PDC Energy Inc (PDCE) Q4 2020 Earnings Call Transcript

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PDC Energy Inc (PDCE)
Q4 2020 Earnings Call
Feb 25, 2021, 11:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Good day, ladies and gentlemen, and welcome to the PDC Energy Fourth Quarter 2020 and Year-End Earnings Conference Call. [Operator Instructions]

I would now like to turn the conference over to your host, Kyle Sourk, Investor Relations. You may begin sir.

Kyle Sourk -- Senior Manager, Corporate Finance & Investor Relations

Thank you and good morning. On today's call we 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 a press release and posted a presentation that accompanies our remarks today. We also filed our 10-K this morning. The press release and presentation are available on the Investor Relations page of our website www.pdce.com.

On today's call, we will also reference forward-looking statements and non-US GAAP financial measures. The appropriate disclosures and reconciliations can be found in our presentation.

With that, I'll turn the call over to our CEO, Bart Brookman.

Barton R. Brookman -- President and Chief Executive Officer

Thank you, Kyle, and hello everyone. It's only appropriate I open today's call with a sincere thank you to all of the PDC employees. Your commitment, perseverance and execution of our business plan have helped PDC navigate some of the most uncertain times in the long history of our industry and position the company for continued success looking forward. And to our investors, our commitment to financial discipline and operational excellence remains as strong as ever, and I believe this will be clearly reflected in today's presentation.

Some key themes to be listening for. First, as a company, we are projecting significant sustainable free cash flow in top tier industry margins and yields. Second, assets which deliver exceptional returns. An ongoing catalyst to the free cash flow of the company and the financial strength of PDC. Third, the cost structure, both capital and operating. Top tier as we continue to drive efficiency gains and reap the benefits of the SRC merger. And last, our three-year outlook, continued strengthening of our balance sheet as we strive over time for a 1.0 leverage ratio. Depending on commodity prices, free cash flow is estimated to be between $1.3 billion and $2 billion for the three years. And a continued focus on returning value to our investors through our share repurchase program and today I am happy to announce, a planned dividend program expected to start mid-year 2021 with an anticipated 1% to 2% yield.

Now some highlights for 2020. Free cash flow for the year was approximately $400 million. The capital investment of $520 million. This is better than our internal expectations. Production for the year of 68.4 million barrels of oil equivalent, a 38% improvement from 2019, primarily due to the SRC transaction. We paid down debt more than $300 million since the merger closed in early 2020 and we remain focused on cost improvements with G&A trending quarter-by-quarter under $2 per BOE post merger and lifting costs of $2.36 per BOE for the year. This is a company record.

I will let the team cover the details of the 2021 budget, but let me reinforce our commitments to our shareholders. You should expect capital discipline around $500 million to $600 million spend levels and planned activity. Modest growth for the company under 10% as we generate abundant free cash flow and the industry leading margins and anticipated reinvestment rate under 60% of our available cash that is calculated with oil at $45 a barrel and our continued push to deliver a 1.0 or better leverage ratio and reduce our total debt to near $1 billion. As I noted earlier, we are excited to announce the first dividend in the history of the company, a direct reflection of our commitment to returning value to our shareholders.

Last, I want to address ESG. Let me begin by extending a sincere thank you to our operating teams for their outstanding safety performance in 2020. PDC's commitment to ESG starts at the top, from our Board of Directors through every level of the company. Some examples of our progress. We ramped up last year was a corporate flaring rate under 0.2% and our Delaware rate under 1.6%, while strong improvements for the company. We remain focused on greenhouse gas and methane emission reductions through a series of investments, operating practices and technological improvements. We also continue to build on our strong commitments to our communities in Charitable giving programs in a very real and meaningful way. And from a governance perspective, our recent refreshment at the Board level shows our commitment to strong, best governance practices in adding diversity.

With that I'm going to turn this call over to Lance to give you an update on the quality of PDC's inventory.

Lance A. Lauck -- Executive Vice President, Corporate Development and Strategy

Thanks, Bart. Before we provide our detailed '21 guidance and three-year outlook in a few moments, I'd like to first review our updated year-end inventory and the tremendous projects in both the Wattenberg and Delaware basins that drive our results. Beginning in the Wattenberg on Slide 8, I first want to call out for our total inventory including 200 DUCs at year-end is approximately 2000 locations. This compares to approximately 1,800 total pro forma locations at year-end 2019. When considering we spud 105 Wattenberg wells in 2020 our updated inventory count represents organic expansion by about 300 locations or more than 15% year-over-year. Throughout the course of 2020, we benefit from consistently lower line pressures across our position compared to the past several years. It's because of improved line pressure and utilization of several SRC best practices that we were able to increase our projected well spacing in certain areas of the field.

Our next step in benefiting from lower line pressure will be further testing and evaluating a variety of completion designs and choke management techniques, aimed at increasing the economics shown at the bottom of the slide. Finally, before reviewing the economics, I'd like to call your attention to the areas themselves [Phonetic]. While the names themselves have not changed as a result of the SRC merger, we've modified the geographic boundaries to more closely align with some of the major township range boundaries. As Dave will show in a moment, this has resulted in a slightly smaller Summit area compared to our prior boundaries and the slightly larger Plains and Prairie areas.

You can see that we provided a detailed update on our current DUCs, approved permits and unpermitted inventory in each of these three areas, actually four areas as well as our planned TIL activity for the next three years. A key takeaway here is that less than 40% of our planned TILs over the next three years is in our prolific Curzy area. The results as an organization, continue to demonstrate the high quality nature of our inventory located in the other three areas. This is very clearly shown in our per well economic projections on the right hand side of the table. I'll note that all of our returns are run at $45 per barrel WTI, $2.50 gas and $12 NGL realizations, prices well below the current strip.

As you can see the weighted average per well internal rate of return for our locations in our Curzy, Summit and Plains areas are incredibly strong between approximately 65% and 80%, while our PV-10 average north of $3.5 million per well. Additionally, our Prairie area offers very solid and repeatable returns. You'll notice this lower pressure area has smaller EURs than the other three areas, but this also has our highest oil percentage. Please keep in mind, we have not been active in the Prairie area for several years as we focused on blocking up our position and increasing our working interest through value-added acreage trades and small acquisitions. We're excited to bring our modified completion designs to our upcoming projects which could lead to improved economics in this area.

Before I leave this slide, I want to call out our Plains area economics. Although it represents the area with our highest natural gas percentage, it also delivers strong and consistent economics that are very competitive with Curzy and Summit.

Moving to Slide 9. We highlight the operational synergies we began realizing in 2020 through our merger with SRC Energy. As you recall, we model G&A synergies associated with the merger, but never quantify the potential operational synergies. Throughout the year, the combination of PDC and SRC best practices has led to significant improvements in our well performance cost structure, drilling and completion times. These operational synergies include the recent well performance from the SRC pad compared to our acquisition type curve. We are seeing the benefit from an improved midstream operating environment in the field. Our team is able to implement a more desirable choke management program directly improving our economics. We have also streamlined our facility design, which has contributed to less frequent line freezers.

From an LOE standpoint, the hand in glove fit of the PDC and SRC assets has allowed for route optimization, reduced contractor pumping and overhead over time needs all contributing to the basin level, LOE per BOE of approximately $2 in the back half of 2020. As Dave will show in a couple of slides, we expect a very competitive LOE cost structure in 2021. Finally, our team continues to improve its drilling and completion efficiencies. Again Dave will provide more color on this in a moment, but we are seeing improvements of approximately 15% for our average spud-to-spud drill times and more than 10% in the number of stages per day.

Moving to the Delaware Basin on Slide 10. We've again provided an overview of our year-end inventory as well as returns by area. Over the past several years, we've taken the appropriate steps to high grade, up space and pursue longer laterals within our Delaware inventory. This focus is driving competitive value and returns at reasonable commodity prices. As of year-end, we've identified approximately 135 future turn in lines with an average level length of about 9,000 feet. This equates to about five to seven years of future planned activity focused primarily in the Wolfcamp A and B zones. Our position also includes a number of SRL locations that we have not included in our inventory count. Our team is focused on a number of cost-effective ways to increase our inventory through acreage trades, joint venture opportunities and small acreage acquisitions. Additionally, if pricing were to hold where it is today as opposed to our modeled assumptions, we believe we could increase well density in certain DSUs further expanding our runway.

As you can see on the table at the bottom of Slide 10. Our inventory including DUCs is split relatively evenly between Block 4 and North Central areas. While these projects offer higher EURs and a greater oil cut than our Wattenberg locations, you can see that the IRRs are slightly lower and average nearly 40% while the PV-10 values are slightly higher at around $4 million per well on average. Because of the relative oil mix in these locations, there is a bit more sensitivity to current prices. If you run the same type curves at $55 oil, $3 gas, staying with $12 NGLs, it projects IRRs of approximately 55% to 60% overall compared to what is shown on the slide. Likewise, the PV-10s nearly doubled to about $8 million per well on average. All-in-all we're very pleased with the opportunity we have in our Delaware Basin position and the value contribution and diversification this asset brings to the overall portfolio.

So to summarize. The company has built a significant inventory of drilling locations, capable of delivering strong and repeatable economic returns for many future years. It's the combination of this capital efficient drilling portfolio along with our strong focus on cost and margins that enable the company to deliver material and sustain free cash flow year-after-year, both safely and responsibly. These accomplishments are a result of our incredible teams. I want to thank our teams for all their hard work, efforts and adaptability through unprecedented and uncertain times in 2020.

With that I will turn the call over to Dave Lillo to discuss the 2021 plan in more detail. Dave?

David Lillo -- Senior Vice President, Operations

Thanks, Lance. The strength of our projects is really seen through our 2021 budget, which is highlighted on Page 12. Similar to 2020, we began the year with a capital investment range of $500 million to $600 million. Approximately 60% of which we expect to spend in the first half of the year. As Bart mentioned, we anticipate generating significant free cash flow, north of $400 million assuming prices well below the current strip. While the current commodity price environment has the potential to lead to modest incremental costs in the back half of the year, we are 100% committed in demonstrating capital discipline and our current operating plan. We continue to treat production as an output of our model and are pleased to not only deliver annual growth in 2021, but strong fourth quarter over fourth quarter growth to position ourselves for continued success in 2022.

Total production is expected to average between 190,000 and 200,000 BOE per day, nearly 5% growth compared to 2020. From an oil standpoint, our 2021 range of 64,000 to 68,000 barrels per day is relatively flat compared to 2020. Finally, we provide some first quarter expectations on the right hand side of Slide 12. I'll add these projections include weather related downtimes we've experienced in the past week, primarily in the Delaware Basin. This is further evidence of our focus and top priority being consistent, quarterly free cash flow with production as our output.

Moving to Slide 13, we provide more details on our 2021 Wattenberg program. You can see our redefined area boundaries that Lance alluded to on the right hand side of this slide. For the year, we expect to invest $375 million to $450 million operating a full time drilling rig and a completion crew with intermittent use of a spudder rig. I'll note that we've also baked in a bit more on our non-ops expectations compared to 2020, due to current pricing, driving an uptick in activity in the basin. From a drilling and completion standpoint, our team continues to demonstrate its best-in-class. We continue to unlock efficiencies now averaging five days spud-to-spud for extended reach lateral while also pumping more than 20 completion stages per day. Our recent performance is as low as 3.5 days and north of 25 stages per day. All of this adds up to well costs of approximately $360 per lateral foot, a 10% decrease from 2020, but most importantly, our Wattenberg team just surpassed 1,000 days without a lost time safety incident. This is a tremendous accomplishment for our team and the entire organization.

Last, we continue to project incredible competitive lifting costs in the field of approximately $2.25 per BOE in 2021. This includes more than $5 million aimed to improving our environmental performance through facility retrofits and air pneumatic installation. We also plan to invest nearly $25 million in plugging and reclamation of approximately 350 wells. For reference, we have been decreasing our operated well count in the basin for each of the past few years and over the past three years, we've completed the P&A and reclamation of more than a 1,000 wells.

Moving to Slide 14, we outline our approach regarding future drilling permits in Wattenberg. While we deem this is an incredibly important initiative in 2021, I want to reemphasize what Lance touched on a few minutes ago. We currently have 200 DUCs and 300 permits in hand. This offers us tremendous flexibility and time as we continue working closely with the COGCC and mapping out our longer term development plan in the basin. Earlier this week, PDC filed an application for a stay relative to our perspective comprehensive area plan or CAP, which we have named Guanella. This is a formal signal of our intent to work through the CAP process with the COGCC Chairman, and he stated yesterday, in his confirmation hearing that he is excited to work through the application process with PDC. Our team is currently designing the CAP and we'd expect to include approximately 450 future wells with a shelf life between six and 10 years once approved.

While we can't predict the timing of approvals, we are extremely confident that our best management practices, working relationship with the state and our zip code are 100% Weld County will lead to continued permit flow. We also plan to apply for a single pad oil and gas development plan or OGDP early second quarter followed by multiple pad OGDP including more than 70 wells in the first half of the year. Each of these permits when approved are valid for three years. All-in our DUCs, approved permits and 2021 permit applications consist of more than a 1,000 wells, which upon approval will secure our expected turn in lines into 2027.

Next, moving over to the Delaware Basin. We expect to invest between $125 million and $150 million to operate a full time drilling rig for the year and a part-time completion crew, which we will turn in line between 15 and 20 wells, all of which are in our oilier Block 4. The timing of these turn in lines contribute to the second half weighted oil growth we expect to see. We're projecting our all-in drilling, completion and facility costs to come in less than $800 per foot, savings of approximately 5% compared to 2020. In terms of LOE, we're anticipating somewhere in the neighborhood of $4 per BOE for the year.

Lastly, I want to touch on our flaring intensity which is obviously a hot topic for all E&Ps. As Bart mentioned, our 2020 flaring intensity in Delaware was 1.6%, while essentially none of this is technically considered routine flaring by definition. It is still our goal to demonstrate year-over-year improvement in this area. Nearly half of the 1.6% was for safety purposes related to H2S. In 2021, we plan to install H2S equipment sooner in the production cycle on all our new wells and are hopeful this will contribute to meaningful reductions in our reporting flare volumes. The remaining flare volumes are related to upset conditions. We are committed to continue working closely with our third-party midstream providers to ensure ample capacity and timely well connects. We hope this will lead to year-over-year strides in this area as well. All-in, as Lance demonstrated, our Delaware projects generate solid returns and value and we're looking forward to another successful year.

Before I turn the call over, I want to thank all the operating teams for their tremendous work in 2020 between integrating SRC assets and people, driving down costs and handling curtailments and returning to production all in a safe manner. 2020 was a banner year.

With that I will turn the call over to Scott Meyers.

R. Scott Meyers -- Chief Financial Officer

Thanks, Dave. Before giving more detail on our three-year outlook, debt reduction and shareholder return targets in 2021, I feel it's important to look back and stress our track record of execution over the past couple of years. On Page 17, from top to bottom, you can see we've highlighted our free cash flow, G&A per BOE and LOE per BOE. We have clearly reached an inflection point with our ability to generate free cash flow. We've not only generated positive free cash flow in each of the two years -- past two years, but in five of the past six quarters. Further, our three-year outlook projects free cash flow in each of the next 12 quarters in a $45 world. Generating free cash flow on a consistent quarterly basis is one of the primary goals in putting together our annual budget, an incredibly important to having a lasting meaningful quarterly dividend in a volatile commodity price world. In terms of G&A we've improved our per BOE numbers by more than 40% since 2018. And that includes $30 million of SRC transaction and transition costs in 2020. Now that we've reached our run rate of just over $30 million of cash and non-cash G&A per quarter, expect our 2021 figures to improve an additional 25% compared to our all-in run rate of 2020. Finally, our 2020 LOE per BOE of $2.36 represents an improvement of more than 25% compared to 2018. Our entire team continues to impress and it's a combination of everything you've seen today LOE, G&A, high return drilling projects that allow us to stand above the rest in terms of free cash flow generation.

Next, the balance sheet. Throughout much of 2020, we are consistent and transparent about our goal to reach $1.5 billion in absolute debt before reinstating our share buyback program. Throughout the back half of 2020, we reduced our debt by more than $300 million and exited the year with a leverage ratio of 1.7 times. In January and February to-date, we've paid down an additional $150 million of debt. As you saw in our press release last night, we achieved the $1.5 billion target and have reinstated our buyback program.

I'll bring this up for one primary reason. Over the next couple of slides, you're going to see some incredibly strong multi-out -- multi-year outlook as well as our commitment for free cash flow allocation in 2021. We feel incredibly confident in our ability to meet or exceed these numbers. We've consistently demonstrated capital discipline in our operating program and financial discipline to our hedging program and commitment to debt reduction. As a result, we have some truly staggering numbers in a $45 world, which can be seen on Slide 19. First, capital discipline. We plan to invest between $500 million and $600 million in each of the next three years. You'll notice, our three year range has a floor of $1.6 billion instead of $1.5 billion. In all reality its extremely unlikely to be at the low end of our range for three consecutive years, especially given where current prices sit.

Dave has done a great job outlining our '21 capital program and this outlook and our plan is to run a very similar program in each 2022 and 2023. These results again in a $45 oil, $2.50 gas, $12 NGL world equates to a three-year cumulative free cash flow of $1.3 billion to $1.5 billion. Here's a couple of different ways to look at that projection. It's nearly equal to our entire debt balance, about half of our current market cap or about a third of our enterprise value. I'll let you do the math, but at current strip prices, you can add approximately another $500 million of cumulative free cash flow over the three-year period.

Now what are we going to do with all the cash? First, we're not done reducing debt. We expect to reduce debt -- net debt by at least $600 million over the next three years. In any reasonable price outlook this has us comfortably below 1 times leverage ratio. Next, our goal is to return more than $500 million to shareholders through stock buybacks in anticipated quarterly dividend payments. This does not include the additional $300 million of free cash flow to flex between the buckets or additional free cash flow based on the current strip. We are extremely confident in our ability to execute this plan and to deliver on these numbers, regardless of size, scale, oil mix or operating basin, this outlook is tough to match.

In terms of 2021, our final slide outlines our commitments for our free cash flow allocation. As you can see, debt reduction is still the primary focus as we plan to reduce our total debt by at least $200 million. We still have a small balance on our revolver and plan to settle our converts in cash later this year as we march toward our 1 times leverage ratio. Lower absolute debt only strengthens our shareholder return program. Should there be another correction, we are well positioned not only to buyback shares in an aggressive pace, but to sustain a competitive dividend. As Bart mentioned, our Board approved a dividend program to commence mid 2021 with a target yield of 1% to 2%. We're excited to be in this new era at PDC.

Last, differentiating free cash flow of approximately $100 million. Look for this not only to cover our working capital needs such as our P&A program, but to flex between further debt reduction and opportunistic shareholder returns. Today, we highlighted our assets, our operations, our financials and our long-term plan. Tying it all together is a track record of transparency, operational excellence and execution. But the key ingredient in all of this are the amazing people at PDC that make all of this possible. Thank you for all you do making PDC the best it can be every day. We are so excited for the next several years. We hope you are too.

With that, I'll turn it over to the operator for Q&A.

Questions and Answers:

Operator

[Operator Instructions] We have our first question coming from the line of Arun Jayaram with JPMorgan Chase. Your line is open.

Arun Jayaram -- JPMorgan Chase -- Analyst

Yes, good morning, Barton and team, really appreciate all the detail in this mini Analyst Day, a lot of great detail. My first question perhaps for you, Scott. At the bottom of -- on the left side of Slide 19, you highlighted some potential opportunities under the three-pronged approach in terms of what you could do with the free cash flow at $45. On our math, we get to call it $1.9 billion of free cash flow generation between '21 to '23. What are these numbers look like in terms of debt pay down, cash return and the additional discretionary free cash flow, if we're going to model something closer to the strip versus $45?

R. Scott Meyers -- Chief Financial Officer

Yes, that's great question. And right now, until we get our debt balance below $1 billion, our debt payment plan will be the largest wedge of our free cash flow. I would say that once we -- so this plan, what you could see in the current commodity price environment, instead of it being a three-year plan, we might be able to achieve these potentially in two years or a little bit more than two years. I think after we get to a $1 billion of debt, we'll continue to pay down debt but at a slower pace, because I still think having a mix of debt in a program where with the company is still good, we just want to get that balance under $1 billion. So I would say when we start reducing the speed of the debt pay-downs, obviously, we would be increasing our opportunity to return capital to the shareholder.

Arun Jayaram -- JPMorgan Chase -- Analyst

Great, that's helpful. And maybe one for you Lance. I wondered if you could maybe provide a little bit more meat behind the bone regarding the increase to inventory. We understand that maybe the reduced line pressures in the new completion design was helpful to increase the number of locations. And I guess one of the questions we've been getting from investors is, hey, generally thought that there is a wide delta between -- wider delta between the economics at Curzy versus Summit etc. And if you could just maybe talk about Plains? What is narrowing the relative economics there?

Lance A. Lauck -- Executive Vice President, Corporate Development and Strategy

Yes. So great question. So in general, our spacing in the Wattenberg ranges from 16 to 24 wells per section, really depend on what part of the field you are in. I'd say our sweet spots around 20 wells per section equivalent. So when you look at the increase of approximately 300 wells year-over-year, that's from tighter spacing within a few of our specific areas of the field. And these were areas that were originally tested by SRC and really if -- Arun if you look back on that Slide 9, you see that our performance there that pad itself the 12 pad is 12 wells total, but it's a 24 well equivalent test. And so what we're finding is there certain areas of the field that SRC has successfully tested and we are continuing with that additional tests and that's why we are taking, what we've learned so far and we're applying that to other areas of the field. So the basis of the inventory increases from some increased density in those key areas where we're seeing the performance. There is still more to go, but what we see so far, we really like very much.

If you then ask the question around sort of some of the differences and you look sort of in the Curzy area kind of comparing it to the rest of the areas, I think the thing that we're seeing more than anything is that, as Dave and his team have done a wonderful job getting our drilling and completion costs down to $3.6 million for two-mile lateral and then you take it in the Plains area, which is an area that's only 25% oil total, where gas prices are and where the tremendous CIG differentials have really closed in a lot. We've got a lot of netback coming from a gas prices along with the strengthening of the NGL prices. That's why we feel very comfortable in saying that we can deliver this approximately 65% rate of return in that area. And so the ability for us to continue with this and continue to improve these economics over time is really based upon foundationally the fact that we now have a much lower midstream line pressure, enables to do more and more of these tests over time.

Arun Jayaram -- JPMorgan Chase -- Analyst

Great, that's super -- go ahead.

Barton R. Brookman -- President and Chief Executive Officer

Arun this is Bart. Just a couple adds to Lance. If you look at Slide 8, in the Plains area and we couldn't be more pleased in the opportunity here and yes, to Lance's point it's gassier. But if you look at the EUR on the table and that's -- that's one of the big driver here in the deepest hottest gassier portion of the base and the reserves per well are tremendous. And this goes back into the mid 80s when he started in this space. And so we've always known that and it's just the mix of the commodities, but overall it's a reserve for well that drive the really quality returns.

Arun Jayaram -- JPMorgan Chase -- Analyst

Great, thanks a lot, gentlemen. Really appreciate it.

Operator

We have our next question coming from the line of Umang Choudhary with Goldman Sachs. Your line is open.

Umang Choudhary -- Goldman Sachs -- Analyst

Hi, good morning and thank you for taking my questions. Wanted to follow-up on the free cash flow priority, allocation priority, once you achieve the debt objectives of $1 billion. How do you plan to allocate the incremental free cash flow to shareholders and appreciate any thoughts you might have on variable dividend?

R. Scott Meyers -- Chief Financial Officer

Okay. Again, I would say that right now as we march debt is going to be the number one priority till we get to that $1 billion mark. But they're both shareholder returns, it's going to be meaningful. And so I want to make sure that you understand that it is -- this is a multifaceted approach that we think is important in differentiation. Right now, I would say that when we look at it -- if you look down the line, once you hit to that $1 billion and then debt becomes less of a focus, we would open up to other forms potentially of returning capital to shareholders. But right now the share buyback is going to be the largest tranche. And we still see that we believe our inventory is not appropriately valued because of the Colorado zip code risk. Although we have confidence that we are going to do and as David talked about the permits, we're working hand-in-hand with the state. We just don't see that it's still reflected in the stock price. So right now, we are excited about the base dividend starting this summer and we're really looking forward to being able to execute on a share buyback program. One after we finish that we can look down the line and maybe consider a variable. But right now, it's not in the cards for the foreseeable next couple of years.

Umang Choudhary -- Goldman Sachs -- Analyst

Great. And I guess that's a good segue to my next question on the permit process in Colorado. How do you expect the process to play out? And if you can highlight any key milestones as you apply for the OGDP and the comprehensive data plan? Thank you.

David Lillo -- Senior Vice President, Operations

Thanks for the question. So the philosophy we've kind of adapted in our planning and development group is preferred by the Oil & Gas Commission. And these are the larger development plans and they consist of an OGDP, which is a smaller scale, good for three years, that can be a single well pad and facility or all the way to multiple locations involving the state and local government, which they are pushing for to collaborate. And then we have the larger CAPs, the comprehensive area planned larger scale which you need a larger geographical area and continuous acreage block to apply for an application in these, both involving the state and local approval there too. We've identified early on. We're taking a three-prong approach, a smaller OGDP with eight wells, three-mile laterals. We have a larger one with 70 wells and then we have our CAP, which is going to incorporate about 450 wells. Large area, it's going to incorporate over 32,000 sections and we just made our first step in applying for that CAP process earlier this week. And the Oil & Gas Commission is ecstatic of us getting the first what we call a stay application in, and they're really excited to work with us. Hopefully that answers your question.

Umang Choudhary -- Goldman Sachs -- Analyst

It does. Thank you.

Operator

We have our next question coming from the line of Dun McIntosh with Johnson Rice. Your line is open.

Duncan McIntosh -- Johnson Rice -- Analyst

Good morning, Bart.

Barton R. Brookman -- President and Chief Executive Officer

Hey Dun.

Duncan McIntosh -- Johnson Rice -- Analyst

Maybe for David, just digging in a little more on the permitting front. So let's assume that you are successful in acquiring these CAPs in these early OGDPs. That gives you inventory through 2027 which is obviously a long way out there today. What's kind of the next step beyond that? I mean, do you plan to focus kind of solely on putting CAPs together from there. That seems to make the most sense as you can kind of lock-up the longest term there and take out the most -- walk into most inventory, but just curious how you think about that scene if these things are successful, you'll be pretty good to go for six years or so?

David Lillo -- Senior Vice President, Operations

So after those three initial permits to be in an OGDP and one be in the CAP, the teams kind of identified, we've had just preliminary, we're looking at 10 to 12 more CAP behind that, I'm sorry 10 to 12 OGDPs and four to five CAPs that we're just starting to look at and put those development plans together. The CAP profile really kind of simplifies the process, because you have one alternative location analysis and one impact analysis, environmental impact analysis. So that's really where we're pushing toward. It seems like the best way it simplifies the process. And like I said before, the Oil and Gas Commission is just a static that we continue to work with them almost weekly on going through our plans. So that's kind of our future philosophy.

Duncan McIntosh -- Johnson Rice -- Analyst

Okay, great, thanks. And then, Bart, maybe for you or Lance. On the NGL front, if you could just give some color on what you're seeing in that market. It looks like in the fourth quarter, there could have been some switching from rejection to recovery? What's going to drive that decision going forward? And just any kind of general commentary you're seeing relative to the strength in that market?

Lance A. Lauck -- Executive Vice President, Corporate Development and Strategy

Yes, Dun, it's Lance. We are seeing a definite strength in NGL prices actually much higher than the $12 that we have in our case. Currently, we were seeing that just to the supply and demand what we're seeing sort of all the storage for NGLs and use of the products and all, every month, Dun, we will do an assessment on our Delaware areas where we look at rejection versus recovery and determine what's the best netback for us there. And so that will factor into our budget throughout the year. And once you put all those numbers together, right now, we're sort of budget that we're going to be more in a rejection mode for C2 versus that of recovery and that's why we said currently at least what we've modeled within our budgeted process. That same process and analysis on the monthly basis is done by BCP for us in the Wattenberg Field and because we have the percent of proceeds contracts here, they make that determination for the best netback prices. And then because as a percent of proceeds we participate in that election.

Duncan McIntosh -- Johnson Rice -- Analyst

All right. I appreciate it. And thanks. Congrats on another strong quarter and really, really solid outlook.

David Lillo -- Senior Vice President, Operations

Thank you.

Barton R. Brookman -- President and Chief Executive Officer

Thanks, Dun.

Operator

We have our next question coming from the line of Brian Downey with Citigroup. Your line is open.

Brian Downey -- Citigroup -- Analyst

Hey, good morning. Thanks for taking the question. Hey, good morning. On the following up on the questions on the comprehensive area plan. Could you update us on base case timing there? I know it's hypothesizing at this point, the process is new for everyone, but if all goes as planned, when do you think you -- we might see those 450 wells with final permit approval in hand?

David Lillo -- Senior Vice President, Operations

That's a really good question. As we continue to work with the Oil & Gas Commission and the local governments on that, we don't have a really good feel, like I said, we started the first part of the process earlier this week. There is several other steps to applying to get all the permits in. We really don't have a good feel on how the Oil & Gas Commission is going to be turning that around for us. We're hoping sooner the better, but as I mentioned we have over 200 DUCs and 300 approved permits out there to buy us time. So, we're really not too worried about the timing at this point.

Barton R. Brookman -- President and Chief Executive Officer

Yes. And Brian, we actually were really encouraged that we had the first step kicked off, probably ahead of our expectations with the outline plan that was submitted to the Commission here this last week. Incredible effort by our teams to get all that data into them. And as Dave said, they were really pleased. So that first step probably was expedited sooner than we ever anticipated. It's very difficult to all the other steps to predict, because there's a lot of technical and land work to be done. So -- but if the first step is any indicator, it's moving along at a decent pace.

Brian Downey -- Citigroup -- Analyst

I appreciate that. And then Bart for you or Scott or Lance, you listed business development initiatives as the last side and within your flex capital bucket. So we received a few investor questions around that. Could you clarify if that's intended to represent what I'll call normal course land work or if you're contemplating more material size bolt-ons within that?

Lance A. Lauck -- Executive Vice President, Corporate Development and Strategy

That's a great question. Yes, it's just sort of the normal course type of land work. So we're mostly focused on sort of trades, that's always such a very efficient way, and that's win-win for both parties to make the longer laterals. And like we talked about in Delaware, we've got several one-milers there we're trying to block that to make two-mile or so. We're talking with parties there and then I think the other one is more along the lines sort of a joint venture, we're open to some types of structures where we might bring capital to another person's -- another company's acreage where we drill some wells there on their acreage. So that's most of what we're looking at. There may be a very, very small types acquisition that we might look at, but that's the focus of what we have. And I think it all summed up really when you look at the breadth of the overall company portfolio and how much inventory we have. We have a really long runway with what we have currently, with very, very strong economics.

David Lillo -- Senior Vice President, Operations

Brian, just to restate the priorities are the execution of our plan that we outlined and the free cash flow uses that Scott Meyers covered. So I just want to be clear on that.

Brian Downey -- Citigroup -- Analyst

Great. I appreciate the comments. Thanks, everyone.

Operator

We have our next question coming from the line of Neal Dingmann with Truist Securities. Your line is open.

Neal Dingmann -- Truist Securities -- Analyst

Good morning, guys. Could you talk just a little bit on activity on maybe cadence level for this year. I see the kind of the plan laid out, but I'm just trying to get a better handle kind of on second half and how that will translate into 2021?

Lance A. Lauck -- Executive Vice President, Corporate Development and Strategy

Yes. So when you're talking about cadence you're talking more production free cash flow, kind of numbers.

Neal Dingmann -- Truist Securities -- Analyst

That's correct.

David Lillo -- Senior Vice President, Operations

Yes, OK. So when you look at for a capital spend for the year, you can figure about 60% of its probably in the first half of the year. The third and fourth quarter should be relatively flat from a capital acquisition respective. The second quarter is definitely going to be our highest capital because that's when we'll have the Delaware completion crew running basically for the whole quarter. So that's kind of, when we look at capital. When I look at production, first quarters are low watermark. We're going to have some nice growth in the second and third quarter and fourth quarter will kind of be relatively flattish is the way we're modeling it now. Clearly when you have that completion crew running in the Delaware and starting to turn those lines on, it really gives your production a shot in the arm and that's what's going to start happening in the second quarter and continue through early parts of the third quarter.

Neal Dingmann -- Truist Securities -- Analyst

And then just one follow-up. You guys are, I guess, one of a few that's still kind of with the priories you're talking about, once you get leverage down, I guess, continue to talk more about sort of shareholder or common share repurchase than some others, others maybe have turned much more to certainly dividends, you have mentioned that in all. So I'm just wondering is it just a level of where your stock is now? And you still think that, obviously, given these levels, where is that, the return makes sense? Is that why that's still in that priority list. And I'm just wondering if the -- is there -- you probably can't tell a certain level, but I guess I'm just sort of curious why that's still in kind of that list versus some others that have sort of gone away from the share repurchase.

R. Scott Meyers -- Chief Financial Officer

Yes, I think you're right, we still look at our shares as undervalued. I mean you can look at the call -- half the call questions are usually on the Colorado permitting process. And so I think we have an opportunity here that while we are still not trading at the multiples that we think that would be a more reasonable level, we think our shares are undervalued. So look for us to continue to go down that path. And then over time, once we get to $1 billion of debt we might look at other approaches.

Neal Dingmann -- Truist Securities -- Analyst

Okay. And could I ask Scott, just would you all continue to keep hedging if leverage certainly is going to be dropping to very nice level, very soon. I'm just wondering with the hedge program continue about the same as it has even if that becomes the case?

R. Scott Meyers -- Chief Financial Officer

Yes, I think, yes, absolutely. We continue to layer in hedges, ultimately as the balance sheet strengthens you could see us maybe not have as many hedges as a percentage or more callers in the mix as well to give us some run room. So when you look at our '21 program, our '21 program is probably basically done. Our '22 program, we're getting close on the base layers and probably would look more callers in the future. And '23 when we start that program, we were just getting ready to start looking at some of that. So I think consistently small little hedges over time is still the best practice for us that's worked over the years.

Neal Dingmann -- Truist Securities -- Analyst

Makes sense. Thank you.

Operator

We have our next question coming from the line of Michael Scialla with Stifel. Your line is open.

Michael Scialla -- Stifel -- Analyst

Good morning, everybody. David, I know you said the COGCC is indicated they are very excited to work with you on these projects. I know you didn't just spring those projects on them. I'm sure you've been talking to them about this project for quite a while. I'm just wondering, can you give any color on what you see as maybe the biggest challenges to getting those approved. Are there areas say within that Guanella CAP or you've got more than 10 building units within 2,000 feet or any other things that the Commission might want to push back on?

David Lillo -- Senior Vice President, Operations

I think it's going to be a mixed bag of challenges. We haven't went through the whole process yet, so we're still learning. I think the Oil & Gas Commission is still learning at the same time. There is a couple of new forms. The alternative location analysis in the cumulative impacts analysis which you put together for the entire area, working with local government, using best management practices. I can't really comment on whether this is going to be our biggest challenge on these coming up so far. What I do know is we've worked very well with them. We meet almost weekly at an operator meeting, making sure that we have the proper forms in place. We want to make sure our first applications are very clean and precise, so that we don't have to go back and do them. So we're really working through that with the local governments. We've been working on the regular [Phonetic] process out there for locations and these are very similar, what they still want. So at this point, I can't give you a precise clarification on where the risks or what the biggest hurdle is, but I think it's going very well at this time. These rules have only been in place for a very short period of time.

Barton R. Brookman -- President and Chief Executive Officer

And Mike I think Dave's answer in my mind is the biggest risk. We've got a process. It's been defined and Dave and the team are working diligently with the state and we feel really good about it. But we literally week-to-week are going through and working with the Commission constructively. And kind of saying, hey, here's the next steps. Here is the next steps, here's the next steps. Our confidence level in the endgame is very high, and that's because almost all the components in the CAP, as far as the operational requirements are things that we have experienced with the Commission and that we have had as part of our operating practices in the past. So I think the biggest thing is we're in the middle of a new rule making, a new reg, biting off a big block of acreage and a large number of wells and the state's learning as we're learning. So hopefully, we provided a little clarity here.

Michael Scialla -- Stifel -- Analyst

Yes, that definitely helps. Lance, I wanted to follow-up on your -- you mentioned on the spacing, some areas going up to as dense as 24 wells per section. I was just wondering, is that more in the low-pressure areas? Or is that too much of a simplification to make that statement?

Lance A. Lauck -- Executive Vice President, Corporate Development and Strategy

Well, I think in general, we are looking at testing that type of spacing in different areas in general, just because the results of the success of that is very impactful to the inventory, if successful in the different areas of the field. I will say that as you look at the wells that are outperforming on Slide 9, they are actually -- were targeted for the Niobrara A, B, C and Codell. So you've got a real stack test there that is what we're putting together as a 24 well per section equivalent. So there's different areas of the field where different parts of the Niobrara are better developed. And in this particular area, it made sense for us to do test in all four of those benches, if you will.

Michael Scialla -- Stifel -- Analyst

Got it. Okay. And last one, I just wanted to ask about, Dave, you mentioned -- talked about capturing the operational efficiencies in the Delaware. But I guess, in my mind, that still kind of seems like a subscale asset there, given that you're not maintaining a completion crew all year. I'm just wondering with the improvements, Bart, in oil prices, if you have any interest in putting that up for sale? Or are there things you can do still where you can be competitive on capital efficiencies with your neighbors in that region?

Barton R. Brookman -- President and Chief Executive Officer

Yes. And Mike, I think we can be competitive. Some of the numbers that Dave laid out. So obviously, we look at all strategies with our assets and -- but I think the Delaware right now, the thing I would encourage investors to look at is the value we're adding. We've got a good plan. We've got five to seven years of inventory. We're focused on execution there. And to Lance's comments, we've got some really creative ideas on adding to that five to seven years through some joint ventures and trades and things. So that's the focus right now. And along with execution in both basins.

Michael Scialla -- Stifel -- Analyst

Very good. Thank you.

Operator

[Operator Instructions] We have our next question coming from the line of Noel Parks with Tuohy Brothers. Your line is open.

Noel Parks -- Tuohy Brothers -- Analyst

Good morning.

Barton R. Brookman -- President and Chief Executive Officer

Good morning.

Noel Parks -- Tuohy Brothers -- Analyst

Back on Slide 9. The top bullet, you talk about under the heading of best practices that you've done some work on choke management. And I was just curious, when was the last time you sort of revisit or modified the practices you're using for choke management?

David Lillo -- Senior Vice President, Operations

We're very fortunate with the Latham II facility coming on that our midstream provider has lowered our line pressure, OK. We've, over the years, had different choke management practices, based on line pressure, based on facility design. Recently, I think we're trying to be aggressive. We're taking some of the learnings from SRC's choke management and some of ours, and we learn from each other. But this is pretty much our consistent our choke management that we've been using for years here. So Lance, you got anything else on our choke management?

Lance A. Lauck -- Executive Vice President, Corporate Development and Strategy

Yes. I think, you said it very well, Dave. And I think with DCP's plant in service Latham II, and now it affords us the opportunity to continue to work on ways to test different choke management styles and stuff. But the main thing is the ability to open them up sooner brings more of the production forward, which improves the economics of the wells. And there's a lot of things that goes into that. That's got to have designed around the facility, etc. But that's something we'll continue to watch and we're happy to be able to do that now.

Barton R. Brookman -- President and Chief Executive Officer

Yes. Just one more comment on this question. I think one of the things that we're really pleased with both basins and the operating teams is the practice of trying new things. And whether it's choke management, completion design, proppant design, perforation schemes, you name it. We have a focus of innovation of improving efficiencies and trying to improve our reserves per lateral foot on our drilling and completion program. So you can always expect to see things that we hope we generate curve similar to the one on Slide 9. And there's a whole bunch of factors that go into that. But just to cap this question, we have the best line pressure environment right now that we've had in the last probably six, seven years. And that is a big benefit to our cost structure and the ability to produce our wells the way we would like to produce them.

David Lillo -- Senior Vice President, Operations

Yes. And one more comment on -- when you reduce the line pressure and you turn these multiple well pads on, this one in particular, which I think was 12 wells and some of the larger pads. Sometimes you can't optimize your choke management because you have hydraulic issues that are centralized in areas with the emission of more compression on our midstream provider, we're able to be a little more aggressive on our choke management so that the system can handle that. If that puts a little more clarity around it.

Noel Parks -- Tuohy Brothers -- Analyst

Thanks. It helps a lot. It's really interesting. And sort of a related question around just continuing to experiment with, in this case, and thinking about on the completion side. As I listen to different companies, talk about their plans across different basins during earnings season. I can't think of a time when I've heard so many different directions or the people have been going with frac intensity. And certainly, when times were soft when prices were low, I think everyone was especially motivated to see -- could they ease up on profit loading and maybe juice the returns a bit. And I was just curious about in both basins for you, where you stand on that is your sort of biased more toward trying to head toward larger fracs or trying to scale back and see if you can actually do as well or better with lower intensity completion?

Barton R. Brookman -- President and Chief Executive Officer

In Wattenberg, we've tried several different pounds per foot of sand. And in recent years, we've had so many fluctuations in line pressure, and there was so much noise about looking through the data on which was working on and which wasn't working. Finally to a steady state where we have our line pressure, it's stabilized, and we're starting to do some of these tests. We're testing lower proppant loadings, higher proppant loadings, we're using micro profits to new technology that replaces the 100 mesh. Over the years, we've been getting very good at our safety on our fracs using quick connects on our wellheads. We have sensors for sensing wireline in the wellhead. We've reduced NPT time. We've optimized our zipper number of wells. We've just done a bunch of things. But when you come to testing proppant loadings and those type of things, we have to have good data so that there's not a lot of noise around it. And we're finally to the point where we have consistent line pressure, and our teams are excited to try some of these new ideas that they've been trying to do in the past.

Noel Parks -- Tuohy Brothers -- Analyst

Sorry, it's conceivable that you -- six months from now or a year from now, you might have actually found new efficiencies just from, again, a more stable environment to test again?

Barton R. Brookman -- President and Chief Executive Officer

And why we're able to get over 20 stages per day is because some of these testing that we're doing is getting really efficient, knocking on that nonproductive time which is so critical to the operation here.

Noel Parks -- Tuohy Brothers -- Analyst

Great. Thanks a lot. Appreciate the answers.

Operator

There are no further questions at this time. I will now turn the call back over to CEO, Bart Brookman.

Barton R. Brookman -- President and Chief Executive Officer

Yes. Thank you, Selena. And thank you everyone for the time today. Little longer than normal, but we really appreciate the questions and just listening in what we think is a terrific story. And probably most important a terrific outlook for PDC. So again, thank you.

Operator

[Operator Closing Remarks]

Duration: 67 minutes

Call participants:

Kyle Sourk -- Senior Manager, Corporate Finance & Investor Relations

Barton R. Brookman -- President and Chief Executive Officer

Lance A. Lauck -- Executive Vice President, Corporate Development and Strategy

David Lillo -- Senior Vice President, Operations

R. Scott Meyers -- Chief Financial Officer

Arun Jayaram -- JPMorgan Chase -- Analyst

Umang Choudhary -- Goldman Sachs -- Analyst

Duncan McIntosh -- Johnson Rice -- Analyst

Brian Downey -- Citigroup -- Analyst

Neal Dingmann -- Truist Securities -- Analyst

Michael Scialla -- Stifel -- Analyst

Noel Parks -- Tuohy Brothers -- Analyst

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