Greetings, and welcome to the EQT Corporation Third Quarter Earnings Conference Call. At this time, all participants are in a listen only mode. A question and answer session will follow the formal presentation. 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'd like to begin this call this morning by thanking Lou 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 Jimmy Sue Smith, our incoming CFO Aaron Cinefani, our new Executive Vice President of Production and Blake MacLean, 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 Aaron Cenafani, Executive Vice President, Production Lou Jenkins, Chief Commercial Officer and Jimmy Sue Smith, Chief Accounting Officer. The replay for today's call will be available a 7 day period beginning this evening. The telephone number for the replay is 201-612-7415, confirmation code 136744186.
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 in 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 6897817, confirmation code 13674493. In a moment, Rob, Aaron and Jimmy Sue will present their prepared remarks. Following these remarks, Rob, Aaron, Balu and Jimmy 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 ks 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 Jimmy Hsu.
Thank you, Blake. This morning EQT announced 3rd quarter adjusted earnings per diluted share of $0.35 compared to $0.10 last year. Adjusted operating cash flow attributable to EQT was $560,000,000 for the quarter, a $345,000,000 increase year over year. As a reminder, the results of EQGP and EQM are consolidated in EQT's results. Net income attributable to non controlling interest was $103,000,000 for the quarter compared to $82,000,000 in the Q3 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 production. 3rd quarter production sales volumes were 374 Bcfe, within the stage of guidance range of 370 to 380. Volumes were 82% higher than the Q3 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 Q3 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 drier after the Huron divestiture and Rice acquisition. So there were improvements in liquid pricing year over year, Q3 2018 total liquids volumes were down by a flat year over year average realized price, including cash settled derivatives of $2.76 per Mcfe. Operating revenues were slightly over $1,000,000,000 for the Q3 of 2018, which is $452,000,000 higher than the 3rd quarter of 2017 on higher production associated with the Rice acquisition. Total operating expenses, excluding a $259,000,000 loss associated with the Huron divestiture, were $912,000,000 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 Q3 was $178,000,000 $92,000,000 higher than the Q3 of 2017. Operating revenues were $136,000,000 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 $75,000,000 44,000,000 higher than the Q3 of 2017, primarily from the acquired assets. EQM Transmission operating income for the Q3 2018 was $59,000,000 essentially flat year over year and EQM Water reported an operating loss of $3,000,000 To conclude, I would like to discuss our cash flow and liquidity position.
As of September 30, 2018, EQT had $450,000,000 of borrowings and no letters of credit outstanding under our $2,500,000,000 credit facility. We currently forecast $1,000,000,000 to 2.7 $1,000,000,000 of adjusted operating cash flow for 2018 at EQT, which includes approximately 2.50 $300,000,000 from EQT's interest in EQM and EQGP and R and P for the 1st 3 quarters of 2018, reflecting the separation timing announced last night. Our operating cash flow guidance does not reflect 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 $100,000,000 We can utilize a portion of our previously anticipated $200,000,000 tax refund for 2018 to offset this tax liability. With our forecasted adjusted operating cash flow and cash from asset sales during the year, we expect to fully fund our forecast 2018 capital expenditure plan of $2,700,000,000 which includes $2,500,000,000 for well development. I'll now turn the call over to Erin Cinephani.
Thanks, Jimmy 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 $300,000,000 or 14%. These costs represent primarily one time 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 our 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 pills 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 determine best practices for the 1st 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 plan. The 1st 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 a manufacturing approach to 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 analytics 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 2.9 $0 We are committed to effectively deploying capital and believe that the lessons learned in 2018 provide the knowledge and experience to draw longer laterals as 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, Sharon. 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 13th. And we expect the record date for the distribution to be November 1st.
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 this 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 are 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 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 $1,800,000,000 in 20 19 to approximately $900,000,000 by 2023. Based on mid single digit annual production growth case, we anticipate approximately $200,000,000 of free cash flow in 20 $19,000,000 to 2019, we are providing the following high level guidance. We expect CapEx of $2,000,000,000 to $2,200,000,000 net sales volumes of $14.70 to $15.10 Bcfe and EBITDA of approximately 2 point $2,000,000,000 to $2,400,000,000 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 am 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 close 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 advisors for 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 today for stepping back into 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?
Thank you. Ladies and gentlemen, we will be conducting a question and answer Our first question comes from the line of Brian Singer with Goldman Sachs. Please proceed with your question.
Thank you. Good morning.
Hi, Brian.
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 length, 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 your the production and CapEx expectations in the plan?
Yes. So on the cost side, we really saw the tightness in cost escalation in mid year 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 cost increase. Now as we've gotten into the Q4, we've backed off on that pace and we're down at 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've reduced our activity. On the lateral lengths, with the Rice acquisition, we all of a sudden have found ourselves in a land position that gave us the opportunity to go from an 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 1,000 feet and many in the kind of 18.5 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 drill will be more like 12000 to 15000 feet and that the ones that are beyond 15000 feet will 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. Thanks. And my follow-up is just a couple of quick numbered clarifications. I'm sorry for this. The $2,000,000,000 to $2,200,000,000 in at least indicated 2019 CapEx, does that include the ongoing leasehold?
So is that comparable to the $2,700,000,000 or is that comparable to the $2,500,000,000 And then you talked about $200,000,000 of expected free cash flow in 2019. Does that incorporate any of the tax 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 2,700,000,000 dollars And there is correct me if I'm wrong, about $100,000,000 of tax gain in 2019 that's included in that.
Thank you very much.
Thanks Brian.
Our next question comes from the line of Scott Harold with RBC Capital Please proceed with your question. Yes, thanks. 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 the longer laterals? And fundamentally, could you be just kind of finding a sweet spot in the 12% to 15%? 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 14000 to 15000 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 that we don't have the surprises that we do with the ultra long laterals. So I would like to reemphasize the move from 8000 feet to 14000 or 15000 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, did you 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 thought 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 2017 sometime, what we originally expected to average in 2018 was 12,000 foot laterals. And we've 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 a physics limitation of the rig and pressure pumping when you get out to those lateral lengths.
Okay. I appreciate that. And 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 means a little bit more that'd be appreciated.
Yes. So 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 is it was not a growth rate 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 $2,000,000,000 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. And when you give your 2019 budget, are you 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 will 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.
Okay. Appreciate it. Thank you.
Thanks.
Our next question comes from the line of Drew Venker with Morgan Stanley. Please proceed with your question.
Good morning, everyone. I was just going to follow-up on the prior two 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're we'd be more like 3 quarters spent on share buybacks versus dividends, but that can move around some.
Okay. Thanks for that.
I'm sorry, there was another part of the question I've forgotten.
Well, and the cadence, so you talked about $200,000,000 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 the Q1 call talking about that being one aspect, but not being very specific on when you would monetize those shares. So just curious as 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 in 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 want to do it when we can get the best economic bang for our buck.
And but we look at that as capital to be deployed for really three 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've said a number of times here in the past, call it 6 months is that we really want to target a leverage level that's somewhere between 1.5 times and 2 times 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 stake to delever the balance sheet a bit further post spin.
Okay. Thanks for that color. So I guess 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, probably less likely?
Yes. That's I think that's fair.
Okay. Thanks, Rob.
Thanks, Drew.
Our next question comes from the line of Michael Hall with Heikkinen Energy Advisors. Please proceed with your Thanks.
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 are you treating MVP in the context
of that?
The price assumptions were stripped for 2019 and then $2.80 for the 4 years after that of NYMEX and then the basis of local basis of $0.50 And then sorry, go ahead. Sorry, then 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's that look like currently? And what does that get by the end of that 5 year outlook?
Yes. It's currently just a little over 30% is the base decline rate and by year 5 it gets down to mid teens.
Okay. And then I
guess lastly That's not exactly linear. It's higher in 2019 2020 and then takes a pretty big step down in 2021 and then flattens out between 2021 2023.
Okay. That's helpful. And then last on my end, I guess, is the on the 2019 outlook, how should we think about given all the kind of challenges on the lateral length 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 lengths, I think, will be in the same ballpark as this year, kind of that 12000 to 13000 or 14000 foot average laterals. The tills do you know what the tills are, Erin?
I believe it's around 170.
And then that will that till rate will come down pretty dramatically over the next few years as the base decline rate drops.
Okay. Appreciate the color. Thanks.
Thanks, Michael.
Our next question comes from the line of Welles Fitzpatrick from SunTrust Robinson Humphrey. Please proceed with your question. Hey, good morning.
Good morning.
It sounds like all the issues on the ultra long laterals are really in the D and 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?
Yes. They're still currently meeting our expectations.
Is there any way could you guys break out
the cost versus the learning curve on that 300 CapEx bump or is it just too kind of mushed up?
Sorry. 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 a quarter or so is from the of the cost is from the problem wells in the Osgrove long laterals.
Okay, perfect. That's all I have. Thank you.
Thanks.
Our next question comes from the line of Holly Stewart with Scotia Howard Weil. Please proceed with your question.
Good morning, guys. Just maybe a follow-up on that last question. Just you mentioned several of the cost escalation just being sort of one time. Can you maybe just give us new well cost numbers as you're thinking about it for either in the plan currently for 2018 or even looking at 2019 for Marcellus and Utica and whether you can give us either on a lateral
significantly higher than what we expected. It's going to be over $1,000 of lateral foot versus more like $900 or 9 15 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 had through the conversations with all three 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 that 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 laterals in Green and Washington Counties.
Okay. That's helpful. Sorry, one maybe just one 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. 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.
Okay, great. Thanks.
Thanks, Holly.
Our next question comes from the line of Steven Richardson with Evercore ISI. Please proceed with your question.
Hi, good morning. Could you help us with the pro form a, how you look at pro form a 2018 production? Just trying to reconcile the 14.70 to 15.10 Bcfe guidance versus 18. Am I right in assuming that there was about 40 Bs of production at Huron and anything else at in the Permian. So Rob, if you could just give us a sense of what you think the pro form a year over year percentage growth is on volumes that would be helpful?
Yes. We think so pro form a for the Huron sale backing that out and a little bit that was in West Texas, we think that the pro form a production is about 1430 Bcfe in 2018.
Okay. Thank you. And then the other question is, I guess, you mentioned a little bit in terms of the timing of MVP, but it 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 just help us with 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, 2020, all of the out years after 2019 will have MVP transportation charges, but also we'll have the uplift for your better end markets as well. Okay.
Thank you
very much.
Thanks, David.
Our next question comes from the line of Sameer Panjwani with Tudor, Pickering, Holt and Company. Please proceed with your question.
Hey, good morning. Good morning. You contained a shift away from the upper Devonian and the Utica. It makes sense that you move to a 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 of the Marcellus 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 will be?
Yes. 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 $1,200,000,000 on average for 5 years. And the updated commentary, if I just kind of do the rough math on the two endpoints, it implies about 10% higher on average. And so is there something that's driving the change there?
Or 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 1st 2 years 2019 2020 that maintenance CapEx number is much higher 1.7 or 1.8 and 1.5 or something like that. But then it drops off significantly in years 3.5. And so the average of 1.2 that we have talked about previously is still right.
It's just that the shape of that is not exactly linear.
Okay, great. That's great color. Thank you.
Okay. Thanks, Sameer.
Our next question comes from the line of Melinda Newman with TCW. Please proceed with your question.
Hi. Can you go over again your CapEx guidance for EQT standalone 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 $1,000,000,000 But what is the exact cause of the mismatch in the decline next year? And am I the production guidance you gave, it's just about a 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 understand the question, but I'll answer what I think I heard. So the it is not a 1% growth in volumes. It's more like 5% growth if you pro form a the 2018 volumes for the sale of the Huron. And so you could I think that pro form a number is about $14.30 and so it's more like 5% or so growth. The $2,000,000,000 to $2,200,000,000 is consistent with the maintenance level just keeping production flat, CapEx number of about $1,800,000,000 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 that you spend in a period really will affect the production in the next period, not the period that you're in.
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, but we were as high as 12 mid year. So what we intend to do and maybe this hasn't quite come through in our comments, but is 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 moving and demoving 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. Okay. Thank
you. Yes. And just to follow on that, that's 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 for a maintenance level.
Our next question comes from the line of Ray Deacon with HS Energy Advisors. Please proceed with your question.
I'm sorry, I was on mute. 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, would that work? Yes.
I mean the type curves that we put out are based on a per foot basis or the type curve right now is 2.4 Bcf per 1,000 feet of lateral. And so at 12,000 feet 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 so I guess does the Bcf per 1,000 foot go up as a result of dropping that out of the program?
No, it really doesn't have an effect.
Okay, got it. Great. Thank you.
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.