Good morning, and welcome to the Cabot Oil and Gas Corporation Third Quarter 2016 Earnings Conference Call and Webcast. All participants will be in listen only mode. Please note, this event is being recorded. I would now like to turn the conference over to Mr. Dan Dingis, Chairman, CEO and President.
Please go ahead.
Thank you, Gary, and good morning. Joining us today for Cabot's Q3 2016 earnings call. With me today are several members of Cabot's executive management team. I trust that everyone has had the opportunity to review our press release from this morning. Additionally, we have posted a presentation to our website, something new that I will directly reference on the call this morning.
This presentation highlights our financial and operational results from the quarter as well as provides an updated outlook on the company's plans for 2017 and beyond. However, before we get started, I'd first like to move to slide 2 of the presentation, which addresses our forward looking statements. Please note that we will make forward looking statements based on current expectations this morning. Also, some of our comments may reference non GAAP financial measures. Forward looking statements and other disclaimers as well as reconciliations to the most directly comparable GAAP Financial Measures are provided in both the earnings release and this presentation.
Moving on to the 3rd quarter financial highlights on Page 3. Cabot once again generated positive free cash flow for the quarter, while growing equivalent production 6% year over year despite our production being impacted by downstream maintenance projects and unplanned upstream gathering downtime during the quarter. We remain committed to generating return focused measured growth within cash flow and this quarter we successfully executed on this plan. While much has been made recently about a widening of regional differentials, we actually recorded our best pre hedge natural gas realization since the Q1 of 2015 when the average NYMEX price was $0.17 higher than this past quarter. Our pre hedge realization of $1.80 per Mcf were 7% better than the comparable quarter last year and 16% higher sequentially relative to the Q2.
Our cost structure continued to improve during the quarter with cash cost operating cost declining 13% year over year. We expect this trend to continue over the next few years as we leverage our operational scale to further improve our cost structure. Our financial position remains strong with over $500,000,000 of cash on hand, approximately $1,700,000,000 of available commitments on our undrawn credit facility and a net debt to EBITDAX ratio of 1.9 times at quarter end. Moving on to Slide 4, where we have outlined the significant decline in our drilling and completion cost and our LOE, which is a direct impact of the efficiency gains our operational teams have accomplished over the past few years. They have done an outstanding job with this.
While it is possible that we could see some upward pressure on service cost, I anticipate that we will continue to see a downward trend in our overall cost structure as we become even more efficient in our operations. On Slide 5, we have outlined the results of a few reduced space pilots that we have been testing in our Marcellus operating area. This is an interesting area for us. The graphs on this slide represent 4 different pads where we completed one well with our Gen 3 completion design and one offset well with our Gen 4 completion design, we have experienced overall a 20% uplift in cumulative production from the Gen 4 wells. As a result, we have decided to implement this completion design for all of our wells going forward beginning in Q4 of this year.
As we typically do each year, we will wait until our year end reserve audit before making any changes to our EUR. However, as you can see by the numbers, we are very excited about what this could mean for our industry leading well productivity going forward. On Slide 6, we have laid out our capital program for 2017, which includes the program wide implementation of the Gen 4 completion design in the Marcellus. As we alluded to on the Q2 call, we are targeting 5% to 10% production growth in 2017. This is based on total program spending of $625,000,000 which includes $575,000,000 of E and P capital and another $50,000,000 for our equity investments in the Atlantic Sunrise and Constitution pipelines.
$535,000,000 or 93 percent of E and P capital is earmarked for drilling and completion activity associated with the 70 well net wells we plan to drill and the 75 net wells we plan to complete next year. 79% of the drill and complete capital will be directed to the Marcellus and the remaining 21% will be directed to the Eagle Ford where the program is focused on maintaining leasehold, holding oil volumes flat and generating a cash flow neutral operating program. We have allocated $225,000,000 for maintenance capital in the Marcellus and Eagle Ford, which is the amount of capital needed to hold our anticipated 2016 exit production flat throughout 2017 and also allows us to meet all our obligatory operating commitments to maintain our leasehold. This flat production profile for the year would imply growth at the low end of our production growth guidance range. The remaining capital for the year provides the productive capacity needed to meet or exceed the high end of our 20 17 guidance range, assuming price realizations are at levels that generate strong return for Cabot, while also allowing us to build the backlog necessary to meet our production targets in 'eighteen when we anticipate a significant amount of new takeaway capacity being placed in service.
Slide 7 highlights the well level economics on the average well we plan to drill in 2017. Even in a low price environment, both our assets generate strong returns. However, from a capital allocation perspective, you can see why the Marcellus continues to receive the lion's share of capital. At a $2 realized price, our wells generate a rate of return over 100%, highlighting the world class asset we in Northeast Pennsylvania. I would also highlight that the well cost on this slide includes facility cost and also reflects our current view of the service cost environment for 2017.
Additionally, the incremental stages and the corresponding increase in well cost for the Gen 4 completion design. Moving on to Slide 8. We have highlighted our natural gas price exposure by index for 2017. While it is no surprise that we have a significant amount of exposure to in basin pricing during 2017 as we await the addition of new takeaway projects in 2018. We have taken numerous steps to mitigate the potential for downside pricing risk next year.
We have about 12% of our natural gas production tied to NYMEX and we have hedged the majority of that exposure at an average floor price of approximately $3.10 per Mcf. We have also locked in another 21% of our volumes with fixed price contracts at an average price of 2.15 dollars The majority of these volumes would typically be tied to the Northeast PA Index that have seen significantly worse pricing over the last few years. As a result, we believe fixing these volumes at prices that generate the high returns we highlighted on the previous slide is a prudent decision. Regarding our balance sheet, as I mentioned at the beginning of the call, we have an extremely strong financial position with a significant amount of flexibility given our cash on cash and availability under our credit facility. You'll notice that our highest cost debt matures in 2018, leaving us with a much lower weighted average interest rate subsequent to those maturities.
Okay. Moving to Slide 9. In light of all of the recent news flow regarding Atlantic Sunrise and other infrastructure projects in Appalachia. On Slide 9, we have provided a brief update on all the projects that we are participating in over the next few years. For today's call, I plan to only specifically address a few of the projects.
However, all of these projects are important steps towards realizing our long term initiatives and value creation from our Marcellus assets. Our 2 infrastructure projects in the power market, the Moxie Freedom Power Plant and the Lackawanna Energy Center Power Plant are currently under full scale construction. Both facilities are on track to be completed by June 2018 with the Lackawanna project phasing in between June December 2018. I'll remind everyone that this new local demand of approximately 400,000,000 cubic foot per day is essentially tied to our gathering system and eliminates the need to commit to expensive long term firm transportation agreements. Overall, we anticipate the netbacks on these volumes to be some of the best in our portfolio.
Tennessee Oron project, on which we are sole supplier, recently received a favorable environmental assessment from the FERC and is slated to begin construction in January 2017. We have approximately $135,000,000 per day on this project and anticipate the netbacks will be accretive to in basin netbacks. Moving on to Atlantic Sunrise. As you are aware, we recently had a slight setback with the FERC moving the timing of the issuance of the final environmental impact statement from October to December in order to accommodate comments from landowners regarding 2 minor route alternatives totaling 1.4 miles. While pointed that this decision has resulted in a delay of in service date to mid-twenty 18, we believe the decision was prudent and that at the end of the day, the Atlantic Sunrise route will ultimately be insured with a full and complete record.
And as you're all aware, in this environment, we simply want to get it done right, particularly concerning the route. You will notice that all of these projects have the potential to be placed in service during 2018, highlighting what an inflection year 2018 can be to Cabot. Not only do we believe that 2018 is going to be a strong year for us, but also additional infrastructure is needed for PA and the nation. And I'd refer you to the Pennsylvania Governor Wolf's support of that position referenced in William's press release this morning. Moving to Slide 10, highlights the cumulative impact of all the projects we have highlighted on the previous slide, allowing us to potentially double our gross production out of the Marcellus to 4 Bcf per day.
Clearly, there has been a lot of questions around Constitution given the ongoing appeal process. But even if you exclude Constitution from the conversation, we would be able to produce 3.5 Bcf per day with these existing projects that are on the slate once all the new projects are online. We remain optimistic the constitution will be built and that we will continue to assess new outlets that enable us to grow our production higher than the levels outlined on this slide. However, even if we were able to hold the production flat at 3.5 Bcf per day, we believe a highly capital efficient asset base provides a unique value proposition via the free cash flow yield. At a range of realized prices between $2.50 $3 per Mcf, our standalone Marcellus asset generates between $1,100,000,000 $1,600,000,000 pre tax free cash flow and we will have the inventory to hold production flat at those levels until 2,037.
Slide 11 illustrates the change in how our market Marcellus production between now and 4Q 2018, which is when we expect to have the majority of this new infrastructure online. As you can see, that our exposure in the Northeast PA price points, Lighty, Tennessee, Millennium, reduces significantly, while our exposure to NYMEX, the DC market area and the newbuild power generation facilities increases significantly. While we fully believe that in price in basin pricing will improve dramatically during this period as major projects like Atlantic Sunrise and PennEast are built. Even if you assume there are no changes in NYMEX or regional basis differentials between Q4 'sixteen and Q4 'eighteen, the addition of our new takeaway capacity would improve realized prices by greater than $0.50 per Mcf on all of our volumes. Based on the midpoint of our expectation of Q4 2018 production range, a $0.50 uplift in realized prices would represent over $450,000,000 uplift in cash flows on an annualized basis.
Moving to Slide 12. Slide 12 highlights our planned production growth through 2018 and some of the anticipated byproducts of this plan based on current strip pricing. As I already highlighted earlier in the call, we plan generate 5% to 10% production growth in 2017. And based on today's strip, we will generate a meaningful amount of free cash flow even after accounting for pipeline investments and dividends. You can also see that we expect to delever by one turn, resulting in year end 2017 target leverage ratio of 1 time.
We also highlighted a preliminary 2018 production growth range of 15% to 25% based on a program that also generates positive free cash flow at today's strip. Ultimately, where we land within that range will be a function of the timing of the in service on the takeaway projects we highlighted previously and what the expectations are for in basin prices during this period of time. However, based on the target in service dates we laid out on Slide 9 and our current expectations of where local prices will be in 2018, we feel very comfortable that we will be able to deliver on production growth within the range, while generating free cash flow, delevering, reducing cash cost and increasing cash margins. While we have not included 2019 growth expectations at this time, given a lineup of new takeaway slated for mid- to late 2018 in service day, it is reasonable to assume 2019 will be another year of robust growth for Cabot Oil and Gas. And Gary, with that, I will now open the lines up for Q and A.
We will now begin the question and answer The first question comes from Drew Venker with Morgan Stanley. Please go ahead.
Good morning, everyone. Hi, Dan. I was hoping you could talk about your basic expectations for 4Q in 2017 and the exposure you gave us is very helpful color. I just thought maybe you could give some more detail.
I'm sorry, I didn't hear the first part. Our base what?
Your basis expectations for 4Q in 2017. Okay. 2017?
Okay. I will Jeff is an expert in marketing area and he sits poised beside me on each of these calls to answer all of the questions that we have in regard to marketing. And as you know, I'll just preface this by saying that basis has been extremely volatile from the 1st Q, 2nd Q and then rolling into 3rd Q of 2017. We see a lot of volatility and we anticipate that volatility to continue into the future to have a fairway of where we think the fundamentals are going to be is not easy, but we've given it a shot.
Okay, Drew. This is Jeff. Obviously, we didn't get off to a good start with October basis, but what we've tried to do is just highlight in the guidance and in the slides exactly what our exposures are to each particular index. So based on the pie chart you see and on the guidance, you can get a pretty good idea of where the exposure lies and it's been up and down all year long and we had a very bad Q1 because of weather. It's heightened up through Q2 and we had another semi blowout, I would say, in Q3.
But basically, it's strengthening on the cash market. We had a very good year on cash in terms of I wouldn't say very good year. I'd say better than what we expected with the weather and the storage conditions. But if you review the pie chart closely, you'll see the exposures.
So, everybody just on a relative basis, Jeff, is it fair to assume that this trip is right for 2017, absolute price should be better, but maybe differential is a little wider relative to NYMEX? Yes. That's fair? Okay. And Dan, if we go back to the completions, you talked about the Gen 4 design.
It looks like you have a lot of history on these. Can you talk about how much you have been using this Gen 4 within your total program? Are we looking at 4 pads and that's the extent of what you've tested? Or has this been more common in your program in 2016?
No. We have we certainly have tested more than 4 pads. We have on the 4 pads we illustrated, it was we thought the best apples and apples comparison where we had side by side heading in the same direction spaced accordingly and going through the same geology, the Gen III and Gen IV. But we have in addition to these, we have approximately 20 other wells that we have history with the Gen 4 completions. What we don't have, we have we can extrapolate on those with the results, but we didn't have we don't have on all of those the exact side by side apples and apples comparison.
But we did see positive results in the majority of the Gen IV completions that we have implemented.
Thanks for that, Dan. And I guess one last one maybe for Jeff on Atlantic Sunrise. The mid-twenty 18 start up seems like to me at least that it's been a risk somewhat expectation. Do you know or have a sense of when you need to get the notice to proceed in order to hit that mid-twenty 18 start up date? Is that a fair amount of protection baked in?
Yes. There's a lot of issues to be resolved over the next few weeks in terms of the fine tuning and the scooter per se. So I'm giving you exact data on those proceeds, not able to do that. That's probably a good question Monday on the Williams call. But as far as mid-twenty 18, looking at all the different accomplishments that need to take place between now and then.
It certainly is doable. And there is some I wouldn't say there is some fluff in there, but it's certainly events have to take place. But we're comfortable on the mid-twenty 18 date from where we are right now.
Thanks, Jeff.
Thanks, Drew.
The next question comes from Neal Dingmann with SunTrust. Please go ahead.
Dan, just going to follow-up to that question about the 4th gen. Is that
so the plans going forward, will you
use that larger completion design, it sounds like, on most given the positive results you're seeing?
We will not only on most, but on all. We plan on with that we have going on out in front of us in the Q4 and the completions that we have scheduled for 'seventeen, we will implement this Gen 4 completion design.
And then Dan, I know some others have mentioned about least when it comes to sand and some sort of call it pushing the limits on some of these completions, some are seeing what they would call diminishing returns. Are you near that? Or do you think we'll see a Gen 5 or Gen 6? How do you guys think about sort of pushing an envelope on these completion designs?
Well, I'll let Phil Sornacker, who runs our Marcellus, answer that briefly. But I would first say that we still even within Gen 4, we still are doing some kind of give us have a range of some of the things that we're tweaking. So, I think kind of give us kind of a range of some of the things that we're tweaking.
Yes. And like Dan said, we're looking at multiple things, number of clusters, the rate that we're
constantly trying to tweak we're constantly trying
to tweak this program and then get the best value for it. So again, it's still a work in progress.
Got it. And then just lastly, we've seen some the M and A activity pick up both the Marcellus and the Eagle Ford. Just your thoughts, I mean, are you just are you all just kind of at bolt on? Are you always just looking at deals in bolt? I mean, again, you definitely alluded to that Slide 7, certainly large returns over the Marcellus for you all.
So when you look at M and A activity, how do you think about both areas?
Yes. We look at value. Kind of blind on commodity, though we have expertise in both oil and gas by virtue of our 2 regions, we're looking at the value proposition, looking at what can compete for our capital and provide what our strategy is and that is to deliver a growth with a high return profile to it. So I think the activity in the Eagle Ford, I think the activity in the Marcellus could be a reflection of maybe how the activity in the Permian Sac scoop has gone with the valuations in those particular basins. But when you look at our ongoing line of business, we're not that acquisitive.
However, we are informed with the transactions that taken place by either being in data rooms or doing our own evaluation of the transactions that have taken place. But primary consideration on our evaluation is value.
Got it. Great color. Thanks, Dan.
Thanks.
The next question comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.
Good morning.
Hi, Jeffrey.
I wanted to ask you on Slide 5, is it correct that you have better than 2 years of 4th gen data as the slide implies? Or has that been is that a shorter data set and then it's been extrapolated out?
No. We have back to the comment I've made about different tweaks and trying significant term on these the definition of our Gen 4. We also though through our Gen 1 through Gen 4 have different modifications within that definition of each one of those that we have employed. In this particular case, we wanted to make sure that we felt good about the long term profile that we didn't get the near wellbore spike on high IPs and then have a fall off later that yielded a reduction in the return. And keep in mind, early on when we were doing these completions, the cost of completion was higher early on.
So you had to be certain early on that you were getting an efficiency uplift in the completions before you were going to spend the money to go forward. And what we a couple of things have happened now, not only has the cost gone down on the completions, which yields even better return profile. But as you can see on these slides that as you go you're going out into deeper into the amount of days on production, you're actually seeing a widening in the type curve that we have for Gen 3 and the type curve we're realizing on the Gen 4 wells, which is a very good positive.
All right. Very much so. So that's pretty impressive. I wanted to ask you, superficially, it appears that you can maintain flat production in 2017 for a lower cost than it took to reach those levels in 2016. But can you identify what portion of the 2016 spend is not going to produce until 2017?
What part of the 2016 is not going to produce until 2017? Correct. It's basically going to be our the wells that we have scheduled to complete late in the Q4.
So the $35,000,000 additional CapEx is basically it?
Right. Or
that portion of it, it's
be for That's allocated to the completions in the Q4.
Right. Okay. Perfect. And then finally, if I could just ask kind of a higher level question. Regarding Constitution, you actually have 2 actions going.
You've got the appeal in the 2nd Circuit and then you've got a separate action in the Northern District. I was just curious, are you many more confident in one approach than the other? And ultimately and I know this is a tough question, but it's germane seemingly to every pipeline resistance that we're getting these days. Ultimately, if the actions are somehow unsuccessful, is there any indication that FERC is going to step up and finally exercise its regulatory authority?
Well, great question and I can just make a macro comment in regard to the latter part, Jeffrey, of that comment. Then I'll turn it to Jeff to give some color on the Constitution and the 2 courts. But we're faced with a challenge on the energy space, all not just Atlantic Sunrise Constitution, but Access and other pipelines that are and infrastructure that are going to be challenged by activists that quite frankly just don't want hydrocarbon in the energy mix. I think it's clear that hydrocarbons are going to be part of the energy mix without a solution for many decades to come. So the argument and the fight today is real to those activists.
But from a practicality standpoint, we're going to need the infrastructure to service the demand needs and the demand growth that is perceived in all of these communities. FERC is certainly challenged with the regulatory side and the legal battles that are in front of it on a regular basis. We've seen in their decision process additional caution that they have implemented in their review process. I think it's prudent for that review process. But to your point about moving forward and moving the country forward with a need and the public need is also part of their fiduciary role also.
And I think they take that seriously. So we're getting better as an industry to be able to answer in advance all the challenges that are being placed before us by the antis and those that want to stop the pipelines and infrastructures. We'll continue to get better on the front end to answer all the questions. And hopefully, answering those questions on the front end will mitigate some of the delays we've seen in some of these projects as we move forward. I will just before I turn it to Jeff, I want to make one distinction.
When you look at Access Pipeline and some of the protests that are going on up there, it challenges the local authorities, it challenges the rule of law on what is being implemented and what is being actually allowed to take place up there. And looking at Atlantic Sunrise, Atlantic Sunrise is a Pennsylvania pipeline. Atlantic Sunrise is a pipeline that for particularly Cabbage position. We see a need on the other end of Atlantic Sunrise once it is constructed. But more importantly, there are areas in Northeast Pennsylvania that royalty owners in Northeast Pennsylvania are getting virtually no return for the royalties because the differentials have been so punitive up there in that particular part of the area.
When that happens, the State of Pennsylvania certainly does not see any return to the coppers in the form of revenue and taxes because of the significant impurities that have been in that area because the gas on gas competition. So in referencing Governor's Wolf letter, I think he recognizes that getting an infrastructure and particularly something as near term and as impactful as Atlantic Sunrise has a significant value to Pennsylvania and its constituents to be able to help its shortfall in its budget process. So we think all of that is part of the equation and another reason why Constitution excuse me, Atlantic Sunrise should move forward. Long winded, Jeffrey, but I'll turn it to Jeff to make a
comment on Constitution. Okay. Well, we certainly
do like the 2nd Circuit action. The appeal is very simple. If you read the briefs at all, you'll see the case that we've laid out is, in our opinion, very strong, very clear. Even the affidavits and testimonials at the end on the conversations between the DEP or excuse me, DEC and our environmental focus is very clear. We read the respondent's brief as well.
It was again, in our opinion, not very strong.
Of course, we
filed a reply to that brief out in the hands of the court. And quite frankly, the schedule
is, I
think, very favorable. We'll have the oral arguments in November. And then we hope to get a reply by the court in the spring. All that said, we still like the action in the Northern District as well. We think it's a very strong case.
It's a
little more complicated. And if it wasn't for the duration of that particular action, we would like it probably equally with the appeal. So we're down 2 paths. We think they're both very strong and we'll see what happens.
Okay, great. Well, that was outstanding color. Thank you. I appreciate it.
The next question comes from Brian Singer with Goldman Sachs. Please go ahead.
Going back to the earlier
B, when you look at the outperformance that you are seeingexpect, do you view this as an increase in recovery rate? Or are you simply recovering the same hydrocarbon overall, but just doing it more efficiently with fewer wells?
Yes. I'm going to answer first and I'm going to turn it to Bill. On the latter part, do I think this is incremental reserves or acceleration? We think this is all incremental reserves. Keep in mind that the spacing on these are the spacing that we have a significant amount of data on through our all of our drilling up there and the spacing on these and where we blade the laterals, we think it's all incremental reserves.
So we're comfortable with that. I'll let Phil answer the rest of it.
Yes. As far as the amount of data here, this is pretty much all the data that we have on these wells. I think that was your first question there. So
you're seeing
pretty much everything we have
on these different pads.
We obviously have Brian, we obviously kind of purposely left off specifics. But and the specifics we left off was to mitigate the Street getting ahead of us on trying to preempt our year end reserve review. Our year end reserve review and audit is we go into excruciating detail. We do a 100% audit and we'll come out with that after the end of the year. But and our comment made to talk about the 20% plus efficiency gain was designed to give a little bit of color, but we have left off some of the details just to allow us to do the year end reserves without setting expectations that would get out in front of the actual.
Thank you. And then I guess shifting to the free cash flow that you're expecting beginning next year and continuing and this is not a new question, but you talked about M and A a little bit earlier. Just wondered if you could give us your latest thoughts on how that free cash flow gets allocated and whether you use that for debt pay down, whether you use that for returning to shareholders or whether that goes into a cough or for potential M and A?
Well, all the above is still consideration is cut in time, Brian. We have and will have conversations in the boardroom about dividend policy. We certainly have a good balance sheet at this stage and I know Scott gets a little concerned about too low of debt levels. But when you look at the value consideration on either looking at other projects to allocate capital. That's part of our internal effort to continue to evaluate all of the opportunities that are out there today.
But we again look at that with a value consideration as priority 1, 23. And knowing that we have such a world class return profile for Marcellus, We want to make sure that if we do have projects outside that it's going to be somewhat competitive with where we might allocate that free cash and to compete favorably with our Marcellus allocation. So in this low commodity price environment, still having efficiency gains in a lot of areas, including our Marcellus. We are penalized by the Northeast differentials that we experience up there. We think we have a fix that has been slid out from what we originally had anticipated.
Extremely frustrating from our perspective that we are moving gas in the range that we're moving it in. But we do think we have some daylight coming down the road. And with that daylight, I don't think we'll be able to find a project that is better than the Marcellus. We're just looking for one that will compete favorably if in fact we go that route.
Great. Thank you.
The next question comes from Charles Meade with Johnson Rice. Please go ahead.
Good morning, Dan, and to the rest of your team there.
Thanks, Charles.
I wanted to ask another question about the that slide on the Gen 4 completions. And I appreciate your comments about trying to withhold some information. And I recognize we can create a lot of mission with partial information. But I wonder if you could perhaps offer what's driving some of that variance from one well pad to the other? Is this and whether that variance that you're observing across these spore pads is coming within the range of what you'd expect once you used it in your whole development program?
Well, I think the tweaks from Gen 3 to Gen 4 and looking at what Phil referenced earlier, whether it's the cluster spacing, the number of clusters, the pumping volumes and the loading are all having an effect on the near wellbore dynamics that we're seeing and the amount of rock that we're breaking up. I think the conductivity that we're creating near Welbore with the Gen 4 completion scheme is yielding the results that we're seeing.
Got it. And so I guess maybe another way. Was there so the variance that you see is you can within the variations within Gen 4 that explains the way some pads are responding better than others, if I understand you.
Well, obviously, we tried to mitigate the sample pools variability by what we've illustrated on this slide by having the laterals placed in what we thought were going to be positions with extremely similar geology, whether it was the smaller faults or areas that we have out there. And again, this is as close to the variability as we can create without a larger sample pool, if you will. But in some of the variability that and are you talking about the when you go out to the 7.50 to 1,000 days, are you talking about the delta between the 2 Gen 3, Gen 4 curve?
Dan, thanks for that question. It was less about the delta on any one given curve. It was more the comparison from PAD A to PAD B to PAD C because when I evolved, it looked like 10 to 20 percent to 20%. But I was wondering why you thought some pads it was just on the lower end and while on some pads it was at the higher end?
Yes. I'll let Bill has a comment, if you'd like here also.
Even on this page, there's difference in the concentration between, say, maybe pad A and B, so that could also be some of the difference you're seeing. Again, we're tweaking the Gen 4 and still working with how much profit we're pumping per foot and there are some differences in between those pads.
Got it. Helpful. And if
I could just sneak in one last one on the well cost and perhaps I'm missing something. But when I look at your new well cost of $7,900,000 and I noticed you guys say that includes some kind of service cost inflation and it's also an 8,000 foot lateral. When I compare that to your $814 per lateral foot from kind of mid-sixteen, it looks like there's a on a lateral adjusted basis, it
looks like there's an uplift
of about $1,500,000 a well. And I'm wondering, am I missing something there? And assuming I'm not, how does that 1.5 $1,000,000 break up to what portion service cost inflation? And then what part is perhaps additional cost from this Gen 4?
Well, Charles, let me get maybe a little bit more color. What lateral length and how many stages are you well are you comparing to?
Yes. That would be normalized at the 8,000 feet.
Yes. Charles, this is Matt, Karen.
I mean, you're talking about an extra 13 to 14 stages on a like for like basis for an 8,000 foot lateral between Gen 4 and Gen 3. So, if you take the extra 13 to 14 stages and adjust a little bit for inflationary costs, you'd probably get there.
Okay. Thank you, Matt. That's very helpful.
The next question comes from Pierce Hammond with Simmons Piper
Jaffray. Dan, when we look at the 2018 growth that you provided, the 15% to 25%, does that reflect fully filling Atlantic Sunrise with new volumes? Or would Atlantic Sunrise have some redirected volumes from other places within your within Northeast PA?
Excuse me, Chris, that reflects additional volumes that would be redirected and does not reflect full volumes on Atlantic Sunrise. Full new volumes. Full new volumes on Atlantic Sunrise.
Combination of old and new. Perfect.
Okay. Thank you. And then my just two quick follow ups, more housekeeping. In the prepared remarks, you had mentioned at $2.50 to $3 realized pricing, you could generate between $1,100,000,000 and 1,600,000,000 pretax free cash flow. Over what time period was that?
We could do that between the end of '18 with the infrastructures in place through 2,037. And then we'd have a blowdown case beyond that.
Thank you. And then final one, What's your rig count that you're targeting next year for Marcellus and then Eagle Ford?
2 in the Marcellus and 1, a half a rig to 3 quarters of a rig in the Eagle Ford.
Thank you very much, Dan.
Thanks, Pierce.
The next question
comes from David Deckelbaum with KeyBanc Capital Markets. Please go ahead.
Good morning, Dan and everyone. Thanks for taking my questions today. I guess since the last update, I think the last time you gave color on sort of achieving mid single digit growth in 2017, it was sort of a 675 slag number. Should we assume that most of the adjustments are basically just a capital efficiency improvement from Gen IV completions?
Yes. That's correct, David.
Okay. All right. Thanks for the clarification on that. And then just curious as I look at the allocation, Jeff, in 'seventeen for your basis impact, is there any reflection, I guess, when you guys are operating at 2 Bcf a day gross or so? Have you picked up any capacity on existing lines within space?
Yes. To be perfectly frank, it's very small scale and it's been month to month. So, there really hasn't been any impactful available capacity in the marketplace.
There's been
a lot out there, but when we look at the netbacks for that capacity, it's basically red ink. And what we've seen is a lot of the locations of the capacity that's available to us is reaching. There's some basis poison in those markets as well and it's spreading. So we're optimistic that we'll find some additional capacity as the growth up there slows down and the capacity exists. But right now, there really hasn't been anything meaningful to latch on to.
Is it possible for you to loosely quantify sort of the gross volumes available sort of in poisons basis impacts markets right now?
Well, let me rephrase the answer then. Just to be clear, the available capacity reaches the point that our production can access, the pricing is just not what it used be. So we're seeing a deterioration of prices at Montblanc, Ramapo and into the West as well. So in that respect, it's just not worth spending the money to get additional capacity in this marketplace until we see some strengthening on basis in other areas.
Thanks for the color, Jeff.
Jeff. The next question comes from Marshall Carver with Heikkinen Energy Advisors. Please go ahead.
Yes. The $225,000,000 in maintenance capital for 2017, does that assume completing DUCs in 2017? Or is that a number you could do year after year after year if you wanted to keep it at the 2016 exit rate level? Yes. That includes completion of some DUCs also.
So okay. So for future years, it would probably be a bit higher than that if you wanted run rate maintenance capital? That's correct. Okay. Yes, the future would be a little bit higher assuming we don't have any additional efficiency gains.
And I would say that increase might be 275 to 300, not increase, but total of 275 to 300. Okay. That's helpful. And what percentage of your 2015 2016 wells were completed with the Gen IV completions? 2015, none.
Well, but besides the 20 or so wells that you see right here on Page 5, Slide 5 and the other wells that are scattered that did not have a direct analogy, probably 10% to 15% would be the number Marshall. For 2015 and 2016? 15, 2016 combined. Okay.
Thank you.
This concludes our question and answer session. I would like to turn the conference back over to Dan Dinges for any closing remarks.
Thank you, Gary, and thank you all for the questions. We remain very excited about the company's future and the opportunity set that lies ahead of us for generating long term shareholder value. The last few years have been extremely frustrating not being able to get infrastructure in the ground. We continue to work through ongoing delays in the infrastructure build out in Appalachia and we do remain confident that better days are ahead of us and particularly in 2018 and certainly beyond. Despite the low commodity price environment and the forecast that we've given, we think we will manage through the differentials and we think that we will continue to be able to generate strong returns, grow production while maintaining our balance sheet, grow proved reserves at an all time low, finding cost and certainly significantly reduce our cost structure through the efficiency gains.
So thank you to all the shareholders that we have out there, particularly to our long term shareholders for their continued patience. And I look forward to speaking with the group again in February. So with that, Gary, that concludes my remarks.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.