Oct 21, 2016
Executives
Michael Hancock - Director, IR William Way - President and CEO Robert Craig Owen - SVP and CFO John Bergeron - SVP, E&P Operations Randy Curry - SVP, Midstream
Analysts
Scott Hanold - RBC Capital Markets Doug Leggate - Bank of America Merrill Lynch Charles Meade - Johnson Rice & Co. LLC Drew Venke - Morgan Stanley Holly Stewart - Scotia Howard Weil Brian Singer - Goldman Sachs & Co.
Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. Kashy Harrison - Simmons & Company International David Tameron - Wells Fargo Securities LLC David Deckelbaum - KeyBanc Capital Markets, Inc.
Operator
Greetings, and welcome to Southwestern Energy Company Third 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. [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.
Michael Hancock
Thank you, Doug. Good morning and thank you for joining us today.
With me today, are Bill Way, our President and Chief Executive Officer; Craig Owen, our Chief Financial Officer; Randy Curry, our Senior Vice President of Midstream; Jack Bergeron, our Senior Vice President of Operations; and Paul Geiger, Senior Vice President of Corporate Development. If you've not received a copy of last night’s press releases regarding our third quarter 2016 financial and operating results, you can find a copy on our website at swn.com.
Also, I’d like to point out that many of the comments during this teleconference are forward-looking statements that involve risks and uncertainties affecting outcomes, many of these are beyond our control and are discussed in more detail in the risk factors and the forward-looking statements sections of our annual and quarterly filings with the Securities and Exchange Commission. Although, we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and actual results or developments may differ materially.
We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers. For any non-GAAP measures, we use a reconciliation to the nearest corresponding GAAP measure, which can be found our earnings release available on our website.
I’ll now turn the call over to Bill Way to discuss our recent activity and results.
William Way
Thanks, Michael, and good morning, everyone. And thank you for joining us on our call today.
This year has been more on the un-laboring focus since win [ph] and that focuses on our commitments that we laid out in February namely to strengthen our balance sheet, aggressively improve margin, optimize the portfolio and remain agile enabling us to be ready to capture opportunities to add value as the commodity price environment improves. And we're delighted to be here today to talk with you about this and to talk about another quarter in which we delivered on those commitments.
I'd like to start by thanking the Southwestern team for all that has been accomplished so far this year. We've tackled a number of different challenges and set the company up for significant value creation as we finish up 2016 and prepare to move on to 2017.
This year's accomplishments are a direct reflection of the commitment and dedication that each employee brings to the work every day and I commend you for all that you do and all that you've done. When we spoke in the last quarter, we discussed our plans to reinitiate investment in drilling and completion activities as a result of our strengthened balance sheet, the improving commodity price environment and our ability to assure solid returns provided by our commitment to prudent [ph] hedging and disciplined risk management.
We'll provide more details about this in a few minutes, however I can tell you that the learning, planning and preparation that each of the team is focused on during the pause in drilling and completions activity resulted in an extremely successful re-initiation of our drilling and completion operations. As expected, we now have five rigs running company-wide, two in Northeast Appalachia, two in Southwest Appalachia, and one in Fayetteville.
The drilling results have been better than expected as we've seen record performance in drilling times that are even better that when we halted activity at the end of 2015. However, speed is only part of the story.
We've also been able to stay within our targeted zone over 95% of the time, which can be as narrow as 10-feet. Steering the well fully in zones supports the completion optimization by placing the entire length of the lateral in the interval that is most favorable for fracture stimulation and initiation.
These impressive results have been driven by the learnings we captured from drilling and completing wells on paper during the first half of the year and applying these learnings now as we resume activity. Additionally, the utilization of technology such as rotary steerable tools and other technologies are now standard on many of our wells.
The activity in the second half of this year primes the portfolio for our robust 2017. Regarding 2017, while we have not approved next year's capital program at current strip prices, we expect cash flow to be in excess of $1 billion.
We've had some questions on maintenance capital for next year, so let me reconfirm that the maintenance capital required to hold 2017 annual volumes flat at 2016 levels is only $700 million given our improved capital efficiency and the benefits of flowing from our recent restart activity of approximately 150 Bcf equivalent of incremental 2017 production from the wells that we are drilling and completing during the second half of this year. With this quarter's impressive restart of activity, we also fully expect to rest [ph] our production decline by the end of the year, this year of 2016.
After which we will be back on the growth trajectory. Reduced overall decline and resumption of value added growth are both the results of our work to improve the performance of our vast portfolio.
This $700 million in maintenance capital is in all-in capital number including capitalized interest and expenses. Closing this part of the discussion while the maintenance capital is approximately $700 million, this is well below the expected more than $1 billion in cash flow for 2017 that I mentioned earlier at current strip prices.
We planned to watch the impacts of the winter weather on 2017 prices and issue public guidance in February. Let me now move onto our marketing and commercial activities.
As this historically the case, we experience our widest differentials for the year in the third quarter. Our overall discount inclusive of differentials and transport cost was a $1.03 per Mcf lower than average NYMEX settlement pricing compared to a $1 per Mcf lower than average NYMEX settlement pricing during the third quarter of 2015.
This slight widening of the 2016 quarter was influenced largely by regional storage levels being at or near capacity and the percentage of total production from our Northeast assets increasing versus guidance. Factoring in the forecasted gains of approximately $0.03 per Mcf on basis hedges currently in place, the company anticipates its total company discount to NYMEX for the year will be at the high end of guidance range or about $0.83 per Mcf.
We do believe that the current challenges facing the Appalachian basin are a short-term issue. And that the quality and quantity of our transportation portfolio in our Appalachian basin businesses is robust and allows us both strong access to markets and growth opportunities this year and beyond.
Over the long-term, our view on improving regional basis to differentials has not changed. And we expect the projected capacity additions out of the greater Appalachian region to come on line over the next few years.
These pipeline projects have robust economics and are of high quality and we remain confident that the capacity from these pipeline projects gets over built albeit not without some scheduling challenges on individual projects. Lastly, we are encouraged by the strengthening of NGL pricing for 2016 and how the NGL demand picture particularly ethane seems to be shaping up over the next few years.
Given the Swin [ph] capacity on ATEC [ph], we are in a strong position to capitalize on rising ethane prices at Mont Belvieu as projects making up the estimated 620,000 barrels a day of new demand begin to come online, between now and 2019. With our vast resource position and the optionality provided by the wet gas window of Southwest Appalachia increased NGL prices materially enhanced the margins provided from that area.
With that, let me turn over to Craig to discuss some of our financial highlights from the third quarter and then will have Jack talk a bit more about some operations.
Robert Craig Owen
Thanks, Bill, and good morning, everyone. I thought I would start this morning by summarizing the steps we have taken to strengthen the balance sheet this year since many of them were in progress at the end of the second quarter.
In the third quarter, we completed the equity offering for $1.25 billion, of which a portion was used to retire $700 million in 2018 debt maturities with $500 million earmarked for a resumption of drilling and completion activities. Additionally, in the third quarter, we closed the previously announced acreage divestiture in Southwest Appalachia.
As you saw on last night's release, net debt as of September 30th, it was $3.2 billion, down from $4.8 billion at the end of the second quarter. And as a reminder, when we amended the bank agreement, it structure change from our historical revolving credit facility.
The new credit facility is supplemented by the fully drawn $1.2 billion secured term loan, which we expect to utilize for liquidity purposes and results in large cash balances going forward compared to our historical amounts. We have made great strides to strengthen the balance sheet this year and expect net debt to EBITDA for 2017 to be in the high twos assuming current price levels.
With these actions and the improved commodity price environment, we are confident in our trajectory and therefore have no other asset sale plans eminent or of a material nature. In the normal course, we will continue to evaluate options and opportunities, but are confident with our portfolio and balance sheet where it stands today.
In the third quarter, we continue to add to hedge position. We have now hedged 535 Bcf excuse me of 2017 production, of which approximately half of these positions are colors providing upside exposure to improving prices.
On these 2017 hedges, we have a weighted average strike price for the swaps and purchase puts of $3 per Mcf. We have also been actively adding financial and physical basis hedges to the portfolio, where we currently have 75 Bcf protected in the fourth quarter and 196 Bcf protected in 2017.
These hedging activities will help us achieve our expected returns providing downside protection, while also retaining upside potential as prices improve. With the financial strengthening steps taken in 2016, we are now positioned to drive value generation with our premier assets.
I will now turn it over to Jack to discuss some of the details of our operational results from the third quarter.
John Bergeron
Thanks, Craig. Good morning, everyone.
As Bill mentioned earlier, we have successfully reinitiated our drilling completion activities, which was a primary focus to the third quarter for operations. It’s not often that you complete the half drilling and completion works for six months and then ramp up to five rigs in such a short period of time as we have this year.
The success of this resumption demonstrates our differentiating agility as a company. While returning the drilling and completions, we did not lose sight of the importance of our 2016 strategic initiatives eminent by once again hitting the top end of our production guidance at 211 Bcfe, while continuing our focus on improving margins.
In particular, we've reduced our lease operating expenses on a unit of production basis for the fifth quarter in a row. In each of our areas, we continue to push the boundaries of our completion design.
We are expanding with the increased proppant volumes with test in Southwest Appalachia reaching up to 5,000 pounds per foot. We are also challenging ourselves to find the technical limits of these solutions with such a vast number of drilling locations in the area determining the optimal proppant loading will significantly increase the value of this play.
Our proppant testing is not just limited to Southwest Appalachia. We are also testing this in each of our other operating areas.
In Fayetteville, we are testing over two times as much proppant as our historical averages were. We expect to have some preliminary results on our next call, but the early indications are promising.
In Southwest Appalachia, we completed eight wells in the third quarter and planned to connect nine wells to sales by prior to the end of the year. While we do not turn on any wells to sales from the third quarter we continue to see strong well performance from our Ridgetop Land Venture pad in Wetzel County, which came online in the fourth quarter of 2015.
As a result, we have increased our lean gas type curve for the second time this year to approximately 25 Bcfe based on 7500 foot laterals. The well that we have drilled and completed they continue to outperform the offset wells drilled by the previous operator by as much as 40%.
As we look forward, this asset provides substantial optionality where capital could be allocated to the wet or dry gas targets depending on commodity prices. Moving to Northeast Appalachia, we currently have two rigs running which were the first two rigs to be mobilized.
As Bill mentioned, the preparation for the re-initiation of activity resulted in some exceptional accomplishments. For the quarter, we have achieved a record total drill depth time of less than eight days from reentry to reentry, which is 5% faster than the fourth quarter of 2015.
Included in these results was one well that drilled over 4,700 foot of lateral in just 24 hours, a company record in the area. On the completion side, we have tested reduced cluster spacing to increase well performance.
This when coupled with the optimized flow techniques, we are using expect to materially improve the flow rate. For example, the Racine pad, we brought on in Susquehanna County this quarter came online at greater than 50 million cubic feet a day from just three wells planned to continue these techniques in the fourth quarter and we will discuss further as we get more information.
Moving to Fayetteville. We hit a very big milestone there during the third quarter, where we surpassed 5 trillion cubic feet of production since our inception in 2004.
Even with the recent reduction in rig count, this place still produces approximately 2% of the nation’s gas supply and contributed over $60 million to the company in cash flow in the third quarter. We continue our testing efforts in Fayetteville during the quarter on the Moorefield Shale, which lies just below the Fayetteville Shale.
We brought online one Moorefield well at the end of June that had an initial production rate of 6.2 million cubic feet of gas per day, the lateral length of approximately 7,300 feet and an estimated EUR of over 4 Bcf. This continues the encouraging results we have seen since the beginning of 2015.
The seven Moorefield wells brought online since the beginning of the year in ‘15 averaged an initial production rate of 7.2 million cubic feet a day, a lateral length of approximately 6,950 feet and an estimated of EUR of over 5 Bcfe. We will continue watching the long-term performance of these wells and determine the aerial expand of the acreage prospective for this interval.
With the potential of the Moorefield and the impact of increased proppant loading in the Fayetteville that we discussed earlier, we are encouraged that these along with other initiatives being tested in the play could significantly lower the breakeven price for the play and help it compete with opportunities available in our Appalachia portion of the portfolio. This concludes today’s prepared comments.
So, we'll now turn it back to the operator, who will explain the procedure for asking questions.
Operator
Thank you, [Operator Instructions]. As a reminder, in the interest of time, please limit yourself to two questions, and afterward you may feel free to re-queue for any additional questions.
Our first question comes from the line of Scott Hanold, from RBC Capital Markets. Please proceed with your question.
Scott Hanold
Thanks. Good morning, guys.
William Way
Good morning, Scott.
Scott Hanold
You know, you all talked about the $700 million to maintain production in 2016 to 2017. Could you give us a sense of, what rig count came into that, is that currently the five rigs you're at or would that require additional activity and the - I guess the follow-up question to that, is based on the hedges you all have in place which gives you, I guess all of the - a fair decent certainty in terms of pricing next year.
What is your view on adding to your current rig count and when could that occur?
John Bergeron
This is Jack. Thanks for the question.
As far as rig counts for the $700 million of maintenance capital, that would be less rigs that we’re running today, that would be right around 3 rigs, maybe 3.5 rigs for the year.
William Way
Capital efficiencies has gone up as we drill more and more in the Northeast and so we are able to do more and more with fewer rigs and I think well count becomes that probably the key question. As you look at our hedges and Randy can talk a little bit about it, but as you look at our hedge positions, as we look at our capital program, we feel very assured on delivering value that we need, as our capital, as we look at gas prices and we see they increased further than they are than we will make some adjustments to our plans at that time and our objective is to invest within cash flow as that cash flow changes or rises it gives us this option is to move forward.
The rigs - our rigs were very flexible in terms of what we can turn on and turn off, and so we can be very agile in that view as we get closer to February.
Scott Hanold
Okay, I know and I appreciate, I turn the front end of your guidance. So maybe the better question I should ask more specific to that is at the current 5 rig count what is that imply for annualized CapEx?
William Way
Around $900 million, give or take.
Scott Hanold
Okay, so just a bit under the billion plus dollar cash flow number you talked about for next year.
William Way
Well, again, we haven’t set our 2017 plan, might only reason for bringing up to $700 million, two points, one, just to make sure people understood that point and there is a good amount of upside we’re returning back to flat production using that just maintenance capital and then we’ll analyze and look at the markets as we approve our budget and again, look for opportunities to either go faster or drill more as economics and cash flow moving forward.
Scott Hanold
Appreciate the color. Thanks, guys.
Operator
Our next question comes from the line of Doug Leggate from Bank of America Merrill Lynch. Please proceed with your question.
Doug Leggate
Thank you. Good morning, everybody.
Good morning, Bill.
William Way
Hey Doug, how are you?
Doug Leggate
Good, thank you. I appreciate all the information this morning.
On the cash flow, breakeven, I wanted if I could just ask you talked about a strip, what’s your outlook for differentials as baked into that number?
Randy Curry
Yeah Doug, this is Randy Curry. The differential outlook, we remain very positive on the structural improvement and differentials over the long-term in spite of the recent headwinds, some of the projects that were going to be coming online in 2017 are facing, we do believe that it’s a question of when not if.
And so, right now our differentials for 2017 or at the strip levels and the strip is also indicating out in the future 2018 and 2019 some structural improvement and that’s consistent with what we’re modeling.
Doug Leggate
Okay, I appreciate. I guess my follow-up is may not be too easy to answer I guess, I am going to have a go anyway.
Just there has been a lot of changes with things that obviously, your proppant loading, your efficiency gains, your cost reductions and everything else. Is it possible to give us kind of an update as to where you see breakevens across your three core plays at this point?
Just to help us a little bit as to how the economics look and I'll leave it there, thanks.
John Bergeron
Yeah, I think if you look at Marcellus and these numbers probably don't have all of the improvements and we're working on that. But Marcellus economic wells are 260-263 kind of range on pricing that’s a 10% kind of return.
West Virginia is probably dry as probably 250. I don't have a way one with a newer kind of outlook on gas pricing we can get that to you, I mean not gas pricing, but ethane improvements.
But the portfolio looks very positive for opportunities to invest and make the returns we need in that range. If you look at 1.3 PVI numbers, and they're probably in the 280s to 290s for each of those two areas.
Doug Leggate
And Fayetteville.
Robert Craig Owen
Doug, this is Craig. In Fayetteville, it kind of follow-up on Bill's note or Bill's comments.
Fayetteville certainly at current prices with the high 17 certainly looks good. What we're seeing in these early results, we talked about these IPs and certainly testing Moorefield continues to push that breakeven down.
But as we've kind of seen - we've kind of layout based on historical results in our IR deck. Fayetteville at $3 flat gives you about 500 well locations.
So, you can maybe push that a little bit lower and certainly with new results can continue to push. And that really kind of goes with all locations as we continue to drive cost out of the system in improved production rates or EURs that helps.
But the numbers Bill quoted are Appalachian assets is fair.
Doug Leggate
That’s great, it's really helpful guys. Thank you.
William Way
And I'll comment we have just one more thing on that, in the Fayetteville, we're doing some Moorefield drilling right now. We don't have - the results are kind of early days, but those wells are coming on quite strong.
So, they have their economics are very solid. We're not doing anything that doesn't meet our 1.3 PVI investment hurdle at strip pricing and that's excluding any hedge benefit.
So, you can kind of see that in each of the three areas there are some depth and some good depth in terms of well locations available to pursue.
Operator
Our next question comes from the line of Charles Meade with Johnson Rice. Please proceed with your question.
Charles Meade
Good morning, Bill and to the rest of your team there.
William Way
Good morning.
Charles Meade
I wanted to ask a question about your completion pace here. One of the things, I was struck by was the uptake in plant completions to left 52 in Q4 from nine in Q3.
Can you talk about what the pattern of that - of those completions will be over the fourth quarter? It's going to be flat over - across the months and weeks of the quarter or you were perhaps weighted towards the backend with the aim of capturing better local pricing.
And what does that mean for your, or do you have as you can share with us for your '16 exit rate?
William Way
Let me talk a little bit about the pace of what we're doing and then I'll do some exit rate stuff. There is a combination of things that work here.
We've restarted the activity; we want to be as efficient [ph] as we can. And so really most of the completions in the fourth quarter will come across fairly ratably.
We expect that we will do; our objective is to complete all the decks or as many decks as we can out of Fayetteville. And then in each of the other two assets retain a level of decks only for efficiency.
We don't - when we halted activities at the end of the year, first part of this year, we had a duct inventory. We then restarted that's all going fine and we're just working them all.
Since we don't anticipate a large amount of drilling in Fayetteville, we don’t need a large amount of inventory and so you get those to market and begin to get returns on those. In the other two areas, you are going to be focused on capturing those that you can get to market in an efficient and timely manner to capitalize on those rising prices, while retaining enough that we can be efficient with our plan and so, I think at the end of the day, you will see it ratably across the year.
And on volume what was your question on volume.
Charles Meade
Just what implications that would have for exit rate on ‘16?
Robert Craig Owen
We are looking at above 2.2 to 2.3 Bcf per day equivalent exit rate and as far as the fracture the level of compilations, we're currently running five completion frac crews. We may pick up a 6, but it’s - we are very smooth and just continuous operations, the only thing that impacts it vis-a-vis we don’t have a little faster paces, water availability in Pennsylvania and it comes and goes they have been getting a lot of rain up there right now, so, we don’t foresee a problem.
Charles Meade
Got it. Thank you.
And then my follow-up question and Bill, I apologize if this is pushing too far into your 2017, so I guess the reflected part of the question, but as you look ahead to 2017, I know you are going to work down your duct inventory, it looks like by 2016 in Q4 and then you say you will be back to your target of that 60% inventory that you need for efficiency, in 2017. So, that implies you are going to work down your duct inventory by another roughly 25 or over the course of the year.
What compared to the 52 completions you are going to have in Q4, what do you think your completion rate per quarters going to look like in 2017?
William Way
You're right. We will get those inventories to where they're efficient.
The completion inventory in 2017 will be directly related to what our capital budget looks like. And we haven’t done that yet, so, we're doing scenario planning around that now.
We want to remain flexible between the two divisions up in the North East and so as that - our duct inventory, our rate of burn off decks, our timing of wells and completions. The underlying theme will be - it will be as efficient as we can to drive higher margin through lower cost and improved well performance and it'll be the makeup of that will be part of our capital plan.
Charles Meade
Thank you for the color.
William Way
Yes.
Operator
Our next question comes from the line of Holly Stewart with Scotia Howard Weil. Please proceed with your question.
Holly Stewart
Thank you. Good morning, gentlemen.
William Way
Hi, Holly.
Holly Stewart
Just quickly maybe following up on Charles question a little bit, how I mean I guess could you just talk through, how you're viewing the ramp process so far versus your expectations, it looks like duct count now versus I guess the slide deck is a little higher and the wells turned to sales projection for the years a little bit, I guess year-to-date is not right on par with the forecast. So just trying get a good sense for how you think it’s going and maybe if to see expectations here, as you work through the fourth quarter?
William Way
Sure, yes. The headline is going terrific remember there is two components to this.
First component on the fracture stimulation side is we want to be as efficient as we can and we want to get the account to where it optimally suits our budget. The second thing that we talked about and this is critical is the frac intensity or the testing that's going on, on some of these wells.
We're ramping sand loading in a couple of cases from a 1000 to 2000 pounds from 2000 to 5000 pounds of foot and so those - that testing impact some of these wells and to put that much more sand and that many more stages into a well takes longer to do, and so the only issue that we have right now and it's not really an issue, I miss called it, it's an opportunity as we are doing some testing related to higher sand loading which will have positive effects, we expect on our wells. We’ve already seen that in West Virginia, where we’ve gone up above two to almost 3000 pounds in wells that are already online and that combined with how we're landing well and how we're flowing them and all of that is improving their individual performance, where we expect that to be the case elsewhere.
And the nuance to all that statement is, we're right now focused on technical limit, so we’ve already proved not to ourselves that we can get whole lot more sand in and they make a whole lot better wells, which makes more economic, we want to know how much can you do. And so, we focused the folks on that, we’ll do those wells and get online and see and then we'll bring them.
And if we go to the place where much higher sand content and stage facing et cetera, it becomes more of the norm after we test it, then we'll readjust our schedule like you know what that looks like and go from there, that's the real big piece of that whole calendar issue.
Holly Stewart
Okay. That’s helpful.
And then maybe just following upon the sand comment, you mentioned in the prepared remarks, the 5000 well, or the 5000 pound per well for foot test, I mean, and you just mentioned 3000, I guess, is that well online, is there anything to, you know, to think through there and then without wet versus dry well, you know, just trying to think through, I guess, historically, you said, you’ve been at GBP 2000 pounds, so just trying to think through, how that could potentially impact the results.
John Bergeron
Holly, this is Jack. We have not brought any of our current tests online yet, they'll be coming on this quarter, but we do have some higher, greater than 3000-pound test that we did last year that are part of the better performance, I mentioned on the Ridgetop Land Ventures pad.
So, we’re building on that actually, stretching again as Bill said the technical limits to do that, we have brought on in Northeast PA, some of our - the Racine pad I mentioned was one that we went to tighter cluster spacing more stages and that contributes to the time, but we’re definitely seeing the performance there, and it’s there with high sand already the GBP 2000 that we’ve adopted last year.
William Way
So, as you walk through these you've got a couple of things going on, you’ve got three different areas of production in the three divisions we have and they are all in various of ramping up and so you take Fayetteville going from 500 or 800 pounds to 2000 pounds that doesn't mean we're stopping there, that’s a big leap for them. In Northeast assets, we've already have proved that in certain areas that you can go past 3000 pounds and get materially better wells.
Now we want to figure out, okay, how do we step that up and what in - and what increment. I've got engineers that would like to do a whole a lot more than even the numbers that we’ve been talking about, that we wanted to be prudent about that as well.
And then we’ll figure out where that economic threshold crosses the technical limit and optimize to that point and go forward, so we’ve got a lot of moving parts here and the early indications both from late last year and early now with the some of the Racine work in Northeast Pennsylvania and some of these is very encouraging and we will continue to pursue that.
Holly Stewart
Great. Thanks, guys.
John Bergeron
Great.
Operator
Our next question comes from the line of Arun Jairam [ph] with JP Morgan. Please proceed with your question.
Unidentified Analyst
Good morning. I was wondered, if you could comment on, you know, the potential delays on Atlantic Sunrise I think, you do have some modest volumes on that project and what that means to Swin [ph] as we think about, you know, 2017, 2018 and how are you thinking about capital allocation?
William Way
Yeah. Just in general our exposure to Atlantic Sunrise and the constitution pipeline, quite frankly on a relative basis to our portfolio is - are small.
We are watching both of those. We are very aware and trying to be more aware every day of the different twists and turns that are going on with those projects.
We think both projects should happen. But we’ve known for some time that we needed to manage our overall portfolio in that area by adding additional capacity.
Last year we've added some additional capacity around what we already had anticipating that you could have scheduling challenges. I think further probably the greatest near-term impact becomes the seasonal differential challenge, especially as production and pricing resumes and if you get production come back online.
We get the differential challenge. We're trying to manage that through basis hedging.
Our overall transportation portfolio pricing is very low in that area. And so, managing that to the markets we serve managing any kind of basis challenge with further hedging, we certainly are doing and we'll watch it closely.
Randy may have some other comments for you, but we feel pretty good about where we sit relative to that right now.
Randy Curry
Yeah. I agree with everything Bill said.
Obviously, the only thing that color I'd is everybody I think is aware the FERC did issue a new deadline for the EIS, which is at the end of the year yesterday. And then there is a 90-day period after that.
So, the project has been certainly pushed back a little bit. But as Bill said, we feel really good about our overall portfolio out of Northeast PA and Southwest Virginia.
And what we have was a 44,000 of the volume on Atlantic Sunrise so.
Unidentified Analyst
And just a quick follow-up on that, can you give us an update on Rovers where you do have more the significant from transportation exposure?
Randy Curry
Yeah Rover has received their final EIS. And there is actually an expectation, I believe by the industry and the market that Bill received some notification here very soon at the exploration of the 90-day period.
So today that I think all the feedback that we're getting from the pipeline is they remain confident on that. And to be able to start construction fairly soon.
Unidentified Analyst
Okay. And just my second question would be just on the NGLs, Bill you highlighted how you're quite optimistic on NGLs and ethane and how could you as you think about 2017, could we see more activity in your Southern Marcellus or Southern Appalachia acreage take advantage of that?
William Way
Yeah, I think the way we're doing this. As I said earlier, we've got economic projects in all three of our operating areas.
And what we do in putting together the portfolio of projects is that we first rank them all. And we look at the PVI contribution to the company from each of the areas and we rank them.
And if as we are working through that planning process and we see further and further signs of some clear strengthening of NGLs you get some of the wells that move around in that positioning. And so, it's entirely likely that as you look at where that mix falls out in fact by the time we issue guidance that you see it move around.
We are I am a firm believer in leveraging every strength you have. And because we have our - we're vertically integrated have our own rigs, we have our flexibility to move around.
We have capacity in each of the areas. We need to take advantage of that and be able to be agile in working through that.
Unidentified Analyst
Okay, thanks a lot.
Operator
Our next question comes from the line of Marshal Carver [ph] from Heikkinen Energy Advisors. Please proceed with your question.
Unidentified Analyst
Yes, what are your wells costing by area now for typical well and how much more expensive are the wells with the larger completions?
William Way
Well, typically Northeast PA we're looking at about still around $5 million, $5.5 million. We have not seen any increase in cost overall with our testing of the completions, because of the service prices right now are very favorable.
We are now in the very large jobs; we're pumping in the West Virginia and Southwest Appalachia we are adding $1 million to $2 million generally to our well cost. They're up to $8 million on the well cost eight day and a half.
But we're getting a great return I believe the work we did at the end of 2015 we think on that $2 million we invested extra on those. We got two PVI on that $2 million.
So, the return is very healthy on the incremental sand and cluster spacing. Fayetteville is still right around $3 million on our wells.
We have our own sand mine and so sand is very cheap there.
John Bergeron
And West Virginia 7 million on 7800-foot lateral in rich gas and about 6.5 on 6,000-foot lateral in the lean gas.
Unidentified Analyst
All right, very good. Thank you very much.
Operator
Our next question comes from the line of Brian Singer with Goldman Sachs. Please proceed with your question.
Brian Singer
Thank you. Good morning.
William Way
Good morning.
Brian Singer
Can you talk about capital allocation to the Fayetteville beyond completing the ducts how aggressive should we expect you to ramp up activity if we are in a say 325 versus 350 gas price environments for 2017?
William Way
Yes, as I kind of mention this a bit earlier. Certainly, as we look at the Moorefield testing that's going on.
We want to understand the air extensive of that we want to understand how the changes to our completion technology, completion practices, flow back practices and drilling practices what impact that has on the Fayetteville I remain in the same place that I spoke about earlier though is that you have some targeted testing and that opens up new frontiers than we put that into the mix, you have some land capture in the two other divisions not Fayetteville. Add some of those and may be one or two other things then you start looking at relative economics to Northeast a big piece of our capital productivity improvement, a big piece of really an overall for some improvement is allocating capital to the highest best use of that capital and today with current technology and current commercial terms and all the other things that go into that our two Northeast assets by and large are have that advantage and so in the first pile up of projects, the majority of it obviously goes to the Northeast.
But as you’re seeing right now we have a rig in Fayetteville, it's focusing on Moorefield, it's focusing on some other testing and we've got some other things we're working on and then the rest of the activity is in the other two places. And we challenge the teams all the time and they take this challenge very well and as you can see from our results it shows through.
Each group while they are working for the whole of the company, they are driving in their own back yard, driving margin improvements, driving productivity of well improvements and you make major inroads into the water management of any of these divisions then you move the needle. So, there is a lot of very exciting testing going on around water management and around different techniques.
It can move the dial so as we work through the remainder of this year and continue to the planning for 2017 all of that will be taken into account, but the headline for you is really it’s all about economic value and driving economic value out of what we have and so the bias at - with the current view at this 10 seconds obviously goes to the - capturing at values in Northeast.
Brian Singer
Okay, great, thanks. And just a follow-up on the Moorefield point that you mentioned a couple of times, obviously that base low, because you are doing that now with the one rate that you’ve added.
Is it also the next - is it also on the margin in other words, if you do want to add more activity to the Fayetteville, would you actually do Moorefield test first with another rig over wider extent or would you actually going to do a more development drilling for the Fayetteville zone and I know you mentioned that would have to come only if the returns are better than Appalachia, but let's just say they are.
William Way
If they are then certainly they would complete in the investment stack and you'd go from there. I am going to do capital allocation based off of proof and so the guidance, the teams are working those out and certainly we will go from there.
I don’t know whether at this 10 seconds whether they will do Moorefield testing in the next year or we'll gain enough to be able to sort of lay that all out and put it again in the Far East
Robert Craig Owen
Yeah, Brian, it’s Craig, and I may just add is as Bill indicated, Moorefield is certainly something that we like, we like what we've seen but all of Fayetteville continues as the teams continue to work and spent the six months doing a lot of work on paper and lot of challenge across divisions and divisions, it is kind of stepped up and we like the early results we've seen, so continues to compete and it continues to crawl back, few have asked that question nine months ago I think in a $3 flat environment our buyers would have been most of the economics would have been in the north, I think that we’re seeing some positive things that maybe changing that.
William Way
You challenge a team with thousands of well locations that are sitting there on the price curve and they rise to that occasion, so we’ll look forward talking more about that as we learn more.
Brian Singer
Great. Thank you so much.
Operator
Thank you. Our next question comes from the line Kashy Harrison with Simmons.
Please proceed with your question.
Kashy Harrison
Good morning, and thanks for taking my question.
William Way
Good morning.
Kashy Harrison
So, on the Racine pad with the really impressive initial results, could you give us some idea of what your expectations are for year one cumulative production on an individual well and then could you also give us some idea as to what extent this optimize well back technique would be incorporated into future wells being brought online?
William Way
Yeah, I think that the headline for you - Jack may have some comments to go with it, the headline for you is just too early to tell. You know, when we - as a matter of practice just now and going forward even in the past, when we have some very high rate performance out of some wells given advanced sand loading or given advanced anything, we’re going to study them, understand them.
And are we accelerating EORs, are we opening up new recovery percentages all of that. And so these have not been all that long and so, you know, I would guard against, you know, adding to EOR at this time, what is clear is when they - as they come on and flow at this regular accelerating value and that’s our driver, is so trying to figure out how do we maximize value.
As soon as we get a bit more of those under our belt, you know, we’re going to kind of fun, but awkward time right now, we’ve been offline in the drilling and completions area for six months we've come back with just and aggressively strong performance and - but it’s too early and I don’t want to lead you down the path that we can’t confirm.
Kashy Harrison
All right. Thank you.
That’s it from me.
Operator
Our next question comes from the line of Dan Mix [ph] from BMO Capital Markets. Please proceed with your question.
Unidentified Analyst
Thank you and good morning.
William Way
Good morning.
Unidentified Analyst
Circling back on previous answer regarding capital spending in 2017, what would five rigs running in $900 million in capital spending mean for production growth in 2017?
William Way
Yeah. I don’t have that yet.
It depends on where you allocate those that capital and where you allocate those rigs and how many - how the completions go and you know that the divisions are all very different and so I'll ask you to stay tuned on that.
Unidentified Analyst
Very good. And then as a follow-up relatively heavy use of swaps in 2017 as part of the hedging program just curious as to why swaps further versus greater use of colors?
Robert Craig Owen
You know our programs one where we just - we try to find the right balance and we want to have the portfolio of both swaps and colors to give us both some forward certainty and then also some opportunity for the upside, so it's really just a balanced approach.
Unidentified Analyst
Very good, great. Thank you.
Have a great day.
William Way
Okay. Thanks.
Operator
Our next question comes from the line of David Tameron with Wells Fargo. Please proceed with your question.
David Tameron
Yeah. Good morning.
Couple of questions, one, I think those that referenced ethane, can you just talk about what type of leverage you have to that and what that mean as far as margins and pricing and I know I have your [Indiscernible] but can you expand on that a little more.
William Way
Sure. Randy?
Randy Curry
This is Randy. We have a nice exposure to Mont Belvieu pricing via our ATEC capacity.
And so that is really one of the primary drivers also ethane represents a little over 60% of our NGL barrel. So those two factors combined really do start impacting kind of the wet versus dry economics when we start seeing some, significant shift in ethane and the longer-term outlook given the crackers that are under construction as we speak.
For demand in the Mont Belvieu area is fairly significant or looking at 600,000 to 700.000 barrels a day demand on top of base that is 1.2. You could do that with some export capacity and that’s why you see a rather strong outlook for ethane which we have some certainly have some good exposure to it.
And export capacity is nearly 3,000 barrels a day so you have got some materially demand happening.
David Tameron
Okay, that’s helpful. And then as it relates to how should we think about 2017, 2018 as far as framework what do you putting up on this.
I get - as far as debt to EBITDA levels within cash flow the off-spin cash flow how should we can - we can point that on prices, but how should we thinking about that?
William Way
Yeah. At this point I think that what you have to think about as you look at the forward curve and depending what that your view of that is you look at our cash flow that our assets can generate and then you look at the capital that investing within cash flow would add up to and that’s how we intend to be thinking about setting these budgets and plans.
You look at assurance of that we have a three-year rolling hedging program that the front year is hedged about where you see we are at for 2017 and then you look at the two following years and we want to have a rigor and discipline around rolling those in and taking into account market versus an economics of the program and the investment. So, but I think right it will be prudent free to look at that from the standpoint of hedging within are not hedging but investing within cash flow is that’s what we think is prudent.
David Tameron
All right. Thank you.
William Way
Thanks, Dave.
Randy Curry
Thank you.
Operator
Our next question comes from the line of David Deckelbaum with KeyBanc. Please proceed with your question.
David Deckelbaum
Hi, good morning everyone. Thanks for taking my questions.
William Way
David.
David Deckelbaum
I was just curious I know on the there is a loss of goods $700 million of CapEx plan the whole things flat. I know a lot of things are dynamic you haven’t given your ‘17 plans.
In that original illustration, does that assume that just the Northeast region was growing and Fayetteville was still in decline in 2017?
William Way
Yeah. I would expect that to be the case, you've got to drill, you've got to put a number of rigs in there to keep the rest decline [ph]
David Deckelbaum
Okay. And the Moorefield Shale can you give us I wasn’t sure if I heard it or not but what are those wells costs right now relative to the Fayetteville wells?
William Way
It's really about $3.5 million to $4 million.
David Deckelbaum
Okay. And then you opened up in your remarks Bill talking about how you basically been 95% within zone of your target where you want to land these laterals.
As you talked about improvements of proppant loading, are you seeing the biggest up seen from that lateral landing for merger or is the performance that you are see this year more of a function of sand loading and where was you have say that you were in terms of percentage of heating zone in 2015?
John Bergeron
This is Jack. The rotary restorables have helped us in giving the laterals in place and speed.
Those are where they are - we were getting our main zone before that we are taking longer, we are drilling slower. The performance of the wells is that the combination of landing in the proppant zone and the completion techniques.
That’s the more sand is definitely making wells but if you don’t get a main zone it doesn't matter how much sand you put in.
William Way
And the other thing we are looking at and we do this all of time but as wells get better and you think we will back and get you’re at the surface facilities and the gathering systems and are they sized appropriately for improving well performance and so we have given you upsized meter runs or upsized production facilities and I am not talking about massive upsizing go from 2 to 3 inch I know you going to huge benefit. Looking at tubing design in history we have done some modified tubing design, we have done some tubing wells in different parts of the company and we are applying all of those learnings back towards these assets as well.
So, you will continue to see the components improve the overall performance and as we can triangulate around well we think sand is contributing this much and better different flow back regimes or different for surface facilities contributed to that much we can share that we do that you know we are getting solid performance out of each component.
David Deckelbaum
Thanks for the answers guys.
Operator
Our next question comes from the line of Drew Venke with Morgan Stanley. Please proceed with your question.
Drew Venke
Hi, everyone, let’s go to the back on the question about your expectations for differentials next year, just want to clarify, are you thinking pricing is better on an absolute basis in Appalachia or you are thinking differential were actually narrower than for 2016.
John Bergeron
Yeah, actually differentials for this quarter compared to 2015 Northeast Appalachia were actually slightly better and our forecast and our outlook and planning is kind of what the current strip is right now for fourth calendar 2017.
Drew Venke
And sorry just to clarify that you are saying in line with strip so is that better than narrower that this year or is it actual little bit wider?
Randy Curry
It's greatly influenced by the seasonal effects I would say there is probably right now about the team as past year.
Drew Venke
Okay. And then you, this quarter Northeast PA production was down I think more than the prior quarter just curious if you shed in any volumes and just wondering on your typical operational plan, as you said in your remarks earlier, typically weakest pricing year, weakest pricing quarter of the year, do you typically try to constrain volumes and pricing are low or is that mitigated by some other basis swaps or other measures?
Randy Curry
We don’t normally constraint volumes unless prices get very low, which in the quarter they were actually not that at that point, there was a lot of maintenance went on different pipelines during the quarter that did hurt our production in the Northeast a little and we brought on the - the wells came on later in the quarter, the new wells that we did bring on. So, it was normal decline generally.
William Way
The investments that we did make early in the year, the benefit of that showed up in Q2 and so then you six months without much of the activity that will do Q3 but as I said earlier when you get to being include the activity that we got going on now and the improvement of the overall business setting aside the activity we have going on now with just the overall improvement we rest decline by the end of Q4 and you’re actually building back volume, so it was probably mostly related to just sequencing and timing .
Randy Curry
And the other thing that just part of that - when we started, restarted our drilling, it usually has simultaneous operations - they are some shut in on the pads that you can do actually curtail production, but it's really from HS and East standpoint that we do it and so that goes in the second quarter we have no operations going on, third quarter we did have some that contributed somewhat.
William Way
And we have minimum volume in the Bailiyes [ph], most of our volume is under contract so we have some just minimal volume initiative, we don’t cover cash cost, we don’t produce it, but it doesn’t show up on the radar it's not material.
Drew Venke
Thank for the color.
William Way
Sure.
Operator
Our next question comes from the line of Ray Deacon [ph] from Coker and Palmer [ph]. Please proceed with your question.
Unidentified Analyst
Yes, thanks for the taking the question. I was wondering if you could talk about your attempts to lock in an additional firm transportation if you were to make the decision to ramp in the Southwest at this point looking out to 2017 and keep the current rig count in place.
William Way
Yeah kind of a high-level view, and I would like Randy to give you whatever cover we can on that. You know when we went into Southwest Appalachia, we saw the very high priced, very up close to a dollar long 20-year agreements.
We got in there early, we acquired as much transportation as we needed to the two things one get an early ramp on the business and assuming the pipes come in when they are supposed to come in, we can ramp that thing at 35% a year for the next three years comfortably. We then wanted to look at where the pipes get drill, so committing to the right pipes with the right price accessory which is really important and when we step back, 16 Bcf a day of pipeline capacity excluding ahead expansion capacity being both all in one area is a lot of capacity.
And taking on long-term commitments the agenda haven’t drilling to whatever didn’t make any sense to us at all. And so, we said we are away because we do believe and I think the industry shares that’s we are going to that I will come in infection point in the all of these expansions where the cost of those and especially if you get into any expansion type capacity the cost of that comes down and we will lead into that a later date as that cost does come down.
And the terms get more rationalized. We also have the opportunity to and so then we have into firm sales capacity where we are making sales into other consuming side, demand side of their capacity and so, we’ll continue to work that and Randy and I have some additional probably lets but on that high level that’s kind of our philosophy.
Randy Curry
Yes, the only thing I would add to that and build touched on it is, we are going to have a portfolio of options at a really automations we operate. So, the mix of F&D and makes of current sales and mix of daily exposure to local industries.
The outlook again there is one that we think structurally overtime improves and we’ll continue to what we have today and F&D we are very comfortable with commitments that we have made on some pipes that will be coming online and so we are continue to watch that the feel very confident about our position as it stands today.
Unidentified Analyst
Great. Thank you.
I just one more follow-up on that is it seems some of notice but you have less exposure to the Midwest relative to others and is that something you see it’s critical to price realization going forward?
Randy Curry
We want to have exposure a balanced portfolio and a broad portfolio. There will be some Midwest exposure in some other capacity that we have is to be wells but we also very orient towards a go close.
It really as if you look at kind of gulf coast in southeast where the demand growth expectations are, that’s certainly a value to us as well.
Unidentified Analyst
Thank you.
Operator
We have time for one last question. Our last question comes from the line of Jeffrey Campbell from Tuohy Brothers.
Please proceed with your question.
Jeffrey Campbell
Thanks for taking my call and congratulations on the ramp up. First, I want to ask was this call we have more discussion around completions rather than lateral length and I think most MPs are pretty unified around lateral length, improving economics.
I was just curious if you also increasing lateral length in your Fayetteville and Moorefield test as well as in the two Appalachian areas?
William Way
Yes, where we can in some places lateral length is limited to by unit size or how that is made up. We’ve done lateral length testing up past 12,500 feet, we are annualizing that and we were up net virtually 100% and so and all things that we’ve talk about and what we are doing is annualizing that flow that those we have four of those wells, I believe in two different areas at some of our longest that we have.
And you want but the trick is making sure that you are getting the contribution out of the full lateral length and that when you re-run economics, so it's not just, it’s not about flow rate of IP, it’s about well economics. You make sure that these extend rich laterals, you are getting the contribution out of the whole thing for the investment that you are making and it’s a risk reward balance, but we do - as we look to block up land we are consistently - so for example in the range we started out in West Virginia to 7500 foot ton target lateral I think some of our latest average is like 7800 we'll continue to block up acreage and trade and exchange so that you can get up those out there while we are testing these longer rich ones.
The Moorefield laterals are longer, the Fayetteville well laterals are longer and as well. So, the trend is longer, but we will make sure that value of her [Indiscernible] and all that make sense.
Jeffrey Campbell
Okay. Thank you.
Just a little higher-level question on Fayetteville to close, if you’re looking at longer-term is there an argument for high grading and downsizing the assets through sales or acreage release, in other words, the more challenged locations and I am also wondering how the Fayetteville midstream might affect any thinking on that point.
William Way
Yeah. I think if you look at the Fayetteville from a number of different dimensions that we do.
First of all, it’s a just a massive cash flow generation machine and the opportunity that affords the company is certainly a bright one. We're seeing the application of commercial and technical and operating expertise we applied at an even greater pace that is unlocking additional opportunities, certainly our midstream business is integral to that, the agility that we have, the ability to move back and forth, the ability to flexible as a corporation, again not drilling into somebody else’s midstream contract or not drilling into firm transportation that you've overcommitted to any of those kind of things, you know, it’s a balance and I think we see the Fayetteville as a vast resource that continues to generate cash flow.
Any of these assets are certainly assets that you look at so can I get greater value doing something different than I am doing now and we work that routinely. Where are they on the cost curve, or you take a subset of it.
We did a transaction in West Virginia on some acreage, we weren't even going to get until 2020, 2023. So, it wasn't that it was not economic, it's just so long dated that that why if we're able to accelerate that value at a good value then do it.
So I think we continue to look at it as the answer, we don’t want to put ourselves in the place where we do A, because we’ve done, B, we want them to be economically synchronized and we think that you had more value on the long run.
Jeffrey Campbell
Okay. Thanks very much.
I appreciate that.
William Way
Okay. Thank you.
Operator
We are out of time for questions. I would like to turn the floor back over to management for closing comments.
William Way
Well, thank you and thank you all for being here today and taking an interest in what we're doing. You know, you've heard a lot of impressive accomplishments throughout the call this morning.
The good news is that we positioned each of these assets well and we think that there each setup. So where you can expect to have even more results and even better results as we go forward in time with the stability that we recaptured in the company this year, we’ve got a clear path to capturing and delivering value, creating growth and we’re doing all of that in rising gas price environment and positioning ourselves to capitalize on rising gas price environment is a big piece of that objective.
Our portfolio is primed to deliver impressive results, well results as we learn from all the things we’ve talked about today and our firm transportation portfolio allows us the flexibility to maneuver and navigate and work through an ever-changing basis environment and ever-changing regulatory environment and ever-changing pricing environment. So we'll continue to divide and implement innovative drilling and operating techniques and efficiencies.
We are - we ever what we call around here an aggressive result on improving margin and so, every individual in this company is driven by and incentivized by the quest of reduced cost, improve the operating results of every part of the business. So, you have it on the revenue side, you have it on the cost side and we are committed to continue to increase that margin.
And finally, we will maintain the rigor capital allocation, capital discipline, financial responsibility that we’ve demonstrated so far this year and is hallmark of our company. So, I want thank each of you for joining us on the call today.
Thanks for all the questions. We look forward to see you along the road and I hope you all have a great weekend.
Operator
Ladies and gentlemen, this does conclude today's teleconference. Thank you for your participation.
You may disconnect your lines at this time and have a wonderful day.