Centennial Resource Development, inc (CDEV) Q3 2021 Earnings Call Transcript

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Centennial Resource Development, inc (PR 0.29%)
Q3 2021 Earnings Call
Nov 4, 2021, 10:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Good morning, and welcome to Centennial Resource Development's Conference Call to discuss its third quarter 2021 earnings. Today's call is being recorded. A replay of the call will be accessible until November 11, 2021, by dialing (855) 859-2056 and entering the conference ID number 6880769 or by visiting Centennial's website at www.cdevinc.com.

At this time, I will turn the call over to Hays Mabry, Centennial's Senior Director of Investor Relations, for some opening remarks. Please go ahead.

Sean R. Smith -- Chief Executive Officer

Thank you, Hays. Good morning, and welcome to Centennial's third quarter earnings call. Following my introduction, George will discuss our quarterly financial results, Matt will then provide an operational update, including recent efficiency improvements and well results and then I'll follow with our updated financial targets and provide a high-level outlook for the remainder of 2021. Overall, I am very pleased with our Q3 results as I believe they demonstrate our continued execution of our key 2021 objectives.

During the course of the third quarter, we once again generated record free cash flow, which helped drive significant deleveraging and absolute debt reduction. We also continued to successfully prosecute our development plan in Texas and New Mexico, delivering strong well results with competitive costs while improving drilling and completion efficiencies. Additionally, we recently signed an agreement to monetize a noncore asset in southern Reeves County that upon closing, will allow us to further accelerate our debt reduction efforts, improve our overall leverage position and optimize our future development.

With that said, I'll turn it over to George to review our financial results.

George S. Glyphis -- Executive Vice President and Chief Financial Officer

Thank you, Sean. We delivered another solid quarter with significantly higher free cash flow, substantial debt repayment and as mentioned, the announced sale of a noncore acreage position. Beginning with the acreage sale, which is detailed on slide six of the earnings presentation, we recently signed a purchase and sale agreement for the divestiture of approximately 6,200 net leasehold acres and related assets for $101 million in cash. The assets are located in an area of southern Reeves County that we did not intend to develop in the near term and is noncore relative to the company's overall acreage production and cash flow profile.

Third quarter production associated with the assets was approximately 1,600 BOE per day, which represents less than 3% of our total production. The transaction is expected to close in early December, and net proceeds will be used to repay borrowings under our revolving credit facility. Assuming a successful closing and continued debt repayment from projected free cash flow generation, we expect to end the first quarter of 2022 with a completely undrawn revolving credit facility. Overall, we're very pleased with the outcome of this divestiture, as we were able to bring value forward from longer-dated inventory and accelerate our debt reduction and deleveraging initiatives.

Turning to our financials, which can be referenced on slides five and 16 of the earnings presentation. Net oil production for the third quarter increased 5% from Q2 to approximately 33,500 barrels per day. Average net equivalent production increased 6% and totaled approximately 65,100 barrels per day. Total revenues increased by 24% quarter-over-quarter to $288.5 million, as a result of higher production levels as well as significantly higher commodity prices. Realized oil prices of approximately $65 per barrel drove a 14% increase in oil revenues.

Notably, higher natural gas and NGL prices made a significant impact with combined gas and NGL revenue up 57% over the prior quarter. Natural gas realizations of approximately $4 per Mcf were up 56% compared to Q2 and realized NGL prices were up nearly $10 to $40 per barrel. Turning to costs. Most unit cost metrics were in line with our expectations. Both LOE and cash G&A per BOE increased off a very low Q2 metrics, but were very much in line with the midpoint of guidance, with LOE of $4.79 and cash G&A of $2.08 per barrel.

Total G&A increased primarily as a result of stock-based compensation expense that is tied to certain stock grants that have been impacted by the significant increase in our share price over the past 18 months. As you will note from our implied Q4 guidance, we expect stock-based compensation expense to drop significantly in Q4 and going forward. GP&T was $4.03 per barrel, which was up 16% from the prior quarter, mainly because of higher natural gas and NGL prices, which increased the expense associated with our percent of proceed contracts.

Importantly, this increase in GP&T expense was more than offset by the material increase in gas and NGL revenue, which was a net benefit to our EBITDAX and free cash flow for the quarter. DD&A declined to $12.69 per barrel from $13.09 in Q2, due to upward PDP revisions and lower F&D costs, a reflection of the significant strides we have made in overall capital efficiency over the course of 2021. Due to a quarter of solid production growth, continued cost control and strong commodity price realizations, adjusted EBITDAX totaled approximately $171 million, up 35% from Q2 and free cash flow more than doubled to $77 million compared to approximately $34 million in the prior quarter.

Additionally, we recorded GAAP net income of approximately $37 million. Turning to capex. Centennial incurred approximately $79 million of total capital expenditures during the third quarter, which was a 5% decline relative to Q2. We continue to run two rigs and one completion crew, which spud 13 wells and completed 10 during the quarter. Finally, of the $79 million in total capex, infrastructure and land capital represented $4 million for the quarter. On slides nine and 10, we summarize our capital structure, leverage and liquidity, which showed marked improvements quarter-over-quarter.

During Q3, we utilized our free cash flow to repay $50 million of borrowings on the revolving credit facility. Net debt to LTM EBITDAX declined by nearly a full turn moving from three times at June 30 to 2.1 times at September 30. The pace of our deleveraging has continued to exceed our initial expectations, and as a result, we have revised our leverage target for year-end 2021 down to 1.5 times from our prior target of less than two times. Notably, net debt to last quarter annualized or LQA EBITDAX has already declined to 1.5 times at September 30.

Additionally, while we haven't yet provided a 2022 leverage target, we believe, based on strip pricing, we will be below one times leverage by year-end 2022. At September 30, total liquidity was nearly $500 million based upon $205 million of credit facility borrowings, $5 million of cash and $6.5 million of outstanding letters of credit. The $700 million borrowing base was reaffirmed in the fall, but I will note that asset loan value is significantly higher than the borrowing base amount.

Given our strong liquidity position, we haven't had a need to push the borrowing base higher, even though our fundamental asset quality and value would support doing so. Turning to hedging. Our hedge position is illustrated on slide 11 of the presentation. Our hedging strategy is designed to protect cash flow in the balance sheet against unexpected declines in oil prices while also minimizing disruptions to operational activity. This is particularly important as we delever the balance sheet.

We also try to balance the downside protection that hedges provide with upside exposure to commodity prices. For calendar year 2022, we have hedged approximately 11,000 barrels per day on average, using mostly fixed price swaps at around $64.50 to $65 per barrel. This compares to approximately 17,000 barrels per day hedged on average for calendar year 2021. Given our deleveraging profile, our 2022 hedges are more heavily weighted toward the first and second quarters where we have approximately 14,500 barrels per day hedged.

In the second half of the year, we have an average of approximately 7,500 barrels per day hedged, providing incremental exposure to commodity prices. Lastly, based on year-to-date performance, we are also refining our annual guidance, which includes the anticipated impact of our recently announced divestiture, assuming an estimated December one closing date. Annual oil production guidance is being increased by 2% at the midpoint to roughly 31,800 BOE per day, and total equivalent production guidance is being increased by 3% at the midpoint to approximately 61,200 BOE per day.

As highlighted over the past several quarters, our operations team has continued to drive efficiencies in the field. Therefore, we are increasing the midpoint of our spud guidance by five wells to 48 gross operated spuds. As a result of the incremental activity, in addition to higher-than-expected working interest in wells completed during the year, we've adjusted our full year capital expenditure guidance to essentially the high end of our previous range. We've also updated our estimates for completions and unit cost metrics, which are all outlined on page 12 of the earnings presentation.

And with that, I'll turn the call over to Matt to review operations.

Matt R. Garrison -- Executive Vice President and Chief Operating Officer

Thank you, George. Q3 was another solid quarter for the operations group. We continue to realize the significant improvements in cycle times that we highlighted in last quarter's earnings update. Year-to-date, cost per foot remain near the midpoint of our 2021 guidance at around $800 per lateral foot, which includes facilities and flowback as we believe that is the proper way to think about D&C capex. In Q3, all of our completed wells consisted of 2-section laterals, and we continue to see the utilization of larger pads and facilities as key drivers of capital efficiency.

As we continue to look for ways to improve our capital efficiency, both longer laterals and larger pad developments will be two main areas that we will focus on. Additionally, our operations team has been working on wellbore design modifications in both the drilling and completions departments. Some of these tests in Q3 resulted in very positive outcomes that we intend to build upon in 2022. Notably, we trialed two different completion designs that yielded a roughly 30% improvement in stages per day.

On the drilling front, we have continued to see the benefits of the significant improvements in drill times realized over the course of 2021 and anticipate trialing a new motor and bit design that we've been working on in the back half of this year. We believe this new design has the potential to further reduce our drilling cycle times by an incremental 10%. As you can see, our operations department is constantly pushing the envelope on the technology to drive further efficiencies.

The team's continued focus on innovation and efficiency will be particularly critical as we look to help offset some of the inflationary pressures we anticipate in 2022. Now turning to recent wells on slide eight in New Mexico. The Mozzarella and Gouda wells were drilled as a 4-well development, targeting the 3rd Bone Spring Sand. These approximately 10,000-foot laterals delivered an average IP-30 of over 2,100 BOE per day or approximately 1,600 barrels per day of oil.

Further east in the central portion of our Lea County position, the Crunch Berry wells were drilled in a 3-well development targeting the 3rd Bone Spring Sand with an average of 9,500-foot laterals. Like the Mozzarella and Gouda package, production numbers were robust posting a IP-30 numbers of approximately 2,000 BOE per day or 1,600 barrels a day of oil. Year-to-date, our development packages in New Mexico have all met or exceeded our internal expectations and will continue to serve as a growth engine for Centennial into '22. Turning to Texas.

The Highlander West Deep C09H is another example of a strong lower Wolfcamp result. Drilled as a single well to finish out a drilling unit, the well result exceeded internal expectations. Drilled to a lateral length of approximately 8,100 feet, this well produced an IP-30 of approximately 1,800 BOE per day or 1,400 barrels of oil per day. The Highlander well represents our eighth Wolfcamp C result in Reeves County this year. We've been pleased with the results of that program that have been yielded thus far and expect this target to continue to play a role in our development program in 2022.

Overall, our team did a tremendous job during the third quarter and brought online some terrific wells. Underpinned by our structural cost reductions, coupled with higher commodity prices, we estimate that all of our wells brought online during the quarter will achieve payout in under 12 months, assuming current strip pricing and further highlighting the quality of our asset base. To wrap up, in Q3, we continued to build upon the momentum we have witnessed in the first half of the year. We have been very proud of our ability to largely offset year-to-date inflationary pressures with improved drilling efficiencies.

We do anticipate inflationary cost pressure in 2022, and that is why we will continue to pursue new technologies and larger scale development to capture additional cost improvements. As we put the final touches on the 2022 drilling schedule in the next 1.5 months, it is important to note that we anticipate a similar development mix between our two assets as what we saw in 2021, with the vast majority of the development in 2022 being focused up north in the New Mexico asset. The bottom line is that I believe our team is up for the challenge. Our operations and asset development teams have provided a solid foundation for Centennial's well costs and unit metrics. We are all incredibly proud of the work that's been done, and I look forward to updating you on our progress early next year.

And with that, I'll turn it over to Sean for closing remarks.

Sean R. Smith -- Chief Executive Officer

Thanks, Matt. As evidenced by today's remarks, Centennial had an outstanding third quarter, and I'm pleased to have increased our free cash flow and reduced our year-end leverage targets for the second consecutive quarter, in addition to increasing full year production guidance. Focusing on slide 13, we've transitioned to generating sustainable free cash flow and expect to generate over $200 million in free cash flow this year. Additionally, we've increased our liquidity by nearly 50% during the first three quarters of the year.

While higher commodity prices have certainly helped accelerate our free cash flow and leverage targets, this would not be possible without our materially lower cost structure. In the field, our operations team continues to do an outstanding job driving efficiencies and reducing cycle times, which have materially lowered our go-forward well cost compared to just a couple of years ago. Before I touch on high-level strategy, let me first comment on our recent noncore acreage sale.

As George mentioned, yesterday, we announced the divestiture in the southernmost portion of our Reeves County position for $101 million. This was a legacy position with quality rock, but given our current portfolio within both New Mexico and Texas, we did not expect to develop this position in the near term. Thus, we view this transaction as prudent portfolio management, considering that our near-term capital will be focused on other areas of our portfolio.

Importantly, these sale proceeds will be utilized to repay borrowings under our revolver. As a result of that pending debt repayment as well as further anticipated repayments funded by future free cash flow, we expect that our -- that during Q1 of 2022, we will have repaid our revolving credit facility in full. With line of sight on an unutilized revolving credit facility and continued balance sheet deleveraging, we expect to have significant flexibility with respect to how we deploy our anticipated future cash flow during the course of 2022 and beyond.

Between now and our February earnings call, when we will release our 2022 guidance, we will be evaluating the best use of excess free cash flow, including various shareholder return options. While we are not in a position to provide further details on these topics today, we have already begun in-depth discussions with our Board to develop those future plans. Overall, I am very excited to see and recognize how our team has performed this year. Our execution in 2021 sets us up nicely as we head into next year. Furthermore, our increasing free cash flow profile and our continued deleveraging provide us with significant financial and operational flexibility to drive value for the company and our stakeholders.

Thanks for listening, and now we'll turn it over to Q&A.

Questions and Answers:

Operator

[Operator Instructions] The first question comes from the line of Neal Dingmann from Truist Securities. Your line is open.

Neal Dingmann -- Truist Securities -- Analyst

Good morning, Sean, going forward, certainly going to have more financial and operational options given how leverage has come down, you talked about that and respect you don't have the full details yet on the shareholder return. But I guess my question, still around shareholder return is a bit more general, and that's more around some of your peers have gone to and suggested more of a -- I think, maybe a no-growth plan is best, while others still think, especially your size, that's still best to continue to scale up a little bit on a go forward. And so again, I'm not certainly asking specifics on how you'd pay out your free cash flow. So I'm just wondering if you would sort of lean to one of those two either the no growth or the scale in direction?

Sean R. Smith -- Chief Executive Officer

Sure. Neal, thanks for the question. Certainly, we're not giving out 2022 guidance. That being said, I think we're being very transparent with the amount of free cash flow that we're going to generate this year. And if you just look forward on a strip basis, that number is going to increase next year. So I feel very good about our financial flexibility, as you mentioned, and we just described in our prepared remarks, and that we have begun some material shareholder return discussions at both the senior management and the Board level.

I mentioned in previous calls and conferences, that as we approach 1.5 times debt to EBITDA, that we would start to have those discussions. That has happened as we plan to end the year at 1.5 times and then have line of sight on being less than one times levered by year-end 2022. So you kind of take all that into consideration, and we've got a lot of options, both from a balance sheet perspective as well as from a free cash flow perspective. So I do think that we will continue to have a serious shareholder return discussions, both internally and at the Board level. In regards to growth, as we think about that into next year, we are currently running two rigs. We have been running two rigs all year this year.

We plan to start next year with two rigs. And if we were to keep a 2-rig program flat for next year because of the operational efficiencies that our team, Matt and his team have incurred over the year and expect to incur next year, we think that does provide some growth. And so while it's a maintenance program from a rig perspective, we do think that there is some production growth that goes with that to the tune of low double-digit growth on a year-over-year basis. So it's a bit of a combination of all of the above, if you will, Neal. We think we're going to have substantial free cash flow in a 2-rig program. We're going to look at a shareholder return program, and all of that is coincident with low double-digit growth if we were to have a 2-rig program next year.

Neal Dingmann -- Truist Securities -- Analyst

I love the optionality. And then just a follow-up. M&A out there, we've seen larger deals. I'm just wondering how often are you guys either seeing somebody knocking your door, showing you some things that they have? Or I'm just wondering, again, on Wall Street here, we don't see it too much under the hood. I'm just wondering, have things increased as they normally do toward the end of the year, Sean? Or just -- again, I'm not asking what you're going to do, but just more how active the market is out there maybe versus earlier this year?

Sean R. Smith -- Chief Executive Officer

I think it ebbs and flows, as all markets do. I think there, there have been deals that have come across that have been public and it's hard for me to gauge that. But any time there's an opportunity in the Delaware Basin, I assure you that our team considers it. But what we're not going to do, and I've said this in the past, is stretch. I think you've seen the numbers. They are very good as a stand-alone business. We've got a quality long-term inventory.

We've got financial flexibility and material free cash flow and a balance sheet that is just in outstanding shape. So we're great as a stand-alone company. I've said in the past, I'll continue to say, if there's an opportunity out there that is -- that adds accretive value to our business, particularly on a cash flow basis and can compete for capital versus our current inventory, we'll absolutely take a look and the price is appropriate, then we'll move forward. But we're going to be very careful and selective about that because we've got such a positive momentum as to driving value for our stakeholders as is.

Neal Dingmann -- Truist Securities -- Analyst

Thanks guys.

Sean R. Smith -- Chief Executive Officer

Thanks, Neil. Appreciate it.

Operator

Your next question comes from the line of Chris Dendrinos from RBC Capital Markets. Your line is open.

Chris Dendrinos -- RBC Capital Markets -- Analyst

Hey, guys, I appreciate it. Just kind of following up on your prior comments, it sounded like you said you're going to start the year, next year at two rigs. So I guess that to me kind of implies that you might be internally considering a third rig. So I guess just kind of honing in on that a little bit, what factors are you all kind of considering and weighing in, in that discussion? And kind of what would tip the scales one way or the other in terms of activity acceleration, I guess?

Sean R. Smith -- Chief Executive Officer

Sure. Chris, appreciate the question. I'm certainly not implying that there's a third rig that's imminent. My point was that we have two rigs now. Without providing 2022 guidance, which will come out in late February, we plan to start the year with two rigs. And then we will look at our capital needs, and we'll have discussions with the Board on what the appropriate level of capital, i.e., rig cadence will be for 2022.

I think that a safe way to think about it is that even in a model where we have two rigs running throughout the year, it provides growth along with free cash flow and allows us to continue to delever the company. So I'll leave it at that. And I certainly wasn't implying that we are near term considering a third rig. As I've said in the past, the world right now with OPEC+ still holding barrels off the market, with COVID still out there impairing on the demand side of the equation, we want to be very careful, and I think the industry should be very careful before it starts talking about material growth, and we are certainly in that same camp.

Chris Dendrinos -- RBC Capital Markets -- Analyst

Yes. Okay. Understood. I guess as my follow-up, you mentioned you guys are still on track to hit your well cost targets for the year. And you highlighted a number of initiatives that could buy us well costs lower in the future. I guess, can you talk about, I guess, current pad development size and lateral lengths? And then obviously, you haven't provided any guidance on 2022 yet. But I guess, maybe just thinking about the opportunity to increase pad sizes, what does that kind of look like and what options are available to you all maybe next year and going forward?

Matt R. Garrison -- Executive Vice President and Chief Operating Officer

Sure. Chris, this is Matt. I'll go ahead and take that question there. With regard to current pad sizes and lateral lengths, I think we've been very pleased year-over-year, if you kind of look at historically back where we're 2019, 2020 kind of time frame, we were typically like a 1- to 2-well per pad kind of company, especially predating 2019. And our lateral lengths in general were at around 7,000 feet or less in prior years. What I've been very proud of our land team and asset team for doing is taking a lot of opportunities in 2020 and this year in '21 to block up through trades and swaps to get these longer laterals.

I think at the beginning of the year, we guided that our average lateral length this year would be kind of in the 8,700 feet range in terms of an overall average for the program. And we've been very happy with the last couple of quarters, that both Q2 and Q3 have been in excess of 9,400 feet on average. So we've been able to block up and get those lateral lengths up. The pad size is also, as part of, I think, some of the things we highlighted in the second quarter, we've gone to more of a modular facility that allows us to bolt-on and continue to build units through a common facility.

And what that's really allowed us to do is push those average pad sizes up from 1s and 2-well pads to more like 3s and 4s on average for kind of where we're at this year. And that's certainly what we hope to kind of be at in 2022 is more of a 3-well to 4-well kind of average for the year. Beyond that, I think given where we're at with our activity levels and things, we're going to be a little bit measured with our approach to going much more beyond a 4-well kind of grouping at one time.

And that's just a function of assessing the current market conditions and where we're at with regard to our activity level at this point. So I think what you should see probably for us is a continued emphasis on these long laterals in excess of 8,500 to 8,700 feet on average for a program. Wherever we can, we're going to be pushing these laterals to around two miles, and then you should expect us to place a high degree of emphasis on pads in excess of three wells per pad. And I think that's kind of our internal goals.

Chris Dendrinos -- RBC Capital Markets -- Analyst

Got it. Appreciate it. Thanks guys.

Matt R. Garrison -- Executive Vice President and Chief Operating Officer

Thanks, Chris.

Operator

There are no further questions at this time. I would now like to turn the conference back to our CEO, Sean Smith.

Sean R. Smith -- Chief Executive Officer

Great. Thank you, Ren. Well, obviously, hopefully, what everybody saw from the presentation and from the remarks that the third quarter was a very positive outcome for Centennial, highlighted by, as we mentioned in the call, record free cash flow, continued deleveraging of the business, noncore asset divestiture, which again went right to the -- will go right to the revolver.

As I mentioned, we plan to have our RBL fully repaid in the first quarter, which is just an outstanding outcome, and that's really driven by lowering of our costs as well as generating free cash flow and of course, higher commodity prices are helpful as well. Updating our guidance pretty much across the board is another positive aspect of how we are running the business and continue to focus on our costs, but all of those things set us up very well for 2022 and beyond, honestly, to allow us to continue to drive value for our stakeholders. So I appreciate everybody's time and attention and for their interest in Centennial. Thank you very much.

Operator

[Operator Closing Remarks]

Duration: 33 minutes

Call participants:

Sean R. Smith -- Chief Executive Officer

George S. Glyphis -- Executive Vice President and Chief Financial Officer

Matt R. Garrison -- Executive Vice President and Chief Operating Officer

Neal Dingmann -- Truist Securities -- Analyst

Chris Dendrinos -- RBC Capital Markets -- Analyst

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