EQT Corp (EQT) 2015 Q4 法說會逐字稿

Good day, and welcome to the EQT Corporation year-end earnings 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, Kyle.

Good morning, everyone, and thank you for participating in EQT Corporation's conference call.

With me today are Dave Porges, CEO; Steve Schlotterbeck, President of EQT and E&P; Phil Conti, Senior Vice President and CFO; and Randy Crawford, Senior Vice President of EQT and President of Midstream and Commercial.

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

The telephone number for the replay is 719-457-0820, with the confirmation code of 483-2196.

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

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

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

The partnership will have a joint earnings conference call at 11:30 am today, which requires that we take the last question on this call at 11:20.

The dial-in number for that call, if you're interested, is 913-312-9034.

In just a moment, Phil will summarize EQT's year-end 2015 results.

Next, Steve will give a Utica update and summarize today's reserve report, and finally, Dave will provide a summary of the 2016 budget and the balance sheet implications.

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 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 at the SEC and also available on our website, and under Risk Factors in EQT's Form 10-K for year ended December 31, 2015, which will be filed with the SEC next week.

Today's call may also contain certain non-GAAP financial measures.

Please refer to this morning's press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures.

I'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 2015 adjusted earnings of $0.75 per diluted share compared to $3.43 per diluted share in 2014.

A high level story for the year, as well as for the fourth quarter, was very strong volume growth in a lower commodity price environment.

Notably, production volumes were 27% higher than last year and Midstream gathering volumes were up by 28%.

Due to the lower commodity prices, adjusted EQT earnings, adjusted EPS, and adjusted operating cash flow attributable to EQT for 2015 were all down versus 2014 by any measure, although results in both years were impacted by some unusual items that should be considered when interpreting and comparing the results year over year.

Adjusted operating cash flow attributable to EQT was $964.3 million in 2015, compared to $1.424 billion in 2014.

And I refer you to our non-GAAP reconciliations in today's release for more details.

Results in the fourth quarter were similarly down.

Fourth-quarter 2015 adjusted net loss was $0.06 per diluted share; that compares to adjusted EPS of $0.97 in the fourth quarter of 2014.

Adjusted operating cash flow attributable to EQT was $233.9 million in the fourth quarter, compared to $390 million for the fourth quarter of 2014.

Production sales volume was 13% higher than the fourth quarter of 2014.

We also realized 12% higher gathering volumes than last year and continued low per-unit operating costs.

In the fourth quarter, we recorded a negative tax adjustment of $79.5 million to reserve certain state income tax net operating loss carry-forwards that may not be utilized in a low commodity price environment.

This had the impact of increasing the effective tax rate for the year.

Netting out the effects of this NOL carry-forward adjustment in the fourth quarter, as well as the regulatory asset tax adjustment in the second quarter would have resulted in an effective tax rate for the year of closer to 15%.

Although subject to many factors, including commodity prices, transactions, et cetera, we think a range of 10% to 15% is a reasonable effective tax rate range for our year 2016 modeling purposes.

Now moving on to a brief discussion of results by business segment.

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

Starting with EQT Production, EQT Production achieved record production sales volume of 603.1 BCF equivalent for 2015, again, representing a 27% increase over 2014.

As has been the case for many years now, the story in 2015 at EQT Production was the growth in sales of produced natural gas, driven by sales from our Marcellus wells.

2015 was our sixth straight year of more than 25% sales volume growth.

However, lower average realized prices more than offset the increased sales of produced natural gas in our financial results.

The EQT average realized price was $2.67 per Mcf equivalent for 2015, and that was $1.49, or 36% lower per unit than last year.

For segment reporting purposes, of that $2.67 realized by EQT Corporation, $1.74 was allocated to EQT Production, with the remaining $0.93 allocated to EQT Midstream.

The majority of the $0.93 is for gathering, which averaged $0.74 per Mcf equivalent for the year.

For the full year, total operating expenses at EQT Production were $1,251.6 billion, excluding asset impairment charges and one-time drilling costs, or 19% higher year over year.

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

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

Per unit LOE, including production taxes, was 25% lower year over year, as volume increased more than expenses.

Moving on to the Midstream results, operating income here was up 23% year over year, mainly as a result of increased gathering and transmission revenues, partly offset by increased operating expenses.

Gathering revenues also increased by almost 27% year over year, as a result of higher gathered volumes in 2015.

Total operating expenses at Midstream were $318.8 million, or $41.2 million higher than 2014, excluding an impairment and the expiration of some right-of-way options.

This increase was consistent with the growth of the Midstream business.

And then finally, our standard liquidity update.

We closed the year in a great liquidity position with $0 net short-term debt outstanding under EQT's $1.5 billion unsecured revolver and about $1.25 billion of cash on the balance sheet.

That excludes cash on hand at EQM and EQGP.

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

We are fully capable of funding our roughly $1 billion 2016 CapEx forecast, excluding EQM and EQGP, with that expected operating cash flow, as well as the current cash on hand.

With that, I will turn the call over to Steve for an update on the Utica program, as well as some thoughts on today's reserve release.

Thanks, Phil.

As Phil just said, today I'd like to review two topics: the 2015 reserve report and an update on our deep Utica program.

Starting with the Utica, as you know, we turned in line our first deep Utica well, the Scotts Run 591360 in July of 2015.

The well continues to produce at a consistent 30 million cubic feet per day, with a steady pressure decline.

The well is exceeding our previous forecast, and we now expect this well to flow at 30 million cubic feet a day until mid April, before it begins its production decline.

As a result, we've revised the range of our EUR estimate to between 5.1 and 5.9 Bcfe per thousand foot of lateral.

As a reminder, this well has a completed lateral length of 3,221 feet, and to date, this well has produced 5.8 BCF.

Our second well, the Pettit 593066 was completed at the very end of December.

This well has a 5200-foot lateral and was completed with a 29-stage frac job.

After initial cleanup and the 24 hour flow test at 43 million cubic feet per day, we shut the well in for an extended reservoir pressure test and to install the permanent production facilities.

On January 29th, we brought the well online at a choke-restricted rate of 20 million cubic feet per day with a flowing casing pressure of 8,700 PSI.

The initial results from the Pettit well appear to be in line with other deep Utica wells in the area and are consistent with our expectations of the Utica across our core focus area.

In addition to the two producing wells we spud another two Utica wells.

The Big 190 well in Wetzel County, West Virginia has been drilled to TD and we are now in the process of completing the 35-stage frac job, it has a 6300-foot lateral and has an expected turn in line date in late February or early March.

Our fourth well, the Shipman well in Greene County, Pennsylvania is currently being top set with a planned lateral length of 7,000 feet.

On the cost side for the Utica, we have been able to achieve significant savings on each of our wells and are ahead of our schedule to meet our target of $12.5 million to $14 million per well.

Savings have been realized in all phases of the development cycle, with the most significant savings coming from improved drilling efficiency.

Adjusting for lateral length, the Pettit well cost $17.3 million and the Big 190 cost $15.4 million.

On a cost-per-foot basis, we have successfully lowered our cost from $9,600 per foot for the Scotts Run well to $2,800 per foot for Big 190.

As a reminder, we have two objectives for our 2016 Utica program.

One, get the cost per well down to our target range, which we expect to achieve on our currently drilling Shipman well; and two, confirm the productivity of the reservoir within our core Utica focus area of southwestern PA and northern West Virginia.

If we can accomplish both objectives, we expect the Utica returns in the core area will be competitive with or better than the core Marcellus, and we will work on a plan to include Utica in our future development plans.

We will update you on our progress each quarter.

Moving on to the reserves report, as you saw in our press release this morning, we announced total proved reserves of 10 Tcfe, with 6.3 Tcfe of these reserves associated with wells that have already been developed.

This proved developed reserves total is 30% higher than year-end 2014 and includes 2.1 Tcfe of increases.

Within that 2.1 Tcfe increase is 386 Bcfe in proved developed reserves from wells that were unproved in 2014, but were ultimately drilled and completed in 2015.

This is consistent with the Company's history of continuing to expand its footprint and develop areas that we believe to be economic, even when they do not meet the SEC's definition of proved reserves.

Also contributing to our increased proved developed reserves is over 300 Bcfe from producing wells that are outperforming our previous forecasts.

Additionally, we converted 1.5 Tcfe, or 25% of our 2014 PUD reserves into the proved developed category.

We also cut our five-year PUD development plan in half, which is consistent with our reduced activity in 2016.

Both of these factors contributed to a 37% decrease in PUD reserves.

Looking at just our Marcellus reserves, the average proved location, considering both developed and undeveloped, is 700 feet longer and has an EUR that is 1.4 Bcfe greater than the average proved Marcellus location booked in 2014.

These statistics demonstrate consistently strong well performance, as well as EQT's ability to continue leveraging our acreage position within our core development area, allowing us to drill longer laterals.

In fact, our PUD reserves reflect 337 Bcfe of increases that is directly related to length extensions of previously booked undeveloped locations.

These length extensions not only boost the economics on reserves of previously booked locations, but also allowed us to book 703 Bcfe of new PUD locations that were previously too short to be considered economic PUDs.

To further offset the effect of low pricing, EQT continued to improve our efficiency and drive development costs lower.

The development cost of wells completed in 2015 was $0.83 per Mcfe versus $1.15 per Mcfe for wells completed in 2014.

This 27% reduction was driven by longer laterals, improvements in drilling and completion efficiency, and significant reductions in service costs, particularly on the frac side.

Our current estimate of total resource potential is 78 Tcfe, which now includes 25 Tcfe attributed to the core of our deep Utica play.

Also within that 78 Tcfe of resource potential are our probable and possible reserves.

As noted in this morning's release, using the SEC's required trailing 12-month pricing methodology resulted in total probable and possible reserves of 14.6 Tcfe.

If you look at forward-looking prices, which are more representative of our development assumptions, our probable and possible reserves would total 35 Tcfe.

Neither of those probable or possible totals includes any deep Utica reserves, as we are relegating that play to other resource potential for now, with the exception of the 24 BCF of proved reserves from our two producing wells.

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

Thank you, Steve.

This morning I would like to review our financial situation and philosophy when establishing our 2016 CapEx budget announced in December, as this is our first call since that time.

As Phil mentioned, we ended 2015 with well over $1 billion in cash and with nothing drawn on our $1.5 billion unsecured revolver.

In that context and given that we have other potential sources of cash such as another Midstream drop, we were comfortable with a CapEx estimate that was moderately higher than our operating cash flow estimate for 2016.

However, we do not have any plans to significantly erode that strong liquidity position, as we believe that our current conservative financial approach is appropriate for today's environment.

The rest of my remarks will elaborate on that view.

First, we have been looking to add to our core acreage position for the past year, but have not yet transacted, as sellers have not fully accepted the valuation impact of low commodity prices.

Ironically, even as sellers' expectations did begin coming more into line with current market realities, we narrowed our geographic focus to possibilities that have real consolidation benefits within the core of the core, as we have referred to it.

As the market continues to evolve, it seems to us reasonably likely that there will be some actual transactions in the first half of 2016.

However, given our tighter focus, as well as some other attributes of the current market, smaller asset transactions seem more likely than larger or whole company deals.

Speaking of the market, let's shift to our view of the natural gas supply/demand market.

You may recall that I do consider rig count to be a reasonable, if rough, leading indicator of natural gas production though some adjustments need to be made to glean any meaning from the published data.

For instance, there is a longer lead time between spuds and marketable production than there used to be.

Rigs are more efficient than they used to be, especially because of longer laterals and also improved completion techniques, and more natural gas production comes from drilling that the data associates with crude-oil-focused activity.

As an example of the latter issue, that is associated gas, when using the published Baker Hughes data, we believe it is best to look at gas equivalent rig count.

An admittedly simplistic adjustment to try to account for this associated gas involves assuming that each oil rig behaves more as if it is three-quarters oil and one-quarter gas, so that the gas equivalent rig count equals gas directed rigs plus 0.25 times oil directed rigs.

The gas equivalent rig count calculated that way was essentially flat at 700 to 800 from mid-2012 through the end of 2014, so for about two-and-a-half years.

The gas equivalent rig count then declined by about 45% by the spring of 2015, at which point it plateaued at about 380 until last summer, and then again declined gradually by another 10% or so.

Then starting in late autumn, the gas equivalent rig count declined an additional 25% plus, reaching 246 last week.

I recognize that only 121 of those are natural gas rigs; as an aside, that 121 compares to a high in Pennsylvania alone of about 117 rigs not that many years ago.

So this 246 is nearly two-thirds below the last rig count of 2014 and 35% lower than it was just in August of last year.

This sharp downturn in activity suggests lower future natural gas production.

The question, in my opinion, is when.

That is, how long is that lag?

At EQT, where we drill multi-well pads and long lateral wells, the lag from well spud to turn in line or TIL is 9 to 12 months.

Other drillers may have somewhat shorter or longer lags, but they all have material lags.

The usage of so-called DUCs, that is drilled but uncompleted wells, obviously lengthens the time lag between spud and TIL.

Also, improved efficiencies can mean that one rig today is equivalent to one plus rigs of a year ago.

But this is only true for some efficiencies, such as longer laterals.

Efficiencies such as reduced cluster spacing, which also tend to accelerate production, can affect the rig-volume relationship somewhat over time, but mainly improve economics, and therefore, reduce the economic clearing price, at which supply equals demand.

My point isn't to try to predict the exact timing of the production decline, but rather that this decline will occur, and it is best if we position ourselves to quickly respond to a higher gas price when the time is appropriate.

We believe that a strong balance sheet does this.

Based on my expectations of declining supply, I am reasonably bullish on natural gas prices once we have worked off the current inventory surplus as the current activity level is insufficient to meet demand over time.

That said, increased efficiencies and a tighter focus on the core of the core have certainly decreased the clearing price for natural gas, perhaps to the mid-$3 per MCF range, down from our previous expectation of around $4.

I do expect that the price will go past that clearing price to the upside eventually, as we have seen in the past, as the lags that have delayed the production decline emanating from reduced activity will also delay an increase in supply from a future increase in activity.

Given the industry-leading cost structure of our core Marcellus acreage, and potentially the Utica, EQT can make excellent returns at mid-$3 gas.

Still, just as we think it is important to be well-positioned when the market overshoots to the down side, we will want to be similarly well-positioned when the market eventually overshoots to the high side, even though that high-side overshoot won't involve prices nearly as high as they were even a few short years ago.

In times of financial stress for our industry, we think the prudent approach is to be conservative financially.

Whatever happens over the course of the rest of this year and into the next year from a commodity price perspective, we believe that having a strong balance sheet and available cash will put EQT in a position of strategic advantage.

This is certainly true if my macro thesis is correct; however, if the alternative thesis of prices that are much lower for much longer is correct, having a strong balance sheet and available cash will also put EQT in a position of strategic advantage.

From what we can see, there is no reasonably likely thesis under which our shareholders would be well served by us surrendering those advantages.

So in summary, EQT is committed to increasing the value of your shares, and 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 over to Pat Kane.

Thank you, David.

This concludes the comments portion of the call.

Will you please open the call for questions.

Thank you.

(Operator Instructions) We will take our first question from Scott Hanold with Royal Bank of Canada Capital Markets.

Yes, thanks.

Good morning, guys.

How are you doing?

Doing well.

Steve, if I could ask you on the deep Utica, obviously, the first well is a little better than you expected.

And if you run the math, it's -- I think you guys are projecting right somewhere around 18 Bcf EUR.

Just so I understand this right, and then the total bookings for the two would be 24, so does that imply the second well is -- are the expectations around 6 BCF?

Is that the correct math?

I would -- I think there's two adjustments you need to make, or keep in mind trying to use the SEC reserves number to back into EUR estimates.

One, those are reserves, not EURs, so anything produced prior to December 31st is not in there.

That's fairly minor for the Pettit well.

But it's also using the SEC definition, so reasonable certainty.

We have two producing wells.

The Pettit well had almost no production data, so our reserve projections in that case tend to be pretty much on the conservative side.

So I'm not sure the SEC numbers for the Utica wells really reflect very accurately our view.

We think it's too early to really comment on our view of the EUR for the second well.

But I would say that it's consistent with our expectations of the Utica.

Very, very early, but probably not quite as good as the Scotts Run.

I think the Scotts Run well will likely stand out for quite a while as an exceptional well and one that is definitely above the mean for the Utica.

Can I ask you this question, what was -- from what you've seen in the Scotts Run versus the Pettit, what made the Scotts Run that much better?

I don't think we know at the current time.

We're doing a lot of reservoir testing and studying it pretty closely.

I don't think we have any firm conclusions.

Again, we have some limited data points.

We have two data points now and the second data point has such limited history that I think it's premature to speculate too much about the reservoir just yet, other than to say, I think one thing we've proven is -- with the Scotts Run, that clearly there's going to be some areas of the Utica that are exceptionally good.

And with the cost that we've already achieved, the economics of those types of locations will be superior to probably any of the Marcellus opportunities that we have.

But we need to define where the areas are, how big they are, how repeatable they are.

And then you're going to have lots of areas that it's going to depend a lot on completion techniques and the final cost of these wells to see how it compares to the Marcellus.

And I think that's going to take us some time and quite a few more wells to really define.

But there's certainly going to be some areas that are exceptional.

Okay.

So would I be correct in saying that, and I realize, I totally respect the fact that we've got limited data, especially on that second well.

But certainly, you guys are still trying to evaluate whether or not this deep Utica opportunity can compete with some of your better Marcellus areas.

Obviously, Scotts Run gave you indications that there's a good chance for it, but I guess the second well, did it put you a little bit on the sidelines yet?

Well, you can't oversimplify the process that we need to go through.

It's a brand-new play, very limited data, potentially over a fairly broad area.

And I would say our expectations always have been that there will be some areas that are really, really good, and I think the Scotts Run clearly demonstrates that.

There's going to be some areas that take more time to figure out exactly how good they are and exactly how they stack up to the Marcellus.

And there's clearly going to be areas that you could drill very productive Utica wells, but they don't compete economically.

The Utica is huge; it covers a very large area.

So there's going to be areas of exceptional performance in economics, areas of competitive with the core Marcellus -- and remember that's our hurdle, is comparing it to the best of our Marcellus opportunities, and there's going to be areas where it falls short.

It's going to take some time to define that.

Okay, I understand and appreciate that.

Thanks.

We will take our next question from Drew Venker, with Morgan Stanley.

Morning, everyone.

I was hoping you can provide a little more color on the well cost targets.

It sounds like it's not really changed at this point but you've made some really great progress so far on getting down to $12.5 million to $14 million.

Can you tell us what your latest thinking is?

I think -- we haven't changed the targets, but I'm feeling pretty confident that our next well will be within that range.

We still have a long way to go on it, so anything could happen, but it is looking pretty good.

I'm becoming much more optimistic that we will be ultimately at the bottom part of that range rather than the top part.

It's just a little early for us to revise that range.

We wanted to get in it for a well or two before we start updating it, but I think our confidence in the lower part of the range goes up every day.

There's still quite a few areas for improvement.

I guess that's why I'm so optimistic that we're going to be within that range and can identify numerous opportunities for future improvements.

So we will keep you up-to-date on how we're doing.

And as far as, it's obviously still early, but as far as the different parts of the play, do you expect well cost to be materially different between West Virginia and Pennsylvania once you get into -- let's say once you get closer to those well targets?

I think well, the biggest driver will be depth.

Across most of our acreage, the depth doesn't change a lot.

So for us, it probably won't vary that much.

There are some regulatory differences between Pennsylvania and West Virginia, particularly around casing and cementing designs, but so it will vary a little bit by state, although, again, not that much.

I think cost variability should be pretty low, other than depth, and of course lateral length and number of stages.

Okay.

And last one, just if you can give us some color on where you plan to drill those next few wells and if you could give a little bit more detail on where that, the well that's completing right now, where that one is too.

The Shipman well is also in Greene County.

I don't remember the distance from the other two, but in the same general vicinity.

And the West Virginia wells will be very dependent on the results we see from the Big 190 well, which we again, we're two-thirds of the way done fracking, so we should have results late February, early March, which will influence our thinking about where the program goes after that.

Okay.

Did you have an AFE for that Shipman well or is that too early for that?

Again, I think we will be within the range on our actual cost, but we just started drilling the well.

So it's premature.

But the high end of that range is where I expect that well to come in.

Okay.

Thanks for the color.

We will take our next question from Arun Jayaram with JPMorgan.

Good morning.

Scotts, just to clarify your comments, you're saying based on your initial results in the deep Utica, it's matching your expectations.

You think based on the limited data that you have, if you can get well costs into that range, that it could compete with your Marcellus program?

Obviously, a lot more drilling and completing to do, but just wanted to get your initial read on how the program initially competes with the Marcellus.

Yes, I think our thinking all along is if we can get within that range and get the results that we were hoping to get, there will be areas of the Utica that are competitive with our very best Marcellus.

And I think clearly the Scotts Run, which I would repeat, we don't expect the Scotts Runs result to be the norm, so that's not -- when we factor in what we think the Utica is going to do we're assuming something a little less productive than the Scotts Run.

But yes, I think our view is if we can get within that cost range and have the productivity that we think we can get, there will be areas that are competitive and probably some areas that will out compete some of our best Marcellus.

Got you.

And just the overall objective of this year's appraisal program, which could be 5 to 10 wells.

As I said in my comments, we had two objectives.

The first one, and going into the year was our primary focus, was to get the cost down.

Since we started at around $30 million a well, we were certain that costs in that range were never going to yield an economic project.

We've gotten those costs down quite a bit faster than I had expected.

So that was our primary objective, but I think we're almost there.

I can't quite declare victory yet, but we're getting very, very close.

The second objective was to understand the productivity and the extent within the core of that productivity of the Utica, and that's why we have to drill a 5- to 10-well program this year and get various data points.

And as we all know, early in new plays, there's always a lot of improvement, even on the completion side, you have got to get up the learning curve.

So we'll make some mistakes, and we'll have some, obviously, we'll have fantastic wells.

We'll probably have some under-performing wells as we experiment with different techniques.

And we have to gather that data and analyze it and it's a lengthy process.

We're going to spend the year gathering data and studying it, and as we become comfortable with the implications, we'll communicate that to you.

Okay, and my final question is just looking at the core Marcellus program.

In 2015, you drilled about 160 Marcellus wells with an average lateral length of 5400 feet.

This year, obviously you're doing much longer laterals, plan to do 72 wells.

Can you comment on what you're seeing in terms of well productivity for the longer laterals?

Are you seeing similar EURs per thousand foot of lateral, and just maybe comment on the potential for well productivity gains in 2016 versus 2015?

Our experience has been that the productivity versus lateral length is perfectly linear, at least out to 10,000 feet.

We have seen no drop-off in productivity per foot as we have drilled longer, which is why we've said for a long time, the longer the better.

So we work really hard on our land department to put together drilling locations with the longest possible laterals.

You've seen our laterals get longer, especially this year.

A lot of that is driven by all the land work that goes on behind the scenes to make that happen.

It hasn't been a change in our thinking about the economics of longer laterals.

We've always believed longer is better.

Thank you very much.

We will take our next question from Michael Hall, with Heikkinen Energy Advisors.

Thanks, good morning.

Good morning.

I just wanted to talk a little bit about the big-picture outlook around production.

David, you walked through your views around the market and the big lags that you can see around laying down rigs and slowing down activity relative to production, and highlighted the 9- to 12-month lag you guys typically see.

In that context with the reduced well count in 2016 versus 2015, how are you thinking about growth potential in 2017, fully understanding it's premature to quantify, but just high level?

What are the key factors within the 2016 program driving our expectations around the year out from here?

We certainly think we will be looking at a lower growth rate in 2017 versus 2016, but also think we will be seeing some growth.

And probably the -- I guess you could always say that the productivity of the specific wells that we drill is going to influence what happens in the next year.

In this case, you'd probably particularly say it hinges on some of the Utica, even though there's not that many Utica wells.

But generally speaking, I think it has to be for any of the companies that you're looking at that when you see lower capital expenditure and these kind of lags, that when you look out another 9 to 12 months, you're going to be seeing a reduction in that growth rate.

I think there is going to be folks like us who would say you'll see that real reduction in the growth rate, and I think probably the great untalked about elephant in the room, as it were, is the companies where they've had a sharp reduction in capital expenditures and their growth rate is going to have parentheses on it in 2017.

And frankly, I think that will probably have a psychologically beneficial effect on the natural gas price market, but that's still within the context of a clearing price that's a lot lower than what we would've thought maybe a couple of years back.

That won't be the case for EQT, but you will see a reduction in growth rate, and you will for anybody who's cutting their capital expenditures.

I'm happy to have anyone else here add their thoughts to that.

Maybe the one piece of information I can provide that's related, might be helpful is, if we look at what our maintenance CapEx needs are to maintain a 2 BCF a day production rate, and this is all in capital, including sufficient capital to replace the acreage that we develop with the program, so certainly in theory, this would be a sustainable level of drilling.

We need about $700 million per year to sustain 2 BCF a day ad infinitum.

So if that gives you any more information.

That's helpful.

Roughly of that $700 million, sorry to get greedy here, but how much of that is acreage replacement relative just raw drilling and completion dollars?

The raw drilling and completion is about $575 million, and then you have acreage, some capitalized overhead, G&G costs, compliance, CapEx, a bunch of other items to make up that difference.

I do want to add one other comment.

Observing that some peers for their own reasons, we assume they obviously -- we all try to do what's best for our shareholders, but are talking about no rigs operating in 2016.

And I think that's phenomenal what the industry has done with improved rig efficiencies.

I'm still a little dubious that you can get down to no rigs and still have your production keep going up.

Yes, at some point that seems like it will give.

And yet frankly, the market seems to behave as if, of course, we can get to no rigs and volumes will keep going up.

I also wanted to think a little more near-term.

You've got a pretty substantial quarter-on-quarter growth rate implied by the first-quarter guidance.

Is that more a function of fourth-quarter timing of well completions or i.e, late completions in the fourth quarter or early completions in the first quarter or some other variable?

It's both of those reasons and really nothing more.

It's really timing of when the rigs get done and the fracs get done and wells get turned online versus specific quarter-end dates.

So yes, we are expecting a pretty substantial growth rate in the first quarter.

We will be -- this year, in 2016, the growth will be more concentrated in the first half of the year than in the second half.

And you will see, if you look at our backlog numbers, they came down a little bit in the fourth quarter.

We expect you will see a pretty substantial drop when we report the results for the first quarter in terms of stages complete not online.

Okay.

So the completion's pace in 2016 is also then front loaded I would assume by that comment?

Is that fair?

In terms of stages that come on per quarter, yes, it'll be more front-end loaded.

And it's just the nature of the timing of the rigs, and the reduction in our capital programs.

So you will see that reflected more in the second half of the year in terms of number of stages that come online.

Sure.

And then last on my end is just the composition of that backlog, do you know the average lateral length on that or maybe the average stage length?

I do not.

I don't have that --

Maybe what's your typical stage?

In between 5,000 and 5,500 feet, Michael.

The last three years our average length has been in that range, 150-foot stage.

150-foot frac jobs, five stages.

Perfect.

Thanks guys, I appreciate it.

Thank you.

We will take our next question from Bob Bakanauskas with GMP Securities.

Hi, good morning guys.

Thanks for taking my question.

Back to the Scotts Run well, I wanted to ask in terms of the increase in EUR per lateral foot, is that simply a function of the pressures not declining as fast as you originally modeled?

Well, that's the primary driver, but it's also, so we model that.

So it's not just the extra time it's going to take to get to pipeline pressure.

It's the history matching of our reservoir models, the pressure decline that we match now indicates a higher potential EUR than the matches we were getting with less data.

But it manifests itself through a slower pressure decline that we originally had modeled.

Okay, got it.

Thanks.

And then just the progress on the cost side on the Shipman well specifically.

It looks like you'll be pretty close to hitting your original target.

Is there a different completion design there, or are you still using ceramics or have you switched to sand?

We switched to sand on the Pettit well.

So only the -- at the current time, our plans are only the Scotts Run will have ceramic.

Our reservoir engineering analysis suggests that we are not seeing any impacts from switching to sand.

We are going to monitor that and clearly, if it would indicate that ceramic would drive a meaningful change in well performance, we would switch back and at least experiment more with it.

But for now, we are going with sand for this and all future wells.

Got it.

That's it for me, thanks.

We will take our next question from Dan Guffey with Stifel.

Hi, guys.

Just piggybacking on that last question.

You guys switched to sand in the Pettit well.

I guess I'm curious on the next two, or the five that will be completed this year, are sand concentration, water volumes, and/or stage or cluster spacing changing in any of those next five wells?

Well, that's hard to answer, because we will decide as we gather data and have to commit to certain completion designs.

I think for now, generally speaking, it's a very general comment, we're going to try to not change too many variables at once.

So I think the completion designs will most likely remain very similar unless the data that comes back is indicating that there is something that we do want to change and gather data on.

So again, I am expecting not a lot of changes, but that said, I would expect that we will be tweaking a few things over the course of the next several wells.

Okay.

That's helpful.

And then I'm curious, switching gears on the Marcellus, can you guys give any detail regarding what you think could be optimal spacing throughout your core Marcellus?

And does this change as you move from Southwest PA dry into the wet West Virginia window?

Well actually, we don't see a lot of change driven by dry versus wet.

We do see some differences in optimum spacing driven more by clay content in the rock.

And our spacing varies from as close as 500 feet in certain areas to as wide as 1,000.

I think our average right now is running around 700 feet, so it varies by geographic location and by geology, but 500 or 750 are probably the two most common spacings, with a few areas at 1,000.

Okay.

That's helpful.

And then just one last one.

Can you guys give me the annual decline on your PDP at year-end 2015?

It's around 30%.

Okay.

Thanks for all the color, guys.

We will take our next question from Brian Singer with Goldman Sachs.

Thank you, good morning.

With regards to the impact of the CapEx trajectory on production, as you see the pace of production start to slow as a result of lower CapEx, is there any correlating impact on Midstream and the Midstream EBITDA growth?

And if not, should we at all see unit cost to the E&P side of the equation move higher, all else equal?

You mean in terms of a load factor, Brian?

Exactly.

Does your Midstream, how aligned is the Midstream growth to what you're doing on the volume side for the E&P business first and foremost?

We tend to be right around the 100% load factor.

We are really spot on with the demand and capacity commitments.

In fact, we're slightly over that in this quarter, so pretty well aligned with the commitments to capacity.

Got it.

Okay.

And then separately, can you just talk about any consolidation opportunities in your strategy there and what you see out there at these valuations and the level of interest?

We just keep looking.

And I think this is what happens in a down market is the sellers have a more difficult time adapting to lower valuations than the buyers do.

I don't think that's unique in oil and gas, I think you probably see that in real estate, you see that in any number of places.

I'm guessing that the Houston real estate market is probably exhibiting some of those same characteristics.

That's just, I think, what happens.

But comment on the other bigger deals , as values drop I think the companies that sell have strategic reasons for wanting to sell.

And at that point, they probably rather sell smaller packages rather than larger packages, because they don't like the values; they're hoping for things to improve.

And as we focus more and more on the core of the core, it just isn't the case.

As an example, there are no -- I think it's fair to say there are no publicly traded companies where we would say all of their properties are in what, for us, is the core of the core.

It just doesn't exist.

And then of course, when you look at the financially troubled ones, that's just a whole different kettle of fish.

You really can't go in and buy those, because the debt is trading at way under par and it just doesn't work for a company like us to go in and execute that.

So I just think all of those things conspire to restrict the number of opportunities for transactions that makes sense for both buyer and seller.

That makes sense.

Does the success you're seeing in the Utica make you more introspective, or introspective might not be the right word -- make you more consider just developing what you have or does it increase the case for broader industry consolidation?

Gee, I don't know.

Steve, do you have --

I would say success in the Utica, the one obvious advantage at face value is it greatly expands our economic inventory, which might make you think consolidation becomes less interesting.

I think one of the big drivers in consolidation for us though is the enhancement in efficiencies you get and synergies from consolidation that will apply regardless of whether the Utica works.

And if the Utica works applies to the Utica.

So longer laterals, more wells per pad, more efficient midstream system design.

So all of those values or incremental value exists, regardless of what happens with the Utica.

So I think there is still a compelling case for consolidation.

Given how fragmented the northeast natural gas plays are, there is definitely a lot of value add in having bigger, more contiguous acreage positions.

Thank you very much.

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

Thanks Kyle, just one last closing statement.

We are updating our analyst presentation to reflect the new information put out today.

That will be available sometime this evening.

And again, thank you all for participating.

This does conclude today's conference call.

Thank you all for your participation.

You may now disconnect.