Greetings and welcome to 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 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 three 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 David 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 Jimmy Sue Smith, Chief Accounting Officer. A 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 seven 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 201-689-7817. Confirmation code 13674493. In a moment, Rob, Erin and Jimmy Sue will present their prepared remarks. Following these remarks, Rob, Erin, Blue 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-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's results. Net income attributable to non-controlling 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 four segments; EQT Production, EQM Gathering, EQM Transmission and EQM Water. Moving on to segment results, starting with EQT Production. 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…

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 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 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 gross TILs 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 was 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 six months of 2018 represented a tight market for Appalachian frac crews, resulting in higher pricing. The…

Thanks, Erin. Today, I'm going to focus on EQT post split. Starting with the time line, 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 also have one of the strongest balance sheets in a peer group, allowing us to weather low commodity prices and allocate meaningful free cash flow through 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 six to seven frac crews on average, which will drive mid-single-digit annual production growth over the next five 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…

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 session. Our first question comes from the line of Brian Singer with Goldman Sachs. Please proceed with your question. Brian Singer - Goldman Sachs & Co. LLC: Thank you. Good morning.

Hi, Brian. Brian Singer - Goldman Sachs & Co. LLC: Wanted to start with regards to the 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?

Yeah. 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, seven 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 feet and 20,000 feet and many in the kind of 18,500 feet range, which present a whole new set of challenges, stretching rigs to the limits 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 12,000 feet to 15,000 feet, and that the ones that are beyond 15,000 feet, we'll take 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. Brian Singer - Goldman Sachs & Co. LLC: Great, thanks. And my follow-up is just a couple of quick numbers clarifications, and sorry for this. The $2 billion to $2.2 billion in at least 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?

Yeah. 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 am wrong, about $100 million of tax gain in 2019 that's included in that. Brian Singer - Goldman Sachs & Co. LLC: Thank you very much.

Thanks, Brian.

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

Yeah. Thanks. Just back onto 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 12,000 foot to 15,000 foot? And what implications does that have on to some of those synergies we talked about during the Rice acquisition by putting the two acreage positions together?

Yes. So, we do think that there probably is a sweet spot and maybe it's in that 14,000 foot 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 foot 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 – we're much more consistent. We don't have the surprises that we do with the ultra-long laterals. But I would like to reemphasize. The move from 8,000 feet to 14,000 feet 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, nine months ago?

No, no. When we thought through the synergies from Rice, we didn't contemplate wells longer than 14,000 feet 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. 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'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, 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 five years. And do you see constraints in that – beyond that, or are you just kind of isolating your comments to the next five years? And if you can dial in what mid-single digits means a little bit more, that'd be appreciated.

Yes. So five years is a arbitrary time period that we think just gives enough visibility into the business that it's an appropriate timeframe, but there's nothing magic about the five 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 that range. And we think at that pace – and really, what was driving that, it was not a growth rate target, but rather an operational target of running somewhere between 6 and 8 frac crews 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 timeframe. So we think that 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 will give more color on the out-years as well when we announce our 2019 budget. Of course, the most granularity will come around 2019 that 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. Drew Venker - Morgan Stanley & Co. LLC: 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?

Yeah. So in terms 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 three quarters spend on share buybacks versus dividends, but that can move around some. Drew Venker - Morgan Stanley & Co. LLC: Okay. Thanks for that.

I'm sorry, Drew, there was another part to the question. I've forgotten. Drew Venker - Morgan Stanley & Co. LLC: Well, on 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 curious as how that free cash flow progress and cash return.

Yeah. So we're going to do the smart economic thing with the retained shares. 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. But we look at that as capital to be deployed for really three things. It's for de-levering the balance sheet as much as we need to, for share buybacks and potentially to fund dividends. And what we've said a number times here in the past, call it, six months is that we really want to target a leverage level that's somewhere between 1.5 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. Drew Venker - Morgan Stanley & Co. LLC: Okay. Thanks for that color. I am 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 probably less likely.

Yes, I think that's fair. Drew Venker - Morgan Stanley & Co. LLC: Okay. Thanks, Rob.

Thanks, Drew.

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

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 you're treating MVP in the context of that?

The price assumptions were stripped for 2019 and then $2.80 for the four years after that of NYMEX and then the local basis of $0.50. And then...

And then – sorry, go ahead.

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

Okay. And then, in the context of the maintenance capital, I think you mentioned that 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 to by the end of that five-year outlook?

Yeah. Currently, it's just a little over 30% is the basic line rate. And by year five, it gets down to mid-teens.

Okay. And then, I guess last...

It's not exactly linear. It's higher in 2019 and 2020 and then takes a pretty big step down in 2021 and then flattens out between 2021 and 2023.

Okay that's helpful. And then, 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-line should we be contemplating as well?

The lateral length, I think they'll be in the same ballpark as this year kind of at 12,000 foot to 13,000 foot or 14,000 foot average laterals. The TILs, do you know what the TILs are, Erin?

Believe it's around 170.

Yeah. And then that will – that TIL 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.

Morning.

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?

(00:31:28)

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?

Yeah. So about a 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 ultra-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.

Hi, Holly.

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 the lateral-adjusted basis or overall well cost?

Well, on a per foot basis, 2018 is going to be significantly higher than what we expected. It's going to be over $1000 of lateral foot versus more like $900 or $915 is what we would've 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 three agencies.

Okay, great. And then maybe one final 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 laterals in Greene or Washington counties.

Okay, that's helpful. Sorry, 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, 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, there's no real change in philosophy.

Okay, great. Thanks.

Thanks, Holly.

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

Hi. Good morning. Could you help us with the pro forma, how you look at pro forma 2018 production? Just trying to reconcile the 1,470 Bcfe to 1,510 Bcfe guidance versus 2018. Am I right in assuming that there was about 40 Bs (00:35:47) of production at Huron and anything else 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'd be helpful.

Yes, we think – so pro forma for the Huron sale, backing that out and the little bit that was in West Texas, we think that the pro forma production is about 1,430 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 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 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 (00:37:03) 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.

Okay. Thank you very much.

Thanks, Stephen.

Our next question comes from the line of Sameer Panjwani with Tudor, Pickering, Holt & Company. Please proceed with your question. Sameer Panjwani - Tudor, Pickering, Holt & Co. Securities, Inc.: Hey, good morning.

Morning. Sameer Panjwani - Tudor, Pickering, Holt & Co. Securities, Inc.: So you continue to shift away from the Upper Devonian and the Utica, which makes sense as 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 five-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?

Yeah. 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. Sameer Panjwani - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay, that's helpful. And then, on the maintenance CapEx numbers, I think the previous messaging was about $1.2 billion on average for five years. And the updated commentary, if I just kind of do the rough math, I mean, 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 first two years 2019 and 2020, 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 three, four and five. 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. Sameer Panjwani - Tudor, Pickering, Holt & Co. Securities, Inc.: 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 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 six or seven 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 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 understood the question, but I'll answer what I think I heard. So 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 1430 Bcfe. And so it's more like 5% or so growth. And 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.

Yeah, understood. Can you give again what you think – I don't know if you're 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?

Six to seven frac crews in 2019 and around 10 horizontal rigs.

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

And the rigs will come down over time. But in 2018, we're down now to, I think, it's seven frac crews, but we were as high as 12 mid-year. So what we intend to do and maybe this doesn't quite come through in our comments, but it 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 mobing and de-mobing frac crews or rigs.

Yeah. I mean, I'll let you go on, but the basic issue is that there's disproportionate – there's a bigger reduction in frac crews, rigs, I believe, than there is a reduction in CapEx. Okay. Thank you.

Yeah, 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 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 foot with about 4 Bcf of cumulative production in year one. I guess is it just ratable if I add somewhere around 10% to the EURs on your current type curve? Will that work?

Yeah. 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 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 so I guess does the Bcf per 1000 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.