Q4 2021 Coterra Energy Inc Earnings Call
Expense, you'll see a lot of what we've added recently, we've implemented kind of started touching winter next year and expanding and we'll kind of keep things 12 to 18 months out in front of us leaning on wide collars with an overall again, we've got a tremendous balance sheet. We've got tremendous term profile out in front of us hedged.
Under pins some of that but we don't need a lot of hedging to underpin. It we're very confident in what we can do at the same time historically legacy Cabot was a third to two thirds I would say that percentages, probably down targeting 25% to 50%, 50% would be more of an outlier based on where.
We are at.
Yeah, Okay. That's great. Thank you guys.
Yes.
Your next question comes from the line of run.
Joe you Ram with Jpmorgan Your line is open.
Good morning, Tom and Scott.
My first question is just looking at the 2022 plant in the Permian Tom as you mentioned Youre, increasing the average development size to just over eight wells per project from call. It five and a half and increasing your lateral lengths by a little bit more than 10%, obviously overall tightness in the perm.
And so I'm wondering if you could just provide some thoughts on how Blake and team are managing some of these risks.
Some of the projects you talked about authentic.
And how is the these larger projects affecting the shape of.
Of your 2022 production profile.
Well obviously.
These projects come on their searches.
We really do look at annual averages.
Yes.
Quarterly timing is what it is based on project architecture, but where.
What we focus on understanding the annual average.
Yes.
It's all baked in in terms of what we've announced this morning, we're going to we're going to hit that annual average now the risks you talk about I assume our marketing and operational risks yes.
I think we're in reasonable shape in the Permian is really tight right now.
Yes, it's been very topical on sand.
We're.
Great relationships with our vendor network.
We anticipate having any.
That said there have been times when frac crews have been waiting on sand, but we don't see that as a as a huge hurdle.
Blake is in the room I'm going to buy Blake to just comment on this yes. Thanks Tom.
Rune.
It's still laser focused on efficiency like we always are.
The needle we can move so wells per pad lateral length.
We also have our E frac crew coming on mid year that were real excited about we think that's really going to move the lever on cost.
And then the market is going to do what it's going to do so.
We've been watching it closely we fixed the vast majority of our big cost movers for 'twenty, two and locked in so we know what those prices will be.
And it'll be up to operations teams, just continue to execute and innovate as they have done year after year.
Great Thanks for that.
My follow up is.
In terms of the Marcellus.
You guys are guiding to roughly 80 net wells to sales this year Tom.
Tom you highlighted call it five to seven years of lower Marcellus inventory I was wondering if you could give us.
Thoughts on how many locations do you have in the lower Marcellus.
And maybe a sense of that that range is that activity driven or.
Spacing I'd love to see if you provide a little bit more color on the on the lower Marcellus inventory.
No I'd be happy to renew I love talking about the business.
We're really.
Making some progress here first of all I must say that our team in Pittsburgh is amazing I mean, not only operating but also new clients.
Just amazing and it's been really fun to see.
Learnings go both ways.
You will remember around that.
<unk>, we had a bit of a challenge with spacing and completion design and how that interplay.
Parent child interference and all of these things are real and they particularly show up as you get into infield development.
I would say certainly the Marcellus is facing those same issues and I think there's some great ideas floating around.
We're looking at where we can.
By enlarging our spacing a little bit in the Marcellus So thats going from 800 feet between wells to 1000 feet and with that we're actually looking at upsizing, our completion energy a little bit and we think that as a.
Complex problem, it's not just spacing its parent child interference and child the child.
Response, but we've got early indications are thats really.
Great.
Effective.
Approach there won't be the last answer, but it's certainly garnering a lot of our <unk> program. So the difference between the five and seven wells and lower Marcellus as a direct answer to your question is whether we go to a 1000 foot spacing or 800 foot spacing, where we can we're planning on going to 1000 foot spacing now because of the geometry avail.
To us that's not something we can do everywhere, but we think it's really going to address some of these issues in the Marcellus as it did in the Permian.
Great. Thanks, a lot.
Yeah.
Yes.
Your next question is from the line of Michael CLO with Stifel. Your line is open.
Yes, hi, good morning, everybody I just wanted to get your latest thoughts on the.
<unk> basis and gas takeaway from the Permian.
Well, Michael I'll, just tee it up I'll, let Blake chime in here.
It's certainly back on the worry list.
As production increases in the basin and gas production increases also.
Yes.
A few summers ago. This was a hot topic.
And at the time I said, there's three words that gave me soulless, Aaron It's God Bless Texas.
In Texas, you have the opportunity for markets to adapt swiftly.
Can you.
What happened and then the concern was oil.
Pipelines were repurposed some NGL lines went to oil there were some new pump stations bill and the market reacted swiftly.
And so the smart play there was to just trust the market and throw them through it.
I think gas is going to be similar to that we're seeing some really encouraging signs of innovation stepping up to get us through the bridge between now and when we will have some new pipelines that envelope Blake specifically address that yes. Thanks Tom.
When we look at our Permian portfolio, our entire gas portfolio is covered by firm commitments that give a surety of flow contractual obligations and like Tom mentioned, we've been through this before.
That we never shut in a barrel of oil or flared and extra Mcf of gas. So we have great midstream partners and we rely on them.
So we do within our portfolio, we have deals that Houston ship, we have deals at Walmart, we have opportunities on the table right now to increase our Gulf coast exposure. If we decide that's a good long term decision we'll pursue it.
We're also in constant contact with our downstream partners and Theres a lot of really good greenfield and brownfield projects that are floating around.
We think those will absolutely come to fruition, if the supply curve materializes. So we're going to stay engaged on it. We also of course always half basis hedging if we need to protect from price. So.
Got lots of levers we can pull on this one.
Thanks for that color.
But just looking at the Anadarko basin. It looks like the next two projects there and the down dip and 13 eight areas.
Can you say, what if anything you can do differently there than what you did when you develop those areas previously.
Any learnings from the Carole elder that or.
Transferable to those areas that youre going back to.
Right.
Mike a remarkable thing is we drilled some wells out there five or six years ago.
<unk> have performed really well over time and so when we look at those wells and uplift them to 10000 feet. If we changed nothing other than use that information. The returns on these anadarko projects are stellar but we're also looking at some new completion designs and using what we've learned.
In our completion and then there are some new offset wells in the deeper part of the basin that are.
Just remarkable and one of the things that makes them. So remarkable isn't just the absolute gas rates, but you also get a pretty good NGL stream index. It's a rich gas. So you have a turbocharge to your revenue.
So we're this is not an <unk> project.
And there are a couple of other operators out there that are included into this as well much to our dismay, because we did a pretty good job of consolidating our position. So we have a good inventory of opportunities where we can exploit this with two mile laterals.
Carol Elder was a good project, we learned a lot there, but loan rock is a different beast, it's a little different pressure sink within the basin. So some of the some of the lessons of Lone rock are more applicable to a lone rock in the basin writ large but.
We're we're pretty excited about the opportunities and.
We love.
To the question about market constraints, having that Ed Darko is a tremendous relief valve for our program, we're glad to have it.
Okay.
Sounds great. Thank you.
Your next question comes from the line of Neal Dingmann with <unk> Securities. Your line is open.
Good morning.
Maybe just a quick first one for Scott Scott you talked a lot about today with.
Shareholder return, but I'm just curious on the buyback.
But just are there sort of optimal.
The drivers of requirements you all look at the buyback.
Hum.
Hi, your free cash flow yield is but I'm just wondering when you when you consider starting repurchases yeah, a lot of guys, who say well, we just buy back shares opportunistically.
Use a mid cycle, so devaluation I'm just wondering.
I mean, I know you looked at a lot of things, but wondering how you are.
Thinking about this.
One of the things we did in the discussion with brokers, we look back as we said in our prepared remarks kind of a relative valuation and also our intrinsic valuation.
Price Prize, we're undervalued on both of those accounts and particularly when you look from <unk>.
<unk> underlying performance from 10, one to date no. One around this table is happy with that unlike legacy Cabot, who did buybacks before pretty much 100% Opportunistically, we're going to be as I said in my answered. The first question, we're going to lean in and be more focused on kind of.
Dollar cost averaging and be more consistent over the course of our periods. When we can buy we're subject to the same blackouts.
Our individual people are subject to so the first two months of this year, even if we had had an authorization we've been blacked out because of the knowledge of the financial statements. So you got a window in March you had a couple and then you get a couple of months each quarter.
After that so we'll be leaning in creating a kind of a formulaic approach for our base.
Buyback.
Still having the opportunistic when we see disconnects in the market on things that just.
Our misinterpreted or misrepresented or however, it takes place to step on the scale when we do that but we are yes.
Yes, we're focused on making a lot of progress on this.
Immediately.
Okay. Good to hear and then just a follow up.
Maybe more just on the maintenance capital I'm just wondering do you all have been estimated.
Kind of a maintenance capital I guess, where I'm going with this kind of been asked around.
When you look at the just my question would be around maintenance capital or how you think about your sort of natural gas baseline decline.
Given how good the cabinet and Tom you wells have been on the gas side was a little bit surprised on the sea even any any gas decline. This year. So I'm just wondering maybe if you can address that from a couple of things just.
How we should think about that maybe as far as yet.
Capital allocation or anything around that.
Yes Neil.
Again.
We just reported the first quarter as co Tara.
And we're kind of in our starting our first full year of our first full year guidance. My expectation is that the maintenance capex number would be less than what we're looking at this year, but I would echo around the gas question that you talked about let's understand that and this was something that we.
We struck that struggle, but we had to manage around as legacy Cabot just as what Tom said before the cadence when you the high capital efficiency and the high productivity of those wells only requires you to run two rigs, maybe two and a half rigs and less than two completion crews and so you don't have a.
Whole inventory of wells to roll on so depending on the cadence of the pad one of the things we looked at our right now this morning.
Right now as a moment in the year. When we have we just added a third rig in the Marcellus, but two of those to three rigs are on eight well pads and 10, well pads and so when you do the lead time on that Youre looking way late in the year before youre going to see the impact of that investment today, and so while our maintenance when we get more on a cadence across.
All three basins I think maintenance will definitely come down from where it is right now and at the same time.
The question is is maintenance the way to manage this company in terms of a question that was asked of Tom earlier in terms of where the market is we're going to run it judiciously like we are we're going to move capital where it makes the most sense, we move more capital in 'twenty two to the oil province, because the margins are just stellar and theirs.
Margin expansion more than in the gas market, even with a good gas prices right now so long winded answer apologize for that but tried to give you a little more color.
Love the detailed level of large scale development.
Okay.
Your next question is from the line of David <unk> with Cowen Your line is open.
Good morning, Tom and Scott Thanks for your time today.
Good morning, David I was hoping I was hoping to.
Digging a little bit around the larger development. Just my first question is Tom you talked about a lot of these development size. It seems like were decisions that were made pre merger.
That was already going into 'twenty, two you talked about planning for 'twenty, three and it sounds like development sizes are increasing.
'twenty, two and 'twenty three.
Is that was that informs more by rice.
Rising service costs, and pricing and logistics or was it foreign informs more by geology.
Well Im not sure I'd say.
Either one as we get more confident about our development scheme.
It just begs for larger projects you can take advantage of tremendous amount of efficiencies there efficiencies of operations rig efficiencies completion efficiencies.
No we've got.
Our completion crews.
No.
We've got a really great partner in our completion vendor and we've got some of the highest productivity in the basin and their fleet.
So we've got a really well oiled machine.
And that part of that is the larger project size.
When you parsed out the smaller project size.
Moving your GMO being your mobility and Theres, just a lot of opportunity for things to interrupt.
So.
We do have a natural bias to larger project sizes in the Marcellus Permian and Anadarko.
That's one of the reasons, we're so excited about the upper Marcellus.
As Scott mentioned, we've got a nine well pad flowing back seven of those wells are in the upper Marcellus.
As I say going back about to come online.
This was the direct I think theres a direction of our industry. If you have the assets.
Really scares you to larger project sizes.
And I guess my follow up and you articulated this as well is certainly on the Marcellus and maybe to another extent in the Permian as well, we should expect to just see greater percentage of co development of sort of full full zones overtime.
Yes, it depends on the rocks, if you're a frac barrier. So we have the luxury of developing zone by zone, and then coming back.
And that we're going to need more time for that subject.
We've recently acquired a lot of science that we've learned a lot about vertical communication within that show the graphic section and a lot that we've learned surprising and it's informing how we are going to develop it but yes.
Whether it's the Marcellus or the Permian or the Anadarko at the end of the day it comes down to the rocks and the resource in place.
And we just we just have some of the best.
<unk> in our business.
I appreciate the answers thanks Tom.
Okay.
Your next question comes from the line of Dave Heikkinen with Pickering Energy Partners. Your line is open.
Good morning, Thanks for taking the questions. It sounded like on your innovative solutions out to things like the Whistler expansion from two to two five BS a day, so really seeing some increments in places that you can get some more gas out of basin is that kind of an accurate when he said innovative solutions, yes, that's certainly we've got.
Two or three different avenues are open to us.
Yes.
There are additional volumes, we might be able to snap.
Perfect and then it also sounded like.
As you are looking at.
Cabot assets that you did a lot of studying of the upper Marcellus and you're really bringing some of the cimarex thoughts to the program with the up spacing and larger fracs. So it's really.
Maybe a benefit of the integration of both companies.
Is that accurate as well.
Look there is both.
Gulf of Cabot too yes.
Really want to brag on that team in Pittsburgh, Yes, they are innovative they're great at the business.
<unk>.
Is just remarkable.
They have accomplished.
I think everybody is benefiting from kotara equally.
Okay, and then when you think about that mix of upper Marcellus as the shorter lateral link.
A representation of more upper Marcellus or.
Curious as you think about the next several years, where that mix goes issue as you go to 1000 foot spacing and.
And kind of the lateral length, well, Dave you said shorter lateral length I mean, the shorter lateral length is going to be a function of our remaining lower Marcellus once we go to the upper Marcellus, we're more or less wide open and Thats one of the many reasons to be really excited about the upper Marcellus.
So really stretch back out this one year downtick from 70 570 to 200 is kind of the.
As you get more upper right, where it is.
Trying to wait things out that makes sense yeah. No that is completely a function of we're in a process now to five to seven years of lower Marcellus inventory is excellent, but it's not wide open we're going back and filling.
Gaps.
On.
One of the one of the constraints there is lateral length.
I had that wrong in my head.
That actually makes more sense.
I just sat around thanks, guys.
Thanks, Eric.
Due to time constraints. Your last question comes from the line of Leo Mariani with Keybanc capital markets. Your line is open.
Okay.
Hey, guys I was hoping you could.
Talk about the synergy progress in 2020 Q have you started to see some of those G&A synergies at this point in time and I guess should we just expect to see maybe the G&A per Boe.
Kind of drop throughout the year and any indication on kind of what the the San Fran payments all roughly in 2022, then obviously describe would go away by the time, we get to 'twenty three.
Leo This is Scott.
Yes, we're seeing progress we've made tremendous progress.
One of the best things, we did was hired independent consulting firm to come in and help with US we have dedicated an employee to the value capture around synergies not just from a G&A perspective, but operationally.
The groups have identified as Thomas talked a lot about the thinking between that.
New ideas the cross pollination of ideas between all the teams and so there is dollars that far exceed what the anticipated G&A savings were that we laid out kind of when we didn't know a lot. We were trying to have and I guess, we're going to hit the $100 million in G&A savings, but like.
We said I think that the big carrot around where we were we were very clear in that.
The press release to say give us 18 to 24 months to do that because of some legacy severance programs that are fairly robust in terms of timing and trying to get.
New people in legacy people out that don't.
We are willing to move and so at the end of the day, we're hoping to accelerate that up to the kind of a 15 month time period at the end of this year.
The severance is probably we're probably 40% of what ultimately it'll be I don't know the cadence through the rest of this year and maybe some does bleed into 'twenty three but our goal is to have that overhead expense function rock solid for 23 years of rock solid as they can be.
Okay.
Good color at the end of the day.
And then just in terms of upper Marcellus I know you mentioned that kind of seven wells on a nine well pad, but roughly speaking do you have kind of the number of wells here youre going to prosecute in 'twenty. Two I think it's 80, something Marcellus wells just wanted to get a sense of is it half of those upper Marcellus can you tell us about the split.
No. It's a handful I don't have the number in front of me, but we're still are primarily focusing on the lower Marcellus and as we go what were doing is were worked very carefully.
Delineating this project, we're flowing back here.
Shortly is important to us, but we really do want to we got plenty to do in the lower Marcellus will throw in a project or two along the way and the upper Marcellus to just gain understanding but.
One because of our overall system constraints, we're mostly focused on the lower Marcellus.
Okay. Thanks, guys.
At this time I would like to turn the call back over to Mr. Tom Jorden.
Thank you and I want to thank everybody for a good set of questions. Just in closing I want to say, we were very pleased to announce our ordinary variable dividend very pleased to be embarking on our share buyback and if you've heard anything on this call I hope you heard that that 50 plus.
<unk> of cash return.
Is not competing with the buyback.
Additive to it and we really do look forward to continuing to be one of the leading companies in our sector.
The yield to our owners so looking forward to a great 2002, and great 'twenty three.
We are.
Hard at work here. So thank you very much I appreciate you joining us.
Ladies and gentlemen, thank you for your participation. This concludes today's conference call you may now disconnect.
[music].