EQT Corp (EQT) 2016 Q1 法說會逐字稿

Greetings, and welcome to the EQT Corporation first quarter 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.

It is now my pleasure to introduce your host Mr. Pat Kane, Chief Investor Relations Officer.

Thank you.

You may begin.

Thanks, Adam, and good morning everyone and thank you for participating in 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; Randy Crawford, Senior Vice President of EQT and President of Midstream and Commercial; and Rob McNally, Senior Vice President and Chief Financial Officer.

This call will be replayed for a seven day period beginning at approximately 1:30 p.m.

Eastern today.

The telephone number for the replay is 201-612-7415.

The confirmation code is 13634047.

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 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 10:30 a.m.

today, which requires that we take the last question at 11:20 this morning.

The dial-in number for that call is 201-689-7817.

In a moment Rob will summarize EQT's first quarter 2016 results.

Next, Steve will give a Utica update, and finally, Dave will discuss certain market and strategic matters.

Following the prepared remarks, Dave, Steve, Randy, and Rob will all be available to answer your questions.

First, 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 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.

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 of most comparable GAAP financial measures.

I'd now like to turn the call over to Rob McNally.

Thank you, Pat.

Before reviewing the Q1 results, I want to review changes to our price reconciliation and production segment page.

Historically, we presented the cost of gathering and transporting our gas as revenue deductions on the price reconciliation and production segment page.

Starting today, gathering transmission and processing costs are not reported as expenses on the production segment page.

The exception is that transportation charges for capacity not used to transport EQT produced gas, which is either resold or used to transport purchased gas by our marketing group, is still presented as a revenue offset in accordance with GAAP.

The new net marketing services line on the production segment page includes these costs as well as the related recoveries, both of which are now excluded from the price reconciliation.

Previously, these capacity costs, which were $0.23 per Mcf for the first quarter of 2016, were reported as a third-party gathering and transmission cost on the price reconciliation, while the marketing recoveries, which were $0.26 per Mcf this quarter, were presented as a component of recoveries included in the average differential.

The main change to guidance that you will see is that our differential guidance went from negative $0.40 to negative $0.50 per Mcf for 2016, to negative $0.60 to negative $0.70 per Mcf.

Offsetting this change to reported differential is a change in our guidance to third-party gathering and transmission expense from $0.50 per Mcf for the year, to $0.30 per Mcf.

So, netting these two charges, necessitated by the change in reporting format, is effectively a reiteration of our previous guidance.

We've posted the historic price reconciliation for the first quarter, and the 2015 results by quarter, using the new format on our website.

Finally, we have also posted our updated 2016 guidance conforming to the new format.

Now for an update on the remaining drop-down.

We're currently working through the internal process which includes all the necessary accounting, legal and commercial work.

We expect the drop-down to occur in the second half of the year.

As we've mentioned in the past, there's about $40 million of EBITDA to be dropped down and expect the value to be up to $300 million.

As Pat mentioned, EQT GP Holdings and EQT Midstream Partners?

results are consolidated in EQT Corporation's results.

In this morning's release we added a table for the calculation of net income attributable to noncontrolling interests.

EQT recorded $82.8 million of net income attributable to noncontrolling interest in the first quarter of 2016, as compared to $47.7 million in the first quarter of 2015.

We currently forecast $77 million of net income attributable to noncontrolling interest for the second quarter of 2016, and $320 million for the full-year assuming the midpoint of EQM's guidance.

I will now provide a brief overview of the first quarter results.

As you read in the press release this morning, EQT announced first quarter 2016 adjusted earnings per diluted share of $0.07 compared to $1.07 in the first quarter of 2015.

Adjusted operating cash flow attributable to EQT decreased to $156 million as compared to $218.6 million in the first quarter of 2015.

The high-level story for the first quarter was strong volume growth and a lower commodity price environment.

We had another very solid operational quarter including record produced natural gas sales and record gathering volumes at midstream.

With the exception of a $3.8 million Huron restructuring charge, the first quarter was very straightforward so I'll keep my remarks fairly brief.

The story at EQT Production continues to be the growth in sales of produced natural gas.

Production sales volume of 179.9 Bcfe in the recently completed quarter was 24% higher than the first quarter of 2015 and 16% higher than the fourth quarter of 2015.

As discussed, the lower average realized price more than offset the volume growth.

The realized price was $2.63 per Mcfe compared to $4.06 per Mcfe in the first quarter of last year.

You'll find the detailed components of price in the tables in this morning's press release.

Net marketing services revenue totaled $4.6 million in the first quarter of 2016, $8.6 million lower than the same quarter last year due to incremental capacity costs in the current quarter and colder weather in 2015.

Total operating expenses at EQT Production were $489.3 million or 7% higher quarter over quarter.

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

Although production taxes were lower for the quarter as a result of lower prices.

Moving on to Midstream results.

Operating income here was $141.9 million, 9% higher than the first quarter of 2015.

Operating revenue was $224.7 million, $16.5 million in the first quarter last year as a result of higher Marcellus volumes.

Total operating expenses were $82.9 million, $4.4 million higher quarter over quarter as a result of our continuing growth in the midstream business.

And then finally, our standard liquidity update.

We closed the quarter in a great liquidity position with zero net short-term debt outstanding under EQT's $1.5 billion unsecured revolver and about $1.6 billion of cash on the balance sheet, which excludes cash on hand at EQM and EQGP.

We currently forecast $600 million to $650 million of operating cash flow for 2016 at EQT, which includes approximately $150 million of distributions to EQT from EQGP.

With that, I will turn the call over to Steve.

Thank you, Rob.

My focus today is to provide an update on our deep Utica program.

Our two objectives for 2016 are to get our cost per well down to our target range of between $12.5 million and $14 million per well, and to achieve consistent well results in line with the median of wells drilled in the deep Utica by EQT and our peers so far.

For the Utica to compete for capital with the Marcellus, we are targeting EURs approximately 75% higher than our core Marcellus wells.

The higher EUR per well, combined with the higher percentage of the EUR being produced in the first few years and lower expected gathering compression costs should provide returns competitive with the Marcellus.

We currently have three wells producing, the Scotts Run and Pettit wells in Greene County, Pennsylvania and the Big 190 well in Wetzel County, West Virginia.

The Scotts Run well began declining at the end of March after producing at a flat rate of 30 million cubic feet per day since July 2015, which was a total of 244 days.

The decline is in line with our expectations and our EUR estimate for this well is currently 20 Bcf, or approximately 6 Bcf per thousand foot of lateral.

The result of the Pettit and Big 190 wells, while not as strong as our Scotts Run well, are in line with what we are seeing from other wells in the area.

It is too early to calculate an EUR for these two wells.

The Shipman well was spud in January and is currently being fracked while the West Run well was spud in April.

After West Run, we plan to move back to West Virginia to drill another well in Wetzel County, probably be called the Big 177.

We used ceramic proppant on the Scotts Run and achieved superior results compared to the Pettit and Big 190 wells, which used sand as the proppant.

It's not clear that the proppant difference explains the results, but we have decided to use ceramic proppant in the next three completions, including the Shipman, to determine if the proppant type has an impact on well productivity.

The good news is we have negotiated a 40% reduction in the price of ceramic proppant since the Scotts Run well.

For our typical 5,400-foot lateral, the incremental cost of using ceramics versus sand is now $1.4 million per well, compared to about $2.5 million incrementally at the time we drilled the Scotts Run.

On the cost side we continue to see significant improvement.

Drilling costs continue to come down as we gain experience and improve the techniques and equipment used to drill these wells.

On the completion side, we will be testing dissolvable plug technology for the first time on the Shipman well.

We estimate that this technology will save us an additional $700,000 per well if successful.

Our team continues to safely reduce the cost of these wells and is confident we can achieve our target well cost even with ceramic proppant.

We will continue to provide quarterly updates on our progress in the deep Utica, and I will now turn the call over to Dave.

Thank you, Steve.

I would like to briefly provide two updates and one other comment on today's call.

The first update is to my comments in our February call regarding rig count as a leading indicator of production.

At that time there were 246 gas equivalent rigs, down from the stable level of 700 to 800 that prevailed from about mid-2012 through the end of 2014.

Since that February call, the gas equivalent rig count declined by another 29% to 174 gas equivalent rigs today.

This means we are now down 57% in the past year and 76% since the end of 2014.

We are beginning to see what appear to be some signs of a supply reduction as April US gas production is about 2 Bcf per day lower than the February peak.

While those end 2014 rig counts probably represented far too much development activity, the plateauing and beginning of a decline in production suggest that our thesis of higher future natural gas prices still looks just as solid, even though we confess that the timing of any meaningful price increase continues to be uncertain.

Given our capital strength and the fact that we have not had to make dramatic reductions in staff, we continue to be well positioned comparatively to adjusted development plans should higher prices materialize.

I do personally continue to believe that the eventual price increase will likely eventually overshoot the equilibrium price necessary to balance supply with demand, but that just means we will have to be as disciplined in a more constructive economic environment as we have been in the current less than constructive economic environment.

On a related update, we continue to look to add to our core acreage position, but have not yet announced any transactions.

The good news is that there are many high quality asset packages being marketed in our core focus area.

Along those lines, so that we do not have to break with our practice of not commenting on specific transactions, we wanted to provide some insight into the types of assets that we are examining.

If you look at our website or a hard copy of our most recent investor presentations, you will see a pretty clearly delineated version of our core area, all of which is in the southwestern portion of the Marcellus play.

If you become aware of opportunities that are largely or entirely within our core, you can safely assume that we are looking or have looked at the opportunity.

You can equally safely assume that we are not looking at, and not interested in looking at, opportunities that lie outside our core area, again, as defined by that rectangle in our current investor presentation.

To expand on that somewhat, we further look closely at the number of drilling locations and potential feet of pay in those locations that represent a combination of EQT's existing acreage and development opportunities, and those provided by the target.

True synergies, if you will.

My final comment pertains to an area of financial risk that I focused on early in my time at EQT.

My philosophical objection to shareholders bearing the investment risks of employees?

portfolios via defined benefit pension plans.

The pension benefit obligation was about $150 million when I arrived at EQT those many years ago, and was forecast to be multiples higher than that within a decade.

As a result, I wanted to reduce the extent of the associated investment risk.

We set about shrinking the plan over the years and as a result we were able to apply for and just recently received approval to finally terminate the remaining vestiges of the plan altogether.

There will be a modest charge recorded, possibly as soon as the second quarter, but we will have finally brought that obligation and the risk associated with it down to zero.

In summary, EQT is committed to increasing the value of your shares.

We look forward to continuing to execute on our commitment to our shareholders and appreciate your continued support.

And with that, I would like to turn the call back over to Pat Kane.

Thank you, Dave.

This concludes the comments portion of the call.

Adam, can you please open the line for questions?

Thank you.

(Operator Instructions)

Phillip Jungwirth, BMO Capital Markets

Good morning.

With more production history on the Scotts Run Utica well, how are you thinking about drainage and reconciling the EUR estimates to some of the gas in place estimates out there?

Phil, this is Steve.

I think we are still exploring that.

It is still a fairly anomalous well in terms of how productive it's been.

So clearly, there's really two areas of focus.

One is the size of -- the drainage area size.

So the size of the box that we're drawing from.

Since it is a reservoir we don't have a lot of experience with yet, I think there is still a lot of uncertainty about what the right drainage area is.

And then there is still some questions about, basically, the density of the gas in the reservoir.

So how much can fit inside a given box at these fairly extreme pressures we are dealing with.

Without getting too technical, the behavior of a real gas versus hypothetical gases can vary quite a bit as pressures get into these levels.

So there's some uncertainty about how do you correct for that?

We have a number of experiments and tests going on in both of those areas, but I would say, bottom line is, it's still too early for us to have a good sense for what a recovery factor would be or what proper spacing would be and, in fact, what is really driving that extreme productivity we are seeing.

Great.

It's been a couple of quarters since you've talked about the value of having both the upstream and the midstream business together and had previously commented that as EQT's production growth rate slows and EQM's third party growth accelerates, the synergies of having the two units together is reduced.

Just wondering, in the past year and looking out to 2017, as growth does slow, has your view of the magnitude of these synergies changed at all or are they still as great as they were in 2015?

Directionally, I will tell you -- this is Dave -- they're still about the same.

You know my view all along has been there's always going to be pressures pulling apart two groups that have cash flows that have different attributes, but I think in this environment we are actually seeing more of the synergies between the upstream and the midstream than we probably would have expected a couple of years ago.

I'm thinking particularly about some of the pipeline projects, but then also going back to the Utica, we do believe that it's still likely that we would want a somewhat dedicated, at least, midstream business for the Utica.

Of course, we're taking a look at what that might look like.

At least, let's say, upstream of the first compressor station.

And to be able to coordinate the development of the upstream and the development of the midstream, is a benefit that we have that we don't think is available to those who are just pure play on one side or the other.

And frankly, on the FERC regulated pipelines, I think you see a disconnect in some circumstances between what the pipelines are saying and what the producer/shippers are saying and you don't see that with us.

So I think that's another case where the -- having the synergies between the upstream and the midstream works to create value over time for the EQT shareholder.

Great.

And then you talked about last quarter a nat gas clearing price of $3.50 and wanting to be able to quickly respond to higher prices.

Strip is up -- moved up $0.20 or $0.30 since that call, but it does feel like, to your point, 2017 supply and demand fundamentals are improving, so the question is, is $3.50 a clearing price that would trigger EQT to increase activity or would it be lower given that you're a low-cost producer and given the historical nine-months spud-to-sales time, is there a way to more quickly respond to higher prices?

Yes, the ability to more quickly respond in both directions is certainly something that we're looking at, but I wouldn't say that we are at a point now where the prices are where we would want them to be.

I mean, to use the analogy that a lot of us have used, there's a light at the end of the tunnel and we are little more confident that it's not attached to the front of a train, but I don't know that we want to be going all in on that possibility.

Great.

Thanks.

Holly Stewart, [Scotia Howard].

Good morning, gentlemen.

You're changing your name.

Is there an announcement you want to make.

(laughter)

Not today.

Dave, first question, I appreciate the comments on the M&A and, without talking about specifics, just kind of curious if you can comment on the size of deals, the quantities of deals and then how you balance that versus keeping the investment grade rating?

I will provide a little bit of comment and Steve might want to provide comment too.

For the most part, we happen to be focused on transactions that are relatively small in nature.

They are not public company transactions.

That's just the nature of what happens to be out there and we do still think that it makes sense for us to be cognizant of the credit risk when we look at those acquisitions and I guess maybe I will just leave it at that.

Frankly, it is more beneficial on the midstream side than the upstream.

I think we've seen plenty of peers that have lower credit ratings than us, and I don't think -- just a little bit lower -- high sub investment grade.

I think you could easily argue it doesn't hurt them.

But on the midstream side, I think to have a seat at the table, and I do see a lot of opportunities -- maybe even more opportunities than we would have before -- with the changes in the macro environment and how it's affecting a lot of the other companies out there.

I still think it's valuable to -- in this environment to maintain that investment grade rating and assume that we will behave in a manner that is consistent with that view.

And, Steve, do you want to provide any more thoughts on what you're seeing on the M&A landscape?

The only thing I would add, really, probably to reiterate points Dave has already made, but we focus mostly on asset packages.

We have a very narrow core area that we think is interesting, so the things that are interesting to us are asset packages that fit nicely with our existing upstream and midstream assets.

As Dave said, we get those through synergies, and I think there's a number of those packages out there right now.

Some are on the market, some we're just in discussions directly with companies.

So we're looking at a lot of stuff.

We're really hoping to find things where -- where we have more synergies than our competitors, which allows us to be competitive on price yet get it at a price that still leaves a lot of value for our shareholders.

In this environment, there seems to be several opportunities that are interesting and we continue to pursue them.

But if the price is not right, we won't do it.

Great.

I appreciate that.

Then, maybe moving on to some of the guidance.

I know there was a change in disclosure, so I want to make sure we have some apples to apples comparisons here on the basis, but we've noticed that basis has really been narrowing.

So, curious as to the Q2 guidance and what you guys are seeing -- maybe this is for Randy -- on the marketing and the basis side of things right now.

Holly, this is Randy.

Yes, the basis has been narrowing a bit.

And so with, obviously, the additional infrastructure that will be coming on into the fourth quarter and our Ohio Valley connector project that we are constructing currently will obviously help us in our realized price throughout 2016 or in the end of 2016.

But in terms of the guidance and some of the accounting, I think Rob addressed it pretty clearly in his comments about some of the change in the accounting related to that.

But we have been pretty much right on our guidance and I give the commercial team a lot of credit for optimizing the capacity in what was a first quarter of essentially warmer weather.

So they did an excellent job in meeting that guidance.

Okay.

And then maybe one last one for Steve.

Steve, it looks like your -- for 2016 your guidance is tracking maybe a similar quarterly progression that you did in 2015.

Is that how to think about it here for the remaining three quarters?

I don't have the 2015 numbers in front of me, but to be at the midpoint of our guidance implies fairly flat production through the balance of the year.

So that's probably how I would be looking at it.

Okay.

Great.

Thanks, guys.

Neal Dingmann, SunTrust.

Good morning, guys.

Maybe a question for Steve.

Steve, you talked about bringing those costs down in those Utica wells.

I'm just wondering -- how do you balance the completion optimizations?

I know you guys are certainly doing some exciting things there.

How do you think about balancing that and some enhancements there while at the same time bringing the cost down?

Just wondering what sort of levers you're pulling there?

I think our thought process on that is we are definitely trying to figure out how to get the costs down with the idea of what the ongoing development mode costs would be.

But to the extent that we need to run some experiments or gather data to get a better understanding of the reservoir, at this point, and the nature of the effort, is a science project still at this point or more exploratory in nature.

We are very willing to make those investments.

And we understand that those are not intended to be ongoing types of costs.

Those are one-time costs to cut a core, to get a specialty log, to run some sort of reservoir test.

I don't think we let that get in the way.

We're certainly not avoiding gathering necessary data in order to get any single well?s cost below some artificial threshold.

Okay.

Okay.

That's where I was going with that.

And, Steve, I know on that rectangular -- and I respect Dave's question where you guys are looking on that slide.

I know you've got a pad just north of that and even quite a bit further north of that I know one of your peers has, obviously, a big well.

So you've got a bit of a position just -- even if you continued going north just little bit further than that, are you definitely sticking to that rectangle or would you consider just a bit north of that?

I guess northeast of that it would be.

You mean in terms of M&A?

Yes, sir.

No, I think we're going to stay focused in that -- there's enough potential opportunities in that rectangle, and that's where we get the most synergies.

We do have some acreage to the north of it in Armstrong County.

I think -- is that where you're referencing?

That's where I was referencing.

Yes, that's exactly right.

Yes, but our midstream operation is focused south of Pittsburgh, Greene County, Wetzel County, the areas south of Pittsburgh in that rectangle are our primary interest, and once you get north of Pittsburgh, even in that rectangle, while we're certainly interested in things that come along, but once you venture beyond it I think, at least for now, is not particularly of interest.

Okay, and just lastly, you mentioned to Holly, I think, on that production assuming it would stay on that guidance pretty flat.

If you said -- I'm just trying to make sure I have this right as far as for the remainder of the year what you're thinking as far as number of Marcellus versus Utica wells.

I'm not sure if I've got that correct.

Yes, so we're drilling 71 or 72 Marcellus wells and 5 Utica wells this year, with the potential to go to 10.

Okay.

That's what I was getting at.

Got it.

Thanks.

Brian Singer, Goldman Sachs.

Thank you.

Good morning.

I wanted to follow up on your comments on ceramic and its potential superiority or improving performance in the Utica.

Can you talk a little bit more about the reasons for why this may be, and then also, is there -- is it something that is unique to the Utica section or do you see the potential for further completion efficiency improvements using ceramic in the Marcellus as well?

Brian, I think -- we believe that if ceramic is a driver in productivity, which at this point is still an unknown, but it's one clear variable between the wells.

We don't think it would apply to the Marcellus.

The real driver behind the ceramic, and the reason we went with it on the first well, is that at these depths with the stresses we're dealing with the strength of the sand we use -- we're pushing the upper limit of it.

We did some laboratory testing of this sand that suggested it should be okay, which is why we switched on the second and third well.

But the results we are seeing indicate that potentially it's a problem -- and it's mostly due to crushing and/or embedment of the sand into the shale.

It's mostly crushing that we are concerned about.

So the ceramic proppant has a higher crush strength and we think that is not a problem.

Again, we're not certain that it is a problem with sand, but since that is an obvious variable between the Scotts Run and the other wells and the cost differentials being cut nearly in half, we thought it was wise to go back and see how much productivity difference that is driving.

Do you view the cost differential as secular or cyclical just because of the decline in activity, particularly for ceramic elsewhere?

I think we will be able to maintain that cost advantage.

We actually got that by talking to a second ceramic provider.

The primary provider, or the provider on the Scotts Run, then did come in with a much better price.

So I think we've got some competition in the space now, and I think if deep Utica full development mode kind of kicks in in the basin there will be enough demand for them to justify getting the ceramic up here.

So I expect that we will be able to hold on to that.

Great.

And then shifting more a little bit to production and the macro, but you've talked in the past about the lead time from when EQT's rig activity and CapEx activity comes down to when you would actually see the production impact, and I think you've talked about it being 9-months-plus, which is in part is why the production stays strong -- relatively strong this year.

Can you just provide any updates on that lead time, whether it's shrinking or expanding?

And then to the degree that you ramp up or decide to recommit capital, does that work on the other direction as well or would there be some reason to suggest that we would see the production response with a shorter lead time?

I think, Brian, when we do our modeling with our current process of how we drill and complete the wells, the 9-months is a pretty good average.

Smaller pads, shorter laterals end up being shorter.

Bigger pads take longer.

We have done some optimization modeling of that to see what we could do to shorten it up.

We do have some options where if we had the right economic incentives we could spend a little bit more money, primarily on more rig moves.

So we would move the rig more often and get wells on line quicker.

Again, it would be based on the forward curve and what we thought the prices were going to do as to whether it would be worth spending the extra money.

But we do have a plan in place where we could shorten that up probably, maybe to 5 or 6 months might be the best we could get, to try and capture an improving commodity market if we saw that happening.

This is Dave.

If we look at the market more broadly, we actually think there could be factors that could lengthen that lag time for a number of companies.

If you've gotten rid of some of your land people, for instance, and you can't get permits as easily.

Some of the rigs that have been laid down and maybe they've been cannibalized for parts.

Crews that have wandered off.

It's one of the reasons we've tried to remain a little bit more consistent in our activity level so that we would be better positioned for that.

I have a feeling that the rest of the market might actually see longer lead times at the early stages of a ramp up assuming prices move up enough to justify such a ramp-up at some point in the future.

Got it.

So the market will have some struggle with this, EQT is a little bit better positioned, if not very well-positioned in your mind, to not have that issue.

Yes.

Look -- there may be other peers who are in a similar situation to us, but we think the market at large -- I think the market at large is going to have longer lead times and EQT and probably a handful of other companies would not be subject to some of those issues.

Thank you.

Scott Hanold, RBC Capital Markets.

Thanks.

Good morning.

Steve, I was wondering -- you all indicated that this third well, I guess the Big 190, had similar results to the Pettit well, if I understood your comments correctly.

Is there any quantifiable number you can provide on what some of the initial relative productivity was and some of the back pressure data on that?

And then also, just to get a sense on how you all are progressing on the cost side of things.

What did the cost on the 190 look like it came in at and what is the AFE on this next one, the Shipman well, that you are going to be drilling?

Scott, we are not prepared to provide any specific details on the Big 190 yet.

It's just too soon.

In terms of the productivity.

On the cost side it came in normalized -- for a 5,400 foot lateral it came in, I think, just $100,000 or $200,000 above the $14 million upper end of our range.

We expect the Shipman well to come in within that range, so below $14 million, excluding some of the science we are going to do on the well.

So, Neal had asked earlier, we are cutting a core on the Shipman well so that ?- there will be some extra cost there.

But if you exclude that, we expect the Shipman well to be within the range, and then things like the dissolvable frac plugs, if that works and we can implement it on future wells across the whole well, that's roughly $700,000 savings that we haven't factored in yet.

So, very, very confident that we are going to be in the midpoint of that range over the next few wells and with still lots of opportunity for improvement.

I think over time we?re feeling pretty good about the bottom end of that range.

Okay.

Great.

And just to clarify, so the right around $14 million for shipment includes the cost of ceramics, but doesn't include the dissolvable plug benefit?

Yes.

That?s great.

Okay, thanks.

And then Big 190, how long has that been online now?

I don't remember.

Maybe a month, month and a half.

Okay.

And really quickly looking at hedging, what is big picture -- when you look at the forward curve, where is a level where you all feel more comfortable layering hedges and would you do it more to just protect the downside or how does that strategy for you guys look going forward?

We do take a portfolio approach, but there's no doubt, when the price is below what we think is the economic clearing price, we tend to be more at the low end of the target range that we have.

And when the price moves above that, we are more at the high-end.

So now I would say we're probably a little bit more -- as we think about it, not for 2016, but as you look beyond it, we would still be layering hedges in, but we would be staying more at the low-end of what our target range would be.

I think the difficulty is going to be -- since I do believe prices are going to move past that economic clearing price to be disciplined about moving up to the top as opposed to getting caught up with the opposite of the current, if you will, depressed feeling in the market.

We've seen it before where it gets euphoric.

Incidentally, when you talk about the current year we have tended to view that as being just a standard commercial activity.

So we let our commercial group make decisions about the things that they want to do in-year to take advantage of some of the opportunities that they see.

We don't really view that as hedging so much as just normal commercial activity.

Okay.

And then typically are you going to target -- I think, and correct me if I'm wrong, you typically like to utilize swaps; is that right?

Yes, but that's just because of the way the market is going.

We're certainly not opposed to using other instruments, whether on their own or embedded in the sale of a physical commodity.

It just all depends on what the market looks like.

You don't want to be buying a lot of options if it's volatile.

You would rather sell them, right?

You would say we're not going to buy floors if it's expensive to do so, you would tend to go more with swaps, and vice versa.

So it's much more market conditions, I would say.

It's not a philosophical view that we should be using swaps as opposed to options or as opposed to collars.

Okay.

Understood.

I appreciate that.

Thanks.

Christine Cho, Barclays.

Hello, everyone.

I just have some -- two bigger picture questions as I try to figure out realized pricing for your E&P segment going forward.

In recent weeks we have heard a number of pipeline projects out of the Marcellus getting delayed due to the regulatory process or being canceled altogether.

Can you talk about what you think the spillover effects from this will be with respect to basis differentials beyond 2016, especially with the cross current of production starting to roll over and maybe NYMEX prices going up, potential opportunities for your projects and what this all ultimately means for the production outlook in the Marcellus Utica?

Christine, this is Randy.

Certainly in the Marcellus and Utica we're really talking about the rate of growth slowing.

So there has certainly been continuing growth.

And the facts are that there have been infrastructure projects that are being delayed.

So in a bigger picture, as you asked, in terms of EQT I think we are very well positioned.

The fact is that we have a broad portfolio of upstream capacity and we have the Ohio Valley connector project that is currently in construction that we anticipate or expect to come online at the end of this year, which will tie into our [rex] capacity and improve our pricing from that standpoint.

Now from the Midstream's perspective, obviously, as we have planned out these projects and build out our hub and are executing accordingly, we think that obviously increases the value of those assets over the long-term and even in the short-term.

I think -- certainly as other projects are challenged, I think we are very well positioned to continue to grow and to improve our realized pricing at EQT.

And just on -- in your presentation, your slide for the Marcellus capacity stops at first quarter 2018.

When Mountain Valley pipe comes on, can you remind us, are you going to be taking all of that capacity day one or ramp into it on a contractual basis?

And because you are underpinning a large amount of capacity there, does some of your existing firm capacity on other pipes roll off so that you don't have all of this excess capacity overnight and you can redirect your volumes to a better market so pricing, in theory, is better for the E&P segment?

Or do you take all of it day one and then you release whatever capacity you are not using on the short-term basis while you grow into it, which I think is what you have historically done?

Can you remind us how that works?

Sure.

When MVP does come online, the capacity obligations do not ramp up, they start at that time.

Having said that, we have the option to continue to keep all of the capacity and to grow into it.

We also have a variety of expirations on other transportation contracts, so it provides us the flexibility, if you will, to reconfigure that portfolio at the time that the MVP comes on, or to maintain all of the capacity if at that time we need it for continued growth.

So as we positioned our portfolio with the anticipation of MVP coming on, we have a variety of different expirations on other upstream pipelines that allow us the flexibility to really optimize that portfolio.

Between now and actually when the pipe is supposed to come online, do you have a number off the top of your head of how much is expiring?

I don't have it in front of me, but there are a couple of contracts that do come off in 2018 -- there is 200 million on TETCO, that I have, and there is some other additional capacity that comes off shortly thereafter that is in the range of around 300 million to 400 million a day.

There's a lot of flexibility.

We also have the right to extend those contracts too, so I think we are in a very good position to be flexible.

Okay.

Great.

Thank you so much.

Arun Jayaram, JPMorgan.

Good morning.

I've got a bigger picture question.

The stock at the EQT level traded at a pretty meaningful discount to your Appalachian peers.

So I was just wondering if you think you're getting the right or the appropriate credit for having the midstream, and maybe some longer-term thoughts about -- if you don't believe the market is giving you appropriate credit ways where you could get that value from EQM?

This is Dave.

I do agree with your premise.

It is difficult at this point to differentiate between a couple of factors that might both be at work.

One of them is that conglomerate issue that we chatted about before.

Different investors for midstream and upstream.

That is certainly a possibility.

I think we all know the best way to go about resolving that kind of issue over time.

Then the other possibility is that people look at the EQGP price and they aren't sure, given the relative lack of float, whether that is a good marker to be using for the midstream value at EQT.

I think we also have been pretty clear that we've got a notion that over time having more flowed out there is going to be a way to get more confidence level that that's going on.

I also happen to think that EQGP, though I notice that it's now trading -- the whole market has been -- had a tough period since its IPO of almost a year ago -- it is now trading just a little bit above -- just above its IPO price.

I still think that that represents a discount on EQGP, and I believe, and I think I've said this before, that I fear that some of that is just -- like a reverse sticker shock.

That folks?

models on growth, et cetera, would have suggested higher valuation for EQGP, but the current yield is still -- that falls out of those calculations is a relatively low number and there is a concern about bidding it up, the price up, such that that current yield drops too much.

But I think as you continue to see distribution increases announced consistent with our guidance at the EQGP level, that will tend to go away and that aspect of the valuation discount will start to be dealt with.

But as far some of those other issues that I mentioned, we do work through those issues.

We do see it the same way that you do and we are working through our alternatives on how to make sure that our shareholders realize that full value.

But you talked about that conglomerate discount -- to resolve that -- I would assume that is a longer-term decision that you would have to make on that.

Nothing in the intermediate-term on that?

Yes.

I'm not going to get into any timing issues on when we do some of that.

I think we all understand what those conglomerate discounts -- what those are and the ultimate ways of resolving those.

I don't know that I would want to go any further than that, because a lot of times what you want to do depends on the market conditions at the time.

That's fair.

I'm not trying to guide you towards or away from any particular timing on any actions that we might take with regard to that.

Okay.

That's fair.

That's clear.

And just secondly, I know you guys have talked about doing five deep Utica wells in the 2016 budget, and I think you gave yourselves some potential to expand that.

Are you still right now planning to do five and when could you potentially talk about expanding that if you decided to do so?

Yes.

Right now the plan is still five, but the actual number we end up drilling any year is going to be very much based on the results we are seeing.

We want to be very careful about not getting ahead of our science.

Nor getting ahead of our ability to take the gas away and get it to a market.

But we also want to progress our understanding and start to make some decisions about what a development mode in the Utica might look like.

I think, for sure we're going to get the Shipman well fracked, which we are currently fracking and get results from it.

It will give us a lot of information on the impact of ceramic proppants and we will get some information on use of the dissolvable plugs, so we might be able to take another step forward in our estimation of cost and therefore economics.

So it's going to be a decide as we go kind of approach I think.

But certainly we don't expect to be making any decisions before mid to late summer in terms of any sort of a ramp-up.

Okay.

Thanks a lot, gents.

Thank you.

Ladies and gentlemen, we have no further questions in queue at this time.

I would like to turn the floor back over to Pat Kane for closing comments.

Thanks, Adam, and I would like to thank everyone for participating in our call today.

Thanks.

Thank you.

Ladies and gentlemen, this does conclude our teleconference for today.

You may now disconnect your lines at this time.

Thank you for your participation and have a wonderful day.