EQT Corp (EQT) 2015 Q3 法說會逐字稿

Good day, and welcome to the EQT Corporation third-quarter 2015 earnings conference call.

Today's call is being recorded, and after today's presentation, there will be an opportunity to ask questions.

(Operator Instructions)

At this time, I would like to turn the conference over to Patrick Kane, Chief Investor Relations Officer.

Please go ahead, sir.

Thanks, Jennifer.

Good morning, everyone, and thank you for participating in EQT Corporation's 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 Vice President and President of Midstream and Commercial; and Steve Schlotterbeck, Executive Vice President and President of Exploration and Production.

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

The telephone number for the replay is 719-457-0820.

The confirmation code is 8682699.

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

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

Earlier this morning, there were a separate joint press release issued by EQM and EQGP.

The Partnership's conference call is at 11:30 am today, which requires that we take the last question at 11:20.

The dial-in number for that call is 913-312-9034.

The confirmation code is 2157781.

In just a moment, Phil will summarize EQT's results.

Next Steve will have a brief Utica update.

Finally, Dave will provide preliminary thoughts on EQT's 2016 capital budget.

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

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, under risk factors in EQT's Form 10-K for the year ended December 31, 2014, 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 financial measures, including reconciliations to the most comparable GAAP measure.

Before turning the call over to Phil, I will walk you through one of the non-GAAP reconciliations that caused some confusion last quarter.

Specifically, production adjusted net operating revenue presented on page 7 of today's release.

This number is used as the basis for calculating our average realized sales price as presented on the price reconciliation, including -- included in this morning's release.

The average realized price is calculated by dividing the adjusted net operating revenue by total sales volumes.

There is a non-GAAP reconciliation in the release that I will briefly explain.

We are making two adjustments to EQT production total operating revenues as reported on the segment page, in order to provide you with operating revenues, and excluding the non-cash impact of derivatives, and the net of transportation and processing costs.

With respect to derivatives, adjustments for non-cash derivative activity have been the subject of SEC comments over the past couple of years.

As a result, in accordance with what appears to be the SEC preference in this area, we adjust out the non-cash activity in three steps.

First, we back out all gains and losses on derivatives not designated -- as hedges that were included in revenues during the period, which is the mark-to-market impact, which was $160.5 million in this quarter.

Two, we add back the actual cash received, $33.2 million, and deduct the premiums paid for derivatives that settled during the quarter, which was $1 million.

This leaves us with just the actual cash received, net of any premiums paid in our adjusted revenue number.

The final adjustment on our non-GAAP reconciliations simply reduces the total operating revenues by $64.7 million of costs reported as expense on EQT production segment page for transportation and processing.

This provides a realized price net of transportation and processing costs, which is consistent with our historic presentation.

With that, I will turn the call over to Phil Conti.

Thanks, Pat, and good morning, everyone.

As you read in the press release this morning, EQT announced the third-quarter 2015 adjusted loss of $0.33 per diluted share, which represents an $0.83 per share decrease from adjusted EPS in the third quarter of 2014.

Adjusted operating cash flow was $156.3 million in the quarter, or 46% lower than the third quarter of 2014.

Results for the quarter were negatively impacted by lower commodity prices.

Due to lower strip prices since last quarter, we also recorded a significant non-cash gain on hedges of future production of $128.3 million during the quarter, and that was some of the stuff that Pat just talked about.

And that's excluded from the adjusted earnings and cash flow.

I'd like to briefly take a look at our current -- continuing in depth in the recently IPO'd EQGP.

(technical difficulty) On October 20, 2015, EQGP announced a cash distribution to its unitholders of $0.104 per unit for the third quarter of 2015, or a 13% increase over the equivalent full quarter distribution in the second quarter.

The third quarter distribution decision represents $24.9 million in payments, which EQT will receive on November 23.

These quarterly payments will continue to grow as distributions at EQGP grow, and they highlight the value of each EQGP to EQT.

The operational results were fairly straightforward in the third-quarter.

So I will move right into the segment results, and I will be brief.

First, EQT production continued to grow production sales volumes by 27%, compared to the third quarter of 2014.

However, revenues from that growth were more than offset by the lower commodity prices, negatively impacting results in the third quarter.

The average realized price at EQT production was $1.21 per Mcf equivalent, a 55% decrease from $2.69 per Mcf equivalent last year, which led to adjusted operating revenue for the quarter of $188.5 million or $142.5 million lower than last year's third quarter.

There were many factors that led to the lower price, but lower NYMEX and liquids prices versus last year were the primary drivers.

You will find the detailed components of the price differences in the tables in this morning's release.

The adjusted operating loss at EQT production was $72 million, excluding the non-cash gain on hedges of $128.3 million that I just mentioned.

That compares to adjusted operating income of $107.9 million in the third quarter of 2014, and that was also excluding a non-cash gain on hedges.

Total operating expenses at EQT production were $325.2 million, or $[53.5] million higher compared to the third quarter of 2014.

DD&A was $30.2 million higher.

Transportation and processing expense was about $[16] million higher.

Exploration expense was $4.6 million higher, and LOE excluding production taxes was about $1.6 million higher, all consistent with the volume growth.

Production tax decreased by $3 million, due to the lower commodity prices in the period.

SG&A expense, excluding $3.5 million in rig release penalties was about $0.5 million higher.

Midstream results.

Here the operating income was up 21%.

The increase is consistent with the growth of gathered volumes and increased fixed capacity based transmission charges.

Gathering revenues increased 23% to $125.9 million in the third quarter of 2015, primarily due to a 24% increase in gathered volumes.

Transmission revenues for the third quarter of 2015 increased by $6.9 million or 12%,driven by additional firm contracted capacity added over the past year.

Operating expenses at midstream for the third quarter of $82.2 million, were about $9.4 million higher than last year, consistent with the growth in the midstream business.

And just to conclude with a brief note on liquidity, EQT did have $1.7 [billion] of cash on hand at quarter end, not including cash at EQM and EQGP, as well as full availability under EQT's $1.5 billion credit facility.

So we remain in a strong liquidity position to accomplish our goals for the foreseeable future.

Our current estimate of 2015 EQT operating cash flow is $900 million, adjusted to exclude the noncontrolling interest portion of EQM and EQGP's cash flow.

And with that, I will turn the call over to Steve.

Thank you, Phil.

Today I'll provide you an update on our deep Utica well program.

As discussed on the last call, we completed our first deep Utica well in July, the Scotts Run 591340.

To remind you, the well's initial 24-hour flow was 72.9 million cubic feet, with an average flowing casing pressure of 8,641 psi.

We been [pouring] this well directly into the shales pipeline at a choke-restricted rate of about 30 million cubic feet per day.

Except for the seven days required to install the wellhead equipment, daily sales have been steady at this rate.

Casing pressure has been declining at an average of 40 psi per day.

As of yesterday, sales volumes were 30.4 million cubic feet per day, and the casing pressure was 6,320 psi.

Cumulative production from this well has totaled 2.6 Bcf in the first 86 days of production.

Our expectation is that the daily production rate will not decline until the well pressure declines to the pipeline pressure which is 500 psi.

Based on an extrapolation of the current pressure decline rate, we estimate that we will reach line pressure after approximately eight months of production, which will be in late March 2016.

The cumulative production at that time would be approximately 7.4 Bcf.

At that point, we have a wide range of possible decline curves, as we do not have any analogous decline data to rely on.

Our current reservoir modeling suggests an ultimate expected recovery for this well in a range between 13.9 Bcf and 18.8 Bcf, for range of 4.3 to 5.9 Bcf per 1,000 foot of lateral.

Using the lowest EUR of our range, and assuming the high end of our cost per well target of between $12.5 million and $14 million per well, we estimate returns at a $2 wellhead gas price to be north of 20%, for a 5,400 foot lateral well.

Since the last call, we have spud two additional Utica wells.

In August, we spud a second Greene County well, the Pettit number 593066, which is located approximately 5 miles northeast of the Scotts Run well.

We are currently at a depth of 12,200 feet, and have installed the intermediate casing.

We are just beginning to drill a curve on this well, and expect this well to be in line before the end of the year.

The third well was spud in September in Wetzel County, West Virginia, the Big 190 well, and is located approximately 30 miles southwest of the Scotts Run well.

We reached TD as a deep intermediate hole.

The top hole rig has been moved off the well, and the well is secured, awaiting the big rig to run the intermediate casing.

The rest of the drilling will be completed when the Greene County rig is finished with the Pettit well, and that rig is moved to West Virginia later this year.

We are making good progress on cost reductions for these wells.

Specifically, at the current depth of the Pettit well, we spent approximately 22% less than we did on the Scotts Run well at the same point.

As I previously noted, we expect it to take several wells for us to achieve our cost target for these wells of between $12.5 million and $14 million.

We are pleased with our progress so far, and remain confident that we will achieve our targeted costs.

We will continue to post well data from the Scotts Run well on our analyst presentation periodically, and we'll update you on the progress of the latest two wells as warranted.

I will now turn the call over to Dave Porges for his initial thoughts on next year's capital budget.

Thank you, Steve, and good morning, everyone.

Today the topic of my prepared remarks as Steve mentioned is our preliminary thinking regarding EQT's 2016 capital budget.

We met with our Board last week to discuss our long-term strategy, as we do every October.

Our Board then meets in early December to approve the upcoming year's operating plan and capital budget.

A key aspect of the discussion in last week's meeting was the impact of the emerging deep Utica play on EQT's strategy.

There have been fewer than 10 wells drilled and completed in the deep Utica around our acreage.

So it is still too early to be confident that the play will be economic, but the early results are certainly encouraging.

Specifically, if the Utica does work, which for us means that the returns are better than returns from the core Marcellus, we will certainly add significant resource potential to our inventory.

However, the clearing price for natural gas will likely be lower in that scenario, than if the Utica is less economic.

As a result, some of our other inventory that requires higher prices to make economic returns would be deferred possibly for many years.

So while those of us, certainly including EQT, who have significant positions in the core of the deep Utica will be the winners, if you will.

The cannibalization of other opportunities will affect everyone, including those of us who will net-net be much better off, if the deep Utica play does work economically.

Given this potential for lower long-term gas prices, we do not think it prudent to invest much money in wells whose all-in after-tax returns exceed our investment hurdle rates by only a relatively small amount.

As a result, we are suspending drilling in those areas, such as central Pennsylvania and our Upper Devonian play that are outside that core.

This decision will affect our 2016 capital plan, though we are just starting to develop the specifics of the 2016 drilling program that forms the core of that plan.

The focus in 2016 will be on this more narrowly drawn notion of what the core Marcellus would be, assuming the deep Utica play works.

We will also pursue the deep Utica play with a goal of determining economics, size of resource, and midstream needs, and on lowering the cost per well to our target range.

Our initial thoughts are a 10 to 15 well deep Utica program in 2016, with flexibility to shift capital between Marcellus and Utica as warranted, based on our progress.

Our preliminary estimate for production volume growth in 2016 versus 2015 is 15% to 20%, which we will refine when we announce our formal development plan in early December.

If we turn in line our fourth quarter wells in late December as contemplated in our fourth-quarter guidance, 2016 growth would likely be nearer the upper end of that range, as those wells would contribute little if anything to volumes until early 2016.

Obviously, this overall approach will result in a 2016 capital budget, absent any acquisitions that is a fair bit lower than 2015, and would result in continuing (technical difficulty) of cash on hand as of end 2016.

But we will provide specifics in December.

Another strategic implication of an economic deep Utica play is the significant opportunity for EQM.

A year ago, it would be hard to imagine -- would have been hard to imagine a more prolific play than the Marcellus.

And EQM has all ready announced a $3 billion backlog of midstream projects to serve the Marcellus play.

Incidentally, that entire current backlog continues to make sense if the deep Utica proves economic, as it either supports core Marcellus, or takeaway projects that are needed regardless of the source rock for the natural gas.

However, if the deep Utica works, it is likely to be larger than the Marcellus over time.

The magnitude of incremental takeaway in gathering pipelines such a play would support is significant, even net of the previously mentioned reduction to Marcellus development that would occur in this scenario.

As we think about the EQT corporate structure, we are not likely to make any major decisions to change the current integrated model, until we do understand the scope of a potential deep Utica development program.

We have reached -- reaped rather much value in recent years from having the two businesses together, and there is the potential that both companies would continue to benefit from these synergies into the dawn of the Utica era.

Finally, the deep Utica potential has also affected our thoughts around acreage acquisitions.

Given our view that our existing acreage sits on what is expected to be the core of the core in deep Utica, we are focusing our interest -- our area of interest even more tightly on acreage that is in our core Marcellus, and potentially core deep Utica area.

As you can probably deduce from the lack of significant transaction announcements, the bid/ask spread continues to be wide.

We are a patient company, and believe that there will be acreage available at fair prices eventually.

But the definition of fair has to contemplate the potential that the deep Utica works.

We do not think that bodes well for the price of acreage concentrated in anything, but the core Marcellus and core Utica.

This narrowing focus also suggests that smaller asset deals are much more likely than larger corporate deals.

However, as we have stated previously, we are comfortable maintaining our industry-leading balance sheet, even as we look for opportunities to create value.

In conclusion, 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.

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

Thank you, Dave.

Jennifer, we are ready to open up the call for questions.

(Operator Instructions)

Neal Dingmann, SunTrust.

Good morning, gentlemen.

Say Dave, just on that last part that you mentioned on the M&A, your thoughts?

And I would agree on that, that the strong, obviously position that you have in that deep Utica.

Are you and Steve thinking more bolt-on in that area?

Are there some big packages you see?

Anything else you could add, about what you are kind of looking at in regard to M&A in that area?

Steve, has been closer to that, so I will let him answer the question.

Sure, Neal.

Our primary focus in terms of looking at acquisitions, is really focused on a pretty narrow core area.

And we will be updating our investor presentation later today, and you will see a map that shows the area most of interest to us, where we will be focusing our development program, as well as any M&A activities that we would be interested in.

So right now, it seems like there's -- people are interested in selling assets.

So far the prices have still been a bit high.

But as Dave said, we plan on being patient, and waiting for what we consider fair prices before we transact.

Okay.

And then, that --the 10 to 15 wells you mentioned, Steve, in the deep Utica, your thoughts.

How far north?

I mean, you have got obviously some interesting acreage all way up into Allegheny, and given how successful CNX is -- obviously their Gaut well was, all the way clear up into Westmoreland.

Just your thoughts on -- any ideas you can give us on those 10 to 15 wells?

Will most of those be focused down around that Greene County area, or will you take them all the way up to -- potentially as north as Allegheny?

Well, we haven't spotted all of those 10 to 15, so it will depend on the results we see.

But I would say, certainly into southern Allegheny County, where we have a pretty significant position and high expectations for the Utica.

Maybe up into the northern Allegheny, but more likely it would be for us, southwestern Armstrong, where we have an acreage position.

I think our view would probably be to let others define that area.

Part of the reason would be a more limited takeaway capacity up there.

So probably not going to be in a big hurry to drill some of these monster wells up there.

Probably more focused, from southern Allegheny down into southern Wetzel, and maybe a bit over into far western Marion County.

Got it.

And then, just a last question.

Just on takeaway for the dry gas.

David, at one time, David, you thought -- I think you commented that the only really limitation might be just takeaway, as far in there, and given how successful these wells, and how economic these wells look?

If you and Steve can talk about it, is that -- again, does that have limitations to how many wells you drill next year?

Or by some point next year, you will have ample Utica takeaway?

Geez, I think these -- if the early results continue to show up, if we see things consistent with those early results in future wells, I think we are probably going to be looking at takeaway limitations for a while.

I mean, I think these wells can probably support volumes that the midstream wasn't really designed for.

And it's -- I mean, we probably ought let Randy speak to this, but it would -- it's going to take a while probably to figure out what the right midstream configuration is for the deep Utica.

Randy, do have any thoughts on that?

No.

I concur.

Obviously, we have been trying to stay out front of the Marcellus, and we have looked at our Ohio Valley connector that is coming on.

But I would also say, we are looking at the Jupiter system, and how we can leverage that, and the infrastructure that we have in Equitrans.

So I think we are best-positioned to move a good bit of the product, but certainly these wells are quite exciting.

And so, that will take a lot of additional infrastructure as we develop the play.

Now we do think incidentally, that the cost per unit is going to be considerably less than it is for the Marcellus, because of the higher volumes.

And frankly, the more concentrated nature of it.

I mean, it's not just higher volumes, it is that you can get it from a tighter area.

That is much better answer from the perspective of unit gathering and compression costs.

Actually, the compression costs early on is going to probably be a round number (multiple speakers).

Good.

Thanks.

Great details then.

Phillip Jungwirth, BMO.

Good morning.

A couple of questions on Utica well costs.

First, wondering if you can provide us with AFE for the second Greene county and first Wetzel county Utica wells?

And then, second, your targeted well costs imply about $2,500 per foot, which I know as compares to some of the smaller peers over in Belmont and Monroe County who are quoting $1,200 to $1.500 per foot.

Obviously, the Pennsylvania Utica is 13,000 feet compared to 10,000.

But do you think the deeper depth and high pressures would account for all of this difference?

Or could there be further room to bring costs down, as you progress through development?

Phil, this is Steve.

I think that -- I guess, regarding the AFEs, I don't have the exact numbers in front of me, but they are in the low $17 millions per well.

That cost will be dependent on the ultimate lateral length, so we have some flexibility about how long we end up drilling these.

So I wouldn't put a whole lot of weight on those numbers, but a significant decrease from the actual costs from our first well, which was around $30 million.

And the second part of your question, remind me again?

Oh, the cost per foot?

I think our view is that, when we sit down and do a bottoms-up analysis of what we think it should cost to drill these wells, once you work through all of the problems, and get the nonproductive time down to a minimum.

That is where we come up with that $12.5 million.

So I think at current service costs -- I never say never -- but we don't see a path to being significantly less than that for these wells.

And I think the $14 million gives us some room to have a few unexpected problems that maybe we wouldn't normally have on Marcellus wells, which is why we are quoting a range right now.

But our hope is to get at the bottom end of that range, but very confident we will get within the top end.

Okay, great.

Yes, it looks like based on the EUR map, that the implied F&D is already pretty comparable to what you're seeing in the Marcellus.

A second question.

On the last call, you had mentioned how EQM is now more of an organic growth story.

But with the narrowing of the Marcellus development in 2016 and beyond, how does this impact future drop-downs, given that most of the gathering and transmission assets held by EQT appear to be outside of the core southwest PA and northwest Virginia areas?

So we are still working through what we want to do, with future drops.

But the comment about, what is most economic for EQM is independent of that.

We're -- EQM is now, as you know, into the high splits.

And it is just more economical for an MLP to organically develop projects, than to have to pay up, as long as it can afford it.

As long as it has got the coverage, that allows it to [wear] that period of time, when they have got assets tied up in projects that aren't generating cash flow.

So we will have to work through what happens with the remaining projects et cetera, as we go through 2016.

But my comments in the past about organic growth being the preference, is just because of the way it works, when you have got all of that incremental cash flow going to the GP.

Got it.

And then, historically EQT has always pre-funded the following year's cash flow [outspend] with asset sales or drop downs.

Would this also be the intention in 2016, or do you consider the $1.7 billion in cash on the balance sheet as having already accomplished that, given that I think you've mentioned that you have built cash as of year-end 2016?

Yes, I'd basically said, we'd already accomplished that.

Okay, great.

Thanks.

Michael Hall, Heikkinen Energy Advisors.

Thanks, good morning.

I just wanted to touch a little bit on the backlog, get your updated thoughts around how that progresses over time?

Just it's up materially year on year, continuing to grow sequentially.

And just trying to think through what the strategy is there, when you think that, if ever, would ultimately be drawn down?

And how that is contemplated in the 2016 plan?

Yes, Michael, this is Steve.

Yes, the backlog in terms of frac stages complete but not online, grew a bit this quarter as you saw.

Our expectation is that the fourth quarter will be a pretty big quarter for new TILs.

Most of those will be in the back half of the quarter.

So it won't affect volumes in the quarter very much, but it should be coming on late.

So I think you'll see a fairly significant drop back to more historic levels, when we -- on the next call, when we are talking about Q4.

Okay.

And so, is there any thought process of continuing to draw that down even further in 2016, or is that move in the following quarter, you think that gets you to a place when you're more at run rate (multiple speakers)?

I think that will be more at a typical run rate.

If you look back over our history, you go back three years or so, I think we have been giving these numbers.

You will see it's always very lumpy.

The biggest driver behind that backlog, is just the timing of the rigs, and the number of wells, the number of fracs per well, for every pad we are on.

So it tends to be very lumpy.

Right now, we haven't been taking any heroic efforts to get wells online super fast.

So that maybe drives the backlog a little bit this quarter.

But again, you will see by next quarter we will be back into more -- more closer to the mean over the past few years.

Okay.

Then any indications around capital associated with that 2016 outlook?

Geez, only that it would be less than 2015.

I mean, that's -- but it's a fall out of this narrowing focus.

But I feel uncomfortable putting numbers out there, when we are still -- what, six weeks away from putting numbers in front of our own Board.

But if you're looking for directional, it would be -- clearly, we are heading less than 2015.

That 's helpful.

Okay.

And then, I guess, I just wanted to -- a last question of mine, and think about the fourth quarter a little bit.

And I think you alluded to it in your comments about the back-loaded nature of the completions.

But just the implications, backing off the first three quarters of the year, kind of flat to down on the quarter.

What are the sensitivities around that, from an operational perspective?

How should we think about, what might put you on one end of the range, or the other?

The rate for the fourth quarter?

I think we would just stick with what Steve said, which is we're aiming towards a lot of those pads getting TILd really at the end of the quarter.

And therefore, having very little impact on fourth quarter volumes.

And so, that results in the guidance being what it is.

But we get asked a lot about our response to current prices at any one point in time.

And as Steve was alluding to, in this price environment, it doesn't seem like the right time to be going through any type of heroic efforts to get things turned online anymore quickly.

Right, so, if they -- the notion that we reflected in the guidance that those TILs are going to drift backwards is just not troublesome.

Look, they still get [TILd].

It's just -- the question is, it's whether it affects the December volumes or the January volumes is really the issue.

Fair enough.

In the past, you have -- and just kind of brought up another question I had -- in the past, you have talked about a pretty substantial spud to turn to sales time of nine months or so.

And therefore, 2015 spending is really baking in the 2016 growth rate.

Given that, I mean, if that is still in place, which I would imagine it is, is there really a price at which in 2016, you would be able to really slow down the production?

Or how do you tactically respond to gas prices in 2016, if they continue to remain at these low levels on a realized basis?

Well, we will look at that, as 2016 plays out.

Obviously, part of the consideration, as you mentioned, is what the prices are, but really the midstream is a big part of the consideration too.

If you have some midstream flexibility, you can slow down and make it up later if you want to.

And when the midstream is more full, then you have to decide, you either want it or you don't.

You want the volumes, or you don't want the volumes, because you can't really make it up on the backend, right?

It is quite a ways down the road before you can make up those volumes.

But, we certainly take prices into account, when we're making our decisions about capital expenditures, and what type of efforts to go through to try to accelerate, or otherwise turn in lines for wells.

Okay.

That is helpful.

And then, one last one.

On the gas processing side, do you have any increase, increases in commitments around volumes from gas processing contracts that we ought to be keeping in mind, given how low NGL prices --?

Michael, there's a little bit more coming on in January.

Less than 5% of where we are.

Okay.

Thanks.

Stephen Richardson, Evercore ISI.

David, as you think about the strategy, and then, you just went through some of these thoughts with the Board.

So is there any evolution in your thoughts in terms of what the right mix of upstream, versus midstream capital is here, in terms of -- I appreciate that EQM is funded to some extent organically.

But in terms of returns, and how to optimize that beyond 2017, just considering the gas outlook versus the gathering outlook from what you see from the different horizons here?

Well, first of all, just to reiterate, my belief is, the further out in the future you look, the clear -- and you mentioned beyond 2017, the clearer it is in my mind, that capital expenditures for midstream should be at the EQM level.

We want to protect that IDR.

And the way to do that is to have the most attractive midstream projects possible, so that they can afford to pay the incremental cash flow to the GP, which is the core value of that IDR, where we stand now.

So, that is going to be the mindset.

Strategically, it is going to a midstream expenditures should occur at EQM.

Now if you're trying to get at what is more valuable, generally midstream or upstream?

I guess, that is a bigger picture question than just one company, and we will see.

We are trying to position ourselves so that we can be agnostic.

So that we can take advantage of wherever the value is in the value chain.

I agree, that with the prospects of Utica and issues like that, it is not clear what the value chain will look like several years down the road.

But we think that the reason EQT is such an attractive investment, is because EQT will participate no matter where the most value shows up in that value chain.

Right.

And can you just remind us, as you think about upstream, like the right capital allocation at EQT production for next year, and appreciating this nine-month or 12-month gap between you deploy capital, and when it shows up in production?

Like what is the -- is it a wellhead hurdle rate, is it a corporate return, is it a Board burden return?

What is the right -- (multiple speakers)?

It's an all-in return -- we look at all, yes, we look at all-in after tax returns is the way we tend to look at things.

But that overlay, that I mentioned in my prepared remarks was, we just think we need to bear in mind, what if the deep Utica works, and what does that mean for clearing prices et cetera?

And therefore, we should be particularly cautious about investing in anything, but the core Marcellus, which does stand up still in those environments, and in the core Utica.

So it's more that.

There's always uncertainty about what prices are going to be.

But whenever you have a new low-cost supply source in any commodity business, you have got to start being warier of where one wants to invest one's money.

So, I think there's a certain amount of caution that we're taking, that we're talking about, because of that unknown, because of not knowing yet, the extent to which the deep Utica will work.

But our feeling that if it works the way it is looking like it might, that the core areas for Marcellus and Utica are simply going to be narrower.

And we are going to be able to supply a big portion of North America's natural gas needs from a relatively small geography.

Right.

And then, sorry, just a final question for me is, have you, and maybe it's for Randy, in terms of conversations or thoughts on what the third-party opportunity is at this horizon?

So again, we are all assuming that if this is economic, and it is lower cost, and isn't just a zero-sum game in terms of different capital going to the Utica, but is EQM particularly well-positioned to capture a larger proportion of potential third-party volumes in these areas than you have in the Marcellus?

Is this a big piece of forward growth beyond $3 billion CapEx number?

This is Randy.

Yes, I think we have a significant opportunity with the well results that we are seeing.

In fact, I think Dave and Steve both mentioned that the core of the core of Utica actually appears to sit right on top of our EQM assets, both at Equitrans, and with the gathering assets along Jupiter in northern West Virginia.

So, and our projects that we have embarked on currently, which is the Ohio Valley connector and our Mountain Valley pipeline, I think position us quite well to both move -- be competitive and move gas for both affiliate, as well as third-parties.

And so, I think we're very competitively well-positioned.

Yes, and look, to your point, probably we weren't as well-positioned as you move a little bit outside the core Marcellus, from midstream perspective.

So, this emergence of the Utica is from a competitive and comparative perspective, a positive for EUM.

Great.

Thank you very much.

Drew Venker, Morgan Stanley.

Good morning, everyone.

Could you speak to how the 2016 program could change if we have a warm winter, and gas prices are well below the strip?

I'm thinking something around $2.25 for 2016?

And I'm particularly interested whether that would significantly reduce your appetite to delineate the Utica in 2016?

And conversely, if prices are higher, would that change that Utica program at all?

You -- at that point though, you're just talking about what 2016 prices would be?

I mean, the norm in commodities, and I understand there's a -- there does tend to be in the investor community a short-term focus.

I recognize that people need to make money each quarter.

But actually lower prices near-term, tend to lead to more robust recoveries later.

So our view is much more, the low-cost opportunities are going to be the ones that win out.

And you want to make sure that you're -- especially if you think prices are going to be stressed at all, that you're focusing on only going after the lowest cost opportunities, and not letting yourself kind of get drawn into investing in opportunities that are other than that.

So I would say, that is our focus anyway.

And look, in a lower price environment -- if we're talking about the deep Utica perhaps helping to create, that obviously becomes even more important.

Right.

So, Dave, it sounds like it's not -- probably not much change?

Well, change for -- yes, but the thing is, we're not telling you what our 2016 plan is yet, because we haven't gotten it approved from our Board.

So I -- it's -- I'm not even sure how I would go about telling you what the change would be, versus the plan that we can't even discuss with you.

Fair enough, Dave.

I mean, but (multiple speakers)

And then -- (multiple speakers)

If prices are lower, then we would probably over time, we'll spend less money.

And if they are higher, we will probably spend more money over time.

But we are talking about 2016 being below, a fair bit below 2015 as it is.

Right.

I was thinking, Dave, you mentioned maybe 10 or15 wells in the Utica in 2016.

That is really what I was thinking about, not the broader program.

Yes, well, that will be governed by how attractive it looks, because those will still be more economical wells than anything else could, probably, that could get drilled anywhere in the country so.

Okay.

And then, you were speaking to probably wanting to build out another gathering system for the Utica.

Does that delay how quickly you want to move into development mode there?

Let's fast forward it and say, you're very happy with the results, or maybe even more pleased than what you're seeing today, would you still need to put that gathering system in place, before you could accelerate in 2017?

Yes, we're actually still -- (multiple speakers)

(Multiple speakers) -- too early to even think about that?

Well, no, it's not too early to think about it, but we haven't actually settled on what that approach will be.

We, our bias is that a fair bit of the gathering for Utica is probably going to be separate, because of the pressures involved.

Right.

But as far as the specifics, and exactly where it is, and exactly how much money gets spent, that we haven't -- we're not ready to disclose that stuff.

We are only just in the midst of even discussing that internally, and with our own Board.

Another way to ask would be, would you be interested potentially to have lower activity levels, so you're not putting those very high pressures into your Marcellus gathering system?

Look, we're not going to put into our Marcellus gathering system.

That's -- (multiple speakers) well, go ahead, Steve.

Actually, in the short-term, Drew, we can put it into the Marcellus system.

It is not the most optimum situation long-term for the Utica, because the gathering -- the unit gathering cost for the Utica in a dedicated system will be significantly lower than the cost to move it through a Marcellus system.

But for the next couple of years, until we figure out exactly what the optimum systems are, and get them built, we can -- and the likely impact, if we were doing that, because Utica was looking so good, would probably be a shift from Marcellus investments to Utica.

Which is how -- which is where the capacity in those systems would effectively come from.

We would replace Marcellus gas with Utica.

And as we built Utica systems, at that point, we would start to get the benefits of the lower unit costs.

Okay.

All right.

That is very helpful color.

The [reasons] are great, and I wasn't trying to talk them down or anything.

Thanks a lot, guys.

Thank you.

At this time, I will turn it back over to our speakers for any additional or closing remarks.

Thank you, Jennifer.

As Steve mentioned, we will be posting a new analyst presentation to our website later today.

So that will be available sometime after 4:00.

And I would like to thank you all for participating.

And that does conclude today's conference.

Thank you for your participation.