EQT Corp (EQT) 2018 Q3 法說會逐字稿

Greetings, and welcome to the EQT Corporation Third Quarter Earnings Conference Call.

(Operator Instructions) As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Robert McNally, Senior Vice President and Chief Financial Officer, for EQT Corporation.

Thank you.

Mr. McNally, you may begin.

Good morning.

As many of you saw, this morning, we announced several changes in our senior leadership team.

So I would like to begin this call this morning by thanking Lew Gardner, Pat Kane and David Schlosser for their years of service to EQT.

They all made lasting contributions and played significant roles in the transformation of EQT over the past decade.

I would also like to make 3 introductions.

I'm happy to be joined today by Jimmi Sue Smith, our incoming CFO; Erin Centofanti, our new Executive Vice President of Production; and Blake McLean, our new Senior Vice President of Investor Relations and Strategy.

So with that, I'm going to pass the call over to Blake for further introductions and call details

Thanks, Rob.

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

With me today are Dave Porges, interim Chief Executive Officer; Rob McNally, Senior Vice President and Chief Financial Officer; Erin Centofanti, Executive Vice President of Production; Blue Jenkins, Chief Commercial Officer, and Jimmi Sue Smith, Chief Accounting Officer.

The replay for today's call will be available for a 7-day period, beginning this evening.

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

Confirmation code 13674486.

The call will also be replayed for 7 days on our website.

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

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

EQM and EQGP will have a joint earnings conference call at 11:30 a.m.

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

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

Confirmation code 13674493.

In a moment, Rob, Erin and Jimmi Sue will present their prepared remarks.

Following these remarks, Rob, Erin, Blue and Jimmi Sue will be available to answer your questions.

I'd also 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, 2017, filed with the SEC, as updated by any subsequent Form 10-Qs, which are on file at the SEC and are available on our website.

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

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

I'd now like to turn the call over to Jimmi Sue.

Thank you, Blake.

This morning, EQT announced third quarter adjusted earnings per diluted share of $0.35 compared to $0.10 last year.

Adjusted operating cash flow attributable to EQT was $560 million for the quarter, a $345 million increase year-over-year.

As a reminder, the results of EQGP and EQM are consolidated in EQT results.

Net income attributable to noncontrolling interest was $103 million for the quarter compared to $82 million in the third quarter of last year.

As a result of the RMP merger with EQM, EQT now conducts its business through 4 segments: EQT Production, EQM Gathering, EQM Transmission and EQM Water.

Moving on to segment results, starting with EQT productions.

Third quarter production sales volumes were 374 Bcfe, within the stated guidance range of 370 Bcfe to 380 Bcfe.

Volumes were 82% higher than the third quarter of 2017, primarily as a result of the Rice acquisition.

Our average differential for the quarter was a negative $0.47, $0.38 better than in the third quarter of 2017.

Differential improvements year-over-year were offset by lower NYMEX and hedge prices in 2018 and a lower Btu uplift resulting from a larger percentage of our gas being dryer after the Huron divestiture and Rice acquisition.

Though there were improvements in liquid pricing year-over-year, third quarter 2018 total liquids volumes were down by approximately 17% from third quarter 2017 as a result of the Huron and Permian divestitures.

This resulted in a flat year-over-year average realized price, including cash settled derivatives of $2.76 per Mcfe.

Operating revenues were slightly over $1 billion for the third quarter of 2018, which is $452 million higher than the third quarter of 2017 on higher production associated with the Rice acquisition.

Total operating expenses, excluding a $259 million loss associated with the Huron divestiture, were $912 million or 56% higher year-over-year.

Cash operating costs of $1.35 per Mcfe were 23% lower than last year.

Moving on to midstream results.

EQM Gathering operating income for the third quarter was $178 million, $92 million higher than the third quarter of 2017.

Operating revenues were $136 million higher, primarily due to the acquisition of Rice's midstream assets and increased development by EQT and other producers.

Operating expenses for EQM Gathering were $75 million, $44 million higher than the third quarter of 2017, primarily from the acquired assets.

EQM Transmission operating income for the third quarter 2018 was $59 million, essentially flat year-over-year, and EQM Water reported an operating loss of $3 million.

To conclude, I would like to discuss our cash flow and liquidity position.

As of September 30, 2018, EQT had $450 million of borrowings and no letters of credit outstanding under our $2.5 billion credit facility.

We currently forecast $2.6 billion to $2.7 billion of adjusted operating cash flow for 2018 at EQT, which includes approximately $250 million to $300 million from EQT's interest in EQM and EQGP and RMP for the first 3 quarters of 2018, reflecting the separation timing announced last night.

Our operating cash flow guidance does not reflect the anticipated taxes on the separation, which are triggered by the disposition of the Rice midstream assets within 2 years of acquisition and are expected to be approximately $100 million.

We can utilize a portion of our previously anticipated $200 million tax refund for 2018 to offset this tax liability.

With our forecasted adjusted operating cash flow and cash from asset payables during the year, we expect to fully fund our forecast 2018 capital expenditure plan of $2.7 billion, which includes $2.5 billion for well development.

I'll now turn the call over to Erin Centofanti.

Thanks, Jimmi Sue, and good morning, everyone.

I'm going to start by providing an update on 2018 CapEx.

As mentioned in our release this morning, we are increasing our 2018 well development CapEx by $300 million or 14%.

These costs represent primarily onetime events that were driven by pace of activity, ultra-long lateral learning curve and some service cost increases.

Our original 2018 development program was designed to have consistent frac and drilling activity throughout the year.

However, first quarter weather events and midstream delays disrupted that schedule, requiring us to ramp from 9 to 12 frac crews in Q2 to meet our planned volume.

While this work led to a record 94 growth TIL in Q3, the ramp in frac crews, robust pace and concentration of activity all placed stress on our supply chain, logistics and pad operations, increasing our CapEx.

Additionally, as we progress up the learning curve on the ultra-long laterals, meaning those laterals that are between 15,000 and 20,000 feet, early well costs are heavily influenced by trying new techniques and adjusting operating practices as problems occur.

This learning curve is no different than what the industry experienced a decade ago as we determined best practices for the first wave of Marcellus development.

Make no mistake, the economics of longer laterals are compelling.

This is a key driver behind our acquisition of Rice and it is a critical component of maximizing the long-term value of our premier acreage position in this basin.

Many of the lessons of drilling ultra-long laterals have been learned and are now incorporated, and we will execute better on this program going forward.

Lastly, pressure pumping and water pricing both increased versus planned.

The first 6 months of 2018 represented a tight market for Appalachian frac crews, resulting in higher pricing.

The same phenomenon was present in our water hauling operations, where increased demand for trucks, a shortage of qualified drivers and new safety requirements for all haulers increased water hauling costs.

As we build our 2019 plan, we are doing so with the manufacturing of purchase development.

This includes consistent levels of activity, a moderate pace coordinated with infrastructure, extreme focus on capital efficiency versus quarterly volume targets and implementation of real-time operation centers for all our processes.

Many of the lessons of drilling ultra-long laterals have been learned and are now incorporated into our program.

Data governance and analytic teams are in place, and we will set measurable operational goals and report the progress to you annually.

We are not waiting until January to begin this process.

We are currently working at a consistent and moderate pace, which will eliminate future inefficiencies.

This decision to moderate activity earlier will result in 30 Bcfe of production being deferred into next year but will allow us to immediately implement our new efficiency model.

As we mentioned in our release, some of these deferred volumes would have been sold in early October at low local pricing of $2 and will now realize Q1 2019 pricing of $2.90.

We are committed to effectively deploying capital and believe that the lessons learned in 2018 provide the knowledge and experience to drill longer laterals at the cost profile we originally anticipated.

These longer laterals, in addition to our manufacturing model, will be the key to maximizing the long-term value of the world-class asset we have built in this basin.

I will now turn the call over to Rob.

Thanks, Erin.

Today, I'm going to focus on EQT post split.

Starting with the timeline as we near the end of the split process.

We announced yesterday that the EQT board has approved the separation of our upstream and midstream businesses.

We expect Equitrans Midstream will begin trading on a when-issued basis on October 31, and then both EQT and Equitrans will trade on a regular-way basis starting on November 13.

And we expect the record date for the distribution to be November 1.

In our updated slide deck, which will be posted this evening, we've included a few slides that highlight the persistent sum-of-the-parts discount that the separation is intended to address.

What you see is that if you assume current market prices for the various midstream entities, the remaining EQT upstream business is trading at a very significant discount to our peers.

EQT will enter the next chapter with one of the best asset bases in the country with 680,000 core Marcellus acres and 2,400 undeveloped locations.

We're capable of generating a combination of modest growth and significant free cash flow.

We will also have one of the strongest balance sheets in the peer group, allowing us to weather low commodity prices and allocate meaningful free cash flow to share buybacks and dividends, driving per share returns.

As we've discussed for the past several months, we're transitioning this organization from a volume growth mindset to a capital efficiency mindset.

We will operate at a more moderate, steady pace.

And we think that looks like 6 to 7 frac crews on average, which will drive mid-single-digit annual production growth over the next 5 years.

We believe this operational consistency will reduce cost per well, increase productivity per foot and continue our long-term trend of driving down development cost per Mcf.

Another advantage of this moderated growth and development pace is the improvement in overall portfolio decline rate.

High growth rates mean a greater percentage of production coming from new high decline rate wells.

In a lower growth scenario where new wells make up a smaller portion of the overall production, baseline decline rates moderate along with capital requirements.

This is what drives the shape of our free cash flow profile.

In our current base case forecast, we see annual maintenance level CapEx dropping from approximately $1.8 billion in 2019 to approximately $900 million by 2023.

Based on mid-single-digit annual production growth case, we anticipate approximately $200 million of free cash flow in 2019 and $2.1 billion in cumulative free cash flow over the 5-year period.

With respect to 2019, we are providing the following high-level guidance: we expect CapEx of $2.0 billion to $2.2 billion, net sales volumes of 1,470 to 1,510 Bcfe and EBITDA of approximately $2.2 billion to $2.4 billion.

We're in the midst of working through our annual budget process, which we will present to the board in December.

Consistent with our practice, we will give formal 2019 guidance at that time.

We do understand that this quarter's operational update is a disappointment to shareholders.

It certainly is a disappointment to me and this team as we underperformed our asset base in 2018.

As the incoming CEO, I'm committed to reshaping our culture to one that's focused on capital efficiency and per share returns as opposed to purely chasing volume targets.

To carve out my remarks, I would like to say thank you to all of the EQT and soon-to-be Equitrans employees as well as our advisers who have done a truly amazing job in getting these 2 strong businesses ready to be independent.

It was a herculean effort that was flawlessly executed in record time.

Great job.

I'd also like to thank Dave Porges for his many years of excellent leadership and strategic vision at EQT.

We're very grateful to Dave for stepping back in to the interim CEO role earlier this year in what was a very dynamic time at EQT.

With that, I'll turn it back to you, Blake.

Thanks, Rob.

This concludes the comments portion of the call.

Doug, can we please now open the line up to questions?

(Operator Instructions) Our first question comes from the line of Brian Singer with Goldman Sachs.

I wanted to start with regards to some of the costs and related lateral points that you mentioned and really more as it focuses on the going forward.

Can you talk about the services environment that you expect when you think about a CapEx budget in the range that you're at least initially indicating, whether you see that falling or rising and what the risks are around that?

And then also on lateral lengths, can you talk about the challenges that you faced a bit more, whether there's any upper limits that you're seeing?

And what's baked into the production and CapEx expectations in the plan?

Yes.

So on the cost side, we really saw the tightness in cost escalation in midyear when we were running -- at one point, we were running 12 frac crews, 15 rigs and on a daily basis would have something like 500 trucks on the road.

That's where we saw the tightness and the costs increased.

Now as we've gotten into the fourth quarter, we backed off on that pace, and we're down -- I think 7 today frac crews and getting to a level where we expect to run long term.

And so those costs have come down, and we expect that to continue.

So on the cost side, the higher costs that we saw through the middle part of the year have abated as we reduced our activity.

On the lateral lengths, with the Rice acquisition, we all of a sudden have found ourselves with a land position that gave us the opportunity to go from, on average, of 8,000-foot laterals to almost 14,000 feet.

But mixed in there were quite a number of laterals that were between 15,000 and 20,000 feet, many in the kind of 18,500 range, and which present a whole new set of challenges, stretching rigs to their -- the limit of their capabilities.

And in hindsight, we probably tried to drill too many of those ultra-long laterals.

In 2018, I think that there is potential upside in drilling those longer than 15,000-foot laterals, but we need to do it at a more measured pace so that we can incorporate the learnings into the next well as opposed to having multiple ultra-long laterals going at once.

So I think what you'll see from us and what's baked into our 2019 thinking so far is that the majority of the wells that we've drilled will be more like 12,000 to 15,000 feet, and that the ones that are beyond 15,000 feet we'll take a much more measured view of.

And we will work out many of the issues and be able to extend the laterals, but the blocking-and-tackling drilling will likely be less than 15,000-foot laterals.

Great.

And my follow-up is just a couple of quick number clarifications and sorry for this.

The $2 billion to $2.2 billion in the indicated 2019 CapEx, does that include the ongoing leasehold?

So is that comparable to the $2.7 billion?

Or is that comparable to the $2.5 billion?

And then when you talk about $200 million of expected free cash flow in 2019, does that incorporate any of the one-off tax benefit inflows?

Yes.

So on the first part of the question, that's the all-in CapEx number.

It does include the land CapEx, so it's comparable to the $2.7 billion.

And there is, correct me if I'm wrong, about $100 million of tax gain in 2019 that's included in that.

Our next question comes from the line of Scott Hanold with RBC Capital Markets.

Just back on to some of the things you're seeing on the long laterals.

I mean, when you step back and look at it is -- on this go-forward development program, in your minds, I mean, is there really -- I mean, do you see a benefit long term of doing a longer laterals than in, fundamentally, could you be just kind of finding a sweet spot in the 12,000 to 15,000?

And what implications does that have on to some of those synergies we talked about during the Rice acquisition by putting the 2 acreage positions together?

Yes.

So we do think that there probably is a sweet spot, and maybe it's in that 14,000- to 15,000-foot range where when you get beyond that, your incremental cost per foot starts to creep back up because the problem wells get to be big problems.

But what we found as an industry, for many years, is that what seems really tough today, tomorrow people start figuring out.

So I think what you'll see from us is we're not going to go both feet in drilling 17,000- and 18,000-foot laterals.

We will do one here and there, but the vast majority of the wells that we drill going forward will be at less than 15,000 feet.

And in that range, the wells are much more consistent.

We don't have the surprises that we do with the ultra-long laterals.

So I would like to reemphasize, the move from 8,000 feet to 14,000 or 15,000 feet is huge in terms of economic efficiency.

So we think that the gain that came from being able to extend that -- the laterals to that kind of length is very real.

It's just going from there to north of 15,000 feet is more problematic.

Yes.

But specifically, on the synergies, some of those synergies you discussed, does that change now knowing what you know on costs and lateral lengths to what we would have thought, say, 9 months ago?

No, no.

When we talked through the synergies from Rice, we didn't contemplate wells longer than 14,000 or 15,000 feet.

In fact, if you remember back to the guidance that we gave in late '17 sometime, what we originally expected to average in 2018 was 12,000-foot laterals.

And we -- so we were able to go significantly longer than that.

It's just that the longest 20 or so wells that were longer than 15,000 feet, there was -- there's a real learning curve associated with that, and frankly, just the physics limitation of the rig and pressure pumping when you get out to those lateral lengths.

Okay, appreciate that.

And then I also appreciate the view on strategically we're going to 2019 and beyond.

And you sort of made a comment of mid-single-digits growth kind of over the next 5 years.

And do you see constraints in that -- beyond that?

Or are you just kind of isolating your comments to the next 5 years?

And if you can dial in what mid-single digits mean a little bit more, that would be appreciated.

Yes.

So the 5 years is an arbitrary time period that we think just gives enough visibility into the business that it's an appropriate time frame.

There's nothing magic about the 5 years.

If we spun it out further, it would look very similar.

And we're not probably ready to give you more specific guidance than mid-single-digits, but I would take that for what it is.

It's the middle of the pack.

So 4%, 5%, 6%, 7%, something in that range.

And we think at that pace -- and really, what was driving that, it was not a growth rig target, but rather an operational target of running somewhere between 6 and 8 or 5.5 and 7.5 frac crews, which we think is a really prudent way to develop the asset where we can be the most capital efficient.

It drives modest growth and generates real free cash flow, of over $2 billion in that time frame.

So we think that's a model that for a company the size of EQT makes a lot of sense.

Okay.

Okay.

That's great.

And sorry, I'm just going to just add a related question to that.

When you give your 2019 budget, do you plan on providing some more details to that longer-term outlook?

Or is that one of those things we'll just get year by year?

No.

We likely would give more color on the out-years as well when we announce the 2019 budget.

Of course, the most granularity will come around 2019, but we will likely give more visibility beyond that as well.

Our next question comes from the line of Drew Venker with Morgan Stanley.

I was just going to follow up on the prior 2 questions around free cash flow and the priority of return of cash to shareholders, how you guys are thinking about dividends versus buybacks and how you expect that cadence of return of cash to proceed starting next year.

Yes.

So in terms of our -- of how we would split free cash flow between dividends and share buybacks, we do think that there is value in a modest but growing dividend.

But that is constrained by a belief that in a highly cyclical business like natural gas and that a large dividend that stresses the cash flows that it is hard to manage in a downturn is probably too much.

So if I had to try to ballpark it, I would say that we'd be more like 3 quarters spend on share buybacks versus dividends, but that can move around some.

I'm sorry, I think there was another part to the question.

I forgot.

Well, the cadence.

So you talked about $200 million of free cash flow next year.

I think Dave had talked about using some of the retained SpinCo shares to fund buybacks or cash return on the last call or maybe it was that first quarter call, talking about that being one aspect but not being very specific on when you would monetize those shares.

So just if you could speak to how that free cash flow progresses and cash return.

Yes.

So we're going to do the smart economic thing with the retained shares, right?

So I think that there's likely to be some noise on the trading in early days for Equitrans and likely EQT as well.

So we're not going to rush out the door to try to sell those shares.

So we'll want to do it when we can get the best economic bang for our buck.

But we look at that as capital to be deployed for really 3 things.

It's for delevering the balance sheet as much as we need to, for share buybacks and potentially to fund dividends.

And what we said a number of times here the past, call it, 6 months, is that we really want to target a leverage level that's somewhere between 1.5 and 2x debt-to-EBITDA.

And I'd say that my personal view is that the lower end of that is probably the right range for us to be in.

And so that would push us towards using the majority of that retained state to delever the balance sheet a bit further post-spin.

Okay.

I'm sorry, just to clarify on the cash return piece, it sounds like for next year, assuming you don't monetize the shares early on next year, probably buybacks or a big increase in dividends is probably less likely?

Yes, that's -- I think that's fair.

Our next question comes from the line of Michael Hall with Heikkinen Energy Advisors.

Kind of coming back to some of the questions.

On the long-term free cash flow outlook, just curious what sort of price assumptions are behind that and how you're treating MVP in the context of that.

The price assumptions were strip for 2019 and then $2.80 for the 4 years after that at NYMEX and then the basis -- a local basis of $0.50.

And then the MVP, the assumption is that it comes on at the end of 2019.

Okay.

And then in the context of the maintenance capital, like you mentioned, there's some obviously moving parts around base decline.

How should we think about the progression of your base decline?

What that look like currently and what does that get to by the end of that 5-year outlook?

Yes.

Currently, it's just a little over 30% is the base decline rate.

And by year 5, it gets down to mid-teens.

It's not exactly linear.

That's not exactly linear.

It's higher in '19 and '20 and then takes a pretty big step-down in '21 and then flattens out between '21 and '23.

Okay, that's helpful.

And last of mine, I guess, is the -- on the 2019 outlook, how should we think about -- given all the kind of challenges on the lateral lengths front, what do you think is a fair average lateral length to contemplate for 2019?

And then how many turn-in-lines should we be contemplating as well?

The lateral length, I think they'll be in the same ballpark as this year, kind of that 12,000 to 13,000 or 14,000-foot average laterals.

The TILs, do you know what the TILs are, Erin?

I believe it's around 170.

And then that will -- that TIL rate will come down pretty dramatically over the next few years as the base decline rate drops.

Our next question comes from the line of Welles Fitzpatrick from SunTrust Robinson Humphrey.

It sounds like all the issues on the ultra-long laterals are really in the D&C portion, but I was wondering if maybe we could get an update on some of those longer ones that you've drilled, maybe the Harbison and the Haywood.

Are those guys still sort of at or above that 2.4 Bcf per 1,000 lateral foot curve?

Erin?

Yes, they're still currently meeting our expectations.

Okay, perfect.

And then is there any way -- could you guys break out the costs versus the learning curve on that $300 million CapEx bump?

Or is it just too kind of mushed up?

Yes.

So about half of the costs were inefficiencies from running so many rigs, so many frac crews, the logistics issues that came with that, about half of that is tied to those inefficiencies.

And then a portion is increased service costs that we saw during that period that have now abated and 1/4 or so is from the -- of the cost is from the problem wells in the ultra-long laterals.

Our next question comes from the line of Holly Stewart with Scotia Howard Weil.

Just maybe a follow-up on the last question.

Just you mentioned several -- the cost escalation just being sort of onetime.

Can you maybe just give us new well cost numbers as you're thinking about it for either in the plan currently for '18 or even looking at '19 for Marcellus and Utica and whether you can give us either on a lateral-adjusted basis or overall well cost?

Right.

On a per foot basis, 2018 is going to be significantly higher than what we expected.

It's going to be over $1,000 of lateral foot versus more like $900 or $915 is what we would have expected.

And we'll expect for 2019 that we're back down in that $900 range per lateral foot.

Okay, that's helpful.

And then maybe, Rob, just is there -- I'm assuming the rating agencies have continued to watch what we're doing here on the spin.

Is there any signal in terms of keeping EQT at that investment-grade level?

We do expect to be able to keep EQT at the investment-grade level.

That's the indication we've had through the conversations with all 3 agencies.

Okay.

Great.

And then maybe one final one for me.

Just given the increase that we've seen in NGL pricing, is there any thought at this point in that 2019 plan on sort of shifting any of this activity from Southwest PA into West Virginia to pick up more of that NGL uplift?

I mean, certainly, that weighs in the economics and we consider that.

The difficulty, though, is that in West Virginia, we're still drilling significantly shorter laterals.

So even with some liquids component that does help on realizations, it still doesn't compete very well with drilling 12,000- and 14,000-foot lateral in Greene or Washington Counties.

Okay, that's helpful.

Oh, sorry, one -- maybe just final one, if I could.

Is there any change in the hedging philosophy here now going forward?

There's not a change in the hedging philosophy necessarily.

But when we see forward pricing that we like -- we've seen some decent pricing in 2019, and at least for the near term, we're likely to layer in a bit more on the hedges.

But in terms of hedging heavier further out, I don't -- there's no real change of philosophy.

Our next question comes from the line of Stephen Richardson with Evercore ISI.

Could you help us with the pro forma, how you look at pro forma 2018 production?

Just trying to reconcile the 1,470 to 1,510 Bcfe guidance versus '18, am I right in assuming that there was about 40 Bs of production that you're on and anything else at -- in the Permian?

So Rob, if you could just give us a sense of what you think the pro forma year-over-year percentage growth is on volumes, that would be helpful.

Yes.

We think -- so pro forma for the Huron sale, backing that out and a little bit that was in West Texas, we think that the pro forma production is about 1,430 Bcfe in 2018.

Okay.

And then the other question is, I guess, you mentioned a little bit in terms of the timing of MVP, but am I right in assuming that EQT does not need to grow any -- you don't have to drill to fill in terms of MVP and that you can divert volumes locally.

So none of this growth is in order to meet your volume commitments on MVP?

That's correct.

And final one for me was just, is there any major moves in the -- in your assumptions on your transmission and midstream costs as you look out to 2021, 2022, maybe just directionally?

I think you mentioned before in terms of the cost of MVP.

But can you just help us, any major changes in those assumptions?

There are no major changes in those assumptions.

The big change is when MVP comes online.

So 2020, 2021 -- all of the out-years after 2019 will have MVP transportation charges but also will have the uplift for better end markets as well.

Our next question comes from the line of Sameer Panjwani with Tudor, Pickering, Holt & Co.

You continue to shift away from the Upper Devonian and the Utica, which makes sense as you move to more moderated program and have a higher focus on capital efficiency.

But how should we think about activity outside of the Marcellus over this next 5-year period?

The activity outside -- our overall activity will be dominated by Marcellus.

I don't know, Erin, if you have that stat in front of you, what you think it'll be.

I think you can assume roughly 30 wells a year in the Ohio Utica, and we won't have any in the Upper Devonian going forward.

Okay, that's helpful.

And then on the maintenance CapEx numbers, I think the previous messaging was about $1.2 billion on average for 5 years.

And the updated commentary, if I just kind of do the rough math, I mean, on the 2 endpoints, it implies about 10% higher on average.

And so is there something that's driving the change there?

Am I just reading too much into that?

No, your math is about right except that the shape of that curve is not linear.

So what you'll see is that the first 2 years, '19 and '20, that maintenance CapEx number is much higher.

$1.7 billion -- or $1.8 billion and $1.5 billion or something like that, but then it drops off significantly in years 3, 4 and 5. And so the average of $1.2 billion that we have talked about previously, it's still right.

It's just that the shape of that is not exactly linear.

Our next question comes from the line of Melinda Newman with TCW.

Can you go over again your CapEx guidance for EQT stand-alone next year, which looks like it's something like a -- maybe like a 20% reduction versus the number of frac crews and rigs you intend to be running next year because it seems like when you talk about 6 or 7 frac crews ongoing, that's like a 40% decline.

And I know you said you ultimately think you'll get the CapEx down to below $1 billion, but what is the exact cost of the mismatch in the decline next year?

And am I -- the production guidance you gave, it's just about 1% production increase.

Is this like extra cost because you had a plan that was a faster growth plan and made commitments based on that plan and now there's a cost associated with taking that back to a more modest growth plan?

I'm not sure I understood the question, but I'll answer what I think I heard.

And so the -- it is not a 1% growth in volumes.

It's more like 5% growth if you pro forma the 2018 volumes for the sale of the Huron.

And so I think that pro forma number is about 1,430.

And so it's more like 5% or so growth.

The $2 billion to $2.2 billion is consistent with the maintenance level, just keeping production flat, CapEx number of about $1.8 billion.

And then the rest is for the growth volumes.

But remember, matching CapEx and production changes in the current -- in a single period is always a bit off because the CapEx you spend in a period, really, will affect the production in the next period, not the period that you're in.

Yes, understood.

Can you give again what you think -- I don't know if you already gave it, you gave us an ultimate aim for frac crews, but what do you think your frac crews and rig count will be for 2019?

6 to 7 frac crews in 2019 and around 10 horizontal rigs.

Okay.

So it's really the proportion of less frac crews per rig, basically?

Well, it's -- and the rigs will come down over time.

But the -- in 2018, we're down now to, I think, it's 7 frac crews.

Yes.

But we were as high as 12 midyear.

So what we intend to do, and maybe this doesn't quite come through in our comments, but it's, we intend to run at a steady pace, moving towards a manufacturing model where we can deploy capital in the most efficient manner as opposed to ramping up and down, which is always very expensive when you're mobing and demobing frac crews or rigs.

Yes.

I mean, I'll let you go on.

But the basic issue is that, there's a disproportionate -- there's a bigger reduction in frac crews, rigs, I believe, than there is a reduction in CapEx?

Yes.

And just to follow on that, you'll see that the CapEx piece will continue to decline as the base decline rates continue to decline for any given growth rate or a maintenance level.

Our next question comes from the line of Ray Deacon with HS Energy Advisors.

My question was regarding the -- what the 15,000 lateral-type curve would look like or will you be putting on out?

I know you have a 12,500 with about 4 Bcf of cumulative production in year 1. I guess, is it just ratable if I add somewhere around 10% to the EURs on your current type curve?

Will that work?

Yes.

I mean, the type curves that we put out are based on a per foot basis.

The type curve right now is 2.4 Bcf per 1,000 feet of lateral.

And so at 12,000 feet and 15,000 feet, the per foot EUR is still the same.

So you can just multiply that.

Okay, got it.

And I know you had talked about the Upper Devonian being sort of a use it or lose it formation in the past that you wouldn't be able to go back and get it.

And if so, I guess, does the Bcf per 1,000 foot go up as a result of dropping out of the program?

No, it really doesn't have an impact.

There are no further questions in the queue.

I'd like to hand it back to management for closing comments.

All right.

Thanks, Doug, and thank you all for participating.

Ladies and gentlemen, this does conclude today's teleconference.

Thank you for your participation.

You may disconnect your lines at this time, and have a wonderful day.