PDC Energy, Inc. (NASDAQ:PDCE) Q4 2022 Earnings Call Transcript

PDC Energy, Inc. (NASDAQ:PDCE) Q4 2022 Earnings Call Transcript February 23, 2023

Operator: Good day and thank you for standing by. Welcome to the PDC Energy Fourth Quarter 2022 Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. Please be advised that today’s conference is being recorded. I would now like to hand the conference over to your speaker today, Aaron Vandeford, Director of Investor Relations. Please go ahead.

Aaron Vandeford: Thank you, and good morning, everyone. On today’s call, we’ll have President and CEO, Bart Brookman; Executive Vice President, Lance Lauck; Chief Financial Officer, Scott Meyers; and Senior Vice President of Operations, Dave Lillo. Yesterday afternoon, we issued our press release and posted a presentation that accompanies our remarks today. We also filed our Form 10-K. The press release and presentation are available on the Investor Relations page of our website at www.pdce.com. On today’s call, we will reference both forward-looking statements and non-U.S. GAAP financial measures. The appropriate disclosures and reconciliations, including a discussion of factors that could cause the actual results to differ materially from forward-looking statements, can be found on Slide 2 in the appendix of that presentation. With that, I’ll turn the call over to our CEO, Bart Brookman.

Bart Brookman: Thanks, Aaron, and good morning, everyone. Let me open by saying over PDC’s entire 50-year history, 2022 stands as the most successful year by almost every measure, a record free cash flow level of $1.4 billion, $1 billion of which was returned to our shareholders in the form of share repurchases, our fixed dividends and a $0.65 per share special dividend this past December, production for the company, a record 85 million BOE. In May, we closed the highly accretive Great Western acquisition, solidifying our already exceptional core Wattenberg position in driving solid production and reserve growth. Reserves year-end 2022, a 440% reserve replacement for the company as we grew reserves to 1.1 billion barrels of oil equivalent and drill permits.

I want to extend the most sincere thank you to our regulatory group, permit specialists, land team, operations and their compliance groups. In 2022, we cracked the code on obtaining permits in the state of Colorado. And through our approved OGDPs, CAP and Great Western acquisition, we now have permits and DUCs in hand for our development program through 2028. Emissions for the company, last year we materially beat our 2022 emission reduction goals with over a 30% reduction in greenhouse gas emissions and over 50% reduction in methane intensity, outstanding results. Based on this achievement, expect us to roll out even more aggressive emission goals in the near future. The recently approved CAP demonstrates the company’s focus on long-term development, aligned with our ESG goals, these emission reduction goals and quality development plans.

A reminder, within this CAP, we have 33,000 net acres, 450 wells, 22 surface locations and a permit life of 10 years. Technically, we are implementing significant best business practices, including deploying more 2 to 3 mile laterals, pursuing 100% electrification and state-of-the-art facility designs. Within the CAP, the company will reduce greenhouse gas emissions by 72% from our 2020 design, resulting in some of the lowest emission production in the world. And the most compelling aspect of the CAP is, while achieving these extremely low emission levels, the drilling projects will be some of the most resilient and economic projects in the country. And Lance will provide more color on this in a moment. Building on these 2022 successes, I’d now like to turn our attention to the company’s plans for this year.

We anticipate 2023 will be another success story, production of 95 million BOE or 260,000 BOE per day. Projects in both basins are well mapped and highly economic. Free cash flow is anticipated to be $825 million, that’s at $75 oil and $3 natural gas, on a capital spend of approximately $1.4 billion. We will modestly reduce debt levels for the company and anticipate year-end leverage ratio of 0.5. Our commitment to returning 60% of the free cash flow, post fixed dividend, remains strong. And our recent announcement on increasing our fixed dividend to $0.40 per share and expanding our buyback authorization by $750 million, both demonstrate the company’s commitment to shareholder returns. And last from my comments today, a sincere congratulations to our EHS and operating teams in both basins.

Texas and Colorado operations are approximately five years, with no lost time injuries, a record for the company and a signature of PDC’s commitment to safety, a job well done. Now I’ll turn the call over to Lance Lauck for an update on the company’s reserves and inventory.

Lance Lauck: Thanks, Bart. Slide 7 highlights our 2022 year-end proved reserves, which increased to approximately 1.1 billion barrels of oil equivalent. This increase now represents 35% compared to our year-end 2021 proved reserves and was driven by our Great Western acquisition and by our annual reserve additions and revisions. This is a very sizable reserve base and one that can deliver material and sustainable value creation in the future. Overall, we generated an exceptional proved reserve replacement of 440% in 2022. Equally important, we generated approximately 220% proved reserve replacement through the drill bit, which demonstrates the high quality of our Tier 1 asset base. At the SEC flat price deck of approximately $93 per barrel at $6 gas, our 2022 year end proved reserves generated a pre-tax PV-10 value of approximately $19 billion.

I would also like to highlight that we have a very resilient reserve base, assuming a flat $50 oil case, PDC reserve volumes only declined by approximately 2% from the SEC price case. This, again, is another measure of the highly economic nature of our Tier 1 asset base. Moving now to Slide 8. I want to take a moment and provide some additional detail on our best-in-class Tier 1 Wattenberg inventory. With the integration of the SRC assets, and now Great Western assets, we have meaningfully consolidated our position in the core of the play. We have historically provided inventory details by geographic area. But in order to more clearly describe our Tier 1 economics, we’re providing our drill well economics by their subsurface characteristics.

This requires a breakout of our inventory by the respective reservoir phase windows. At year-end, we have identified more than 2,100 core economic locations, inclusive of 200 DUCs in the Wattenberg field. As shown on this slide, our locations encompass four distinct reservoir phase windows, including two black oil windows, a light oil window and a retrograde gas window. This slide highlights that four of our five geographic areas have more than one reservoir phase window. For example, the Prairie area to the North has a black oil window as well as a light oil window, while our Summit, Plains and Kersey areas have three distinct phase windows. Our Guanella CAP acreage is primarily located in the light oil and retrograde gas windows. On the next slide, I’ll highlight some of the differences in EURs and economics in each of the phase windows across our core Wattenberg position.

So continuing on to Slide 9, we provide a detailed breakout of our approximately 2,100 locations by phase window. Before touching on the economics, I want to point out how derisked our inventory is from a permitting perspective. Overall, our year-end inventory of more than 2,100 locations are over 50% permitted, including the CAP, which gives us tremendous line of sight into multiple future years of highly economic development. Our highest permitted phase window is in the black oil range acreage area that we acquired from Great Western. While it’s 100% permitted, we want to note that our teams are working on various inventory-expanding opportunities that was not included in the original transaction. Our lease permitted acreage is in the black oil window in the North, but it’s also located in very rural areas with less permitting risk due to minimal building units and structures to plan our surface locations around.

We look forward to pursuing these permits in the future. The table on this slide highlights our per well reserves for a 2-mile laterals, which range from approximately 460,000 barrels with 48% oil in the Northern black oil window to 900,000 barrels equivalent with 20% oil in the retrograde gas window. While the EURs and oil mix percentages vary between each of these phase windows, the key takeaway is that all four phase windows deliver exceptional economics that range from 63% to 96% internal rates of return based on $75 oil and $3 gas. As we start development of our Guanella CAP assets in 2024, keep in mind that the CAP is located in the light oil and retrograde gas windows. These phase windows will have a higher liquid-rich gas component, but they also deliver some of our largest EURs and economics in the company’s inventory.

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These two windows generate an average rate of return on 2-mile lateral wells of nearly 100% and 85%, respectively, again, based on $75 oil and $3 gas. While the black oil North window represents a lower EUR of 460,000 barrels equivalent, it also has the highest oil cut at 48%, which still generates approximately 63% rate of returns at the same price deck. One final comment, all phase windows deliver strong oil volumes. Dave will cover more of this in his comments next, but I want to highlight that our oil volumes provide a strong base for economics, allowing for the gas and NGL contribution to enhance the returns. Before handing the call over to Dave, I want to summarize this section of our earnings call by sharing that PDC today is in the strongest position in its 50-year history.

We have tremendous assets, a great team, a strong financial position and confidence in the regulatory environment. I will now pass the call over to Dave to cover some of the operational highlights for the quarter.

Dave Lillo: Thanks, Lance. Jumping in on Slide 11, I want to review some of the operational highlights for the quarter. Total production for the quarter came in at 22.7 million Boe or approximately 247,000 Boe per day. Oil production for the quarter was 7.4 million barrels or approximately 80,000 barrels per day. Our production for the quarter was strong, especially when accounting for approximately 450 MBoe of production that was impacted from the December weather event that hit many in the industry. Our team did an amazing job of proactively managing the extreme cold weather in Colorado and Texas, minimizing production impacts and most importantly, keeping our employees and contractors safe. On the expense side of the equation, we invested approximately $345 million during the quarter, slightly above our implied fourth quarter guidance.

The slightly higher capital for the quarter was tied to increased non-OC activity; field-level efficiencies, both on the drilling and completion sides as our teams continue to set records; investments related to the CAP; and continued inflationary pressures. As we look into the 2023 plan in our budgeting, we are confident that we have captured each of those incremental investments appropriately. Scott will discuss the 2023 capital plans in more detail shortly. During the fourth quarter, our team maintained great focus on managing costs. And our LOE for the quarter was $3.04 per Boe and an all-in G&A expense totaled $1.60 per Boe. In the Wattenberg field, we invested approximately $200 million or $320 million to run three drilling rigs and two completion crews during the quarter.

We spud 53 wells and turned in line 50 wells. For the quarter, production in the Wattenberg averaged 219,000 Boe per day, of approximately 32% was oil. LOE for the basin came in at $2.52 per Boe, highlighting the low cost nature of our operations. In the Delaware, we invested approximately $30 million to maintain our one full-time drilling rig activity level focused on batch drilling operations. And we ran an average of 1.5 workover rigs to manage our base operations in the field. Production in the Delaware Basin averaged 28,000 Boe per day, of which approximately 39% was oil. LOE in the basin came in at $7.03 per Boe and is reflective of the continued workover activity during the quarter. Moving to Slide 12. I want to take a little more time to dive into the Wattenberg field operations and build upon some of the details Lance provided earlier in the call.

Our Wattenberg assets has industry-leading economics, and years of Tier 1 inventory development mapped out. Before highlighting the longer-term outlook in the base, I want to provide an update on our 36-well Gus and 28-well Cordon pads that are beginning to be turned on in line with our €“ in line in our new acquired range area. Completions activities on these two larger pads began in the fourth quarter, and we’re happy to report that the wells are coming online, meeting our pre-completion estimates. As we discussed on calls before, larger number of well pads, where acreage supports can reduce surface footprint and the impact to communities while driving efficiencies. Production from the 60-plus wells that are in process of coming online now will support our planned production growth into the second quarter.

Turning focus to our longer-term view in the basin. Our operations are supported by the consistency that the development in only a core Tier 1 asset can provide. Though we have historically, and will continue to turn wells in line across multiple phase windows, our oil curve remains very durable, yielding more than 22 barrels per lateral foot consistently over a representative five-year development plan. It is important to note, on the upper left-hand graph of the slide, our incremental recovery per lateral foot in 2025 and 2026 are tied to bringing online larger EUR wells in our CAP acreage. This incremental production, on top of a consistent oil component, further supports our strong economics. Finally, I want to highlight the depths of our economic inventory.

When considering the more-than-2,000 locations Lance highlighted, approximately 80% of these locations breakeven below $40 per barrel price without adjusting current well prices that would likely decrease in such a commodity environment. If there was one chart that shows the differentiation of our asset amongst peers, this is it. The deep inventory of projects that is incredibly resistant to changes in commodity prices support our long-term sustainable cash flow model. Finally, on Slide 13, I want to provide a brief update on the Delaware asset. During the quarter, we ran one to two workover rigs as part of our normal operation to support our base production. Additionally, we continued our batch drilling operations, utilizing one full-time drilling rig.

The batch drilling process is where we drill the surface of each of the wells on the pad before moving on to the intermediate sections and finally drilling each of the lateral sections. We anticipate this process may result in reducing drilling days and ultimately costs. The completion activity in the field resumed as planned in January of this year, and 2023 program is preliminary focused on continuing to develop of the Wolfcamp A and B zones. We will also evaluate opportunities in the Wolfcamp C and third Bone Springs intervals, where offset operators have had success. Success in these zones would be inventory accretive for our asset base and extend the life of years of our operations. At the end of the year, we have identified approximately 30 core economic locations, inclusive of 12 DUCs, in our inventory.

At current development pace, this represents more than three years of operations. We have also identified approximately 40 contingent additional location as targeting other known zones and locations with shorter laterals that will require improved pricing or additional evaluation before including them in our core inventory count. With that, I will turn the call over to Scott Meyers.

Scott Meyers: Thank you, Dave. Starting on Slide 15 and has already been €“ as has already been pointed out on the call, 2022 was an exceptional year operationally for PDC, and that has translated to approximately $1.4 billion in free cash flow, a record for the company. We received a pre-hedged realized price of approximately $50 per BOE, while operating expenses came in at approximately $8 per BOE. Our G&A came in as expected at approximately $1.60 per BOE, exclusive of the approximate $0.22 per BOE of cost associated with the Great Western acquisition. For the fourth quarter, we generated approximately $260 million of free cash flow. This is quite strong considering the decline in pricing in the fourth quarter and the planned increase in investment tied to adding the second DJ completion crew during the quarter.

Moving to Slide 16, I’d like to highlight a few details on our shareholder returns program. In the fourth quarter alone, we returned approximately $350 million through our share buyback, $0.35 base dividend and $0.65 special dividend. Ultimately, for the year, we returned $1 billion by buying back approximately 12% of our outstanding shares and exceeding our 60% post base dividend target. Our returns framework that we laid out earlier in 2022 is underpinned by the robust inventory of economic long-lived locations. It has allowed us the flexibility to execute on the Great Western acquisition, increase our base dividend while meaningfully reducing debt. On Slide 17, I want to quickly highlight the continued strength of our balance sheet. During 2022, we reduced our debt by approximately $530 million from the peak level after closing the Great Western transaction.

We exited the year with approximately $1.3 billion in long-term debt and a leverage ratio of 0.5 times. Our only near-term commitment is $200 million due in 2024, which can be easily paid by our forecasted free cash flow. On Slide 18, I want to continue the shareholder return topic and outline some of our 2023 return guidance. Using the midpoint of our anticipated 2023 capital investment guidance and the ability to generate more than $2 billion in adjusted cash flow from operations in a $75 per barrel and $3 gas world, we target being able to return more than $550 million to our shareholders in 2023. We remain committed to returning 60%-plus of our annual post-dividend free cash flow to shareholders via systematic share repurchases and a special dividend, if needed.

We continue to use share repurchases as the primary tool in our shareholders’ return program and anticipate being able to buyback another 7% to 10% of our shares in 2023. We are establishing a track record of increasing our base dividend, as we announced last week another increase to our quarterly dividend from $0.35 to $0.40 per share. This marks the third increase and second consecutive annual increase since implementing the dividend in 2021. Through Tuesday, we have invested approximately $83 million to repurchase 1.3 million shares this year. Combined with the increased dividend of $0.40 per share announced last week, we’ve already committed $118 million of returns during the first quarter. Finally, on Slide 19, I want to provide more detailed guidance for 2023 in the first half of the year.

We anticipate 2023’s capital investments of $1.35 billion to $1.5 billion, which generates between 255,000 to 265,000 BOE per day and 82,000 to 86,000 barrels per day of oil. In the Wattenberg field, the company expects to invest approximately 80% of the total capital in 2023. By running a three-rig program and one full-time plus a part time completion crew, we plan to spud and complete approximately 200 to 225 wells. The capital budget also includes non-ops; infrastructure for our recently approved CAP, land and ESG-related projects. In the Delaware, the company plans to invest approximately 20% of the total capital investments by running a one-rig program and a part-time completion group. We plan to spud and complete approximately 15 to 25 wells in 2023.

In the first quarter, the company expects to invest between $400 million and $475 million, with total production being in the range of 240,000 to 255,000 BOE per day and 78,000 to 84,000 barrels per day of oil production. In the second quarter, the company plans to invest between $325 million and $400 million and total production to be in the range of 257,000 to 272,000 BOE per day and 84,000 to 90,000 barrels per day of oil production. This is a material step up in production as we begin to receive the full benefit of the activity level in the first quarter that includes more than 60 Wattenberg TILs in 12 Delaware TILs, of which almost all occur in the second half of the first quarter. To summarize our call before we move to Q&A, our strong execution in 2022 helped us expand the foundation for PDC’s continued and long-term success in building value for our shareholders.

We exited the year with approximately 1.1 billion equivalent Tier 1 proved reserves, a rock-solid balance sheet and a durable inventory of projects capable of driving a sustainable free cash flow for the years to come. I will now turn over the call to the operator for Q&A.

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Q&A Session

Operator: Certainly. And our first question will come from Gabe Daoud of Cowen. Your line is open.

Gabe Daoud: Thank you. Hey everybody. Thanks for all the prepared remarks and for taking my question. Maybe just starting on the 2023 guide, Bart, could you maybe just give us a little bit more color on the cash tax guidance? I think it’s a little bit below what we had €“ at least, have been anticipating for you, guys, for this year. Is there anything specific that you can point to? And maybe how should we think about cash taxes on a go-forward basis?

Scott Meyers: Yes. Thank you for the question. Yes, a couple of things lined up for us for 2023. One of them was that we had better-than-expected GW from our Great Western acquisition cost allocations, which increased our deductibility in 2023. We also did not have any limitations after doing finalizing our analysis on Great Western NOLs. And then we also did not fall into the new IRA rules that we have been put out, but that will impact us in 2024. And finally, with the lower commodity prices, the NOLs that we have outstanding existing are just going to be more fully utilized in 2023. So in a long way, we had a bunch of stars that lined up for us that are really materially lowering our 2023 tax bill. However, we will not be able to take those advantages, and we will likely be in the IRA category in 2024.

So I can give a more firm update on 2024 cash taxes probably in about 90 days, as we’re still formalizing a few things as we’ve wrapped up 2023. But I would give you this guidance, the 15% to 18% of pretax free cash flow for 2024 is probably a good number, as I think we’ll fully exhausted what’s left in our cabinet to use in 2023. So hopefully, that helps. 2023 should be fairly minimal, but 2024 should be more material, probably what you were expecting for 2023.

Gabe Daoud: Awesome. Yes, Scott, that’s great color and super helpful. So maybe switching gears now maybe for Lance, just as we think about inventory. And I guess, particularly in the Permian, you guys noted maybe just three years left or so of core economic inventory, and maybe there’s some upside in that number through exploration. But just how should we think about the Permian moving forward? I think maybe at one point, there was discussions around potentially selling the asset. But how do we think about that in the portfolio? And then whether or not we should always assume PDC prefers a two-basin strategy? Thanks guys.

Lance Lauck: Yes. Thanks, Gabe. I appreciate that, and good question there. We really step back strategically and really think that having a presence in two basins is very important for future value creation for the company. And so when we look at our Delaware position, we’re very thankful for that position. And as you can see, we’re working on ways on our existing position to grow that inventory, not only the 60 core locations, but the additional 40 that we’re testing up with the Wolfcamp C and the third Bone Spring carb shale that we’re going to be testing this year. So Gabe, our teams continue to look for ways, what I would call a blocking and tackling where we can trade with other parties or putting a section together with another company and drill two milers versus one milers.