Greetings and welcome to the EQT Corporation Year-End Earnings Conference Call. At this time, all participants are in a listen-only mode. A brief question-and-answer session will follow the formal presentation. And as a reminder, this conference is being recorded. I would now like to turn the conference over to, Patrick Kane. Thank you. You may begin.

Thanks, Brenda. Good morning, everyone, and thank you for participating in the EQT Corporation's conference call. With me today are Dave Porges, Chief Executive Officer; Steve Schlotterbeck, President of EQT and President of Exploration and Production; Robert McNally, Senior Vice President and Chief Financial Officer; and Lisa Hyland, Executive Vice President of Midstream. This call will be replayed for a seven-day period beginning at approximately 1:30 Eastern Time today. The telephone number for the replay is 201-612-7415, with the confirmation code of 13637701. The call will also be replayed for seven days on our website. To remind you, the results of EQT Midstream Partners, ticker EQM and EQT GP Holdings, ticker EQGP are consolidated in the EQT's results. Earlier this morning, there was a separate joint press release issued by EQM and EQGP. The partnerships will have a joint earnings conference call at 11:30 AM today, which requires that we take the last question of this call at 11:20 AM. The dial-in number for that call is 201-689-7817. In a moment, Rob will summarize EQT's year-end 2016 results, and Steve will give a brief operational update. Following the prepared remarks, Dave, Steve, Rob and Lisa will all be available to answer your questions. First, I have one administrative note. As a result of the asset dropdowns into EQM, we changed our reporting format for the Midstream business unit. We now report gathering results and transmission results separately, which aligns with EQM's reporting. The Midstream assets that were not dropped into EQM are now rolled into the EQT Production's results. For your use, we have posted on our website, the Q4 and full-year 2016 results using the old format as well as the 2016 quarterly results using the new format. I'd like to remind you that today's call may contain forward-looking statements. You can find factors that could cause the company's actual results to differ materially from these forward-looking statements listed in today's press release and under Risk Factors in EQT's Form 10-K for the year ended December 31, 2015 as updated by any subsequent Form 10-Qs, which are on file at the SEC and available on our website; and under Risk Factors in EQT's Form 10-K for year ended December 31, 2016, which will be filed with the SEC next week. Today's call may also contain certain non-GAAP financial measures. Please refer to this morning's press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. I'd now like to turn the call over to Rob McNally.

Thanks, Pat and good morning, everyone. As you read in the press release this morning, EQT announced 2016 adjusted loss of $0.33 per diluted share, compared to $0.75 adjusted earnings per diluted share in 2015. Adjusted operating cash flow attributable to EQT was $816 million in 2016 compared to $825 million in 2015. The high-level story for the year was very strong volume growth in a lower commodity price environment. As a reminder, EQT Midstream Partners and EQT GP Holdings results are consolidated in EQT's corporate's results. EQT recorded $322 million of net income attributable to non-controlling interest in 2016 and $83 million in the fourth quarter of 2016. Notably, 2016 production volumes were 26% higher than last year and gathering volumes were up by 21%. Due to the lower commodity prices, adjusted EPS and adjusted operating cash flow were both down versus 2015. Although results in both years were impacted by some unusual items that should be considered when interpreting and comparing the results year-over-year. Now, looking at the fourth quarter, adjusted EPS was $0.25 per diluted share that compares to adjusted loss per share at $0.07 in the fourth quarter of 2015. Adjusted operating cash flow attributable to EQT was $327 million in the fourth quarter compared to $239 million for the fourth quarter of 2015. Production sales volume was 28% higher than the fourth quarter of 2015, while commodity prices were slightly lower. During the quarter, we realized better than expected average differential due to a colder December. In the fourth quarter, EQT completed the final drop of Midstream assets to EQT Midstream Partners for $275 million. The dropping included Allegheny Valley Connector, transmission and storage system along with several Marcellus gathering systems. The sale did not include a small gathering system, which was sold in a…

Thanks, Rob. Good morning, everyone, and thank you for joining us. As we announced in early December, we are planning to invest $1.5 billion in 2017, including $1.3 billion for well development. Our 2017 sales volume guidance is between 810 Bcfe and 830 Bcfe, with the 2017 growth coming primarily from completing wells which were spud in 2016. Our 2017 activity will result in 15% to 20% growth in 2018 and we expect to grow in the 15% to 20% range for at least the next several years. Moving on to year-end reserves. Our 2016 year-end total proved reserves increased 35%, to 13.5 Tcfe versus year-end 2015. This increase was driven by our 2016 acquisition activity and our drilling efforts, which continue to expand the boundaries of our core Marcellus and Upper Devonian development areas. Acquisitions added approximately 2.4 Tcfe, 2.1 Tcfe of which is associated with PUD reserves that we will be developing over the next five years. Drilling activity resulted into 2.4 Tcfe of extensions, discoveries and other additions. Excluding the impact of acquisitions, we replaced 246% of our 2016 production. With the acquisitions factored in, we replaced 555% of our 2016 production. Consistent with our consolidation strategy, the average lateral length of our PUDs is more than 600 feet longer than those booked in 2015. It's also worth noting that our 2.4 Tcfe of acquired proved reserves is only associated with reserves directly associated with that new acreage. Over 600 Bcfe of this year's proved reserves resulted from the synergies created from our leasing and acquisition activity. These synergies allowed the lengthening of laterals on our existing acreage and are a key driver of our consolidation strategy that not only adds proved reserves, it also dramatically improves the economics of our existing development opportunities. We continue to…

Thank you, Steve. This concludes the comments portion of the call. Brenda, can we please open the call for questions?

Certainly. Our first question comes from the line of Drew Venker with Morgan Stanley. Please go ahead with your questions. Drew E. Venker - Morgan Stanley & Co. LLC: Good morning, everyone. Steve, congratulations on the new role and Dave, you obviously will be missed. And then maybe if we can just start by, Steve, if you had anymore thoughts on – the focus of your role as you take over the helm and you guys talked more about shifting to more operations related strategy than financially related strategy, do you have any thoughts there?

Well, thanks, Drew. I think just – maybe a – just a couple of general comments in that area. I've been here for 17 years now. So, I've been working either for or with Dave for that entire time. So, I've been involved and certainly onboard with the strategy and the direction of the company. So, I think you shouldn't expect to see dramatic strategic changes in what we're trying to accomplish. More likely, you'll see changes in how we – or how differences and how we function between Dave and I. So we have different personalities and different approaches to things, but I think the general strategy will remain consistent and that is to focus clearly on increasing shareholder value, ultimately a lot of that comes from driving costs lower. And I think you've heard us talk about it, but two big themes here are consolidation and innovation. So, we've talked a lot about longer laterals and economic benefits we get from that. And over the past eight years or so with the Marcellus, you've seen the progress us and the industry has made on improving returns through innovation and new technologies and we will continue to try and be a leader in that area. So, I think there has always been a strong operational focus as well as a strong financial focus. You will see that continue, although I think, there probably a little less financial engineering that will be needed in the future than we've seen over the past seven years or so. Drew E. Venker - Morgan Stanley & Co. LLC: Thanks for that, Steve. So, I guess, if you're talking about focusing on, partly on costs and lateral lengths, how much of extending laterals do you think you can do from really blocking up and acreage swaps versus needing to really consolidate land position through acquisitions?

Well, I think it's going to require both. But I think to get meaningful improvement, it's clearly going to require some additional acquisition opportunities. We've seen significant benefits from the ones we've done, and that's a kind of thing that builds on itself. So the more you do, the more benefit you get even from the previous acquisitions. And that said, the bigger position we build in the core area certainly facilitate additional trades with our partners who are also trying to consolidate their positions because they see the value as well. So, you're going to see both. And I think, we'd like to continue to do some acquisition activity, as I mentioned. We think the smaller deals like we've done are much more likely than any sort of large strategic merging of big players. Drew E. Venker - Morgan Stanley & Co. LLC: Okay. Last one from me, Steve. You guys will have a bigger program in the Upper Devonian this year than I guess last year, in particular, do you feel like you'll likely learn a lot more about how to develop those two concurrently or do you feel like you already know only about the reservoir and incremental earnings will be small?

I think we have a pretty good understanding. I think we have more producing Upper Devonian wells than anyone else. And we feel strongly in the data that's coming in is confirming our belief that within that, that certain area that we show in our Investor Presentation, within that area, it is a user-delusive proposition, and incrementally the NPV per acre is significantly higher if we take the Upper Devonian now in conjunction with the Marcellus than if we don't, and then lose the opportunity forever. So, we feel even more certain about that conclusion today than we did even six months ago. But I think because of the number of wells we are producing, I think, we have a high-level of certainty about the results and what the right approach is in that area. Drew E. Venker - Morgan Stanley & Co. LLC: Thanks for that Steve. And congrats again to both of you.

Thanks, Drew.

Thank you. Our next question comes from the line of Scott Hanold with RBC. Please proceed with your questions.

Thanks, good morning.

Good morning.

So, Steve, I like that – I like the consolidation and innovation theme, it's pretty catching, and pretty applicable to you all. Can you talk a little bit more on the innovations side of things, where can you go from here, I mean, obviously longer laterals, are sort of the – I guess, I'll say the layup, but when you look at just in sort of the proppant loading, stage facing, where you think you could go from where we're at today?

Well, I think on the completion side, as we mentioned before, we've started doing bigger frac jobs and higher proppant loadings. We're not quite ready to announce any revisions to our type curves, but I would expect it will, we'll have an update by the next call. We just want to get a little more data there, and we're expanding that to – we're now testing even higher proppant loads that will take some more time to conclude how much or if, there is a benefit there, but we continue to experiment and look for better ways on the completion side. I would say our innovations aren't solely focused on drilling completion activities though, and a couple areas we're doing a lot of work in are kind of more on the logistical side. So, we're doing a lot of operations research kind of work on our rig scheduling and our frac scheduling and how we move and transport water. And what we're finding through some pretty advanced modeling is our previous assumptions about what was optimum turn out to be pretty far off. And the conclusions from these models really aren't intuitive. Very difficult for a human being to look at a spreadsheet and come up with the optimum schedule. So we're just starting that kind of work. We think the applicability to our business could be pretty widespread and potentially pretty dramatic in terms of lowering our unit operating costs. So a lot of work happening in that area. It'll take some time, but we're pretty excited about it.

Can you give us an example of what you mean by that, just some of the logistical things? Maybe just one salient example just to give us some construct of what you all are doing and seeing?

Sure. So one example we did is we brought in a PhD from Carnegie Mellon University to help us with this modeling because it's pretty advanced stuff for certainly for someone like me. And first thing he did was he did a look-back on a group of pads in Greene County that we had already drilled. So we knew what we had thought was optimum. And our typical assumption was generally if we have multi-well pads, drill all the wells with the rig. It's very expensive to move rigs. It's about $0.5 million every time we move a rig. So we thought it was best to drill all the wells, move the rig somewhere else, bring in the frac crews, bring in the water and the sand, and frac all the wells back-to-back and then bring them all online. And he looked back and built this model which incorporated the logistics of the water, logistics of the crews, the downtime associated with the production, the pipeline capacities and capacity availability, a number of other variables. And the rig schedule that it printed out looked like a pig's breakfast. I mean, it was moving rigs a lot more often than we thought. But said that we would have created significantly more value had we followed that schedule. So that really opened our eyes. And we really thought, well, this might really add some value if we get these kind of results everywhere else. So we're starting to apply that, again, to rig and frac scheduling, but also to helping us decide how to better design our pipeline systems to make that capital more efficient and, importantly, the best ways to move our water, because that's becoming a bigger and bigger piece of our cost structure.

No, that was really helpful. Thanks. And then for a follow-up question, on the consolidation side of things, and it sounds like you did an acquisition here recently. And I'm sorry if I missed it, did you say what the production volume you added from there was? If you have that, that'd be great. But just big picture, how many of these outside of just regular trading – how many of these little bolt-on opportunities are still hanging out there in your core area?

Well, on your first question, it didn't add any current production. This was strictly undeveloped acreage. And I will mention on it just because it makes this one of bit unique, is all of that acreage is either fee, about half of it is in fee, so 100% net revenue interest, and the other half is held by production by shallow wells. So we'll control that acreage forever and have a very high net revenue interest. Regarding how many others are out there, it's always hard to say because there's been, for the past year or so, a fairly steady flow of opportunities. And we've been involved in all or most of those. And I think we're still optimistic that that flow is going to continue. But it's hard to predict. At any given time, there is two or three that are, I'd say, active. But sometimes active means there is a data room and the seller is clearly motivated to sell. And other times active means we're in discussions with a party and it seems like there might be a deal to be done. But sometimes it doesn't work out. So I would say for the scale of acquisitions we've been doing, we expect the flow to continue for at least a while.

Okay. I appreciate that. Thanks.

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

Morning, gentlemen. Just a couple quick ones. First, maybe on the guidance. Just curious on the expectation for better differentials, what you're seeing there. Is that just two months now of better bid week (26:45) pricing, or if you've got some sort of fundamental change that you're seeing could flow through for the rest of 2017?

Hi, Holly. This is Rob. Really that just reflects what the market pricing is. We're just taking the forward curve at the different places where we sell our gas. So we're not taking a view that's different in the market's. It's just that the forward curve has improved on basis.

Okay. Great. And then maybe, Steve, I know you mentioned MVP, maybe just some thoughts there. It looks like we should receive a Final EIS maybe in mid-March. So, just given kind of what's going on with the Commission right now, just any sort of thoughts there on how this thing could play out for MVP?

Yeah. I think, Holly – well, first of all, the Final EIS is not dependent on having a quorum on the Commission. So, the staff can take care of that. So, we think, as far as the current situation with the commissioners shouldn't have any impact on our receipt of the Final Environmental Impact Statement. We are responding to a long list of questions, which seems to be the norm in today's environment and we continue to hope to get it on time. I think, we understand it, there is a possibility that the FEIS could be delayed. I would say, we still have some slack in the schedule and the real target date for us is to receive the notice to proceed in November. So, I think, we're still optimistic that we're on schedule and we'll be able to get this thing in line by the end of 2018. Probably the last thing, I would say is, a lot of the work we're doing and responding to the questions. We think we'll go a long way toward answering a lot of the questions and help with a lot of the work that the other agencies have to do, once we receive the FEIS. So, even if we get delayed on the FEIS, it doesn't necessarily mean that the entire process is delayed.

No, that's great. Thank you for that. And then maybe one final one from me. On the seven Utica test for 2017, can you give us the PA, West Virginia split?

Well, I would say, right now, we don't know. We're going to keep that open depending on results. Right now, from what we're seeing, I would imagine, the majority will be in Pennsylvania; but as I said, we're currently fracking a well in West Virginia and if that result is encouraging, we might shift a few of them to West Virginia. So, we're going to be driven by the results we see.

Great. Okay. Thanks, guys.

Thanks, Holly.

Our next question comes from the line of Brian Singer with Goldman Sachs. Please go ahead with your questions. Brian Singer - Goldman Sachs & Co.: Thank you. Good morning.

Good morning. Brian Singer - Goldman Sachs & Co.: On the topic of longer laterals without additional acquisitions, where could you get to on a company average basis, a couple years out versus where you are today? And if we think about the acquisition opportunity, is there some way of summarizing, or you could say, for X billion dollars of acquisitions you could take that company average lateral length out to some, fill in the blank greater number?

Well, those are pretty impossible questions to answer. What I can tell you is, when we're looking out 2018, we expect the average to be 8,000 feet or above. So, we continue to increase that average length pretty significantly year-over-year. It's hard to predict with additional acquisitions, what the impacts will be, because they're very dependent on where they're at. Also, dependent on other activity, leasing activity where that is, how contiguous those pieces are? So, it's very tough to answer that. I will say, in theory, we think 15,000 foot laterals are optimum, I don't expect that we will get there, so to be clear on that. But any additional length up to something close to that adds real value to our investment. So, we're going to continue to do everything we can to get them as long as we can. Brian Singer - Goldman Sachs & Co.: Thank you.

Brian, just one – just one additional comment to that is, I would say that we clearly will have a view, if we're doing an acquisition that it is helping us with lateral lengths, if it's not – it's not an acquisition that we would likely do, it's hard to quantify how much that would be, but there will – we will clearly have a view that it's improving lateral lengths. Brian Singer - Goldman Sachs & Co.: Okay. Thank you. And then, having just gone through the reserve report and having acquired some additional acreage, can you just give us an update on the natural gas price points both locally in the local market and Henry Hub where you would both either pull back on activity or accelerate activity?

Well, I think we run most of our economics at the local price. So, if it doesn't make sense at that we're not going to be investing. And I think we've laid out on our Investor Presentation, what our market mix is, and so that should give you a pretty clear idea of – and it's all pretty fungible because of the Equitrans header system, all that's connected. So we can move gas to all those markets pretty easily. And the next big shift you will see beyond the recent OVC and (32:33), the next big one will be when MVP comes operational, and we're selling a lot of gas to the Southeast market. Brian Singer - Goldman Sachs & Co.: Great. Thank you.

You bet.

Our next question comes from the line of Arun Jayaram with JPMorgan. Please go ahead with your questions.

Yeah. I just had a one clarification on lateral lengths, because Steve you talked about wanting to extend laterals, but if we look at the 2017 program, the lateral lengths of the Marcellus are down a little bit, and also for the Upper Devonian. Could you just comment on why you're drilling shorter laterals this year versus last?

Well, I think when it's all said and done, that's probably not likely to be the case, but we did have a large, very long lateral pad right at the end of 2016 that bumped those averages up. Originally, that pad was probably going to be at 2017 pad, but I think that's really an indication of the results we're seeing from the acquisitions, and we're still getting our arms around some of the specifics of the more recent acquisitions, and what they're going to add. So for now, we haven't really built that in. So, I think that's – some of that's just preliminary numbers.

Okay. Fair enough. Fair enough. I just wanted to make sure, but it sounds like the trend is to go to eight in 2018?

Yeah. We'll certainly be above eight in 2018. Yes.

Okay. Great. Great. My follow-up question for you is really to talk a little bit about the 2017 program. I understand that the CapEx program does include cost for your enhanced completion program, but I believe that you guys haven't yet adjusted your type curves to include the uplift from that, so I was just wondering Steve, if you could maybe comment on what you're seeing in terms of potential well productivity gains from using more proppant in stages, clusters et cetera. And perhaps frame some potential upside to production for this year?

Yeah. I think I'm going to pass on that for now. I think we want to gather a little bit more data before we start quoting our uplift estimates. I will say, from the results we're seeing, they seem pretty consistent with what our modeling suggested we'd see. So, we're optimistic that it's working, but we don't quite have enough data to want to commit to any number. So, I'd ask you to hold off until the next call where we would expect to be able to quote something that we can stand behind.

Okay. And just last question regarding MVP. It sounds like you guys are still confident in the timing, but if there are some timing slippage, how could that affect the company and what are some thoughts around managing around that timing risk?

I think the nature of the construction process is the, the critical path on the MVP project is around the compressor station construction, about a 14-months timeframe to do that. So, because of the nature of that, a one-month delay in getting approval is probably a one-month delay in turn in line. The next item on the critical path is the actual construction of the line, which is dependent on our ability to be able to clear trees. And there are limits around because of the bat populations when we're able to do that. So generally speaking, and there are lots of variables to this; none of this is for certain. But delaying the notice to proceed at least on that part of it, because it's possible to get a partial notice to proceed on the compressor stations, but if the pipeline construction is delayed into February, it might get difficult to get the trees cleared in the tree clearing window to hold to that end of 2018 timeframe. So those are kind of some of the key dates we're focused on. But that said, there are possible mitigants to that in terms of, again, partial notices to proceed or possibilities of being able to extend the tree cutting window. So lots of variables, but those are some key dates we're shooting for.

That's very helpful. Thanks a lot.

You bet.

Our next questions comes from the line of Michael Hall with Heikkinen Energy. Please go ahead with your questions.

Thanks. Good morning. I appreciate you having me on the call. I guess I was curious on the West Virginia activity in 2017. I guess 47 wells will be drilling. How much of that would you say is on let's say the Eastern side of the core development area highlighted in the slide decks? And what sort of timeline do you think in terms of providing some incremental well results on that, let's say, more extensional side of the core?

I think – so East versus West. In West Virginia, it coincides pretty well with the wet versus dry. So it's about two-thirds on the wet, so that would be the Western side, one-third on the Eastern side.

Okay.

And I think probably on the next call we can provide some updated information on the results on the Eastern side. I think we have some recent wells over there that we're real happy with the results. So I think our confidence is even higher, particularly like this acquired acreage in Marion and Mon that's right nearby a pad we brought online last fall that's outperforming our expectation. So we'll try to target for the next call or next press release to give you some more insight on that.

Great. That'd be helpful. And it seems like with some of the deals late last year and then now these most recent acreage adds, those seem to be kind of bulking up in that side of the window. Is that a fair statement? And is that kind of a focus area for further acreage consolidation going forward? And how would you characterize that?

I would say we don't have particular focus areas. We look at the opportunities that come up and see how well they fit. And some of those are on the Eastern side in the dryer area fit very, very well. So we get a lot of the synergy value, which is what we're looking for. But as always, they have to make sense. So we're not going to go by acreage in areas where we're not confident we can earn good returns on our drilling investments. Again, we've been pretty encouraged with the results we're seeing in those areas, so I think we feel really good about them. And they've been a particularly nice fit with our existing position.

Great. That make sense. Yeah. It seemed like perhaps with your actions speaking to a view that you thought you had a slightly differentiated view on that, that part of the play. So we'll keep our eyes out. I guess I wanted to follow-up also on I think it was Scott's question around the logistical side of things. Just curious, that logistical optimization you talked about. Might that have impacts around the kind of historical cycle time you guys talked about (40:34) about nine months in the past? Do you think you could potentially shrink that. And what, if any, potential impacts could that have on 2017, or would that be more of a potential impact to 2018 numbers?

We certainly think it could have an impact on that. And if it does, the impact is almost certainly to shorten those cycle times.

Sure. Any quantification...

We already – we haven't done enough of the work yet to really build in any benefit in 2017. Not to say we won't see any. We might. But I would think we'll have enough of the modeling done and tested it enough hopefully by 2018 to incorporate it into our planning.

Okay. Great. Appreciate it.

Our next questions comes from the line of Neal Dingmann with SunTrust. Please go ahead with your questions.

Morning, guys. Steve, the first question I had was more on the new acreage everybody has been talking about around West Virginia. Is there a room of just looking at that Equitrans expansion project, is there room on that for incremental production there? Or what are you thinking about takeaway in that area?

Do you want to take that, Lisa?

Hi. This is Lisa Hyland. We are certainly in the process of working through the Equitrans expansion project. And we do have expansion capabilities that would line up with MVP expansion capabilities as well.

Okay. Okay. Great. And let me ask just a second one, Steve, for you on this – the new acreage, you mentioned in the press release talking about the 42,600 in the Marcellus in West Virginia. Now there are 17,000 in the Marcellus in southwestern Pennsylvania, and that mentions about 39,300 of that has Utica on both, does that mean you all have – have just you bought the deep rights just on 39,000 or you currently are just assuming the 39,300 has the potential, maybe I just want to make sure I'm think about that correct?

That was just the rights that we acquired. So, it's not a comment on the prospectivity of any of that, that's the Utica rights that came with that package.

Okay. So that's 60,000, about two-thirds of that, then you acquired the Utica rights with? Is that correct, Steve?

Yes, yes, that's correct.

Okay, okay. And then just last one I had was, we have certainly seen a nice uptick in NGL prices. Does that – I know people have – and you've kind of talked about Steve on the call so far, where you are thinking about drilling with all the rigs you are certainly going to be active? Does the improvement of NGL prices change how you think about target areas? I mean, when I look particularly in the Marcellus, you've got that rectangle always laid out where you're looking at new and existing acreage. Does the improvement of NGL prices change or you might target some of the drilling for the latter part of this year?

Neal, I don't think the changes in NGL prices so far have been dramatic enough to have us rethink where we think we're going to be drilling. And there is always a number of factors that go into how we develop our plan. Certainly prices are a big factor, but available capacity where the gathering systems or – have capacity to get gas to market, where we have processing capacity. And at least personally I'm always reluctant to make short-term changes in our plans, based on short-term changes in commodity prices, especially given the nine month to 12 month delay from when we change our plans to when we're getting the production online. It just seems like every time we try and do that, we're never in sync with the market, we're always chasing the market and it's changed by the time we benefit from it. So, the moves would have to be dramatic and we'd have to have a view that they are going to be sustained before we would really rework calendar year development plan.

That sort of makes sense. And maybe if Lisa could maybe just comment on one other takeaway question about all the Utica drilling potentially doing either in PA or West Virginia. Just sort of how you all look for takeaway this year with Utica, takeaway in those areas?

I think for the areas we were likely to test, we have plenty of takeaway for seven wells. So, I think the takeaway question really isn't going to factor into where we're drilling, these tests are still mostly designed to understand the reservoir. Again I think on the cost side, we're real happy with where we're at. But we want to understand what the production mechanisms are, what the recoveries are going to be and what's the extent of the economic area of the Utica. So that's what's going to drive our location decisions in 2017.

Great. Thanks for the details, Steve and Lisa.

Okay.

Thank you. This concludes today's question-and-answer session. I would like to turn the floor back to management for closing comments.

Thanks, Brenda. And thank you all for participating.