Q3 2022 Callon Petroleum Co Earnings Call
Sir the security of high quality drilling services in a tight market and to support our operational plans in early 2023. These.
These plans now include multiple large scale Permian projects, each with over 10 wells targeting multiple zones in keeping with our co development model.
With the early edition of our six drilling rig we created more operational flexibility to execute these projects without significant modifications to our overall 2023, D&C plans and associated timing of production.
Importantly, we will be completing these projects using two simultaneous crews running consistently in this mode of development through the first quarter, adding the benefits of improved cycle times, and resulting capital efficiency to the economies of scale of larger projects.
The sixth rig is scheduled to begin operations this quarter and we also plan to run one completion crew for the remainder of the year for adding back a second dedicated crew for simultaneous operations at the beginning of 2023.
The number of gross wells placed on production in the fourth quarter is expected to be between 20, and 24 and our operational capital spending to be in a range of 180 $195 million on an accrual basis.
I will now turn the call over to Jeff to discuss operations.
Thank you and good morning, everyone.
I'm very pleased with this quarter's results as we exceeded our production forecast, averaging 107000 Boe per day and also reduce our per unit operating costs.
I'd like to point out that the work we did early in the year laid the foundation for the growth we are experiencing now and as Joe discussed our development program is focused on disciplined co development of large projects, which is the most capital efficient way to develop our multi zone asset base with more consistent well productivity over time.
For the quarter, we placed online 43, new wells, a 30% increase from the second quarter.
We continue to see the benefits of our active ESP optimization and conversion programs in the Delaware basin, Realizing strong initial production responses and more stable production profiles.
Across all of our operating areas, we're always looking for ways to reduce well costs and improve overall production performance. So earlier. This year, we made some modifications to our completion design in the Eagle Ford focusing on pumps schedule and fluid properties, which enabled us to place the same amount of proppant per stage with less overall fluid.
And besides reducing the cost of the well the reduction in food resulted in faster first oil production post Frac and also less impact on offsetting parent wells, enabling us to return them to pre frac production levels much faster.
Another cost savings and operational efficiency item that we have successfully implemented is the use of coiled tubing to drill out plugs post frac in the Midland Basin. This is a technique of course, so even utilizing in the Delaware and Eagle Ford and through the use of our Nitrify mud system and changes in Frac plug design, we were able to implement it recently in Midland.
And using coil to drill out frac plugs not only save this money, but also enables us to get wells on production much more quickly improving cycle time to first oil.
Now I'd like to provide you with an update on each of our operating areas. So let's start with the Midland Basin.
Our Midland Basin asset continues to outperform particularly in Howard County.
We would develop this acreage in a thoughtful committed manner that maximizes recovery and overall capital efficiency.
This multi zone integrated subsurface curriculum protects both our future inventory and existing wells from unnecessary degradation.
A great example of our co development model is the Ponderosa project, an 11, well venture with four target zones, including the middle Sprayberry, lower Sprayberry, Wolfcamp, a and Wolfcamp b formations.
This project is performing above expectations with all zones, producing above the type curves.
In addition, we placed eight colonial and Wyndham unit wells on production in Central Howard County that offset legacy wells that have been online for several years. These.
These eight wells achieved strong production results with a peak average 30 day rate of over 150 Boe per day per thousand foot of lateral with an oil cut of 85%.
This is very much in line with the initial less bounded older wells.
And because <unk> has the advantage of being a multi basin company, we don't have to overcapitalized any individual asset. So we can rotate our development strategies and plan for the future while executing strong current year performance.
During the majority of the quarter, we had two rigs running rigs running in the basin and drilled 14 gross wells, we dropped down to one rig at the end of the quarter on our Midland acreage and plan to maintain that level of activity through the remainder of the year.
Shifting to the Delaware.
During the quarter, we completed 12 gross wells and brought online 10 in Reeves County.
Focused on our eastern and southern positions in the Delaware for most of the year and are now turning activity to the Delaware West. So I'll highlight one project in particular, our four well Fox project that has been online since July these.
These wells targeted both the Wolfcamp, a and b with an average lateral length of 10750 feet.
And have a peak average 30 day rate of approximately 700 Boe per day with an oil cut of 51%.
Similar to other projects earlier this year, the Fox program employed higher proppant intensity and is benefiting our well productivity and economics.
Moving to the Eagle Ford production from this area also continues to be a key part of our robots robust asset mix and we were able to bring on wells earlier than expected given some of the operational improvements that I previously discussed.
During the quarter, we brought online 11, new wells, which completed our 2022 Eagle Ford program.
One of the wells that was brought online in the third quarter was an initial test of the Austin chalk potential on our leasehold.
We are still early in the flowback of this well so it's a bit early to discuss production results, but I can say the results of the subsurface evaluation from the logs rebrand are encouraging and consistent with our pre drill a characterization of the target formation.
In aggregate, we finished the quarter with five rigs and one completion crew, which is a good transition to provide an update on where we stand with regard to securing services for next year's capital plan.
We currently have one dedicated completion crew contracted under a multiyear agreement and have recently entered into a contract for a second crew that will combine to cover our activity for 2023.
On the drilling side, a rig requirements are contracted under ladder maturities, which ensure high quality services, while also maintaining a high degree of flexibility.
We've really enjoyed outstanding relationships with our primary partners and anticipate more of the same in 2023.
With my final comments I'd like once again to acknowledge counts field operations teams as they've continued to perform extremely well across the board.
This year has not been without its challenges, we're integrating a new asset in the Delaware South we've ramped up completions activity and we've done all of this in a very tight oilfield services environment I'm really proud of the results. Our team has been able to deliver and remained extremely excited about what we can accomplish in the quarters and years ahead.
And with that I'll now turn it over to Kevin to handle the financials. Thanks, Jeff during the third quarter, we posted strong financial results delivered on further deleveraging and increased our debt maturity runway, which by the way is now the longest weighted average bond maturity profile in the smid cap space.
Let's briefly go through some key financial details first we experienced a quarter over quarter reduction in oil and NGL prices, resulting in a 12% decrease in wellhead revenue to just over $73 per BOE. However, on a post hedge realized basis, our revenue per barrel of oil equivalent was largely unchanged from the second quarter.
<unk> as the oil hedging losses declined sequentially.
As a reminder, the back half of 2022 has lower amounts of production hedged as compared to the first half of this year.
After factoring in hedging and a reduction in per unit LOE and G&A operating costs.
<unk> reported its ninth consecutive quarterly increase in adjusted EBITDA per Boe to over $46.
Our top tier operating margins helped us realized adjusted EBITDA of $459 million in the third quarter, a 10% sequential increase over the second quarter.
During the third quarter <unk> generated adjusted free cash flow of approximately $150 million, a number which we expect to increase again in the fourth quarter. We used this quarter's free cash flow to reduce the borrowings under our revolving credit facility by approximately $140 million.
At quarter end, we had $636 million drawn on our facility, leaving us approximately $850 million of availability based on our recently amended credit facility.
In total during the first nine months of this year.
We reduced our debt balances by approximately $330 million.
In addition to using free cash flow to retire debt, we remain opportunistic and taking steps to further strengthen our financial standing we recently renewed our revolving credit facility extending the maturity date of that to October 2027.
New facility has a borrowing base of $2 billion and an elected commitment of one 5 billion.
Excluding the $187 million unsecured senior notes due in 2025, which we expect to retire with free cash flow in the coming year, we will have no debt no debt maturities until July 2026.
Turning to our hedge profile, we have a good base layer of hedges for 2023 at this point and are in the mid 20% area in terms of hedged oil volumes, we remain constructive on crude oil prices and we'll continue to layer into a moderate hedge position on price strength to take advantage of optimization opportunities on sell offs and heightened market volatility.
Next I want to discuss the upcoming accounting change from full cost of successful efforts as we discussed last quarter. Starting in 2023, we plan to report our financials using the successful efforts method of accounting we have prepared some slides discussing the reasoning behind the change and highlighting the line items in our financial statements that will be impacted by the conversion.
The main items on the income statement impacted by the conversion our interest G&A and exploration expense I do want to keep reminding everyone. There is no impact to cash flow from this accounting change.
Courage you to look at the slides on our quarterly earnings presentation for more details about the differences between the two methods.
As well as generalized financial impacts to Cowen.
Expect more explanation on the coming months, when we offer formal 2023 guidance <unk>.
Finally, I would like to also say a few words about our outlook on cash taxes. This item has become pretty topical on our industry recently reflects positively on how profitable. The E&P industry is in the current environment at year end 2021, Cowen had over $1 billion of net operating losses that helped to offset our income and reduce our tax.
Burton.
Taking into account, our NOL position and making some capex assumptions, we expect to pay minimal cash taxes in 2022, and 2023 in the range of $10 million to $20 million per year, however, depending on oil and natural gas prices as well as a host of other operating assumptions. We expect that number will increase in 2024 as our net operating loss.
<unk> balance decreases and with that I'm going to turn things back over to Joe before we move to Q&A.
Great. Thanks, Kevin before moving to questions I'll leave you with a few key takeaways.
Our focus on co development of top tier zones has created a visible path for sustained inventory quality for future drilling as we've steered away from just drilling our best wells at the expense of degrading offsetting locations in adjacent zones. This has allowed us to continue to realize increases in well productivity in the Delaware and Midland basins at a time when other operators are.
Seeing declining productivity levels.
With a scaled model of development comes repeatable drilling and completion activity the benefits of which we saw this quarter with the 2022 operational plan is being executed as laid out at the beginning of the year.
We have been actively securing the right services and partners for 2023, which will provide the foundation for consistent execution in the quarters to come.
Additionally, we remain focused on continuous improvement and are still finding ways to reduce costs increase well efficiency as we modify our drilling and completion methods and apply emerging technologies and.
And finally, our financial position is solid and we will continue to improve at a fast pace and year end.
<unk> financial strength will remain a key priority for the longer term, even as we look to implement return of capital frameworks and the future.
With that Lisa if we can open up for Q&A that'd be great.
Thank you if you would like to ask a question on the phone lines. Today. Please press star one on your telephone keypad again to remove yourself from the queue that is press star. One again, we will take our first question from Neal Dingmann with <unk> Securities.
Good morning, Joe and team. Thanks for the time, Joe My first questions, maybe get right to it does on your large scale development specifically, it's been interesting there's been a lot of attention. This earning season on companies talking about that in a multi stack full scale development and to me. This seems largely what you all have been doing with your field of life development now four quarters I'm just wondering could you.
Maybe provide some details on how you all view your program, maybe the same or different than some of these programs at others now just recently seem to be changing.
Sure Neal.
We have been doing this quite consistently over the last few years.
So it's interesting is coming to light now and we've stuck to our knitting on this and I think we're starting to see.
The benefits of it.
It's a little bit more of a medium long term type of strategy versus short term, but the medium and long term is here now and this is where we're going to see differentiation.
Slides I alluded to I think it was pages eight and nine we provide some some examples of how our co development strategy lines up to an alternative strategy.
If you just high grading all of your best zones, and what that means for potential degradation down the road. So it's.
Good to see that this is coming to light.
But for US this has been a consistent message that we've had over the last few years, because we we knew that if you.
You made near term drilling decisions in terms of high grading will have longer term value impacts and thats. What we wanted to preserve more consistent capital efficiency over time versus hitting hitting a wall on that over the next few years.
Now clearly seen and then just to follow up trying to get a sense on the latest.
Latest rigs to six rigs will be coming I'm just wondering.
On that will the duration of that sixth rig be price dependent next year or do you already have firm plans on.
What that duration of that rig might be through next year.
We've been putting together the 2023 plans pretty proactively.
So we will provide some more detail here and there.
Coming months, but.
This will very much be a part of the plan for most of 'twenty. Three importantly, with all of the contracting we've gotten ahead of especially on the drilling rig side, we have ladder maturities. So we do have some flexibility if we want to move.
Move away from the base plan, but we wanted to make sure that we underpinned certainty of services throughout the year and then add on some flexibility if things needed to pivot.
That's great to hear thanks for the detail.
Sure. Thanks, Dan.
We will take our next question from Derrick Whitfield with Stifel.
Thanks, Good morning, Congrats on your strong ups.
Thanks Derek.
Perhaps for you Joe as you guys are rapidly approaching your deleveraging goals could you help frame your thoughts on when you'd be in a position to announce return of capital and your views on preferences or preferences, sorry on the appropriate split between dividend and share repurchases.
Sure.
Let Kevin start off here since he's been out in front of walking.
US through the analysis with the board and the management team. So I'll, let him start with if I can pick up but I'm sure he'll cover this well Derik I think we've been consistent on each call for the last couple of quarters, we want to hit those targets before we announced so the $2 billion of debt and the one times leverage target we hit those in and we'll be ready to go.
No.
But we still have some some road between there.
Darren here.
In terms of preference, we're certainly watching our peers out there and seeing what folks are doing we've given a number of recommendations.
Our to our board.
But I think.
We're still waiting to clarify what that mix of shareholder returns will look like and I think just.
Follow up on that one thing that.
We have to fill in some details but philosophically.
As a smid cap company, we think one of the benefits we have is being able to be nimble.
Being able to allocate capital in different ways. So any framework that we come out with.
Overarching principle be not to limit our flexibility to allocate capital obviously continue to pay down debt to have opportunities for smaller acquisitions that can live on the balance sheet.
Type of bolt ons returns of capital et cetera. So.
We want to avoid taken away that flexibility with anything thats overly formulaic.
Sure.
As my follow up I wanted to talk to your Liza field concepts on page nine.
I think there is a general misunderstanding around pioneers message this quarter, maybe for the benefit of the investment community could you broadly speak to the intervals included in life of field development plans in Howard in Reeves and I'm asking for broad development as I understand pass operator activity could skew it.
Absolutely. This is Jeff Balmer, so we can start in <unk>.
Howard County.
And then the page nine is a really good general representation of what would benefit companies to have done similar to what <unk> has done on the left hand side and then the potential negative ramifications of Cherry picking and.
And only <unk>.
Drilling up your best stuff on the right hand side. So what Cowen has done similar for instance to the ponderosa pad that I had mentioned earlier.
We remain committed to a large scale vertical and horizontal integrated system. So for.
For instance.
Most recent pad drilled the middle Sprayberry, which is normally a pretty well segregated.
Thats multiple hundreds of feet.
On top of the rest of the stack.
Lower sprayberry, which has been extremely strong performer in the Midland Basin.
And then the Wolfcamp, a and the Wolfcamp b. So if you think about that 11, well project for instance, Youre really.
Advantaged by going out and you have your high productivity bread and butter zones, but they are complemented by the operational efficiencies of drilling and completing in providing water and getting water.
All the time when Youre out there once and then you also benefit from the offset wells surrounding the existing parent wells are.
Were fairly spread out. So this is a half half section that we're developing.
Have limited amount of shut in time for those parent wells that get returned to production relatively quickly and thats. The only thing that you have to do you are not coming out six months later or two years later and drilling another three wells, our drilling vertically above or below some of the existing production, which creates significant degradation.
<unk> to the to the wells that you are putting in into the system.
And its fairly similar in Delaware.
It's very similar but slightly different on what the stack looks like there are as we alluded to there is an opportunity for organic delineation and some of the shallower and deeper zones. So while that wolfcamp a would be kind of your primary stack, which is shown in the highest return segments in the green.
We're also drilling.
Wolfcamp B and we've got a wolfcamp C deeper tests planned.
And so what the idea behind it is to have a very robust overall and whether we call. It.
Profit to investment ratio of rate of return you name. It it's much better to come out and drill that stack, both laterally and vertically.
As opposed to Cherry picking.
When you come back out later on and it doesn't matter if it's again a year two years or three years, you will have significant degradation of all the wells within that system.
Due to simply Depletions depletion effects virtually all of those wells are going to interfere with each other one way or another and the best way to maximize capital efficiency is to do the majority of it all at once if you have that opportunity and and Joe answered this before but I'll reiterate this cowen has been doing this for a long time, we've been very thought.
<unk> committed to our development program, even in 2020 in 2021, where there were some cycle.
Commodity prices.
And I think Youll see that <unk> continues to reap the benefits of this very thoughtful development program.
Jeff and I could if I could just squeeze in one additional question I wanted to focus on slide seven.
<unk> really first and foremost I want to compliment you guys on your operations in Hollywood in light of the headwinds that your peers are experiencing but referencing that slide seven could you speak to some of the drivers of your year over year improvement in Midland well performance is it D&C design or location because the mix I mean, you guys have been incorporated.
<unk>.
Life of field now for some time, but theres definitely some outperformance there that youre benefiting from.
Yes, and thanks for pointing that out we're very proud of that position.
First and foremost it's excellent rock.
That helps quite a bit when you're in an acreage position that you have the opportunity to experiment and optimize something thats already good and its natural state.
The performance of these wells continues to be.
An outcome of this thoughtful and committed development program.
When we come in and we can drill multiple pads on the same development program. So we will have a.
Our rig that'll come out and drill.
Four wells and another rig next door to it its sister rig will put in four wells and then you can multiple bond from a completion standpoint.
You are able to look over time at opportunities for testing changes in completion design Frac plug drill outs, what we should do from some of the neighboring wells on how we should shut those in and the time it takes to return those wells onto production.
What are the Geo mechanics of the reservoir system on how the rock breaks and how it transfers fluids across the system.
And because we have a multi basin asset.
We're able to rotate our capital intensity around so that we're not committed to doing only one asset from a development perspective, we can.
Attempt to different items with technology applied to it and then we reap the benefits of watching them over a series of months or in this case several years.
Determined not just what the short term effects are on productivity, but the medium and longer term effects. So when we come back into these areas and drill for instance, this the ponderosa and the colonial Wyndham units. Those are those are large scale developments on half sections.
Relatively greenfield so youll see this.
Just very robust educated approach.
The development of those areas.
Great update guys. Thanks for your time.
Thanks Derek.
As a reminder, everyone that is star one to ask a question we will take our next question from Paul Diamond with Citi.
Good morning, Thank you for taking the time.
My first question actually a bit of a concern in the last one so slide 67, you guys are obviously showing some production gains.
Do you guys view, how much more how much more meat on the bones there.
And do you guys see that cadence there is slowing or I guess, how much more do you think you guys.
Can wring out of those developments.
Okay.
The Delaware is.
There is less mature than the Midland basin. So.
My my thoughts on the opportunity is probably a little bit higher in the Delaware basin simply because.
It's a little more of an unknown in the less mature from a development perspective.
In addition.
We're looking at is some organic delineation. So we'll be testing some some slightly different zones, and we'll get some information on how those interact with each other.
But one advantage that <unk> has is through how Cowen was built over time, we've had three independent datasets from different companies that have combined to result in a very advantaged subsurface evaluation.
Originally prior to the Carrizo acquisition was more focused on the lateral interference and effects on wells drilled next to each other and the parent child relationships.
Over time and the lateral distances.
Zoe had done some outstanding work on the vertical integration of zones on how they would interact with each other.
Timing of it where some of the zones segregated so that they werent necessarily needed to be developed over time at the same time or could you wait and then the <unk> acquisition in October of 2021 had a tremendous subsurface dataset on seismic evaluation artificial intelligence machine learning and now.
Cowen has is the beneficiary in aggregate of these three well developed interpreted and integrated data sets.
So that there is still an opportunity I think in the Delaware to continue to grow and evaluate what the optimal development programs should be but what you can see is the company flexing its muscles on on some of the outcomes that are pretty black and white not to say theres not opportunity in the Midland basin, but it is a slightly more mature basin for us.
So continue to obviously evaluate it and optimize it but I.
I'd say, the Delaware has slightly more upside.
Okay.
Understood. Thanks, and then just as a quick follow up how are you guys.
To plan out your.
2023 development cadence and cost structure, how are you guys seeing inflation impact that it will trend continuing unabated or have you guys seen any particular.
Using points of pressure points kind of come up in those conversations.
Yeah, I'll start at a high level and Jeff could probably talk to some of the <unk>.
Areas, where we're seeing some of this particular tightness I think overall in terms of the major categories, we've seen a plateauing.
These are general industry observations as I said, we've been very active over the last couple of months getting ahead of 'twenty, three and accessing the right crews and services.
And products moving forward and getting as much price certainty as we can so we're not exposed to the spot markets, which have continued.
Continue to tick up during the course of the year.
Overall.
Inflation I think estimates we've heard out there from from others are in that 10% to 20% range is where things started last couple of months I'd say that what we're hearing and seeing is probably moving up there.
Of that range, but again, we've stayed ahead of that we don't want to be riding the curve out there in terms of spot market. So, let's get contracted with the right crews and services and let's get real contracts in place with price certainty.
In terms or in a repeatable program of development, which not only adds cost certainty, but also benefits of just repeated activity doing the same thing over and over with the same people and equipment.
Say one area on the big ticket items is probably on the casing side of things, but harder to lock in pricing. There you want to work with your providers to get.
Your allocation and make sure they understand your plan well in advance so thats, where youre benefited by showing them here's our 'twenty three plan, we're ready to go on this we need this this casing or steel and I'll make sure to get it just getting price certainty is difficult to get in this market, but there's probably some other ancillary pieces of the business that you don't really control.
<unk> four but do have impact on where our cost estimates.
Shakeout, Jeff do you want to think about some of the tighter Gibson.
That hit really the majority of the pieces that the short summary is that the average cost of doing business in 23 will be higher than the average cost of doing business in 2022.
Labor continues to be an issue across the board what Youll see is companies that are performing better tend to have been on their front foot as far as.
Paul policies to keep good employees and keep them.
Employed working on locations et cetera, So youll see some benefits of that.
Other items.
That will continue to see some potential pressure will be there.
Chemicals.
Availability of good workover crews and those kinds of items.
But we anticipate having a.
A very solid we are already in a position where all of our primary.
Contracts are either being negotiated or are negotiated so we have a very.
High level of confidence in executing our 23 program.
Understood. Thanks for your time gentlemen.
Thanks.
Yeah.
And that does conclude today's question and answer session I would like to turn the call back over to Joe Gatto for any additional or closing remarks.
Thanks, Lisa and thanks, everyone for taking the time out.
The third quarter earnings call always appreciate the time and the questions.
Well look forward to catching up again in the new year.
Thanks.
And that concludes today's presentation. Thank you for your participation and you may now disconnect.
Okay.
Yes.