Q2 2022 Callon Petroleum Co Earnings Call
Come on the marketing front, where we continue to be proactive in our approach to moving hydrocarbons and capturing incremental economics, we announced in June accounted entered into multiple natural gas transportation agreements for firm transportation to the Gulf Coast for approximately 75000, and then Btu per day beginning in mid 2023. Please.
Transactions will increase our pricing exposure to Gulf coast gas pricing and provide additional flow assurance benefits.
Turning to ESG, we are steadily executing on our accelerated emissions reduction goals, we are well on our way to achieving our two year plan to replace all of our pneumatic devices with zero emission or nobly devices, which will significantly reduce our overall emissions, particularly methane.
And consistent with our track record of acquiring improving assets. We are investing this year and facility upgrades in our Delaware South operations to bring them in line with Cowen standards, and reduce flaring and other emissions.
With these and other activities, we remain committed to our goal of reaching a 50% reduction in emissions intensity by 2024.
You can read more about our progress and initiatives and our forthcoming sustainability report, which will be released in the coming weeks. So please be on look out for that.
Now turning to our second quarter results.
Operationally this was a transitional quarter for us as we ramped up our completion activity and placed 33 gross wells on production almost double the first quarter as we started developing our DUC backlog at an increased pace early in the quarter.
Headline production came in at the midpoint of our guidance 101000 barrels of oil equivalent per day carrying the oil cut 61% and total liquids content of 81%.
Volumes for the quarter were relatively flat compared to the first quarter and were impacted by a couple of onetime items.
First.
We set up our workover activity as we accelerated the implementation of <unk> artificial lift program in the Delaware basin, particularly in the Delaware South area as we experienced higher levels of well downtime from power disruptions and typical equipment failures that occur after useful life is reached.
In total our level of Workover activity was approximately twice the amount in the first quarter and pull forward workovers repairs lift conversions forecasted for later in the year.
While the conversion of wells to our artificial lift program doesn't extend downtime relative to normal repairs. This initiative has proven to be an important operational synergy that improves production rates and longer term run times as shown on page nine of the materials.
Through the first half of 2022, we've seen an average sustained uplift of over 25% through the first 60 days of install which equates to very short payouts. After factoring in near term downtime required to perform the conversion of repair.
Importantly, it also extends run times and reliability for the long longer term.
In addition, we restructured one of our primary Midland basin gathering contracts changing the contract from a percentage of proceeds structure to a fee based contract, which increased our natural gas and NGL volumes, resulting in a lower oil cut on a percentage basis.
The impact of these items have been factored into our updated guidance for the remainder of the year.
Continued strong well performance, particularly in the Delaware Basin, we are raising the bottom end of our annual production guidance from 101 to 102000 Boe per day with sequential growth expected over the next two quarters.
We are also increasing our natural gas mixed by 1% on an annual basis to.
To incorporate the additional gas volumes realized in the gathering contract conversion.
Our average wellhead price increased 15% to approximately $83 per Boe.
We have not seen since 2014, the topline increase contributed to an eighth consecutive quarterly increase in cash margins driving quarterly adjusted EBITDA to approximately $420 million on a hedge basis and over $600 million on an unhedged basis.
As our hedge portfolio steps down as a percentage of production relative to the first half and associated hedge prices increase our participation.
Anticipation of strong commodity price environment will improve in the back half of the year.
We will also benefit from our ongoing exposure to international and MGH pricing, which represent approximately two thirds of our oil volumes in 2022 on a combined basis.
Beyond strong price realizations controlling inflationary cost pressures is also critical preserving our cash margins.
While we have seen inflationary pressures from power and fuel on the LOE front.
Elevated workover costs in the second quarter from the ESG initiatives I discussed.
Our guidance range for absolute although we spend has remained unchanged.
<unk> provides a $5 million reflective of the Midland gathering contract conversion, which will increase our exposure to natural gas and NGL volumes and a new contract that transfers operator ship and maintenance of a compressor station to a third party, operator, which we believe will improve operational efficiency.
And finally G&A expense has been squarely in line with initial expectations.
Overall, we have managed our absolute dollar spend well in an inflationary environment and our per unit metrics will benefit from second half production gains.
As we turn to the second half outlook completion activity will increase over the first half with approximately 40% more wells placed online in the second half.
Our second half of 2022 drilling program will remain Permian focused with over 80% of the new wells coming from this area in terms of mix. The Midland Basin will constitute a larger portion representing approximately 50% of our new wells in the second half of the year.
We expect third quarter production volumes to increase to between 102, and 105 Boe per day, a strong well performance and ongoing contributions from second quarter activity will be bolstered by increased activity in the third quarter with approximately 40 gross wells scheduled to come online.
Our operational capital spending is forecasted to be between 245 $255 million on an accrual basis, which is slightly above our second quarter figure.
As we've highlighted in the past.
We have one of the deepest drilling inventories amongst our peers at over 700 locations equating to roughly 15 years of drilling inventory.
It is underappreciated by the market at times. However are the implications of our life development philosophy, which focus on scale co development optimize the value of a larger part of the reservoir system.
The strategy captures multiple zones to deliver strong economics on both an individual well and project level basis, and minimizes parent child relationships overtime as.
As a result, we've maintained more balanced inventory opportunity set for future development.
On page 11 of the presentation.
We've referenced a third party independent analysis that illustrates that concept.
The analysis created shaft or shapley additive explanation values. They are used to explain the relative contributions of a group of factors to the outcome of a predictive model.
In this case chap values were developed for factors, such as geology, well spacing completion design and well timing to provide the marginal impact of each on a three year oil production target outcome.
The specific geologic shop value quantifies, the marginal impact of rock quality on well performance.
These geologic SHAP values were aggregated to create distribution that characterizes accompanies remaining inventory.
The median of that distribution has been compared to the meeting of the shaft value distribution for wells placed online in 2021 to FERC comparability of rock quality for future drilling relative to 2021 rock quality drill.
That analysis revealed that out of 16 operators in the Delaware Basin that were included in the study 12 companies had a negative shack value, meaning the company's inventory quality is expected to decline relative to 2021 drilling over the next couple of years.
On the contrary.
<unk> had one of the highest positive values, reflecting calendar inventory opportunity set is expected to improve the quality in the coming years as we as we execute our life of field development program.
We've been consistent in our development approach over time, and we believe this will be an important differentiator and generated free cash flow on a sustained basis with a prospective inventory that has been developed in a more balanced manner.
I'll now turn the call over to Jeff to cover operations.
Thank you Joe and good morning, everyone.
From an operational standpoint, this quarter was very impactful as we significantly increase our completion activity.
While our second completion crew began operations late in the first quarter due to accrued moving from the Delaware over to the Eagle Ford, We really didn't hit our stride until the start of the second quarter and over the three month period. The number of completed wells increased by 75% versus our activity in the first quarter.
And as Joe pointed out we continue to raise the bar on operational efficiency.
This year, we began utilizing a fourth generation electric frac system. Besides the cost savings to the reduction in diesel costs. We're also realizing operational improvements and in fact during the quarter, we set a new company record in terms of our pumping hours per month.
This has allowed us to increase the efficiency of our overall completion operations and we've realized a 160% improvement in profit tons per day, despite the artisan maintaining the fracture stage spacing to approximately 200 feet.
On the drilling side, we've also seen operational improvements.
Through the use of rotary steering tools multi bore wellhead design and improved bits and bottom hole assemblies, we've seen an increase in our drilling feet per day specifically.
Specifically during the first half of 2022, we averaged approximately 830 feet per day, and the Delaware basin, reflecting about a 50% improvement since 2018.
And now I'd like to provide you with an update on each of our operating areas. So let's start with the Eagle Ford.
That's not placing any eagle Ford wells on production during the first quarter, we placed 15 wells from three pads online as part of our 26, well 2022 Eagle Ford Development program. The remaining 11 months from this year's drilling program are scheduled to be completed during the third quarter and as we discussed last quarter as part of this program.
We plan to complete an Austin chalk tests, well, we recently drilled that log the well and plan to complete and place. It on production later this quarter.
So shifting to the Midland Basin, we continue to have success with our multi bench development in our life of field development philosophy.
One example of this are the two chaparral unit pads that we placed on production in early June the.
710900 foot lateral wells were completed targeting multi bench development in the Wolfcamp, a wolfcamp b and lower sprayberry formations.
Surface system was a combination of infill and co development and the results have exceeded our expectations.
During the quarter, we had two rigs running in the basin and drilled 16 gross wells and we plan on keeping the two rig drilling program on our Midland acreage through the third quarter and then it will drop down to one rig for the remainder of the year.
Moving to the Delaware during the quarter, we completed six gross wells and brought online 11, all in the East Delaware 11 Wells were completed targeting multi bench development in Wolfcamp, a and b formations.
In the past that I'd really like to highlight the three drainage unit wells that were completed with a larger proppant design. These on average 8700 foot lateral wells achieved strong production results with a peak average 30 day rate of 680 Boe per day with an oil cut of 75%.
Overall on the drilling side, we finished the quarter with six rigs and will drop our Eagle Ford Group. Shortly and then we will maintain our five rig development pace for the majority of the remainder of the year.
And prior to my final comments I once again like to acknowledge talents field operations teams as they continue to perform extremely well across the board and I'm very proud of everyone on the team.
So in closing in the first quarter of 2022, our focus was largely on building a DUC backlog for efficient operations and now our second quarter was largely focused on ramping up completion activity across our three major areas.
With both of these objectives successfully completed we are now in a great position to operationally delivered sequential production growth in the second half of the year, while maintaining our commitment to capital discipline.
And with that I'll now turn it over to Kevin to handle the financials. Thank you, Jeff our strong financial results during the quarter allowed us to continue moving closer to our near term balance sheet goals, reducing our outstanding debt $2 billion and our leverage ratio to one times, we generated positive free cash flow for the ninth consecutive quarter, allowing.
For continued reduction of our debt stack the high yield markets open for US late in Q2, and we Opportunistically refinanced term debt, allowing us to extend our maturity profile lower our interest rate and simplify our capital structure by removing the second lien notes.
Briefly go through some key financial details first driven by our top tier high oil weighted production profile, we realized a 50% increase in wellhead revenue to $82 98 per barrel of oil equivalent.
After factoring in hedging and operating costs calendar reported its eighth consecutive increase in operating margin of $67 EBITDA per BOE, which was a 16% increase over Q1.
Our top tier operating margins helped us realized adjusted EBITDA of $418 million in the second quarter of <unk>.
6% sequential increase over Q1.
During the second quarter <unk> generated adjusted free cash flow of approximately $126 million, which brings us to over $300 million of adjusted free cash flow for the first half of the year. We expect this number to ramp up in each of the remaining quarters of the year and drive continued reductions in depth and absolute debt.
Besides using free cash flow to retire debt, we remain opportunistic and taken steps to further strengthen our financial standings. When the market Windows are open in late June we issued $600 million of senior unsecured notes due in 2030 price to yield seven 5%. We used the proceeds from this offering combined with the free cash flow.
We generated during the quarter to redeem $780 million of term debt, including the near term 2020 for maturity and our second lien notes overall through this refinancing we reduced our outstanding term debt by approximately $200 million.
<unk> eliminated second lien notes from our capital structure lowered our overall weighted average interest rate and extended the maturity profile about two years.
Our next term debt maturity is not until 2025 and has less than $200 million outstanding on it. This is an amount we can easily fund with free cash flow in the coming quarters.
And as part of the financing all three credit rating agencies reviewed the callan name and upgraded our rating. They all took notice of our rapidly improving leverage profile and overall strengthening financial health with.
With regard to hedging we have positioned the portfolio with a good base layer of hedges for 2023 and are north of 20% hedged for our WT up <unk> volumes during the second quarter. We added 3500 barrels per day of swaps at approximately $95 per barrel for Q4 of 2020 to through Q2 of 2023.
Additionally, we added another 3500 barrels per day in the first half of 2023, using white collars that have a floor price of $80 per barrel and ceilings of $110.
Finally, I'd like to discuss at upcoming accounting change as we have met with investors. We've received plenty of feedback about how cowens election to use full cost accounting makes it difficult to compare the company's financials with our peers as background. The full cost accounting approach was traditionally appropriate for companies with long lead time large <unk>.
Capital projects like offshore drilling given that some of the reasons that we originally elected to use full cost accounting are no longer relevant.
And to make <unk> more.
Comparable to our peers, we are pursuing a project to convert our financial reporting from full cost. So the successful efforts accounting method at this point, we are targeting reporting our first quarter 2023 results using this method.
To head off questions, we're not ready to discuss all the ways. This will impact our financials, but we plan to provide detailed information as we get closer to year end. However, I can add a couple of early guidance points first this change will have no impact on cash flow.
Next we would expect to have no capitalized G&A or capitalized interest in 2023 and beyond and finally EBITDA is likely to increase slightly as the capitalized portion of the G&A comes back on the income statement in 2023 and beyond and with that I'll turn things back over to Joe before we move to Q&A.
Kevin before turning to questions I'll leave you with a few key takeaways.
We are driving improved capital efficiencies are well level as we refine our development model in the Delaware basin, including solid contributions from our asset acquisition last year.
Our focus on co development of top tier zones over time has created a visible path sustained inventory quality for future drilling as we have steered away from just drilling our best wells at the expense of integrating offsetting locations in adjacent zones.
Our balance sheet and overall financial position is solid and will continue to improve at a fast pace of the year end.
<unk> improvement will remain a key focus for the longer term, even as we look to implement return of capital frameworks in the future.
And finally, we see a compelling value proposition for shareholders Cowen currently trades at a 2023 consensus free cash flow yield of approximately 30%.
Price earnings ratio of two three times and our enterprise valuation is over $1 billion below the June 30, PV 10 of just our proved developed producing reserves using last month 12 month pricing and current operating cost under SEC methodologies.
We recognize the challenges faced by investors in a volatile environment. We believe the companies with sustainable business model supported by quality assets and people will be rewarded so.
So you can open up the line for Q&A.
Thank you Mr Yano, ladies and gentlemen at this time to begin any questions or comments simply press star one.
Joining us today using a speakerphone please pick up your handset before pressing star one.
A more balanced mix of inventory going forward versus if we just focus on our best stuff and then you're left with integrated inventory going forward. So that's really the essence of.
What we've been talking about it's been something that we've done even through 2000 22021. So that's what it's showing up now and we think it's going to be a very meaningful differentiator going forward.
Extent that folks have maybe taken a different tack on that and this was an interesting analysis.
It's a very good report.
Chance get your hands on it but I think it is.
There is sort of a complex concept like you said it intuitively, maybe you wouldn't have thought that but still has a pretty well.
<unk> that there's only a few people that are on the right side of that equation and we're happy to be one of them.
That's great that makes sense.
Look forward to seeing the report.
Great.
Okay.
Thank you we'll go next to David petrol RBC capital markets.
When you all thanks for taking my questions.
One and you touched on in your prepared remarks in the release, but can you just expand a little bit more on kind of the power disruptions in the Delaware, causing that increase well failures, and specifically kind of where you're at in the process of addressing and accelerating.
Michelle lift upgrades.
Okay.
Sure.
There is again kind of two parts to that answer one of them and it can really be broken into planned and unplanned downtime the Delaware basin, South as Joe had mentioned earlier.
Anytime we take over a large scale asset we always want to make sure that the level of consistency and quality, particularly the production systems.
Both in the subsurface and surface are.
Consistent with our operating procedures, our safety metrics.
And are just consistent across the board and so.
What we did was we went in and proactively looked at opportunities.
We knew we were going to have downtime say, we were going to go into a facility upgrade for a clearing system or we've put a lot of work into the chemical program and how we treat hydrogen sulfide and while we were out there. We analyzed all the wells that are within the production system and determined whether or not the USPS, but right sized or a dip.
Changing gears the sizing for the age or the vintage of those downhole systems needed to be addressed and we took advantage of those.
And then the second half of those were the ones.
That we came in and were unplanned and so again, depending upon the quality of the systems that are in place, we had a slightly higher than expected.
Drop in their systems and their efficiencies. So we went in.
On an unplanned basis and had to do a certain level of workovers and change the change outs.
When you combine that with a relatively tight market from a workover crew perspective, and the fact that we take safety extremely seriously. We did not go out and pick up crews that we didn't feel were going to fit our operational model from a safety and performance perspective and that.
<unk> realized a little bit more downtime than we would've normally expected in any quarter.
The nice thing about that is the vast majority of that is taken care of so we would anticipate.
History, leading performance from our <unk> going forward as it has been for the last several years.
Got it and just kind of follow up quickly on that.
It was more of a pull Florida of Workover activity in that kind of plan bucket versus.
It kind of increase.
An increase that's why that Louis, but the chip with.
If the stay constant is that correct.
That is correct yes.
And then just one last quick one for me and kind of delving into the dialogue the Delaware a little bit more.
I don't think there was any completions on legacy <unk> assets this quarter, but can you remind us kind of when that first batch of <unk>.
<unk> drilled uncompleted wells will come online and kind of anything so far you'd continue to see from those those wells on those assets.
Sure we've had a handful of wells that came online earlier than they are probably 150 days in the key the Campbell wells are the ones that stick out.
Forefront and Thats.
A combined 11, well system and they are performing tremendously.
Hit two different benches in there so kind of the traditional wolfcamp a wolfcamp BS.
<unk>.
Very appropriate well spacing, we built predictive models based on our subsurface analysis, both from a geologic perspective from <unk>.
Fluid systems that we have in place and then of course, all the Petro physical properties that roll in in our predictive models have been outperformed by about 5%, 10%. So far year to date and again. These are these arent wells that are 30% 30 days old or in the 150 day range.
We're continuing to do a lot of work out in the Delaware Basin South.
And as I've mentioned before I think in the first quarter I am very excited about this acquisition the rock quality is terrific.
Prior the prior operator did a great job in getting this asset up and running and we anticipate continued terrific performance going forward.
Got it good to hear I appreciate the time.
Thanks.
And ladies and gentlemen, just a quick reminder, questions or comments simply press star one.
Now to Fernando's Nabozny Pickering partners.
Alright, okay.
Good morning, My question is around the Eagle Ford activity.
I would assume that youre looking to add back an eagle Ford rig next year and if so how confident are you in the ability to get the rig you need and how do you think about managing the longer planning cycles to keep activity levels consistent.
Sure those are great questions.
Yes, you are 100% correct, we will be bringing an eagle Ford rig back in.
Literally getting ready to lay that breakdown at TD, the last well on the pad.
And so we will be dropping that we'll be picking up another rig since we on January one.
Im frame.
And we will be able to go in and get the majority of the year of drilling in 2023, the nice thing about what Cowen has done in the past and continues to use we have long term relationships with all of our vendors.
Even if it's a new vendor for us we establish those well in advance.
<unk> put a drilling and completion program together and we stay very consistent in committed and Joe had mentioned this about.
Some of the items that that <unk>.
He discussed earlier this allows us to have a very strong planning relationship with everything from type two our completion crews to our sand delivery our chemical programs.
And it's very much appreciated from the vendor community and our partners. So while there is always.
Opportunities to have long term discussions with new partners, we have been very satisfied with the folks that we have.
And so we anticipate being able to move.
<unk> moved from our five rig program back up to a seven rig program.
<unk> had the right pressure pumping services in rigs.
Okay got it thanks.
All for me thanks for that.
And gentlemen, it appears we have no further questions. This morning, Mr. Gautam I'll hand things back to you for any closing comments.
Thanks, Paul.
I appreciate everyone joining the call today and.
In the interest obviously any follow up questions. Please reach out to Kevin and we'll get those answered otherwise we look forward to talking again after the third quarter.
Yes.
Thank you and again, ladies and gentlemen that will conclude this.
Morning, Callen Petroleum second quarter 2022 earnings conference call I would like to thank you all so much for joining us and wish you all a great day Goodbye.
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Yes.