EQT Corp (EQT) 2015 Q2 法說會逐字稿

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

Today's call is being recorded.

(Operator Instructions)

At this time, I would like to turn the conference over to Patrick Kane, please go ahead.

Thanks, [Kya].

Good morning, everyone.

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 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 PM.

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

The confirmation code is 9281362.

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

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 partnership's conference call at 11:30 -- there was a conference call at 11:30 today for the partnerships, which require that we take the last question at 11:20 today.

The dial-in number for that call is 913-312-9034, with a confirmation code of 7812066.

Later today, we will be updating our analyst presentation on our website to reflect the 5% reduction in our cost per well since April, 16% year to date.

We also updated our base case lateral lanes to better reflect the actual drilling program and made other minor updates.

Under news releases, we updated our guidance metrics for 2015, including a modest reduction of our CapEx of approximately $100 million.

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

Next, Steve will have a brief topical update and finally, Dave will provide a review of EQTP's IPO, including valuation implications.

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

I'd like to remind you that today's call may contain forward-looking statements.

You can find factors that could cause the Company's actual results to differ materially from these forward-looking statements listed in today's press release and under risk factors in EQT's Form 10-K for the year ended December 31, 2014, as updated by any subsequent Form 10-Qs, which are on file with 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 to the most comparable GAAP financial measures.

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 2015 adjusted earnings per diluted share of $0.01, which represents a $0.60 per share decrease from adjusted EPS in the second quarter of 2014.

Adjusted operating cash flow attributable to EQT also decreased by $202.3 million to $80.7 million for the quarter.

Results in the quarter were significantly negatively impacted by lower commodity prices, which I will address in a minute.

There were two fairly significant non-cash items that partially offset each other in the adjusted earnings this quarter.

First, we recorded non-cash losses on hedges of $25.9 million during the quarter.

The second item was a positive $35.7 million benefit based on IRS guidance on the regulatory rate-making treatment of a like kind exchange associated with the utilities sale, which had the effect of favorably distorting the reported effective tax rate for the second quarter.

This tax benefit will reverse either over the life of the assets or upon a taxable disposition, such as a future drop-down.

Excluding this tax benefit, our year-to-date effective tax rate was 10.5%, which is still abnormally low due to an increase in our earnings attributable to the non-controlling unit-holders of EQM and EQGP, which are not tax affected, as well as negative production operating income as a result of lower commodity prices.

As Pat mentioned, EQT Midstream Partners and EQT GP Holdings results are consolidated in EQT corporation results and EQT recorded $58.2 million of net income attributable to non-controlling interests or $0.38 per diluted share in the second-quarter 2015.

Other than that, the second quarter was fairly straightforward and I will keep my remarks rather brief.

Starting with EQT Production, the story here continues to be growth in sales of produced natural gas, although that growth was overshadowed this period by lower commodity prices.

Production sales volume in the recently completed quarter was 34% higher than the second-quarter 2014.

Despite that volume growth, we recorded a $66.9 million operating loss in the quarter at Production, including the non-cash losses on hedges of $25.9 million that I just mentioned.

And that compared to operating income of $113.7 million last year, excluding the $31 million gain on the asset exchange in the second quarter of 2014.

So again, the significantly lower average realized price more than offset the volume growth.

Operating revenues were $269.5 million, excluding the non-cash loss, $113.5 million lower than last year's second quarter.

The realized price at EQT Production was $1.41 per Mcf equivalent compared to $3 per Mcf equivalent last year.

And you'll find detailed components of the price differences in the tables in this morning's release.

Total operating expenses at EQT Production were $310.5 million or $50.7 million higher quarter over quarter.

DD&A was $37 million higher, transportation and processing expenses were about $11 million higher, and LOE excluding Production taxes were about $3 million higher; all consistent with volume growth.

Exploration expense, including $9.4 million of non-cash lease impairments, was $4 million higher quarter over quarter.

Moving onto the Midstream business, operating income here was $108.2 million, up 22% over the second quarter of 2014.

This is consistent with the growth of gathered volumes and increased capacity-based transmission revenue.

Gathering net operating revenues increased by 35% to $122.9 million as gathering volumes increased by 35%.

Transmission net revenues increased 19% to $61.1 million, as additional firm capacity was added over the past year, mostly in the fourth quarter of 2014.

Storage marketing and other net operating revenues were down $4.3 million in the quarter.

Total operating expenses at Midstream were $81.2 million or $10.6 million higher, as a result of our continuing growth.

On a per-unit basis, however, G&C expense was down 19% as a result of volumes growing faster than expenses.

Just a brief note on liquidity, EQT had about $2 billion in cash on hand at quarter end, excluding the cash on hand at EQM and EQGP, as long as full availability under EQT's $1.5 billion credit facility.

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

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

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

Thank you, Phil.

Today, I'll give you an update on the two topics of interest to investors over the past few months: upstream M&A and our deep Utica well.

On the upstream M&A front, we've not seen many deals getting done.

It seems that sellers have not changed their value expectations to reflect the natural gas strip that is significantly lower than a year ago.

We continue to believe that they're a significant value creation opportunity by consolidating core Marcellus positions into larger, more contiguous blocks.

This would not only add to our core Marcellus development inventory, but more importantly, it would increase the economic value of our existing leasehold by taking advantage of the significant economies of scale of larger multi-well pads and longer laterals.

We also believe that attractive M&A opportunities may present themselves as the effects of the low price environment become more pronounced for companies that entered this cycle with insufficient liquidity.

However, we will be patient to ensure that any M&A activity we pursue will create additional value for our shareholders.

Moving on to our dry gas Utica well, last week we successfully completed the fracking of this well.

The frac was an 18-stage job in a 3,221-foot lateral that utilized ceramic proppant.

We were able to successfully place 100% of the planned proppant while maintaining our desired pumping rate.

Last night, we concluded a 24-hour deliverability test to sales of this well.

During this test, the well averaged 72.9 million cubic feet per day with an average flowing casing pressure of 8,641 psi.

This equates to a 24 hour IP per 1,000-foot of lateral of 22.6 million cubic feet per day.

To the best of our knowledge, this is the highest reported IP of any Utica well to date and the per-foot rate is more than double the previous high.

As you might expect, we're very pleased with the results of this well.

I want to make note of the fact that we were able to flow this well directly into the sales pipeline without shutting in production from our other wells.

This was possible primarily because of the integrated nature of our upstream and Midstream businesses.

Our Midstream group was able to reconfigure the gathering system to allow this capacity to be available, which likely would not have been possible on the third-party system.

Our current plan is to produce this well at a choke-controlled rate of approximately 24 million cubic feet per day, to manage the stress on the proppant and to monitor the pressure decline so we can begin to get an understanding of the decline profile and EUR potential of this well.

Currently, the well is producing 26 million cubic feet per day and approximately 2,000 barrels of frac water per day, with flowing casing pressure of 9,555 psi.

In fact, the flowing pressure is currently climbing as the well continues to clean up.

In addition, we plan to spud another deep Utica test in Wetzel County, West Virginia in the third quarter of this year.

Following that test, we will evaluate our next steps and we expect to quickly begin focusing on lowering the cost of drilling and completing these wells.

Our current estimate is that wells in this area can be drilled at a total cost of approximately $12.5 million, for a 5,400-foot lateral, but it will take us several more wells to get fully up to learning curve.

Finally, I'd like to take a moment to congratulate all the EQT folks involved in this success.

As you've heard me say before, this well is the most technically challenging well we've ever drilled and completed.

Our outstanding team was up to the challenge and it delivered a truly phenomenal well, while continuing to maintain a safe and environmentally responsible operation.

I'll now turn the call over to Dave Porges for his comments.

Thank you, Steve.

I'm going to mainly discuss topics related to EQGP, but before doing so, want to convey my congratulations to Steve and his team for the recently completed Utica well.

They provided me with daily updates that focused on the issues that were created by the tremendous reservoir pressures we encountered, but also made clear their excitement about the possibilities, and clearly that excitement was more than justified.

Great job.

Now, on to EQT GP Holdings LP or EQGP, which completed its initial public offering of 26.5 million units, priced at $27 per unit in mid-May.

To remind you of our motivation to take the GP public, we were seeking more Midstream value transparency for EQT investors.

EQT Corporation owned 90% of EQGP, a value of about $7.6 billion or about $50 per EQT share.

This is a pre-tax value and the tax basis is low.

Assuming a 15% cash-tax obligation, our stake in EQGP is worth about $6.5 billion.

We also still have about $800 million of Midstream assets that have yet to be dropped for a total Midstream value of $7.3 million.

EQT's market cap is $11.1 billion, that was based on last night's close, implying a value of EQT Production of $3.8 billion.

Using consensus 2016 cash flow estimates of $995 million, EQT Production is being valued at less than 4 times cash flow; less than half the multiple of our Marcellus peers.

So either we are not getting full value in our stock for our Midstream business or our Production business or a combination of both.

We will focus on our IR effort toward highlighting the value of our Company and still anticipate that the transparency provided from a publicly traded GP should start showing up in EQT's stock price.

While the valuation discount rates tension, we think having the two businesses together continues to create significant value for both Midstream and Production, as evidenced by the relative out-performance of EQT and EQM stocks.

The MLP has provided a significant source of capital to fund development of our Marcellus and Utica acreage.

Those volumes are flowing through the Midstream pipes, generating earnings growth at Midstream.

Furthermore, matching the deductions generated from the capital investments at Production minimizes the cash-tax hit from the drop downs of Midstream assets to EQM.

More important strategically is that the combined companies also make projects such as the Ohio Valley Connector and the Mountain Valley Pipeline more viable.

This is because the Midstream starts with a significant anchor shipper in the form of EQT Production and EQT Production gets optimally located by blind projects.

However, we recognize that over time, as EQT Production's growth rate slows and EQM's third-party growth accelerates, the synergies of having the two units together is reduced and the uplift in market value of a separation could exceed the value creation from the synergies.

We are frequently asked about the tax consequences of monetizing our EQGP stake.

So I will summarize the tax impact of a few scenarios we get asked about.

In the event of future sales of EQGP units by EQT, up to about $1 billion per year, we would be able to use our current year drilling deductions to offset the gain on the sale of units.

We would still expect to incur alternative minimum tax obligations of between 10% and 15%.

Given our cash balance and planned drop-down in the first half of next year, it is unlikely that we would need to access this source of capital for some time, but did want to respond to inquiries about that hypothetical situation.

Given the strong M&A market in the Midstream space, we also get asked what would happen in a hypothetical situation in which we sell the entire EQGP stake.

As you likely inferred from my comments on ratable sales, a sale of the entire stake would result in a large gain that would overwhelm our drilling deductions.

In that case, the proceeds in excess of the available deductions would be subject to attacks greater than 15%, but well less than the 35% federal tax rate because of carrybacks.

This would be the worst case from a tax leakage perspective, though the premium that would be required to make that a viable scenario would offset some or even most of the tax leakage.

Clearly in that scenario, we would look for more tax efficient transaction and would also need to find a way to get that value to EQT shareholders rather than just leave that much cash on the balance sheet.

Finally, a tax efficient separation of Midstream from Production is an alternative.

If done properly, a separation would not trigger a tax obligation.

And to answer questions we have received on that scenario, we continue to do a lot of work to ensure that we would not inadvertently endanger a tax-efficient separation.

Though my purpose in this discussion of EQGP was to discuss value transparency and also answer questions related to tax issues, the Utica results also point toward the need to consider Midstream implications of a potential further shift of the North American natural gas supply mix toward the core Marcellus/Utica play.

As Steve alluded to, coordination between upstream and Midstream is even more important if these large Utica wells become the norm.

In addition, even or perhaps, especially in a low-price environment, an environment largely created by Marcellus/Utica productivity, the organic opportunity for Midstream investment in this region grows.

We will continue to focus on gathering and [header] projects with EQM's announcement this morning of another large investment for Range Resources being the latest example.

We'll also continue to look for the occasional complementary takeaway project, such as OVC and MVP.

We are not convinced that these growth prospects are fully reflected in the unit prices of EQM or EQGP, yet the growth prospects for both EQM and EQGP look even greater in the wake of our enormous Utica well and the great results our neighbors have also been getting in their early Utica wells.

The Utica is not exactly a positive for longer-term natural gas prices, but it is very much a positive for those of us with core Utica positions and those of us with Midstream assets in this region.

We will sort through these Midstream implications in the coming months and share our thoughts with you on future calls.

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

We have a very strong balance sheet, which will allow us to continue to be focused on 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 appreciate your continued support.

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

Thank you, Dave.

This concludes the comments portion of the call.

Kya, can we please open the call for questions?

(Operator Instructions)

Phillip Jungwirth from BMO.

Can you expand upon the reduction in the 2015 capital budget by $100 million?

Is that all E&P that can be attributed to incremental cost deflation?

Because it looks like you spent roughly 60% of the $1.7 billion budget which would imply a second half quarterly run rate of $350 million or so or if you are lowering that budget to $1.6 billion, a run rate of about $300 million per quarter.

Phil, about $25 million to $30 million of that is E&P because not all of the well cost will see the reduction for the full year.

The rest is that Midstream projects that are basically slipping into next year on the gathering side.

Great.

With the success in the Utica, EQT is still spending quite a bit of money in the Upper Devonian, which you guys show as a lower return zone.

I think 22% of the spuds this year are going to the Upper Devonian.

Is there a nat gas price where you would rethink that codevelopment with the Marcellus?

Also, how would that compete for capital given the success in the Utica?

Phil, this is Steve.

I think we've already reassessed our Upper Devonian areas based on the lower gas prices, so we'll continue to do that.

There are certain areas at the current prices that makes sense.

Relative to the Utica, while this is clearly a phenomenal well, we need to get up the learning curve and get our costs down and get some decline history of this well so we truly understand what the economics are.

I would say the initial data far exceeds our expectations.

So, I think that's a very positive sign for the economics of the Utica.

But we're going to need to drill a few more wells and understand the type curve a lot better before we make any major shifts to our development plan.

Great.

Then my last question, you highlighted the implied sum of the parts multiple for the EMP business being roughly half what the publicly traded pure play comps are trading at.

In your view, what would you attribute this discount to more?

Is it the market's view that peers have higher returns, greater inventory depth, or is it simply a conglomerate discount that won't be unlocked unless there's a full split from the upstream to Midstream?

Well, my basic view, this is Dave, I'll have Pat answer, too, though, an inadequate Investor Relations effort.

(laughter) Pat, I haven't actually studied why that would be, so I'm happy to --

It is very hard to know.

If you start with the Midstream value, the upstream looks cheap.

If you start with an upstream value, then the Midstream looks cheap.

It seems to be the conglomerate issue.

Thanks, guys.

Scott Hanold with RBC Capital Markets.

Steve, obviously, dry gas Utica well came out at a pretty robust rate and it sounds like you guys are trying to manage it around 26 a day.

I know it's really early, but based on what you've seen from some of the other wells and what you all know from this one, in the short time frame that you've had it online, what is your expectation in terms of that mid-20 a day rate?

How long can that stay flat and implications on what an EUR, an early day EUR could look like?

I think, Scott, we literally finished the deliverability test last night.

The results were quite a bit in excess of our expectations.

So, I think it's a little premature for us to be predicting EUR's and even length of time at the current rate.

We're going to need to study it a little while before we have any reasonable sense of that.

But I think given the 24 hours we've seen, it's a very strong well and the pressures seem to be holding up very well.

In fact, it's still cleaning up.

Like I mentioned in my comments, the pressure is actually still inclining a bit as the water production declines.

It hasn't even really fully cleaned up yet for us to get a good, clean data set.

So, I think you're going to have to wait a little while for that -- those kind of predictions.

Can I ask a question, on what -- when you look at some of the other dry gas Utica wells that have been drilled in, what had been your general expectation?

You said it exceeded expectations, but what was your sense of what EURs can be based on the dozen or so wells that have been drilled with some history in the basin?

Well, again, I don't know that I want to comment on EURs of competitors' wells.

I think you can refer to what they thought.

What I will say is, we had set up to flow this well at 60 million a day and to be honest, I thought that was a bit insane.

I didn't expect that from this short lateral.

We had some extra units out there, in case of mechanical problems, and once we saw what this well is capable of, those backups became primary units so that we could go above the 60 and frankly, we were struggling to hold this well back at those rates.

So, it definitely was -- we were expecting a good result.

Setting up for 60 million a day and then to see these rates with even higher pressures than we expected, which means lower drawdown.

We didn't have to pull on this well very hard at all to get those rates.

The kind of makes us have to go back and reassess what's better about this?

What's better about the reservoir than we expected?

Do we have the right gas in place numbers?

Is there more gas in place?

It's premature, really, to comment on any of that, given less than two days of production data on one well.

The Wetzel County well that you all will be drilling, what is the relative depth to that compared to what this one was at?

It's similar.

Is similar to that 13,000 to 14,000 foot thousand range.

Okay.

My next line of questioning is you had a lot of frac stages in -- that weren't online at the end of this quarter.

Can you give us a general discussion on why that number was so high at the end of the quarter and what we should expect in the coming quarter or two?

Sure.

Same answer I give every call.

That's completely driven by timing of multiwell pads and long laterals with lots of stages.

What I will tell you, that I really haven't provided on future calls, is we expect an increase as the year goes on, in the number of stages we're turning in line per quarter, with the fourth quarter of this year being the highest for the year, which will drive production results in early 2016, but it's strictly driven by the timing of rig moves on big pads.

Okay.

Just so I understand it right, so if there is a multi-well pad there, you're going to complete a certain amount of those wells, but that pad may not be timed correctly to get it online by the end of the quarter, but it would be, for example, in early July and so those would come online a little bit later?

Exactly, yes.

Understood.

Thanks a lot, guys.

Holly Stewart from Howard Weil.

Dave, appreciate the comments on the valuation discrepancy.

It sounds like as you get Pat working harder, this discrepancy will it erode, over time.

He said it was the sell side that had to step up, just so you know.

(laughter) You guys have certainly not been ones to sit on your hands.

I'll leave that discussion, there.

Maybe bigger picture on 2016 thoughts, maybe just thinking similar commodity levels, how does your commodity price levels -- how does your activity change, maybe from this year to next year?

We'll have to take a look at that in the normal course of events.

We do try to be influenced more, given the lags of the wells, by the longer-term strip, something that will match when the gas is actually getting sold.

Of course, one of the things that's going on in the basin right now is that supply is outstripping, for the time being, takeaway capacity.

A number of projects, our projects, EQM projects as well as other Midstream companies projects are coming online over the course of the next couple of years.

That at least will help with that.

Clearly, we will have to relook at activity level and where we allocate resources.

As Steve mentioned, it's very early with the Utica to figure out what the implications are.

If we keep getting these kinds of results and our peers keep getting these kinds of results, then I do think we have to assume that's going to shift the supply demand balance again, which will mean that some places probably don't make sense to develop.

It will probably mean that the Marcellus/Utica, in future, would make up an even higher percentage of the overall mix and we'd have to take that into account, North America's supply mix, and we'll have to take that into account, also.

Clearly, we have to be working all of that in ahead of coming up with a budget for 2016.

Okay.

Perfect.

Maybe, Dave, one other bigger picture question on the cash, I looked back through notes from the end of the year and you said financial stress makes you want to keep more cash on the balance sheet and come out stronger on the other side.

Assuming things haven't changed in that line of thinking, but any color there would be helpful.

That's exactly right.

Still wearing the fire retardant pants so it doesn't burn a hole in our pockets.

Look, as Steve mentioned, if there's opportunities, especially on the upstream side, to enhance our current acreage position, that's great.

We want to be prepared to take advantage of that, but this is one of those times where, after the last three months, I think just for the whole sector, we'd probably say no one would feel bad about having the liquidity position that we've got and if anything, I think we feel better about it.

I'm guessing we will get fewer questions about what we're going to do with all that cash because of this environment.

It just means that we're able to make decisions that we think are the right economic decisions for our shareholders, rather than being overly influenced by near-term liquidity matters.

Yes.

Perfect.

One final minutiae question, on the NGL realizations, I'm assuming no change to the barrel there?

We're still rejecting ethane?

Yes.

For years, our view, or at lease my view has been, getting heat value for ethane is, on a net back basis, not a bad deal versus the alternative.

I've got to tell you, nothing's happened in 2015 that would've change my mind on that.

Yes.

Okay.

Great.

Thanks, guys.

Our next question from Michael Hall from Heikkinen Energy Advisors.

Just wanted to come at the Utica question maybe a little bit different way as relates to competitiveness within the inventory.

What sort of EUR level, given a $12.5 million development cost, would compete with the Marcellus in your thinking?

Again, I'm going to pass on answering that question because it's not based on EURs, it's based on the decline profile of the well.

With 24 hours of data, we just don't know.

It's going to take some time.

Fair enough.

Worth a shot.

(laughter) Somewhat similar to some of the questions that have been asked, but I don't think it's been answered.

Are you all curtailing any material amounts of production?

You had a lot of wells come on in the quarter, but gas production was relatively flat.

Just curious if you're curtailing much?

Operational issues.

Nothing beyond just the normal day-to-day operations.

That's likely due to the fact that a lot of those stages came on late in the quarter and just didn't have time to contribute.

Yes.

That would make sense with the third quarter guide.

The net back to EQT Production, after working through their more fixed type Midstream cost, has fallen quite a bit quarter on quarter and obviously, year on year, even more so.

How sensitive is the second half program to prices, given the fixed cost nature of some of the cost structure?

The second half program isn't really sensitive to near-term spot prices.

We always, again, evaluate based on what the strip is going to be, because there's nothing we will do in the second half that would result in revenues in 2015.

Really, at this point, probably, there's nothing we do going forward that's going to result much in the way of revenues before the second half of 2016, just because of the lags involved.

That's really more what we follow and we do recognize the strip has declined.

But the other issue has been the seasonality with basis has been probably a bigger deal.

That's going to be -- we do time some of these activities to when takeaway projects will be coming online.

That's what I was getting at was more the strip level.

If the strip falls more materially, --

Absolutely.

Always reassess what the economics look like, absolutely.

Okay.

At I think about the G&P to EQT Midstream cost as well as the G&P to third parties, how should we, just from a high level modeling standpoint, think about those on a per unit basis, call it, over the next 18 months?

Are there general pressures one way or the other that we ought to keep in mind?

They've been pretty steady, they've moved a little bit, Michael.

We do, later today, we'll put out updated guidance for the rest of 2015 and you'll see that the second quarter numbers are consistent with that.

Okay.

Sounds great.

Appreciate it.

Neal Dingmann with SunTrust.

Great well.

Steve, I'm just wondering on the 400 -- I think on the slide it shows about 400,000 potential dry gas Utica acres.

What's your thought as far as fully delineating that or are we just sort of stick to this -- call it -- I don't want to call it a quarter, yet, because you don't really know yet where the quarter is.

Will you stick to a concentrated area?

I think our plan will be to drill the Wetzel County, West Virginia well later this year.

We believe both our current well and that well, geologically, should be very similar.

So, we think that.

We think between those two wells and the acreage that they will delineate, we will have delineated plenty, given what these wells will produce.

Then, we'll likely -- rather than focus on delineating the extent of the play, we'll be focused more on cost reductions and efficiencies on the drilling and completion side and probably let our competitors do a little more of defining the limits of the play.

So, I think you'll see most of our drilling concentrated in that southwestern PA, northern West Virginia corridor where we think we have some really excellent Utica rock.

Steve, just the two wells this year?

On the slide or your last update, you mentioned maybe about five or so dry Utica wells this year.

So plan just for the two this year, now?

I think there's a chance we will spud a third late in the year.

We'll have to see on timing.

I think our plan is, since the real economic key, at this point, appears to not be the reservoir, it appears to be the cost to drill and complete.

So, we don't want to go too fast so that we have the opportunity to learn lessons from each well we drill.

For the meantime, we'll probably be drilling one well, sequentially, rather than doubling up rigs so that we can get full benefit from what we learn on each well.

A well in the third quarter, depending on timing of that.

Around the end of the year would probably be another well, maybe it will be late this year, early next year.

Depending on how we progress up that learning curve and what the economic looks like and the decline curve looks like, that's when we'll know when it's time to accelerate or, really, what the plan is.

Steve, was this first one -- this latest one -- was 100% ceramic used on it?

Well, we used some 100 mesh sand in the first part of each stage, but for all of the large-size proppant was 100% ceramic.

Okay.

Do you think you'll build on the same pad, Marcellus and Utica and it may be probably too early to ask about stack laterals, but will you be able to put them on the same pad, you think?

That's our intent.

This well is on an existing Marcellus pad.

Last overall question, maybe for Dave, now, you continue to have this massive Midstream, obviously, value you were talking about there.

Does that encourage you to, maybe, increase the speed at which you do some drop downs or really that doesn't change your thought process, Dave, about how quickly you continue to drop some of those things down?

Again, you certainly have a phenomenally large position and even now with EQM with news this morning, new pipe, there are a lot of things going on over there, as well.

Just your thoughts on the size and maybe the speed of the drop downs?

I think we've kind of moved a little bit past where it's mainly a drop down story.

I see EQM as being more of an organic growth story and I agree with you.

The agreement to build out that system for that pretty sizable system for Range Resources is a good example of that.

That is happening all at the EQM level.

We haven't updated our guidance or even our thought process, yet, about whether we've got one more or a couple of more drops and we've alluded to how much value, cash flow, et cetera we have remaining at EQT and we do continue to invest a little bit at the EQT level in some of that.

But generally speaking, you should be thinking about this as being organic growth at EQM.

It's not like I'll volunteer that from an economics perspective, since we are into the high splits, it winds up being most value accretive all the way around to focus on organic projects, rather than, say, acquisitions or things like that.

That includes with the drop-down.

We will drop what remains, but the focus at EQM is to create value through pursuing these organic opportunities.

Again, as you're seeing, we're trying to grow our market share.

That's what that Range Resources deal shows, to provide services to other producers and I think the Utica's going to open up even more opportunities for EQM.

Got to agree with that.

Thanks, guys.

Sameer Uplenchwar with GMP Securities.

My question relates to service costs and operating efficiencies.

Since the start of 2015, you have already seen like 16%.

That's what I think Pat said on the call, 16% deflation and costs.

That is, I'm guessing, is both high grading of the fleet and labor and also drilling core acreage.

I'm just trying to figure out, on a long-term basis, how much of this do you think is sustainable, where you can hold on to some of these lower cost and hold onto the labor and the fleets?

I think actually that 16%'s driven strictly by renegotiated service contracts.

So, there's no drilling efficiencies or any other factors in that 16%.

Any of those factors would be over and above that.

I think the reality of service cost reductions is they're not very sticky.

If gas prices ramp back up, which I'm not expecting any time soon, but if they would, I think we'd likely be faced with service cost increases.

So they tend to move with gas prices and operating levels.

Got it.

Thanks.

On the cash side of the equation, I know you have answered all the questions pretty well, what I'm trying to understand, you want to hold onto that cash as a dry powder safety net, but how long do you want to do that?

At what point in time do you decide that we could do a buyback, we could do a dividend growth or something along those lines, if the better spread continues to remain wide?

We continue to reassess that periodically.

That'll also factor in with drop schedules and the capital budget and things like that as we look later in the year.

The next time we take a real serious look at that -- and this is really starting now -- is the run-up to the capital budget, the annual plan and capital budget for the coming year.

So, that'll cause a pretty deep dive on some of those things.

Got it.

Thank you.

Drew Venker from Morgan Stanley.

I was hoping you could give us a little more color on the Utica well costs for that first well?

Drew, we don't have the final numbers, yet, but it's going to be right around $30 million.

If you recall, we had some pretty significant issues dealing with the extremely high reservoir pressures.

It was pretty expensive.

Right.

You cited this $12.5 million target, what are the primary cost items that you're trying to reduce?

Is this just rig time with the rig upside or completion time?

Anything else as a big component?

A lot of all of that.

The rig time was long, the completion time was long.

There's lots of opportunity for improvement, which is why there's such a big gap between the cost of this first well and what we think these should be able to be drilled for.

Like all these, anything new, there's a learning curve.

I think we'll be able to get up it pretty quick.

I would expect our next well would be substantially less expensive than this first well, but it's probably going to take several wells for us to approach that $12.5 million number.

Okay.

Then you said you probably will spud another two or three wells this year, do I have that right?

No, one more, I'd say, for sure and the possibility of a third very late in the year.

Might hit this year, might hit next year.

Do think we'd have results from that Wetzel County well this year?

No, I doubt it.

You doubt it?

Okay.

To the plan for drilling in 2016 is really predicated on results from your next couple wells, is that fair?

Yes.

Probably as much predicated on how this current well performs.

We'll be watching it for the next few months.

That'll start to give us a first read on decline rates and EURs.

At this point, all we really know is the productivity of the well, the deliverability, which again, was exceptionally high, but we need to see how it holds up, to really understand the economics and what this really means.

But it's good place to start.

That's a very impressive well.

Then, thinking about the spending plan for next year, I know it's too early for guidance, probably, but have you run some sensitivities on what kind of spending you think would be reasonable if this trip proves to be about right for next year?

We actually look at that as we get into the autumn.

This is the time of year we're probably least likely to do that type of back of the envelope sensitivity.

We're into the normal run up to our typical process.

We will be doing that in some depth as we move in through the third quarter and into the beginning of the fourth quarter.

Okay.

As Dave, as you mentioned, potentially splitting at least hypothetically splitting the Production segment from the Midstream segment.

Is this something you're looking at doing in the near-term future?

Because I think we probably hear a lot of the same frustration that your investors communicate to you, that they really feel out of value in both pieces and they don't feel like it's fairly reflected in the stock price.

I'd just say we are always focused and I think over the course of the time that I've been here, this Company has prided itself -- and I think it's reasonably so -- on being focused on creating shareholder value.

I'd just leave it at that.

We just want to figure out the best way to create shareholder value over time.

Okay.

Fair enough, Dave.

Thank you.

We'll take our final question from Dan Guffey with Stifel.

On your second Wetzel County, or on your first Wetzel County well, your second Utica, first was around 3,200 feet on the lateral.

What's the length of your second well and do you have an AFE on that yet?

I don't know.

We don't have an AFE on it, yet.

I don't know the projected lateral length.

I'm sure we will try to drill it longer than the 3,100 feet or 3,200 feet, but I don't know the exact length.

Okay.

We made a comment after drilling the Wetzel County well, you'll have plenty of acreage that's derisked.

Care to throw an initial estimate on how much you think will be delineated after that second well?

Maybe not that, but, I will say that this first well gives us a high level of geologic and deliverability certainty around at least 50,000 acres.

So, there's 50,000 acres we think looks identical to this without getting too far away from this.

We think Wetzel County looks similar, but that's getting pretty distant and is not included in that number.

That gives you, sort of, an estimate of, I'd say, our certainty levels going way up on at least 50,000 acres with the first well.

Okay.

Great.

Final one for me, 16% decline in cost since year-end.

You gave some detail in terms of those potentially not being sticky.

I'm curious, as we head into the second half this year, how much capacity do you think you have for further cost reductions?

That's always hard to project.

In April, I think when we announced our first set of cost reductions, we had gone through all of our suppliers and gotten what we thought we could at the time, but continued to work at it.

Now, have announced another 5%.

I don't know if there's another 5% or not, but I can tell you, we're going to continue to keep working at it.

A lot depends on what happens in the market, what gas prices do, what activity levels do.

We are going to keep trying to squeeze a little bit more.

Fantastic.

Thanks for all the color, guys.

I would now like to turn the call back over to Pat Kane for any additional or closing remarks.

Thank you and thank you, everybody, for participating.

This does conclude today's conference call.

Thank you all for your participation.

You may now disconnect.