EQT Corp (EQT) 2014 Q2 法說會逐字稿

Good morning, and welcome to the EQT Corporation's second-quarter 2014 earnings conference call.

All participants will be in a listen-only mode.

(Operator Instructions)

After today's presentation, there will be an opportunity to ask questions.

(Operator Instructions)

Please note that this event is being recorded.

I would now like to turn conference over to Patrick Kane.

Mr. Kane, please go ahead.

Thanks, Dana.

Good morning, everyone, and thank you for participating in EQT Corporation's second-quarter 2014 earnings conference call.

With me today are Dave Porges, President and Chief Executive Officer, Phil Conti, Senior Vice President and Chief Financial Officer, Randy Crawford, Senior VP and President of Midstream Commercial, and Steve Schlotterbeck, Executive Vice President and President of Exploration & Production.

This call will be replayed for a seven-day period beginning at approximately 1.30 today.

The telephone number for the replay is 412-317-0088.

Confirmation code is 10037707.

The call will also be replayed for seven days on our website.

To remind you, the results of EQT Midstream Partners, ticker EQM, are consolidated in EQT's results.

There was a separate press release issued by EQM this morning, and there is a separate conference call today at 11.30 AM which creates a hard stop for this call at 11.25.

If you are interested in the EQM call, the dial-in number for that call is 412-317-6789.

In just a moment, Phil will summarize EQT's operational and financial results for the second quarter of 2014.

Then, Steve will comment on the findings of our review of our dry Utica acreage.

And finally, Dave will provide an update on our transmission projects and GP cash flow projections and valuation included in our updated analyst presentation, which was posted on our website this morning.

Following Dave's remarks, Dave, Phil, Randy, and Steve will all be available to answer your questions.

I'd like to remind you that today's call may contain forward-looking statements related to future events and expectations.

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 under risk factors in EQT's Form 10-K for year ended December 31, 2013, filed with the SEC as updated by any subsequent Form 10-Qs which are on file at the SEC and are 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 to the most comparable GAAP financial measure.

I'd now like to turn the call over to Phil Conti.

Thanks, Pat, and good morning, everyone.

As you read in the press release this morning, EQT announced second-quarter 2014 adjusted earnings of $0.58 per diluted share, which represents a $0.02 per share increase versus the second quarter of 2013.

The GAAP EPS was $0.73 per share in the quarter and included a $38 million gain on the asset exchange with range, with $31 million of that gain realized at Production and the balance recognized at Midstream.

As Pat reminded you, EQT Midstream Partners, or EQM's results are consolidated in EQT's results.

The impact of the non-controlling interest in those results is a little clearer on the income statement than it is on the cash flow statement.

EQM operating cash flow, or adjusted EBITDA as it is defined in the EQM press release, was $57 million in the quarter and is included in EQT's consolidated cash flow.

However, as we have noted in the past, not all of that cash flow is available to EQT as non-controlling unit holders owned approximately 64% of EQM at the end of the second quarter 2014.

Summarizing the quarter from an operational and financial perspective, EQT Production volumes were 110 Bcf, or approximately 17% higher than the second quarter last year, but about 4 Bcf below our previous forecast.

The shortfall versus guidance was due to the delay in installation of a gathering pipeline, which postponed two multi-well pads from being turned in line, and also due to the delay in construction of well lines to another multi-well pad.

In total, 22 wells were delayed, and all 22 of those wells are currently flowing which explains why we are reiterating our full-year guidance of between 465 Bcf and 480 Bcf equivalent.

We expect third-quarter Production volumes of 118 Bcf to 122 Bcf equivalent, or a 9% sequential growth rate assuming the midpoint of that range.

Midstream gathered volumes were also up in the quarter about 17% higher than last year.

However, the volume growth at both businesses was largely offset by lower commodity prices and absolute costs that were higher than last year consistent with but the less than the growth in volumes.

Prices were obviously a big factor in the quarter.

At the consolidated level, EQT's average effective sales price of $3.85 per Mcf equivalent was about 10% lower than the $4.29 we realized in the second quarter last year.

The average NYMEX gas price for the quarter was actually considerably higher at $4.67 per MMBtu compared to $4.09 last year.

Although from a hedge price perspective, a portion of the impact of that higher NYMEX was offset by the fact that some higher price swaps rolled off in 2014.

Also, basis was significantly lower at negative $0.78 in the second quarter 2014 compared to basis which was basically flat with NYMEX last year.

However, we were able to recover about $0.20 per Mcf equivalent in the second quarter 2014 through transporting some of our gas to higher priced markets and also through the resale of our unused capacity.

The realized price of $3.85 included an $0.08 non-cash hedge loss on derivatives that were mark-to-market.

The realized price at EQT Production was $2.92 per Mcfe compared to $3.24 last year, were also about 10% lower.

EQT Midstream realized $0.93 compared to $1.05 last year as a result of a lower gathering rate -- lower average gathering rate.

And finally, our third-party gathering and transmission costs where $0.54, or about $0.05 per unit lower than the second quarter last year.

A few brief comments on the Production results.

EQT Production operating income, adjusted for the gain on the range transaction, was 8% higher than last year.

As I discussed a minute ago, the 17% volume increase was significantly offset by lower commodity prices.

The result was net operating revenue of about $322 million in the quarter, which was only 5% higher than the second quarter 2013 despite the healthy volume growth.

Operating expenses were about 1% higher, excluding the $4.8 million legal reserve.

SG&A, production taxes, and LOE were all higher as you would expect given the volume growth.

However, DD&A was lower as a result of a depletion rate that is 19% lower than last year, primarily as a result of the increase in reserves at year-end 2013.

Moving on to Midstream results in the quarter, Midstream operating income adjusted again for the gain on the range transaction was up 13% due to the growth of gathered volumes and increased capacity base transmission revenue.

Net revenue was $152 million, up about 16%.

Gathering net revenue increased by 5%, and gathering volumes increased by 17% but were somewhat offset by an 11% decrease in the average gathering rate.

That gradual decrease in average gathering rate has been ongoing and is due to the continued increase in the Marcellus gathered volumes in the mix, which are relatively less expensive to gather, and therefore get charged at a lower rate.

Midstream transmission net revenues also increased by 33% in the quarter, driven by higher capacity reservation charges and throughput.

Third-party transmission revenues were 73% higher than last year and accounted for half of the second quarter transmission revenue.

Storage, marketing, and other operating revenue was $4.1 million higher in the second quarter as result of revenue from storage assets that were received as part of the consideration from the utility sale that closed in December.

Operating expenses at Midstream were up 20% quarter over quarter.

However, per-unit gathering and compression expense was 6% lower driven down by the volume growth.

A couple of comments on funding and liquidity in the second quarter.

As you know, we sold our Jupiter gathering system to EQM for $1.2 billion in May of 2014.

There was no EQT income statement impact from that transaction, as EQT controls EQM through the general partner ownership, and therefore, EQM results are consolidated with EQT.

From a tax perspective, however, EQT did realize a gain on the transaction, and we expect to pay cash taxes of approximately $100 million related to the sale of the Jupiter gathering system.

A quick update on our share repurchase authorization.

We bought back 300,000 shares of EQT stock during the quarter and have 700,000 shares remaining under the current authorization.

And then, just a quick couple notes on the balance sheet, we closed the quarter with no short-term debt other than the $330 million of short-term debt at EQM that gets consolidated into EQT's balance sheet and a current cash balance at EQT of approximately $1.4 billion.

We also continue to have full availability under our $1.5 billion revolving credit facility.

Using the current strip for the remainder of the year, our operating cash flow estimate for full-year 2014 is approximately $1.5 billion.

And, with that, I'll turn the call over to Steve Schlotterbeck.

Thank you, Phil.

As we discussed at the time of the first-quarter call, we were revisiting our geologic and engineering analysis of the dry Utica Point Pleasant potential in our acreage.

As we look at the initial results of the wells drilled so far in the play by other operators, our technical teams are very encouraged that the results are basically in line with what our models would predict.

Until now, we've been hesitant to drill our own well based solely on those models given the lack of well control, but we think it is now time to drill a test well on our acreage.

Based on our review, we have approximately 400,000 acres that could be prospective for Utica.

There is little disagreement that there is tremendous amount of gas in place in the play.

The question is whether or not the gas can be profitably produced, as each well could cost as much as $15 million.

Based on our work, we decided to drill the first test well in Greene County.

The main reasons for this were, one, the geology under Greene County looks quite good, and two, we have existing pads, roads, and takeaway pipes in place that could be leveraged if we are successful.

We realize that this well is an experiment and could result in a $15 million dry hole, but the upside if successful is tremendous.

We've begun the permitting process and expect to spud the first well before year-end.

We will keep you informed of our progress.

Shifting gears, we published an update to our Marcellus analyst slides this morning.

We updated our acreage position to add 20,000 acres that we acquired over the past few quarters.

We also framed a fourth Marcellus development area in the dry window of northern West Virginia.

We have 30,000 net acres in this area.

There are about 300 locations, and we have 46 producing wells there.

The EURs are about 15% less than our wet West Virginia acreage, but about 25% higher than Central Pennsylvania.

We are drilling 18 wells in the area this year.

We also published an Upper Devonian type curve for the first time.

As those of you that have listened in in the past, we like to wait for data from actual wells before publishing type curves.

We estimate a mid-40% return from our Upper Devonian wells.

Finally, we increased the average EUR of our Southwest Pennsylvania acreage to reflect better performance from the wells drilled there.

With that, I'll turn the call over to Dave.

Thanks, Steve.

I would like to comment on the status of our pipeline projects and the related topic of our current thoughts on the EQM GP.

Before giving specifics on the status of three pipeline projects; however, I'd like to provide a strategic overview.

With the growth in Production volumes in our region, we have become quite confident that there will be many attractive Midstream investment opportunities.

In fact, I believe there will be more opportunities over time than we can prudently pursue.

Therefore, we need to prioritize our selection criteria and also make sure that EQT and EQM are prepared for this sustained growth.

The primary drivers of our prioritization are -- the overall attractiveness of the project, its fit with our existing assets, its fit with the objectives of EQT Production and other Equitrans customers, its ability to access attractive markets, and the flexibility it affords in accessing multiple markets.

As to specifics, at the time of our first-quarter call, EQT Midstream Partners, or EQM, had an active open season on a project that connects our Equitrans system to pipes in eastern Ohio, the so-called Ohio Valley Connector, or OVC.

We announced today that we are moving forward with OVC, and that it will be built by EQM as an organic growth project.

This 36-mile pipeline extension will connect our transmission system in northern West Virginia to Clarington, Ohio.

There, the pipeline will interconnect with both the Rockies express pipeline and the Texas Eastern pipeline.

The current project scope is estimated to cost approximately $300 million and will provide about one Bcf per day of capacity.

The estimated in-service date is mid-2016.

EQT has contracted for 650 million cubic feet per day of OVC capacity, and EQM is actively engaged with other shippers to firm up contracts for the remaining capacity.

Next, I'd like to update you on the Ohio express project.

As you may recall, this project originated through requests from producers seeking to move gas from Clarington to liquidity points further West in Ohio.

Since completing our open season, we have reassessed our priorities, and Ohio express has slipped below other projects so it is on the back burner at least for the near future.

Finally, the third of the projects, the project supplanting that amongst our priorities, is the Mountain Valley Pipeline project, or MVP, which we announced in the second quarter.

MVP is designed to serve the southeast markets by extending our transmission system through West Virginia to Southern Virginia.

This 330-mile pipeline is expected to have a capacity of about 2 Bcf per day and has two anchored shippers including EQT Production who have already agreed to a total of 1 Bcf per day of capacity.

The non-binding open season for MVP ended in mid-July.

We are encouraged by the interest expressed by shippers and are now working toward precedent agreements with those shippers.

We expect MVP to be constructed and owned by a joint venture with NextEra Energy with EQT as operator and largest owner.

Once the project size and scope become clearer, we will determine whether the project belongs at EQM or EQT.

The reason MVP has become a higher priority is that we believe the Southeast offers one of, if not the most attractive markets in terms of future natural gas demand growth, as well as an attractive price environment.

We think Southeast markets can support multiple Bcf per day of new supply to satisfy the expected demand growth and continue to offer strong pricing relative to Appalachian basin pricing.

We will keep you updated.

Moving to the GP.

As you know, our ownership of the EQM general partner entitles us to a growing proportion of the MLP distributions.

Per the incentive distribution rights, or IDR schedule, the GP receives 50% of incremental quarterly distributions above $0.525 per limited partner unit.

The purpose of IDRs is to align the GP interest with the limited partner interest by incenting increases in quarterly distributions.

We will pass this key milestone of $0.525 later this year.

The quarterly LP distribution that will be paid next month is $0.52 per unit, and EQM has given guidance that it plans on increasing the distribution by $0.03 per quarter through at least 2016.

GP distributions are determined based on two variables -- distribution per unit and LP units outstanding.

Therefore, forecasting the cash payments to the GP is rather straightforward.

In our updated analyst presentation, we laid out a schedule of GP cash flows based on assumptions for these two variables.

One, is that the $0.03-per-unit increase in quarterly distributions continues through 2019.

This appears very achievable given the visibility of distributable cash flow growth at the MLP from organic growth and future accretive drop-downs.

The second assumption is that the rate of drops from EQT to EQM is $75 million of EBITDA each year for the next three years which EQM finances using a 50/50 debt equity mix.

As EQT still has almost $200 million of Midstream EBITDA, and is investing over $350 million in Midstream this year, the drop inventory needed to support this assumption is already in service or being built.

If EQM continues to have success, there will of course be new projects or additional drops.

Along these lines, neither OVC nor MVP is explicitly assumed to occur though we did assume a 4% terminal growth rate in distributable cash flow after 2019.

We are planning for more rapid growth post-2019 than that, but this assumption is consistent with what we have seen from investment banks, so we used it as a benchmark to assess the value of GP cash flows.

As you will see on the slide in the analyst presentation, the GP cash flow increases dramatically.

It grows from less than $15 million in 2014 to nearly $200 million in 2019.

The relatively low GP cash flow in 2014 shows why we need to be a bit patient in taking action to realize the GP value.

With our estimate of the present value of the pretax cash flow is nearly $4 billion, it seems unlikely that EQT investors would pay the multiple of 2014 cash flow needed to achieve that valuation inside EQT.

We believe that our GP stake is quite valuable, and we are on track to decide around year-end on the best path to realizing that value for our shareholders.

In summary, EQT is committed to increasing the value of our vast resource by accelerating the monetization of our reserves and other opportunities.

We continue to be focused on earning the highest possible returns from our investments and are doing what we can to increase the value of your shares.

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

With that, I will turn the call back to Pat.

Thank you, Dave.

That concludes the comments portion of the call.

Dana, can we please now open the call for questions?

(Operator Instructions)

Neal Dingmann, SunTrust.

Good morning.

A few questions.

First, maybe just to follow on what you were saying at the very end there.

You mentioned -- and I would agree with you -- about the material value of the GP.

And, you mentioned by year-end, you would consider, or look at some options for monetization.

Can you discuss this maybe in a little bit more detail?

Some things that maybe you or the Board or anybody has talked about at this point?

Certainly, there is value there.

I'm wondering, any thoughts --.

I think I'd rather not do that, Neal, other than -- first, thanks for your question.

I'd rather not do that other than just mention that we are looking at what a lot of other folks have done.

Frankly, when I've gone through the list of alternatives, in the past, it hasn't turned out well.

So, I'd just as soon we -- you can probably remember.

But, you just recall that we did -- we've been saying around year-end for a little while, and we both know that there are -- we all know on this call probably.

That a number of different companies have gone down this path before.

They've picked different routes, and we've taken a look at a lot of that.

And, we've used some experts, some investment banks, et cetera, to try to help us think that through.

Frankly, I would just as soon leave it at that, if that's okay.

Maybe moving on for Steve.

Steve, you mentioned about the 400,000 prospective Utica acres.

I was glad to see you finally breaking this out.

Your thought on this first well in Greene County.

Steve, would you think about doing co-mingled pads where you would drill a Utica and Marcellus on the one?

Or, is this just a step-out test well?

Or, how do you foresee developing some of these Utica wells mixed in with the Marcellus there?

I think, Neal -- first of all, we are reviewing this first well as a test.

So, it's an experimental well.

We see lots of resource potential.

There's a lot of gas in place.

I think that's pretty clear to everybody.

But, there are some challenges.

It will be the deepest well we've drilled.

It will be the deepest Utica well drilled so far, I believe.

It is looking like it's going to be around 13,500 feet deep.

So, there are some -- not so much drilling questions, but I think on the completion side, we have some questions we need to answer and some tests we need to run.

So, for now, this is an experimental well.

Our view though is, if successful and depending on the ultimate economics of Utica development, I think we would develop it on existing pads, or, in combination with Marcellus drilling.

We don't see a need for separate pads or separate facilities.

It could all be done in conjunction with each other.

Steve, I'm going to ask one thing, does that depth preclude you from taking a lateral out further than you might otherwise?

Or maybe, if you could comment around that?

I don't think so.

I don't think we're too worried about the drilling aspects.

Our test well is planned to be about 6,400 feet.

We feel very comfortable with that, and I think we feel like will be able to go longer.

Probably our biggest questions in our mind concern the pressures and the stresses.

So, what's the right proppant?

We know we won't be able to use sand so we will be using most likely ceramic proppants.

What strength do we need?

What pumping pressures are we going to see and pump rates can we get at this depth in those pressures.

A lot of experimentation to do.

We are in a new frontier here in terms of depth and pressures.

So, we have some questions to answer on this first well.

Thank you.

Scott Hanold, RBC.

Morning.

Maybe if I can follow up since we're talking about the Utica well right now.

So, when you step back and look at it -- I know it is really early today, but given what you know on what you think the cost could be -- what do you think you need to get out of this well to make it economic?

And then, I will say along with that then, make it competitive with some of the higher return projects you have in your portfolio?

I think probably the simplest way to think about it, back of the envelope is, the wells are going to cost twice as much as a Marcellus well.

So, they're going to have to produce twice as much to be competitive.

They can obvious produce less than that to be economic, but I think given the large inventory of Marcellus opportunities we have, our real goal is to make it competitive with the Marcellus, not just meet our cost to capital.

Basically, we are looking for double.

Okay.

Got it.

I know you provided a pretty wide range on the cost expectations because obviously it is really -- you haven't drilled the well yet.

But, what would be the ideal cost?

Is it -- when you say twice the EUR, do you think twice the cost of a Marcellus well is also going to be the go-forward thought so if you can get your Marcellus wells down to say $6 million, $6.5 million, these are always going to be in that $12 million, $13 million range on the low side?

I'm not quite sure it works that way.

It is really -- the well -- it happens to be about double our estimate.

But, it is really based on the specifics, and because of the depth of the Utica under a lot of the most prospective acreage, they are going to be expensive.

I think that range -- the range that we are providing is driven more by what strength casing we're going to need and what kind of horsepower and pressure limits on our frac equipment is going to be required.

Those are things that we are going to have to drill a well to find out, but that that's why there's such a big range now.

And, I think a lot of the costs go into higher prop and higher horsepower so a lot of the extra costs are coming on the stimulation side.

There is a little more cost because of the depth on drilling, but it is really driven by increases in our fracking needs.

Okay.

Understood.

And, my follow-up would be then on Production.

Obviously this quarter, a little bit below expectations because of well timing.

Was there any other constraints in the field just due to lime -- high lime pressures that you may all have seen?

Or, maybe a mix shift in terms of what you completed in the quarter?

And, I guess what I'm getting to is even with the 4 Bcf, you were within your guidance, but it is pretty much been a beat-and-raise story in terms of production historically for you all.

Not to be well above your production range was a bit of a surprise.

I think when we provide guidance, we are giving you our best estimate, and sometimes things go more favorably than we expect, and sometimes we have some issues that we didn't expect.

In this quarter as we mentioned, we had 22 wells that were delayed for a couple different reasons, mostly around just getting them in line.

But, just for reference, that's 22 wells from 3 pads on average delayed about 2 weeks.

So, because of the large number of wells per pad and the large production per well, it doesn't take a long delay to have some fairly significant impacts -- positive and negative.

So, if things happen a little faster, our numbers can exceed pretty easily.

And, if they are little bit late, they can miss.

In the end of the day, it is all timing.

I think when you look on a calendar-year basis, the impacts are pretty minimal.

Okay.

Thank you.

Philip Jungwirth, BMO Capital.

Morning.

Wanted to ask a question on the GP valuation.

If I look at the LP distribution forecast for 2019, it looks like the LP is trading at a 4.8% yield.

And then, applying the same yield to the GP cash flows in 2019 basically gets you to the $3.9 billion base-case valuation.

But, the GP growth rates doubled in the LP.

So, my question is, do you think an 8% whack is really realistic to use for the GP base-case valuation?

We based that whack on information we got from various, as Dave mentioned, experts, investment bankers.

The range is 7% to 9%.

We picked the midpoint.

Didn't put a lot more thought into that.

We did give you a table so you could pick a different one if you prefer to.

Can you talk about what percentage of Midstream EBITDA is still held at EQTC Corporation versus EQM?

I don't know if we talk about what percentage is there.

It is a little less than $200 million of EBITDA currently is still at EQT.

Roughly 40%.

Great, thanks.

Holly Stewart, Howard Weil.

Good morning, gentlemen.

Good morning.

Dave, maybe a couple of strategic questions.

Lots of cash on the balance sheet.

Can you just talk about your priorities at this point for use of cash?

Really, it is just to pursue the strategy that we've had with both the upstream and the Midstream.

That's why I think we've said in the past, Holly, we've got no desire to let cash burn a hole in our pocket.

I think that it hasn't in the past when we've been in this situation.

I understand we went through a period of years where that wasn't the situation.

But we will not, for instance, accelerate just because we have cash.

We are going to make what we think are the decisions that are most likely to create value for shareholders.

It does factor in a little bit in decisions on whether we build Midstream projects at EQM or EQT.

But, realistically, EQM has had access to capital markets at pretty fair pricing since it has been around.

So, that hasn't really factored into it too much.

We'd also like investors to have a sense that we are, in fact, able to continue the development programs that represent the optimal development of our resource base for a period of time.

That we are not constantly having to look behind the sofa cushions, as it were, to find extra loose change.

So, no thoughts at this point on further accelerating in the Marcellus?

Not because of having cash available, no.

That would be -- if we look at things with the Marcellus or the Utica or for that matter now I guess you could say the Permian and, we think that's the best way to create value then we'd certainly be interested in doing that.

But, it isn't because -- we try to studiously avoid being affected by the fact that we happen to have a lot of cash on the balance sheet.

I think that's a good way to fritter away value over time.

And, we don't do that.

You had a good segue into the Permian.

Maybe just some strategic thoughts there around the deal?

I noticed that you increased the well count for 2014.

I'm happy to let Steve comment on the Permian.

I think we've talked about the deal as a whole, which was that the Nora -- Nora was non-core for us, and we've known for a long time it was more interesting for range that it was for us.

But, I think we've commented on that, and that Permian was at the top of our list when we looked at other basins.

But, as far as what we are up to there, I will turn that over to Steve.

Holly, I think the change in well count is really driven by the fact that we expect to have a rig available in the fourth quarter.

And, when we think it will be available and get the first well spud, we think will likely be able to spud three more wells.

That well count includes the well started by range, being finished by us that we are actually starting the frac job today on that well.

So, that's well one of those.

And then, two or three more at the end of the year just to keep the rig running.

All Upper Wolfcamp targets in the western part of our acreage position where we feel very comfortable about the economic returns.

Perfect and appreciate all the detail on the GP value.

Maybe, Dave, you can give us some thoughts on EQM's appetite at this point for the remainder of year for more drops?

We are still working through that.

I don't know that we have anything to announce on further drop timing right now.

I will observe that EQM has had a pretty ready access to capital markets.

But, for us, a lot of it is making sure that an asset is ready to drop also.

We have those arm's-length agreements.

I know we have talked about that in the past, but we've long had tariffs.

But, you really need to -- with separate entities, you need to make sure you have the full agreement in place and that all other legal aspect of it are taken care of as well.

So, I don't really have any announcement on drops other than we are just going to continue to plug along.

Perfect.

Then my last one would be maybe for Randy.

There some good detail in the slide presentation on your end market mix and how that shifts in 2015.

If you could just maybe give us some color on some of those changes?

Looks like your M2 exposure goes down and Midwest and NYMEX goes up?

That's right, Holly.

In November, (inaudible) our team 2014 capacity comes into service which provides us additional access to the Gulf Coast as well as to northeast markets and certainly some of the capacity that we are looking for to go to the midwest will kick in as well.

With the OVC into the future, so we feel pretty good around our portfolio right now.

Perfect.

Thanks.

Thank you.

Amir Arif, Stifel.

Thanks, good morning.

A couple quick questions.

For the 400,000-acre Utica position, how much of that is in roughly in Greene County in West Virginia?

I believe roughly 50,000 acres is in Greene County, plus or minus a little bit.

Then, the West Virginia side?

I don't have that number specifically handy, but it is 150,000 acres or so.

Okay.

And, are all the Utica rights held by the Marcellus Production?

Actually, most of them are held by shallow Production for Marcellus, but they are nearly 100% held by Production.

And, the new dry gas area that you put out there, the 30,000 acres.

Is that newly acquired acreage, or is that acreage you had previously and you are defining the Marcellus acreage right now?

It is a bit of a mix.

We did acquire some acreage in that area recently, but I think the bulk of it was existing acreage.

Okay.

And finally, on the basis for the second half, the $1 to $1.10 -- could you give us some granularity on what you expect in 3Q versus Q4 that?

I don't think we have the details on that, but all we did for that guidance was to just take the published DRIP for the local basis and average it for the six months.

We are not really trying to make a prediction, it is different than the strip.

But, [pat] generally wider in 3Q and then narrows in 4Q?

Is that fair?

Yes.

Sounds good.

Thanks.

Joe Allman, JPMorgan.

Thank you.

Good morning, everybody.

Quick question on gas differentials.

What are you seeing so far this quarter on gas differentials?

And, what is your expectation for the rest of year?

I do see the market mix slide, so I'm assuming that you are expecting differentials to improve in 2015?

Joe, we gave a specific forecast on what we think for differentials for the second half of the year.

So, from a local basis perspective between minus $1 and minus $1.10, but we think because we have capacity and are able to get to some higher-priced markets, we are able to recover $0.60 to $0.65.

So, a net $0.50 negative.

Got you.

Am I correct that next year, you are expecting the differential assuming, say $4 flat gas to be better than 2014?

We are not really making predictions other than what the strip is.

It is hard to predict.

All you're really getting from us is a reflection of what the market shows.

Got you.

Okay, got it.

On the GP monetization options.

Is it possible that because of the ramp in cash flow that one of the options is actually to wait until some point later when you get a better valuation?

We are still working through that process.

We had early on recognized that one of the things that we need to do as part of this process is provide a bit more transparency on GP cash flows to investors.

That's the only reason that we put this out when we did.

We just -- this is still consistent with our thought process of trying to get to some type of an idea of what we think makes sense by the end of year.

Really don't have a view on timing beyond -- since we're really just almost like halfway into that process.

Or, a little more than halfway, I guess.

Okay, got it.

Any comments on service costs?

Are you seeing service cost pressures, and any specifics around that?

No, service cost has been holding fairly steady over the last quarter, and I think our view is we expect that to continue at least through the next quarter.

Hopefully longer.

I don't expect certainly any reductions, but we're not really feeling a lot of upward pressure at the moment either.

I would like to while I have the microphone clarify my previous comment.

We have 65,000 acres in Greene County with Utica rights.

Very helpful, thank you.

Drew Venker, Morgan Stanley.

Good morning, everyone.

Wanted to go back to the Permian.

Did I hear correctly?

You said all of the wells in the 2014 program are upper Wolfcamp, is that right?

That's correct.

Can you remind us how thick the Wolfcamp is there?

I will be honest, I don't recall off the top of my head.

Okay.

So, thinking ahead to next year, what is the goal of the 2015 program?

Are you trying to delineate the whole acreage position?

Or, are you more trying to hone well design?

Can you provide some color there?

We haven't set out a 2015 plan yet, but I think generically speaking, it won't be to delineate the entire position.

I think our strategy will be the bulk of the investment will be focused on the Upper Wolfcamp in the areas where we feel pretty confident about the economics.

With some test wells sprinkled in, perhaps in the lower Wolfcamp or the cline.

And also, with a couple testing the eastern limits -- find out where that economic threshold is going to be on the acreage.

But, I think the bulk of the investment will be focused on areas we think we can get good returns with some delineation tests sprinkled in.

Thanks.

That's helpful.

And then, on the Ohio Utica, have you completed any of those wells that were waiting on completion?

We have fracked the wells and will be flowing them back shortly.

As we said previously, we don't intend to provide updates, specific flow information on those wells, but they are on the previous schedule that we talked about.

Okay.

Thank you.

Michael Hall, Heikkinen Energy Advisors.

Thanks.

A lot of mine have been answered at this point.

But, just dive into that recovery line item a little bit more, and the guidance around that?

The $0.60 to $0.65 positive recovery, how should we think about that going forward?

How much of that during the quarter was actually from better pricing versus selling capacity?

And, how much of those prices are on a fixed basis versus floating?

It is different every period, Michael.

So, it is really tough to give you specifics.

But, the intent was that separating the recovery from the expense of transmission, which is what we did in this quarter's presentation, should allow you to take the -- would give you the sales points where we are selling our gas.

So, you should be able to use the weighted -- the weighting of volumes at those points and the pricing at those points to better approximate the net of the local basis and the higher prices at the other sales points.

That would give you -- that would be reflected and the recovery line would be the higher price portion of it and the basis is basically the first delivery point for our gas.

Generally speaking, we're going to have more opportunities when there's a lot of demand in some of those other areas.

For instance, cold weather will help, just as it did in the first quarter.

And, milder winters would mean there wasn't as much opportunity.

Some, but not as much.

A question I had as it relates to your view, if you have one, on the seasonality in the northeast markets?

And, how you see that playing out as we move into 2015 and beyond given the increased volumes and the supply dynamics in the northeast.

Do you think points like M3 still exhibit a lot of seasonality going forward?

Or, does that get materially muted given the supply situation?

Michael, obviously as David said it is a lot contingent on the weather and the conditions and the power generation load into the winter.

Certainly, there is some aspect of seasonality, and we saw this in our first-quarter results in the winter.

So, there's significant -- our team and the portfolio approach that we take attempts to maximize our sales prices by optimizing the portfolio.

So, I think with regard to M3, you've seen some significant pricing advantages this past winter and depending on the conditions, we may very well see similar results.

Okay, that's helpful.

Sorry to beat on this, but in terms of those contracts, are all those floating on a price basis?

Or, are there material amounts that are fixed price contracts as it relates to the firm transportation you have outlined?

As I said, we take a portfolio approach so it changes, but we do have some fixed.

But, we also have others that are floating so we take -- overall, we attempt to manage our price mix through a mix of each.

I don't have the specific percentages for that with me.

Fair enough.

Appreciate that.

On the midstream side of things.

EQT midstream, can you review the growth outlook as you see it for 2015 and beyond, on EQT midstream, at the EQT level?

Basically, we've been pretty much 20% growth of EBITDA for the last several years, and we haven't given a forecast for volumes for next year.

But, we're certainly seem to be on track with that to continue.

And, Pat, that's a 20% growth relative to the growth EBITDA stream, right?

You have to look at consolidated because of the dynamics of the drops.

So, if you look at the consolidated midstream EBITDA, it is a pretty steady growth trajectory.

Obviously whenever you are taking -- dropping $100 million or so from one entity to the other mid-year, it is going to make the sub-comparison choppy.

If you look at the consolidated growth, it is pretty predictable.

Basically, it is tracking the production growth.

We are obviously been having more and more that's third-party, but generally speaking, we've been trying to organize it so that the projects that support non-affiliated producers are at the EQM level.

So, at the EQT level generally speaking, you are going to wind up seeing results -- growth results that track EQT's Production growth.

Okay.

That 20% growth rate for the gross EBITDA stream is still reasonable?

Should be, yes.

All right.

I was looking for a little more color on the increase on EUR on the Southwest PA assets.

Any additional color there?

Not really.

Just the normal update based on results seen to date.

So, it wasn't a big change, but it was enough that we thought we'd communicate it to you but really nothing more than that.

Sounds good.

Appreciate the time.

Congrats.

Thanks.

Thanks.

Due to the hard stop necessary for your next call, this concludes our question-and-answer session today.

I would like to turn the conference back over to Mr. Kane for any closing remarks.

Mr. Kane?

Thank you, Dana, and thank you all for participating.