Cabot Oil & Gas Corporation
Q3 2016 Earnings Call Transcript

Published: 29 Oct 2016

[Operator:]

Welcome to the Cabot Oil & Gas Corporation Third Quarter 2016 Earnings Conference Call and Webcast. [Operator Instructions]. I would now like to turn the conference over to Mr. Dan Dinges, Chairman, CEO and President. Please go ahead.

[Dan Dinges:]

Thank you, Gary and good morning. Thanks for joining us today for Cabot's third quarter 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 would 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 third 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 down time 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, with actually recorded our best pre-hedge natural gas realization since the first quarter 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 second quarter. Our cost structure continued to improve during the quarter, with cash costs, 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 million of cash on hand, approximately $1.7 billion of available commitments on our undrawn credit facility and a net debt to EBITDAX ratio at 1.9 times at quarter end. Moving on to slide 4, where we have outlined a significant decline in our drilling and completion cost and our LOE which is a direct impact of 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 four 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 the fourth quarter 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're 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 second quarter call, we're targeting 5% to 10% production growth in 2017. This is based on total program spending of $625 million which includes $575 million of E&P capital and another $50 million for our equity investments in the Atlantic sunrise and constitution pipelines. $535 million or 93% of the MP capital, is earmarked for drilling and completion activity associated with the 70 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 lease hold, holding oil volumes flat and generating a cash-flow-neutral operating program. We have allocated $225 million 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 lease hold. 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 2017 guidance range, assuming price realizations are at levels that generate strong returns for Cabot, while also allowing us to build the backlog necessary to meet our production targets in 2018, 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 the capital. At a $2 realized price, our wells generate a rate of return over 100%, highlighting the world-class asset we have in northeast Pennsylvania. I would also highlight that the well cost on this slide includes facility costs and also reflects our current view of the service cost environment for 2017. Additionally, the Marcellus well costs include the incremental stages and the corresponding increase in well costs for the Gen 4 completion design. Moving 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 down-side 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. 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 will notice that our highest cost debt matures in 2018, leaving us with a much lower weighted average interest rate subsequent to those maturities. 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're 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 asset. Our two 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 and December 2018. I remind everyone that this new local demand of approximately 400 million cubic feet 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 net backs on these volumes to be some of the best in our portfolio. Tennessee Orion project, in which we're sole supplier, recently received a favorable environmental assessment from the FERC and is slated to begin construction in January 2017. We have approximately $135 million per day on this project and anticipate the net backs will be accretive to end basin net backs. Moving often to Atlanta 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 land owners regarding two minor route alternatives totalling 1.4 miles. While disappointed that this decision has resulted in a delay of in-service date to mid-2018, we believe the decision was prudent in that the end of the day, the Atlantic Sunrise route will ultimately be ensured of a full and complete record. And, as you are all aware, in this environment we simply want to get it done right, particularly concerning the route. You will notice that all these projects have the potential to be placed in service during 2018, highlighting what an inflection year 2018 can be for 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. I would 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 four 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 that 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 cash flow yield. At a range of realized prices between $2.50 and $3 per Mcf, our stand-alone Marcellus asset generates between $1.1 billion and $1.6 billion pre-tax free cash flow. We will have the inventory to hold production flat at those levels until 2037. 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 -- Lydee, Tennessee, Millennium -- reduces significantly, while our exposure to NYMEX, the DC market area and the new-build power generation facilities increases significantly. While we fully believe that in-basin pricing will improve dramatically during this period as major projects like Atlantic Sunrise and Penn East are built, even if you assume there are no changes in NYMEX or regional basis differentials between Q4 2016 and Q4 2018, the addition of our new take-away capacity would improve realized prices by greater than $0.50 per Mcf on all of our volumes. Based on the mid-point of our expectation of Q4 2018 production range, a $0.50 uplift in realized prices would represent over $450 million 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 by-products of this plan based on current strip pricing. As I already highlighted earlier in the call, we plan to generate 5% to 10% production growth in 2017. 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 de-lever by one turn, resulting in year-end 2017 target leverage ratio of one 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 for these take-away projects we highlighted previously and what the expectations are for end-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, de-levering, reducing cash cost and increasing cash margins. While we have not included 2019 growth expectations at this time, given the line-up of new take-away projects slated for mid-to-late 2018 in-service date, it is reasonable to assume 2019 will be another year of robust growth for Cabot Oil & Gas. Gary, with that I will now open the lines up for Q&A.

[Operator:]

[Operator Instructions]. The first question comes from Drew Venker with Morgan Stanley. Please go ahead.

[Drew Venker:]

I was hoping you could talk about your basis expectations for Q4 and 2017? The exposure you gave us is very helpful color. I thought maybe you can give some more detail?

[Dan Dinges:]

I'm sorry. I didn't hear the first part. Our base what?

[Drew Venker:]

Your basis expectations for Q4 in 2017?

[Dan Dinges:]

Okay. Jeff is an expert in this 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. As you know, I will preface this by saying that basis has been extremely volatile from the first Q, second Q and then rolling into Q3 of 2017. We see a lot of volatility and we anticipate that volatility to continue into the future to have a fair way of where we think the differentials are going to be is not easy, but we have given it a shot.

[Jeff Hutton:]

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 highlight in the guidance and in the slides exactly what our exposures are to each particular index. Based on the pie chart you see and on the guidance, you get a pretty good idea of where the exposure lies. It's been up and down all year long. We had a very bad first quarter because of weather. It tightened up considerable in Q2. We had another semi-blowout I would say in Q3. Basically, it's strengthening on the cash market. We had a very good year on cash in terms of -- I wouldn't say a very good year, I'd say better than what we expected with the weather and the storage conditions. If you review the pie chart closely, you'll see the exposures.

[Drew Venker:]

Just on a relative basis, Jeff, is it fair to assume that this strip is right for 2017. Absolute price should be better, but maybe differentials a little wider relative to NYMEX?

[Jeff Hutton:]

Yes.

[Drew Venker:]

Okay. 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. If you talk about how much you have been using this Gen 4 within your total program, are we looking at four pads and that's the extent of what you have tested or has this been more common in your program in 2016?

[Dan Dinges:]

No, we certainly have tested more than four pads. On the four 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 3 and Gen 4. 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 can extrapolate on those with the results, but we don't have on all of those the exact side-by-side, apple-and apples comparison. We did see positive results in the majority of the Gen 4 completions that we have implemented.

[Drew Venker:]

One last one, maybe for Jeff on Atlantic Sunrise, this mid-2018 start-up seems, to me at least, that it's been a risked 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-2018 start-up date? Is that a fair amount of protection baked in?

[Jeff Hutton:]

Yes, there's a lot of issues to be resolved over the next few weeks in terms of the fine-tuning in the schedule, per se. Giving you an exact date on those to proceed, not able to do that. That's probably a good question Monday on the Williams call. As far as mid-2018, looking at all the different accomplishments that need to take place between now and then, it certainly is doable. I wouldn't say there's some fluff in there, but certain events have to take place. But we're comfortable on the mid-2018 date from where we're right now.

[Operator:]

The next question comes from Neal Dingmann with SunTrust. Please go ahead.

[Neal Dingmann:]

Dan, a follow-up to that question about the fourth gen, is that plans going forward will use that larger completion design, it sounds like on most, given the positive results you are seeing?

[Dan Dinges:]

We will -- not only on most, but on all. We plan on, with the completions that we have going on out in front of us in the fourth quarter and the completions that we have scheduled for 2017, we will implement this Gen 4 completion design.

[Neal Dingmann:]

Then Dan, I know some others have mentioned about -- at least when it comes to sand and some 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 will see a Gen 5 or a Gen 6? How do you guys think about pushing the envelope on these completion designs?

[Dan Dinges:]

I will let Phil Stalnaker, who runs our Marcellus, answer that briefly. But I would first say that we still, even within Gen 4, we're still doing some tweaking. I would anticipate there might be modifications and maybe something -- either a Gen 4-A or a Gen 5. I'll let Phil give us a range of some of the things we're tweaking.

[Phil Stalnaker:]

Like Dan said, we're looking at multiple things -- the number of clusters, the rate that we're pumping, different concentrations of the sand. We're constantly trying to tweak this program and get the best value for it. Again, it's still a work in progress.

[Neal Dingmann:]

Dan, lastly, we've seen the M&A activity pick up, both in the Marcellus and in the Eagle Ford. Your thoughts? Are you all just looking at bolt-on or are you always looking at deals in both? You definitely alluded to that slide 7, certainly a large bit of returns over the Marcellus for you all. When you look at M&A activity, how do you think about both areas?

[Dan Dinges:]

We look at value. Blind on commodity, though we have expertise in both oil and gas by virtue of our two regions. We're looking at the value proposition, looking at what can compete for our capital and provide what our strategy is. That is to deliver a growth with a high-return profile to it. I think the activity and in the Eagle Ford, I think the activity in the Marcellus, could be a reflection of maybe how the activity in the Permian back 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're informed with the transactions that have taken place by either being in data rooms or doing our own evaluation of the transactions that have taken place. But our primary consideration on our evaluation is value.

[Operator:]

The next question comes from Jeffrey Campbell with Tuohy Brothers. Please go ahead.

[Jeffrey Campbell:]

I wanted to ask you on slide 5, is it correct that you had better than two years of Fortune data, as the slide implies or is that a shorter data set and it's been extrapolated out?

[Dan Dinges:]

No, back to the comment I've made about different tweaks and trying different things that make a lot of sense, we have a 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-well bore spike on high IPs and then have a fall-off later that yielded a reduction in the return. Keep in mind, earlier on when we were doing these completions, the cost of completion was higher early on. 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. 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'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.

[Jeffrey Campbell:]

I wanted to ask you, superficially it appears 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 2017 spend is not going to produce until 2017?

[Dan Dinges:]

What part of the 2016 is not going to produce until 2017?

[Jeffrey Campbell:]

Correct.

[Dan Dinges:]

Basically going to be our wells that we have scheduled to complete late in the fourth quarter.

[Jeffrey Campbell:]

The $35 million additional CapEx is basically it?

[Dan Dinges:]

Right.

[Jeffrey Campbell:]

Or that portion of it that's going to be for--

[Dan Dinges:]

That's allocated to the completions in the fourth quarter.

[Jeffrey Campbell:]

Finally, if I could ask a higher-level question. Regarding Constitution, you actually have two actions going. You've got the appeal on the second circuit and then you've got a separate action in the northern district. I was curious, are you any more confident in one approach than the other? 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?

[Dan Dinges:]

Well, great question. I can make a macro comment in regard to the latter part, Jeffrey or that comment. Then I'll turn it to Jeff to get some color on the Constitution in the two courts. We're faced with a challenge on the energy space -- not just Atlantic Sunrise, Constitution, but Access and other pipelines and infrastructure that are going to be challenged by activists that quite frankly 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. 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 have 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. I think they take that very seriously. 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. Hopefully, answering those questions on the front end will mitigate some of the delays we have seen in some of these projects as we move forward. I will, just before I turn it to Jeff, I will 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. In looking at Atlantic Sunrise, Atlantic Sunrise is a Pennsylvania pipeline. Atlantic Sunrise is a pipeline that for particularly Cabot's position, we see a need on the other end of Atlantic Sunrise once it is constructed. More importantly, there are areas in northeast Pennsylvania that royalty owners in northeast Pennsylvania are getting virtually no return for their 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 coffers in the form of revenue and taxes, because of the significant impunities that have been in that area because of the gas-on-gas competition. In referencing Governor Wolf's letter, I think he recognizes that getting an infrastructure, in particular 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. 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.

[Jeff Hutton:]

Okay, well, we certainly do like the Second Circuit action. The appeal is very simple. If you read the briefs at all, you'll see the case that we laid out is in our opinion very strong, very clear. Even the affidavits and testimonials at the end on the conversations between the DEC and our environmental folks is very clear. We read the respondents brief, as well. It was again, in our opinion, not very strong. Of course we filed a reply to that brief. Now it's in the hands of the court. 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. If it wasn't for the duration of that particular action, we would like it probably equally with the appeal. We're going down two paths. We think they're both very strong and we'll see what happens.

[Operator:]

The next question comes from Brian Singer with Goldman Sachs. Please go ahead.

[Brian Singer:]

Going back to the earlier question with regards to slide 5 and the fourth-generation completions, how much actual data do you have for the pads that you mentioned, A? Then B, when you look at the out-performance that you are seeing slash expect, do you view this as an increase in recovery rate or are you simply recovering the same hydrocarbon overall, but doing it more efficiently with fewer wells?

[Dan Dinges:]

All right. I'm going to answer first, then I'm going to turn it to Phil. 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 all of our drilling up there. The spacing on these and where we blade the laterals, we think it's all incremental reserves. We're comfortable with that. I'll let Phil answer the rest of it.

[Phil Stalnaker:]

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. You're seeing pretty much everything we have on these different pads.

[Dan Dinges:]

We obviously have, Brian, we obviously have purposely left off specifics. The specifics we left off was to mitigate the street getting out ahead of us on trying to pre-empt our year-end reserve review. Our year-end reserve review and audit is we go into excruciating detail. We do 100% audit. We'll come out with that after the end of the year. But in 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.

[Brian Singer:]

And then I guess shifting to the free cash flow that you're expecting beginning next year and continuing. This is not a new question, but you talked about M&A a little bit earlier. I wonder if you 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 coffer for potential M&A?

[Dan Dinges:]

All the above is still consideration at this point 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. I know Scott gets a little concerned about too low of debt levels. 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 value consideration as priority one, two and three. Knowing that we have such a world-class return profile for our Marcellus, we want to make sure if we do have projects outside, that it's going to be somewhat competitive with where we might allocate that free cash and to convene favorably with our Marcellus allocation. In this low-commodity price environment, still having efficiency gains in a lot of areas, including our Marcellus, we're penalized by the northeast differentials that we experience up there. We think we have a fix that has been slit out from what we originally had anticipated -- extremely frustrating from our perspective that we're moving gas in the range that we're moving it in. But we do think we have some daylight coming down the road. With that daylight, I don't think we will 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 with go that route.

[Operator:]

The next question comes from Charles Meade with Johnson Rice. Please go ahead.

[Charles Meade:]

I wanted to ask another question about that slide on the Gen 4 completions. I appreciate your comments about trying to withhold some information. I recognize we can create a lot of mischief with partial information, but--

[Dan Dinges:]

No.

[Charles Meade:]

Yes. 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 are observing across these floor pads is within the range of what you would expect once you used it in your whole development program?

[Dan Dinges:]

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-well bore dynamics that we're seeing and the amount of rock that we're breaking up. I think the conductivity that we're creating near-well boar with the Gen 4 completion scheme is yielding the results that we're seeing.

[Charles Meade:]

Got it. Maybe that variance that you see, within the variations of -- within Gen 4, that explains the way some pads are responding better than others, if I'm understanding correctly?

[Dan Dinges:]

Well, obviously we tried to mitigate the sample pool's variability by what we 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 the fractured areas that we have out there. Again, this is as close to variability as we can create without a larger sample pool, if you will. In some of the variability -- and are you talking about when you go out to the 750 to 1,000 days, are you talking about the delta between the two Gen 3 and Gen 4 curves?

[Charles Meade:]

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. When I eyeballed it, it looked like 10 to 20 -- it was helpful that you quantified in at 20 -- but I was wondering why you thought some pads it was on the lower end and why on some pads it was at the higher end?

[Phil Stalnaker:]

Even on this page there's difference in the concentration between maybe pad A and pad B. 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 between those pads.

[Charles Meade:]

If I could sneak in one last one on the well cost. Perhaps I'm missing something, but when I look at your new well cost of $7.9 million, I noticed you guys said that includes some kind of service cost inflation and it's also an 8,000-foot lateral. When I compare that to your $8.14 per lateral food, from mid-2016, it looks like there's a -- on a lateral adjusted basis, it looks like there's an uplift of about $1.5 million a well. I'm wondering, am I missing something there? Assuming I'm not, how does that $1.5 million break up to -- what portion is service cost inflation and then what part is perhaps additional cost from this Gen 4?

[Dan Dinges:]

Well, Charles, let me give maybe a little bit more color. What lateral length and how many stages are you -- well are you comparing to?

[Charles Meade:]

That would be normalized at the 8000 feet.

[Matt Kerin:]

Charles, this is Matt Kerin. 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. If you take that extra 13 to 14 stages and adjust a little bit for inflationary costs, you'll probably get there.

[Operator:]

The next question comes from Pearce Hammond with Simmons Piper Jaffray. Please go ahead.

[Pearce Hammond:]

Dan, when we look at the 2018 growth that you provided, the 15% to 25%, does that reflect fully filling Atlantic Sunrise with knew volumes or would Atlantic Sunrise have some redirected volumes from other places within your -- within northeast PA?

[Dan Dinges:]

That reflects volumes that would be redirected and does not reflect full volumes on Atlantic Sunrise -- full new volumes on Atlantic Sunrise.

[Phil Stalnaker:]

A combination of old and new.

[Pearce Hammond:]

Then my two quick follow-ups, more housekeeping. In the prepared remarks, you mentioned at $2.50 to $3 realized pricing, you could generate between $1.1 billion and $1.6 billion pre-tax free cash flow. Over what time period was that?

[Dan Dinges:]

We could do that between the end of 2018, with the infrastructures in place through 2037. Then we would have a blow-down case beyond that.

[Pearce Hammond:]

Then final one, what's your rig count that you're targeting next year for Marcellus and then Eagle Ford?

[Dan Dinges:]

Two in the Marcellus and one -- 50% of a rig to 75% of a rig in the Eagle Ford.

[Operator:]

The next question comes from David Deckelbaum with KeyBanc Capital Markets. Please go ahead.

[David Deckelbaum:]

Curious, I guess, since the last update. I think the last time you gave color on achieving mid-single-digit growth in 2017 it was a $6.75 swag number. Should we assume that most of the adjustments are basically that capital efficiency improvement from Gen 4 completions?

[Dan Dinges:]

Yes, that's correct, David.

[David Deckelbaum:]

Curious as I look at the allocation, Jeff, in 2017 for your basis impact. Is there any reflection when you guys are operating at 2 Bcf a day gross or so, have you picked up any capacity on existing lines within basin from some of the competitors that gave up some of their space?

[Jeff Hutton:]

Yes. To be perfectly frank, it's very small scale and it's been month to month. 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 net-backs for that capacity, it's basically red ink. What we have seen is a lot of the locations with capacity that's available to us is reaching -- there's some basis poison in those markets, as well and spreading. 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.

[David Deckelbaum:]

Is it possible for you to loosely quantify the gross volumes available in poisons basis impacts markets right now?

[Jeff Hutton:]

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 to be, so we're seeing a deterioration of prices at MALWA [ph], Arapahoe and to the west, as well. In that respect, it's just not worth spending the money to get additional capacity in this market place until we see some strengthening of basis in other areas.

[Operator:]

The next question comes from Marshall Carver with Heikkinen Energy Advisors. Please go ahead.

[Marshall Carver:]

Yes, the $225 million in maintenance capital for 2017, does that assume completing ducts 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?

[Dan Dinges:]

That includes completion of some ducts, also.

[Marshall Carver:]

For future years, it would probably be a bit higher than that if you wanted it for a run rate, maintenance capital?

[Jeff Hutton:]

That's correct.

[Dan Dinges:]

Yes, the future would be a little bit higher, assuming we don't have any additional efficiency gains. I would say that increase might be $275 million to $300 million -- not increase, but total of $275 million to $300 million.

[Marshall Carver:]

What percentage of your 2015 and 2016 wells were completed with the Gen 4 completions?

[Dan Dinges:]

2015, none -- well, 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.

[Marshall Carver:]

For 2015 and 2016.

[Dan Dinges:]

2015 and 2016 combined.

[Operator:]

This concludes our question-and-answer session. I would like to turn the conference back over to Dan Dinges for any closing remarks.

[Dan Dinges:]

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. While 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, 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. Thank you to all the shareholders we have out there, particularly to our long term shareholders, for their continued patience. I look forward to speaking with the group again in February. With that, Gary, that concludes my remarks.

[Operator:]

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.