issue. It's a straight-up economic issue.
But in this case, at this moment in time, with clearing up excess inventory, you recall we came to a very abrupt halt. And so, as you work off that inventory, 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 it, those will be done and many more West Virginia's will be done, and we'll have Fayetteville's or Appalachia's towards the end of the year, but we end up at 60 or so by the end of the year.
And keep in mind, from an operational perspective, calendar years are only to do budgets. Operationally, we keep the machine flowing through the year, and part of our plan of this restart had 2017 in mind and again a continuous efficient, hyper-efficient operating regime.
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Understood. And I know you guys just raised capital here for over the second part of the year, but thinking beyond that as commodity prices merited even more acceleration going into next year kind of mid next year.
Would that leave you then to have a similarly balanced approach in terms of blowing down portion of DUCs but also adding rigs?
William J. Way - President and Chief Executive Officer
Talking about our plan next year, as we get into middle of next year, prices recover?
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Yeah, exactly.
William J. Way - President and Chief Executive Officer
I think 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 pile up a bunch DUCs and wait for price to get better and then move them all.
So, 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 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 through a hedging program.
And 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.
So, it will ebb and flow but not by plus and minus 30s because we'll have cleaned it up by then.
Jeoffrey Restituto Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc.
Thank you.
Operator
Thank you. Our next question comes from the line of Kashy Harrison with Simmons & Company.
Please proceed with your question.
Kashy Harrison - Simmons & Company International
Hi. Good morning, and thanks for taking my questions.
William J. Way - President and Chief Executive Officer
Good morning.
Kashy Harrison - Simmons & Company International
I was wondering if you could just provide some latest thoughts on the nat gas macro.
William J. Way - President and Chief Executive Officer
Sure. Randy?
Randy L. Curry - Senior Vice President, Midstream
Yeah. I'll 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.
You look at exports combined, LNG and exports to Mexico, up roughly 1.2 Bcf a day. And we see lower dry gas production year-over-year decline of about 1.5 Bcf a day.
So, 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 weeks to three weeks. The weather, at least balance the summer, is looking like the heat is going to stay with us.
So, I think overall from a macro standpoint, balance of the year into 2017, it's a positive outlook.
Kashy Harrison - Simmons & Company International
And just one more for me, when we look at the presentation that shows the gross drilling locations at various commodity prices. So, the economic hurdle rate embedded into that table in the presentation assumes the 1.3 times PVI, is that fair?
Robert Craig Owen - Senior Vice President and Chief Financial Officer
No. It's kind of a combination.
I wouldn't say it's 1.3 times across the board. Those are economics for the industry.
Obviously, as Bill mentioned, we use more stringent than 1.3 times at the current pricing. But 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 times in most cases, just kind of depends on what the view of the price is when that was run and when that table was put together.
William J. Way - President and Chief Executive Officer
NGL side, yeah.
Kashy Harrison - Simmons & Company International
Well, thank you. That's it for me.
Operator
Thank you. Our next question comes from the line of David Tameron with Wells Fargo.
Please proceed with your question.
David R. Tameron - Wells Fargo Securities LLC
Good morning. And I apologize – I don't think you've answered this yet, a lot have been asked though.
The comment specifically from 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? And I'm talking about the guidance raise.
John E. Bergeron - Senior Vice President-E&P Operations
Yeah. This is Jack.
The primary driver for our increased guidance and our increased performance of our production is, we've worked very hard this year and last year at de-bottlenecking our gathering systems, and working on compression and line loops and things like that. That's 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. Those wells are just a shallower decline than what the previous wells had been, and better performing at this point.
David R. Tameron - Wells Fargo Securities LLC
All right. That's helpful.
That's all I've got. Thank you.
William J. Way - President and Chief Executive Officer
Thank you.
Operator
Thank you. Our next question comes from the line of Mike Kelly with Seaport Global.
Please proceed with your question.
Michael Dugan Kelly - Seaport Global Securities LLC
Hi, guys. Good morning.
William J. Way - President and Chief Executive Officer
Hi.
Michael Dugan Kelly - Seaport Global Securities LLC
I was hoping we could 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 Bcf and 20 Bcf type curves here, and really I'm just curious if you could quantify how much your acreage is truly core of the core here in your opinion and has this 20 Bcf-plus potential.
Thank you.
Paul W. Geiger - Senior Vice President - Corporate Development
Sure. This is Paul.
From a standpoint of West Virginia land, while we were very pleased with that sale from a metric standpoint at the time, we've got quite a bit of that inventory left. And 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 (52:33) type area, we've got the opportunity to develop dry Marcellus over there as a natural offset, as our Northeast VA (52:43) is to NGL prices. And then across both of those positions, you see that industry is aggressively proving that up for very strong Utica development.
So that's the basis of those type curves.
Michael Dugan Kelly - Seaport Global Securities LLC
Okay. In terms of – if you had to break it down, is there a rule of thumb that you've got 200,000 net acres that could be 20-plus type, it's really – I guess, I'm trying to get sense of how much do you believe is probably as good as it gets in this portion of the play?
William J. Way - President and Chief Executive Officer
Both of those, like I mentioned, the panhandle and the eastern portion of that player, are very strong. As you see, in the IR materials on southwest in the deck, as you move towards the very south of that position and towards the southeast of that position, their lower recovery type curves as to the Marcellus and as to the Utica are still developing play within the industry.
Michael Dugan Kelly - Seaport Global Securities LLC
Got it. Do you have an acreage number that you could kind of peg to that or a location count or maybe I'm missing the presentation here too.
I'm going back to what's on the website just shows kind of the overall aggregate position there still at...
William J. Way - President and Chief Executive Officer
No, I don't. If you look from a May IR deck standpoint, probably the best source that you can give for that is, we've got a solid OGF map there for the entirety of the position that I think you could use to scale that.
Randy L. Curry - Senior Vice President, Midstream
Yeah. And so about 200,000 roughly is in the core, and we're de-risking more of it as we continue to evaluate it.
So that number is going up, not down.
Michael Dugan Kelly - Seaport Global Securities LLC
Okay. Appreciate that.
And I just – one follow-up for 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 into really kind of what's a D&C number versus that capitalized interest number as part of that $700 million all in?
Thanks.
Robert Craig Owen - Senior Vice President and Chief Financial Officer
Yeah. 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 in the interest impact. It's a little bit lower.
There's still a significant number as part of that D&C on our overall capital.
Michael Dugan Kelly - Seaport Global Securities LLC
All right. I appreciate it.
Good update, guys.
William J. Way - President and Chief Executive Officer
And Mike, that 200,000 is surplus acres and, remember, it's a stacked play, so there's an opportunity for additional locations.
Michael Dugan Kelly - Seaport Global Securities LLC
Understood. Thanks.
William J. Way - President and Chief Executive Officer
Thank you.
Operator
Thank you. Our next question comes from the line of David Deckelbaum with KeyBanc Capital Markets.
Please proceed with your question.
David A. Deckelbaum - KeyBanc Capital Markets, Inc.
Good morning. Thanks for taking my questions, guys.
William J. Way - President and Chief Executive Officer
Sure.
David A. Deckelbaum - KeyBanc Capital Markets, Inc.
I was hoping, if you have it handy, could you provide a color on how you think your PDP decline is performing in 2016 on a percentage basis and how you see that evolving into 2017?
William J. Way - President and Chief Executive Officer
Yeah. Right now, it's kind of running in the low-20%, and it'll be 19%,18% next year if we didn't – yeah, for PDP.
David A. Deckelbaum - KeyBanc Capital Markets, Inc.
Thank you. And then, to your comment earlier that you've 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 so. 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?
William J. Way - President and Chief Executive Officer
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. And so, I think, as we – should we get interest and as we get to the place where we are ready to transact or do transact, we'll put that on the marketplace.
I don't have a specific goal to go and sell a certain number or 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.
Robert Craig Owen - Senior Vice President and Chief Financial Officer
This is Craig. As you know, the term loan that we have left, it's now pushed out to 2020, but it's wired such that assets and proceeds go to that term loan.
That's the term loan that went into effect in November 2015.
David A. Deckelbaum - KeyBanc Capital Markets, Inc.
Thanks for the color, guys.
William J. Way - President and Chief Executive Officer
Sure.
Operator
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.
William J. Way - President and Chief Executive Officer
I want to say thank you to all of you for all the questions. I really appreciate, and then the dialogue is good.
We set out this year, as I've said earlier, committed to strengthening our balance sheet, enhancing our margins, optimizing our portfolio. And as you can see, and as we have demonstrated, we delivered on those commitments.
And I really believe we've accomplished a tremendous amount in the first half 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've married that with a disciplined capital approach and a focus on returns. And so we're able to create tremendous value, and 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 the things that we've been able to do. Our investors and banks and bondholders and all of the other folks supported this 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 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.
And so, I want to thank each of you again, and I hope you all have a great weekend. Thanks for your time.
Operator
Thank you. This concludes today's teleconference.
You may disconnect your lines at this time. Thank you for your participation.