Q4 2022 Vital Energy Inc Earnings Call

Good day, ladies and gentlemen, and welcome to vital Energy, Inc. 's fourth quarter and full year 2022 earnings conference call. My name is Martin deep and I will be your operator for today.

At this time all participants are in a listen only mode.

We will be conducting a question answer session after the financial and operations report.

As a reminder, this conference is being recorded for replay purposes. It is now my pleasure to introduce Mr. Ron Hagood, Vice President Investor Relations you May proceed Sir.

Thank you and good morning, joining me today are adjacent packet President and Chief Executive Officer, Brian Zimmerman Senior Vice President and Chief Financial Officer.

Katy Hill, Vice President operations as well as.

<unk> members of our management team.

During today's call, we'll be making forward looking statements. These statements, including those describing our beliefs goals expectations forecast and assumptions are intended to be covered by the safe Harbor provisions of the private Securities Litigation Reform Act of 1995.

Actual results may differ from these forward looking statements for a variety of reasons many of which are beyond our control.

In addition, we will be making reference to non-GAAP financial measures.

Reconciliations to GAAP financial measures are included in the press release and presentation, we issued yesterday detailing our financial and operating results for fourth quarter 2022.

The press release and presentation can be accessed on our website at www Dot final energy Dot com.

I'll now turn the call over to Jason Pigott, President and Chief Executive Officer.

Thanks, Ron and good morning, everyone. We appreciate you joining us this morning.

Posted strong results in the fourth quarter and full year 2022.

<unk> value on a foundation of recent oil weighted acquisition and the efficient development of our holiday portfolio.

Full year 2022, we had a strong year with the following highlights.

We generated $220 million of free cash flow of $913 million of consolidated EBITDAX.

We purchased $285 million of term debt and $37 million of common stock.

Our leverage multiple 44% from 2.14 times to 1.18 times. We also grew production, 19% compared to full year 2021.

During the fourth quarter, we generated free cash flow of almost $37 million, we sold non operated properties for $110 million and we repurchased more than $100 million of face value term debt and almost $11 million of common stock.

Operationally, our oil and total production were above the high end of guidance. We showed continued capital discipline with capital expenditures below expectations.

We limited the production impact of severe weather in late 2022 that severely disrupted many Permian basin operators.

Now, let's talk about 2023.

This is a challenging time for our industry with oil and gas prices softening over the last few months and service costs remaining high resulting in lower margins and cash flow.

History says that you will find an equilibrium, but this will take some time.

We are focused today on what we can control.

2023 plan is designed to maximize free cash flow with emphasis on developing our highest return assets and maintaining a strong balance sheet that we have worked so hard to achieve.

'twenty three plan, excluding the recently announced driftwood acquisition.

Largely focused on our most productive acreage in North Howard County, where we're seeing strong oil production.

Current commodity prices, our 2023 development plan is expected to generate more than $70 million of free cash flow.

Development drilling continues to bolster our inventory as we have maintained about eight years of oil weighted inventory organically, adding wolfcamp D locations in Glasscock County.

Offset reductions in our Wolfcamp b inventory.

For the past three years, we've observed growing industry activity in the Wolfcamp D around our Glasscock County acreage.

These results combined with our own previous drilling results underpin. The addition of ADL Wolfcamp D locations in Glasscock County.

On slide six of our earnings presentation, we bought industry activity in the Wolfcamp D around our leasehold and show the results from wells, we have developed with modern completion.

Last week, we announced that we signed a purchase agreement for the acquisition of the assets of Driftwood energy.

This acquisition gives us a foothold in a prolific part of Upton County, adding about 30 high margin oil weighted locations and high oil cut production.

Additional planned approach for creating scale was rewarded with this accretive transaction and we are confident that it will generate material future value for vital energy.

On slide eight we show the productivity of the acquired PDP Wells I believe the undeveloped locations will be competitive with portions of Howard County.

We plan to develop this asset over the next several years without increasing activity levels.

We have high confidence in our 2023 plan our team is executing extremely well today, we plan to maintain capital discipline and a steady pace of development that will allow us to capture synergies and capital efficiencies.

We have prioritized free cash flow high margins and maintaining a strong balance sheet.

Now I'll turn the call over to Brian for a financial update.

Thank you, Jason I'll start with some comments around our capital budget.

2023 capital investments are expected to be between $625 million and $675 million.

May prices have fallen over the last few months and service costs have yet to adjust.

This takes time, but we have factored in approximately 15% inflation over 2022 average levels.

Capital expenditures were slightly front end loaded in 2023 with around 55% of capital expected to be invested in the first half of the year.

Currently utilizing a second completion crew, which we plan to release at the end of the first quarter, taking us down to one crude for the remainder of the year, we expect to operate two drilling rigs throughout the year as continued efficiency gains in our drilling operations allow them to stay ahead of our completions crew.

We announced last week, our acquisition of Driftwood, we expect this transaction to close in early April and it will add PDP production of approximately 3400 Boe per day, 50% of which is oil the last nine months of the year.

We will update our combined production guidance at the closing of the transaction.

Part of the Driftwood purchase we also received four ducks in Upton County that will be worked into our completion schedule. This year.

Not currently anticipate that the accident acquisition will add any capital to our 2023 projections.

Finally, we expect a decrease in our RBS Nat draw from our current net draw of approximately $120 million. This mid February and now includes three weeks of payables and no offsetting revenue for February .

Which will be received later this week.

It also includes our semiannual interest payments from January .

And the Driftwood acquisition deposit.

Then expect quarter and increases in net borrowings to reflect mainly the interest payments and the deposit I will now turn the call over to Katie Hill, who joined US last year as Vice President operations. Thank you Brian .

In the fourth quarter, we returned to operating at our high performance expectation.

Oil and total production exceeded the high end of our guidance ranges. Despite late December for your guidance.

Outperformance was driven by improving uptime upsizing to a larger ESP and increasing deployment of our production optimization technology.

And upsize Esp's unloaded wells more efficiently brought new oil production online sooner and more quickly return frac hit well to previous production performance.

Winter innovation preparation delivered whether resilient operations throughout the fourth quarter.

We continued field wide deployment of production optimization technology to improve bottom hole pressure drawdown and production uptime, and we began to realize the impact of our multiyear digital operations cultural transformation.

This performance is also driving production volumes reflected in our guidance for first quarter 2023.

Oil production for the year, we will continue to exhibit some volatility due to the timing and number of new wells.

Based on our current development schedule, we anticipate daily production to peak in Q3 for the year.

The increase included production from our oil weighted high margin development plan will impact 2023 operating cost yes.

Although we guidance reflects an increase in total water production year over year increase per barrel water handling cost and additional electrical infrastructure development.

This infrastructure will support continued efforts to electrify other operational components of our development plan, including our primary Frac fleet and yield compression.

Operator, please open the line for questions.

The floor is now open for your questions to ask a question at this time. Please press star one on your telephone keypad. If at any point you would like to withdraw from the queue. Please press star one.

We'll be provided the opportunity to ask one question and one follow up question, we will take a moment to render our roster.

Yes.

Our first question comes from the line of Derrick Whitfield from Stifel. Please proceed.

Thanks, and good morning, all and congrats on a strong year end.

Eric Good morning.

Well My first question I wanted to focus on the bigger picture for vital now that you've expanded into opt in and you've added organic inventory in the Wolfcamp D.

With what's been announced to date and the potential you'll likely have in the Wolfcamp C interval in the Deadwood area could you comment on your degree of confidence in the eight years, you've outlined and share your thoughts on what's the right depth of inventory to attain.

Fair peer multiples.

Okay. Great question I'll answer the first part and then I'll turn it over to Kyle to tell you a little bit more about what work development plans for the driftwood area for us again.

We feel good about the eight years that we've added again when I started we were pretty much wipe the slate clean on inventory and have built.

The inventory we have today, both organically by testing new formations like the Wolfcamp D or the Wolfcamp B in Howard County, or sorry, Middle Sprayberry in Howard County.

As well as the acquisitions that we've done and we'll continue to do so for US I think what we want to continue to do is build scale.

We continue to do acquisitions, the ideal acquisition for US is 4% to $500 million say they'll bring in 50 to 100 locations, it's probably $250 million to $300 million in PDP. So those are the ideal things that we try to do that will again, if we can continue to do them, one or two per year, while eventually.

Inventory and we think more not extending our inventory of 10 years, but bringing in inventory that will start to feed a third rig and a half completion crew and ultimately two completion crews, which will give us stability. When we bring on 12 wells a quarter. It can move the production volumes up or down pretty significantly each quarter.

<unk>.

But as we roll the dice more in our drilling 100 wells per year.

That allow us stability in the production forecast it allows us to grow.

So I think those are the things that will ultimately lead us to the higher multiples I will again, we've been doing it consistently.

Didn't do as much last year, but we had this one kind of in the works for a while and have a strong start for 2023.

I'll now turn toward the pilot is to talk a little bit about the driftwood, yes understood.

We underwrote that acquisition.

Our our inventory in the Wolfcamp B there are two primary wolfcamp b targets, an upper and a lower and we used a conservative spacing assumption is four wells per targeted intervals. So eight wells per section. So really all of the inventory that we that we're talking about here. The 30 wells is all in the Wolfcamp B, but as you mentioned there are this is a stacked pay.

Environment. There are there are wolfcamp C wells to our south to our northwest we view that as an upside target that we'll be looking at closely to add.

Peter inventory beyond what we've already.

As stated in our release.

Terrific.

As my follow up and perhaps for Kt in light of your Q4 production performance and stronger than expected 2023 production guidance could you expand on the impact technology is having on our current base production optimization and how differentiated your approach is relative to the industry.

Yes, another great question Derrick I'll take the first part of this and then turn it over to Katie to talk about the operations. When I started with the company. We really wanted to put in place. This digital first mindset.

We took our existing it infrastructure and pretty much scrapped it we've taken everything to Amazon's cloud.

To run our data Lake and a lot of our operations off of that and what that does is allow us to use machine learning algorithms AI to optimize our production. For example, 25000 of our 35000 barrels per day are on submersible pumps, and we're using things like machine learning to change that.

Frequency at the pumps the pressure we hold on him to both extend life and get more production out of the well. So I think those are the things that we are doing that no. One none of our peers are doing it so we're a leader.

In that respect, but I'll turn it over to Katie and she can tell you a little bit about what theyre doing to optimize how we run our routes everyday thanks, James and good morning, Derik I think in 2022, I would categorize a lot of our operational progress and advanced technology from design into our demonstration phase we achieved really repeatable success in implementing our dining.

Routing and some of the base optimization technology that Jason talked about added towards that helped us deliver on our expectation that these off for Q4, primarily by repaying response time for our operators, increasing our production uptime and preventing subsurface failure at specifically on Ftes, Although we're excited to expand that to other artificial lift type.

I would anticipate the technology continuing to evolve as we continue.

Continue to deploy the technology across the asset, particularly focusing on different lead types as we move away from an FTE, depending on where we are in the area.

Got it that's great color. Thanks, that's all for me.

Thank you Sir.

Our next question comes from the line of Gregg Brody from Bank of America. Please proceed.

Good morning, guys excuse me.

Just a couple of questions for you first could you just give us an update on how you're thinking about your <unk>.

Long term debt reduction plan.

Has that changed at all as a result of that.

Westwood acquisition.

This is Brian .

Has it changed I mean, our primary focus is debt reduction and achieving.

A debt leverage ratio of below one times and Youll continue to see that we are focused M&A. Obviously plays a part in our business and so we just have to navigate around that but our focus is getting that debt down below 1.0 times.

It has been for a couple of years and we'll continue on that.

I think you also had a had an implied that target in there.

Has that changed at all.

We had we had an implied debt target of approximately $700 million last year.

I think that that will change modest modestly both acquisitions.

Was targeting basically a an EBITDA level at $55 to $60 price environment. So as we update our.

Projections for acquisitions that you'd probably see it change directionally along those same lines.

Got it and then just.

You have to 'twenty fives, there, which.

<unk>.

Curious, how youre thinking about them.

Any.

Refinancing our capital structure in general.

Yes, we're looking at ways to continue to pay those down we know we have the ability to call them under the revolver and paying debt with cash flow.

As the year progresses, we'll evaluate everything a lot of it will depend on the M&A markets and what success, we have there but.

We're keeping an eye on all the markets.

And just last question for you commented on the increase in costs.

That you expect this year on the operating side.

I see the guidance number you gave for first quarter or is that is that a fair number just to assume for the year or does that will that change at all.

I think it's directionally accurate for the year. We are excited to continue to grow in Howard County, and as we bring some of those oil way to add really high margin wells online. We are increasing our total fluid productions are that operating costs reflects continuing to build out our water and electrical infrastructure to support our accounting Department.

On the capital side again, we're going to be more heavily weighted for the first quarter, just because of that extra frac crew. That's running in the first quarter and then capital will come down in future quarters as that crew is.

As released.

Thanks for the clarification.

Yeah.

Okay.

Our final question comes from Nicholas Pope from Seaport Research. Please proceed.

Good morning, everyone.

Hi, good morning.

I was hoping you could talk a little bit about.

I guess two parts here with the driftwood asset kind of curious how.

Sure.

Do you think the returns kind of fit into the whole a hierarchy of what you have in Howard and.

And then Glasscock and also just really well costs.

As you look at the new driftwood assets.

Are we expecting the same kind of lateral length same kind of size of wells as you look at.

And well costs down there and this upton this new update asset compared to kind of what you have in hand and Howard.

And in Glasscock.

Yeah, that's a great question on our deck Thats published online we have a.

Sorry, I'm on the wrong spot there.

Perfect.

Sorry, I got a new deck slide eight.

Have a production comparison of the wells from Driftwood versus Howard County, Western Glasscock. So the wells driftwood are very comparable on a production side to our wells and that.

Central Howard County.

And then we're working through now is just completion optimization and things like that so I'll turn it over to Kyle for a little more color kind of on how we're thinking about that yes.

Yes, so I would say from a from a.

Capital cost perspective, there's a lot of similarity between our Howard County Wells and what we're modeling here for Upton and Reagan.

You asked a question about about lateral length all of the inventory. The 30 wells that we're talking about are all 10000 foot laterals.

So very similar to our base development plan that we have and in Howard County, and in Western Glasscock. So I would say a lot of similarity in the capital cost not a material difference between the two.

And from a geometry standpoint, theres no problem being able to kind of I think <unk> been averaging 11000 foot up in Howard.

Are you all able to get the 10000, plus type type laterals with with the kind of footprint that you haven't.

So then it really is 10000. So it is kind of the base the base design and kind of what we're what we're planning on based upon the footprint.

The reason that we're averaging 11000 up in Howard is because we often have 15000 foot laterals that are kind of sprinkled into our development plan.

But typically we either drill tens or <unk> is a kind of two.

Types of designs that we typically that we typically drill but in up to and it is all 10000 foot laterals.

Got it I appreciate it that's all I had guys. Thank you.

Thank you Zack.

Concludes today's questions I would now like to turn the call over to Ron Hagood for closing remarks.

I'd like to thank you for joining us this morning, and we appreciate your interest in vital energy. This concludes today's call.

Thank you ladies and gentlemen, this does conclude today's call. Thank you for your participation you may now disconnect.

[music].