EQT Corp (EQT) 2016 Q4 法說會逐字稿

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.

(Operator Instructions)

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, Operator.

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 1:30pm 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 the EQT Midstream Partners ticker, EQM and EQT GP holdings, ticker EQGP are consolidated in 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 11:30am today, which requires that we take the last question of this call at 11:20am.

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 dropouts 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 would 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 other 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 other risk factors in EQT's Form 10-K for the 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 would 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 Corporate's results.

EQT recorded $322 million of net income attributable to noncontrolling 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 of $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 drop included the 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 separate transaction for $75 million resulting in total proceeds of $350 million from the transactions.

Now I'll move on to a brief discussion of results by business segment.

I will limit my discussion to the full-year results as the explanations for the full year, for the most part apply to the fourth quarter as well.

Starting with the production results.

EQT production achieved record production sales volume of 759 Bcfe for 2016, again representing a 26% increase over 2015.

As has been the case for many years now the story in 2016 at EQT production was strong production growth driven by production from Marcellus Shale wells.

2016 was our seventh straight year of more than 25% sales volume growth.

However, lower average realized prices more than offset the increased production in our financial results.

The average realized price, including cash-settled derivatives, was $2.47 per Mcf for 2016 which was $0.62 or 20% lower than last year.

For the full year, total operating expenses at EQT production were $2.1 billion or 6% higher year over year.

DD&A, gathering transmission, processing and SG&A were all higher, again, consistent with the significant production growth.

Per unit LOE, including production taxes were 21% lower for the year as volume increased more than expenses.

Now moving on to the Midstream results.

EQT gathering operating income was $289 million, up 19% year over year, mainly as a result of increased gathering revenues partly offset by increased operating expenses.

Total operating expenses were $109 million, or $17 million higher than 2015.

Looking at EQT transmission, operating income was $238 million, 12% higher than 2015.

Operating revenues were $40 million higher than 2015, primarily due to affiliate contracting for additional capacity under firm contracts, primarily on the Ohio Valley Connector which was placed into service October 1, 2016.

Operating expenses were $100 million or $10 million higher than in 2015.

And finally, our standard liquidity update, we closed the year in a great liquidity position with zero net short-term debt outstanding under EQT's $1.5 billion unsecured revolver, and about $1.4 billion of cash and marketable securities on the balance sheet, excluding EQM.

We currently forecast $1.3 billion of operating cash flow for 2017 at EQT, which includes approximately $200 million of distributions to EQT from EQGP.

So, we are fully capable of funding our roughly $1.5 billion of 2017 CapEx, which excludes EQM and EQGP with operating cash flow as well as the current cash on hand.

With that I will turn the call over to Steve.

Thanks, Rob.

Good morning everyone, and thank you for joining us.

As we announced in early December we're 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 a 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 crude 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 of which is associated with PUD reserves that we will be developing over the next five years.

Drilling activity resulted in 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 are 2.4 Tcfe of acquired crude reserves is only associated with reserves directly associated with that new acreage.

Over 600 Bcfe of this year's crude reserves resulted from the synergies created from our leasing and acquisition activity.

These synergies allowed the lengthening of laterals on our existing acreage and our key driver of our consolidation strategy that not only adds crude reserves, it also dramatically improves the economics of our existing development opportunities.

We continue to focus on operational efficiencies, and the combination of longer laterals and technical improvements has decreased our per unit development costs year over year.

Our development costs from Marcellus wells completed in 2016 was $0.72 per Mcfe, 10% lower than the $0.80 per Mcfe for last year's Marcellus wells.

Compared to last year, total probable and possible reserves are 2.1 Tcfs lower due to a 7.2 Tcf reduction in the Huron.

However, Marcellus and Upper Devonian probable and possible reserves are up 5.3 Tcfe or 83% from 2015.

Regarding our total resource potential figures it should come as no surprise that our acquisitions helped increase our estimate significantly.

But, I do want to emphasize our Utica estimates still only reflect the 30 Tcfe associated with what we believe is in the core.

Additionally, the only proof Utica reserves booked this year are from the five producing wells which still have approximately 39 Bcfe of net remaining reserves.

We have not yet booked any proved undeveloped probable or possible reserves in the Utica.

The questions on investors minds most recently have been on the status of MVP, the Utica, and consolidation.

I will briefly update you on these three topics.

There's not much to update on MVP.

Last September we received the first draft environmental impact statement and a comment period on the draft EIS ended in late December.

We are currently preparing responses to a FERC environmental information request which is typical for the process as a commission works to develop the final EIS.

We continue to target a late 2018 in-service date.

On the Utica, since last quarter we have not turned any new wells online.

We're currently fracking the big 177 in West Virginia and we're also currently drilling another well in Greentown, Pennsylvania.

We plan on spudding seven Utica test wells during 2017.

On consolidation, as I mentioned last quarter, we added a 230,000 net core Marcellus acres from 2013 to 2016.

We believe the biggest benefit from continued consolidation is the economic benefits of longer laterals.

We will continue to look to add acreage that bolts on or fills in our existing core acreage position.

This week we purchased an additional 14,000 core West Virginia acres primarily in Marion and Monongalia Counties, West Virginia for $130 million.

Consistent with our objective of extending laterals, this acquisition will allow us to extend 64 well locations from an average of 1,900 feet to 5,700 feet.

The latest deal is consistent with our previous comments on consolidation.

One, we're focused in our core, motivated by longer laterals; and two, small deals are more likely than larger acreage deals or corporate transactions.

Our focus continues to be increasing shareholder value by focusing on full-cycle returns.

We will accomplish this by driving development and operating costs lower, expanding optionality in our sales portfolio to improve our realized prices and maintaining a strong balance sheet in order to weather the inevitable commodity price cycles.

With that I will turn the call back over to Pat Kane.

Thank you, Steve.

This concludes the comments portion of the call.

Operator, can we please open the call for questions?

(Operator Instructions)

Drew Venker, with Morgan Stanley.

Good morning, everyone.

Steve, congratulations on the new role, and, Dave, you obviously will be missed.

I thought maybe we could start by, Steve, if you had any more 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, if you had any thoughts there?

Thanks, Drew.

Just a couple of general comments in that area.

I've been here for 17 years now.

I've been working either for, or with, Dave for that entire time.

I've been involved and certainly on board with the strategy and the direction of the Company.

I think you shouldn't expect to see dramatic strategic changes in what we are trying to accomplish.

More likely, you will see changes in how we -- differences in how we function, between Dave and I. 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 cost lower.

I think we -- you've heard us talk about it, but two big themes here are consolidation and innovation.

We've talked a lot about longer laterals and the 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'll see that continue.

Although I think there is probably a little less financial engineering that will be needed in the future than we've seen over the past seven years or so.

Thanks for that, Steve.

You're talking about focusing partly on costs and lateral lengths.

How much of extending laterals do you think you can do from merely blocking up and acreage swaps versus needing to really consolidate land positions through acquisitions?

I think it's going to require both.

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.

That's the kind of thing that builds on itself, so the more you do, the more benefit you get even from the previous acquisitions.

That said, the bigger position we build in the core area certainly facilitates additional trades with our partners who are also trying to consolidate their positions because they see the value as well.

You're going to see both.

I think we would 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.

Okay.

Last one for me, Steve.

You guys will have a bigger program in the Upper Devonian this year than last year, in particular.

Do you feel like you will likely learn a lot more about how to develop those two concurrently?

Or do you feel like you already know plenty 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.

We feel strongly in the data that's coming in is confirming our belief that within that certain area that we show in our investor presentation, within that area, it is a use-it-or-lose-it proposition.

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.

I think, because of the number of wells we have producing, I think we have a high level of certainty about the results and what the right approach is in that area.

Thanks for that, Steve, and congrats, again, to both of you.

Thanks, Drew.

Scott Hanold, RBC.

Thanks.

Good morning.

Good morning.

Steve, 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 innovation side of things?

Where can you go from here?

Obviously, longer laterals are the -- I will say the layup -- but when you look at just in the proppant loading, stage spacing, where do you think you can go from where we are at today?

I think on the completion side, as we mentioned before, we 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 that we will have an update by the next call.

We just want to get a little more data there.

We are expanding that to -- we are 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 are not solely focused on drilling completion activities.

A couple areas that we are doing a lot of work in are more on the logistical side.

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 turned 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.

We are 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.

Lot of work happening in that area.

It will 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 to give us some construct of what you all are doing and seeing?

Sure.

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.

We knew what we had thought was optimum.

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.

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.

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 and a number of other variables.

And the rig schedule that it printed out looked like a pig's breakfast.

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 this might really add some value at this -- if we get these kind of results everywhere else.

We are 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 is becoming a bigger and bigger piece of our cost structure.

That was really helpful.

Thanks.

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 that you added from there was?

If you have that, that would 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?

On your first question, it did not add any current production.

This was strictly undeveloped acreage.

I will mention on it just because it makes this one a 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 will 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 has been, for the past year or so, a fairly steady flow of opportunities.

We've been involved in all or most of those.

I think we are still optimistic that flow is going to continue.

It's hard to predict.

At any given time there is two or three that are, I would 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 are in discussions with a party and it seems like there might be a deal to be done, but sometimes it doesn't work out.

I would say for the scale of acquisitions we've been doing, we expect the flow to continue for at least a while.

I appreciate that.

Thanks.

Holly Stewart, with Scotia Howard Weil.

Good morning, gentlemen.

Just a couple quick ones.

First, maybe on the guidance.

Just curious on the expectation for better differentials, what you are seeing there.

If that's just two months now of better bid-week pricing or if you've got some fundamental change that you are seeing good flowthrough for the rest of 2017?

Hello, Holly.

This is Rob.

Really, that just reflects what the market pricing is.

We're taking the forward curve at the different places where we sell our gas.

So, we are not taking a view that's different than the markets.

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.

Just given what's going on with the commission right now, just any thoughts there on how this thing could play out for MVP?

I think, Holly, first of all, the final EIS is not dependent on having a quorum on the commission.

So the staff can take care of that.

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.

We continue to hope to get it on time.

I think we understand that there is a possibility that the FEIS could be delayed.

We'd say we still have some slack in the schedule, and the real target date for us is to receipt the notice to proceed in November.

I think we are still optimistic that we are on schedule and will 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 in responding to the questions, we think will 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.

Even if we get delayed on the FEIS, it doesn't necessarily mean that the entire process is delayed.

That's great.

Thank you for that.

Maybe one final one for me, on the seven Utica tests for 2017, can you give us the PA/West Virginia split?

I would say right now, we don't know.

We're going to keep that open depending on results.

Right now from what we are 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.

We are going to be driven by the results we see.

Great.

Thanks, guys.

Thanks, Holly.

Brian Singer, with Goldman Sachs.

Thank you.

Good morning.

Good morning.

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 where 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?

Those are pretty impossible questions to answer.

What I can tell you is when we are looking out 2018, we expect the average to be 8,000 feet or above.

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 are at.

Also dependent on other activity, leasing activity, where that is.

How contiguous those pieces are.

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, be clear on that.

But any additional length up to something close to that adds real value to our investment.

So, we are going to continue to do everything we can to get them as long as we can.

Brian, just one additional comment to that, 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 we would likely do.

It's hard to quantify how much that would be, but we will clearly have a view that it's improving lateral lengths.

Okay.

Thank you.

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 either pull back on activity or accelerate activity?

I think we run most of our economics at the local price.

If it doesn't make sense at that, we are not going to be investing.

I think we've laid out in our investor presentation what our market mix is.

So that should give you a pretty clear idea, and it's all pretty fungible because of the header system on the Equitrans header system.

All that is connected, so we can move gas to all those markets pretty easily.

The next big shift you will see beyond the recent OBC and REX capacity, the next big one will be when MVP becomes operational and we are sending a lot of gas to the southeast market.

Great.

Thank you.

Arun Jayaram, with JPMorgan.

Yes, I just had 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 for 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?

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 a 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 are going to add.

For now, we haven't really built that in.

So, I think some of that is just preliminary numbers.

Okay.

Fair enough.

I just wanted to make sure.

It sounds like the trend is to go to eight in 2018.

Yes.

We will certainly be above eight in 2018.

Yes.

Okay.

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 costs for your enhanced completion program, but I believe that you guys haven't yet adjusted your type curves to include the uplift from that.

Wondering, Steve, if you can maybe comment on what you're seeing in terms of potential well-productivity gains from using more proppant and stages clusters, et cetera, but perhaps frame some potential upside to production for this year?

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 would see.

We are optimistic that it's working.

We don't quite have enough data to want to commit to any numbers.

I would 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.

Just a 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-month time frame 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 are able to do that.

So, generally speaking, and there are lots of variables, so none of this is for certain.

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 time frame.

So those are kind of some of the key dates we are 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.

Michael Hall, with Heikkinen Energy.

Thanks, good morning.

Appreciate you having me on the call.

I was curious on the West Virginia activity in 2017.

47 wells will be drilling.

How much of that would you say is on the eastern side of the core development area highlighted in the slide decks?

And what timeline do you think in terms of providing some incremental well results on that, let's say, more extensional side of the core?

So east versus west in West Virginia coincides pretty well with 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.

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 are real happy with the results.

Our confidence is even higher, particularly this acquired acreage in Marion and Mon, that's right near by a pad we brought online last fall that's outperforming our expectations.

We will try to target for the next call or next press release to give you some more insight on that.

That would be helpful.

It seems like with some of the deals late last year and now these most recent acreage adds, you seem to be bulking up in that side of the window.

Is that a fair statement?

And is that a focus area for further acreage consolidation going forward?

Or 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.

Some of those 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.

We're not going to go buy acreage in areas where we're not confident we can earn good returns on our drilling investment.

Again, we've been pretty encouraged with the results we're seeing in those areas.

So, I think we feel really good about them.

They've been a particularly nice fit with our existing position.

That makes sense.

It seemed like perhaps with your actions speaking to a view that -- I thought you had a slightly differentiated view on that part of the play.

We will keep our eyes out.

I wanted to follow up also on, I think it was Scott's questioning around the logistical side of things.

Just curious if that logistical optimization you talked about, might that have impacts around the historical cycle time you guys talked 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 number?

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

(Multiple speakers) we haven't done enough of the work yet to really built in any benefit in 2017.

Not to say we won't see any; we might.

But I would think we will have enough of the modeling done and tested it enough hopefully by 2018 to incorporate it into our planning.

Okay.

Great.

Appreciate it.

Neal Dingmann, with SunTrust.

Good morning, guys.

Steve, a quick first question I had was more on the new acreage everybody's been talking about around West Virginia.

Is there room -- I was just looking at the Equitrans Expansion Project.

Is there room on that for incremental production there?

Or what are you thinking about takeaway in that area?

You want to take that, Lisa?

This is Lisa Hyland.

We're 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.

Great.

Let me ask a second one, Steve, for you, on this new acreage.

You mention in the press release talking about the 42,600 in the Marcellus in West Virginia another 17,000 in the Marcellus in southwestern Pennsylvania, and it mentions about 39,300 of that has Utica on both.

Does that mean you all have just -- you bought the deeper rights just on 39,000?

Or you currently are just assuming the 39,300 has the potential?

I just want to make sure I'm thinking about that correct.

That was just the rights that we acquired.

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 60,000, about two-thirds of that you acquired the Utica rights with.

Is that correct, Steve?

Yes, that's correct.

Okay.

Just last one I had was, we've certainly seen a nice uptick in NGL prices.

I know people, and you've talked about it, Steve, on the call so far, where you're thinking about drilling with all the rigs.

You guys certainly are 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 where 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 are going to be drilling.

And there's 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 are -- 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 9 to 12 month delay from when we change our plans to when we are getting the production online.

It just seems like every time we try and do that, we are never in sync with the market.

We're always chasing the market, and it's changed by the time we benefit from it.

The moves would have to be dramatic and we would have to have a view that they're going to be sustained before we would really rework a calendar year development plan.

That certainly makes sense.

And maybe if Lisa could maybe just comment on one other take-away question about all the Utica drilling potentially doing either in PA or West Virginia.

Just how you all look for takeaway this year with Utica takeaway in those areas?

I think for the areas that we're likely to test, we have plenty of takeaway for seven wells.

I think the take-away question really isn't going to factor into where we are drilling.

These tests are still mostly designed to understand a reservoir.

I think on the cost side, we are really happy with where we are 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.

That's what's going to drive our location decisions in 2017.

Great.

Thanks for the details, Steve and Lisa.

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.

Thank you.

This concludes today's teleconference.

You may disconnect your lines at this time.

And thank you for your participation.