Q4 2020 PDC Energy Inc Earnings Call
[music].
Good day, ladies and gentlemen, and welcome to the PDC energy fourth quarter 2020 and year end.
<unk> conference call.
At this time all participants are in a listen only mode.
Later, we will conduct a question and answer session and instructions will follow at that time.
If anyone should require assistance during the conference. Please press Star then zero on your Touchtone telephone as a reminder, this conference is being recorded.
I would now like to turn the conference over to your host Investor Relations you may begin Sir.
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 level.
Yesterday afternoon, we issued a press release and posted a presentation that accompanies our remarks today. We also filed our 10-K this morning.
This release and presentation are available on the Investor Relations page of our website Www Dot P. D C E Dot com.
On today's call. We will also reference forward looking statements and non U S 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.
Thank you Kyle.
Hello, everyone.
It's only appropriate I open today's call with a sincere. Thank you to all of the PDC employees.
Movement, perseverance and execution of our business plan.
PDC navigate some of the most on certain 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 todays presentation.
Some key themes to be listening for.
First as a company we are projecting significant sustainable free cash flow.
Top tier industry margins and yields.
Second.
Assets, which deliver exceptional returns.
Ongoing catalysts to the free cash flow of the company.
Financial strength of PDC.
Third the cost structure, both capital and operating top tiers, we continue to drive efficiency gains and reap the benefits of the Src merger.
And last.
Three year outlook continued strengthening of our balance sheet as we stride.
Over time.
One point on leverage ratio.
Depending on commodity prices free cash flow is estimated to be between $1 43, 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 one to two per se.
Now some highlights for 2020 free cash flow for the year of approximately $400 million capital investment of $520 million. This was better than our internal expectations production for the year of $68 4 million barrels of oil equivalent.
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 trend quarter by quarter under $2 per Boe post merger.
Lifting costs of $2 36 per Boe for the year.
This is a company record.
I will let the team covered the details of the 2021 budget.
But let me reinforce our commitments to our shareholders.
You should expect capital discipline around or $5 million to $600 million spend levels and planned activity.
Modest growth for the company under 10% as we generate abundant free cash flow and industry, leading margins and anticipated reinvestment rate on.
60% of our available cash that is calculated with oil at $45 a barrel.
And our continued push to deliver a one point 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 commenced ptc'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 wrapped up last year was a corporate flaring right under.
2% and our Delaware rate under one 6% while strong improvements for the company.
We remained focus on greenhouse gas methane emission reductions through a series of investments operating practices and technological improvements. We're also going to continue to build on our strong commitments to our communities Inc.
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 and adding diversity.
With that I'm going to turn this call over to Lance to give you an update on the quality of PDC inventory.
Thanks, Bart before we provide our detailed 'twenty one guidance on three year outlook in a few moments I would like to first review our updated you on inventory and a tremendous projects in both the Wattenberg and Delaware basins that drive our results.
Beginning in the Wattenberg on slide eight our first one to call out for our total inventory, including 200 docs at year end.
As approximately 2000 locations. This compares to approximately 1800 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, where 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.
Is it 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 on.
Our next step and 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. 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.
As Dave will show in a moment. This has resulted in a slightly smaller summit area compared to our prior boundaries and a slightly larger planes and priority areas.
You can see that we provided a detailed update on our current ducks approved permits and unpermitted inventory in each of these three areas actually four areas as well as our plant T. I L activity for the next three years.
A key takeaway here is that less than 40% of our plant T. ILS over the next three years is in our prolific kersey area. Yet. The results is the organization continued 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 on a run at 45 per barrel of <unk>, $2, 50 gas and $12 NGL realizations price as well below the current strip.
As you can see the weighted average per well internal rate of return per locations and our kersey summit and plains areas are incredibly strong between approximately 65% and 80%, while our PV tens 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 <unk> than the other three areas. But is 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 to 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 other plains area economics, although it represents the area with a highest natural gas percentage. It also deliver strong and consistent economics that are very competitive with currency and summit.
Moving to slide nine we highlight the operational synergies we began realizing in 2020 through our merger with Src energy.
As you recall, we modeled G&A synergies associated with the merger, but never quantified 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 Src pad compared to our acquisition type curve.
We are seeing the benefit from an improved midstream operating environment in the field.
Our team was able to implement a more desirable choke management program directly improving their economics. We've also streamlined our facilities on which has contributed to less frequent line freezes.
From another standpoint, the hand in glove fit of the PDC and Src assets has allowed for route optimization reduced contractor pumping and overhead.
Overtime needs all contributing the basin level LOE per Boe of approximately $2 in the back half of 2020.
As Dave will show on a couple of slides, we expect a very competitive low cost structure in 2021.
Finally, our team continues to improve its drilling and completion efficiencies.
Dave will provide more color on this in a moment, but we are seeing improvements of approximately 15% for on average spud to spud drill times and more than 10% and 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 turned in lines with an average lateral length of about 9000 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 S. R. L 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 to 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 D. S shoes further expanding our runway.
As you can see on the table at the bottom of slide 10, our inventory, including DOCSIS split relatively evenly between on block four and north central areas.
While these projects offer higher eur's and a greater oil cut that our wattenberg locations you can see that the <unk> 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 ran the same type curves at $55 oil $3 gas staying with $12 Ngls it projects irr's of approximately 55% to 60% overall compared to other shown on the slide.
Likewise, the PV tens nearly doubled to about $8 million per well on average on.
All in all were.
Very pleased with the opportunity we have on our Delaware basin position and the value contribution and diversification. This asset brings 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 costs and margins that enable the company to deliver.
Material and sustained 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'll turn the call over to David <unk> to discuss the 'twenty and 'twenty one plan in more detail Dave.
Thanks Lance.
The strength of our projects is really seeing through our 2021 budget, which is highlighted on page 12 Sim.
Similar to 2020, we begin 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 and 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 <unk>.
Growth to position ourselves for continued success in 2022.
Total production is expected to average between 190000 and 200000 Boe per day, nearly 5% growth compared to 2020.
From an oil standpoint, our 2021 range of 64 to 68000 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 downtime.
We have experienced in the past week, primarily in the Delaware Basin.
As 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.
Side of the 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 three and a half days and north of 25 stages per day.
All 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 1000 days without a loss 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 on 25 cents per Boe in 2021.
This includes more than 5 million aim to improving our environmental performance through facility retrofits and Aaron nomadic installation.
We also plan to invest nearly $25 million and 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 PNA and reclamation of more than 1000 wells.
Moving to slide 14, we outlined 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 docs and 300 permits in.
Hand.
This offers us tremendous flexibility in time as we continue working closely with the C O GCC 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 granola.
This is a formal signal of our intent to work through the cap process with the Seo GCC chairman.
And he stated yesterday and 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.
But our best management practices working relationship with the state and ZIP code of 100% Weld County will lead to continued permit flow.
We also plan to apply for a single pad oil and gas development plan are Oh GDP.
Early second quarter, followed by a multiple.
Pad, Oh, GDP, 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 Ducks.
Permits in 2021 permit applications consist of more than 1000 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 on a $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 oily or block four.
The timing of these turned 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 low 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.
Mark mentioned, our 2020 flaring intensity and Delaware was one 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 one six was for safety purposes related to reach to us.
In 2021, we plan to install <unk> 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 the remaining player volume so 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 world in this area as well.
All in it's Lance demonstrated our Delaware projects generate solid returns and value.
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.
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.
<unk> per Boe.
And LOE per Boe.
We have clearly reached an inflection point with our ability to generate free cash flow, we have 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 and putting together our annual budget.
And incredibly important to having a lasting meaningful.
Quarterly dividend and 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 transaction trends.
Transition costs in 2020.
Now that we've reached our run rate of just over $30 million of cash and noncash 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.
It represents an improvement of more than 25% compared to 2018.
Our entire team continues to impress and it's a combination of everything <unk> seen today low G&A.
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 one 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 one seven times and.
In January and February to date, we paid down an additional $150 million of debt as you saw on 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 youre going to see some incredibly strong multi out multiyear 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, and our operating program and financial discipline to our hedging program and commitment to debt reduction.
As a result, we have some truly staggering numbers and a $45 world, which can be seen on slide 19.
First capital discipline, we plan to invest between five and $600 million in each of the next three years, you'll notice our three year range has a floor of one 6 billion instead of one five.
In all reality, it's extremely unlikely to be at the low end of our range for three consecutive years, especially given where current prices set.
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, and a $45 oil $2 50 gas $12 NGL world equates to a three year cumulative free cash flow of one three 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 do we need 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 and any reasonable price outlook. This has us comfortably below a one times leverage ratio.
Next our goal is to return more than $500 million to shareholders through stock buybacks and anticipated quarterly dividend payments.
This does not include the additional $300 million of free cash flow to flex between the buckets, where additional free cash flow based on the current strength.
We are extremely confident in our ability to execute this plan and to deliver on these numbers rigs.
Regardless of size scale oil mix, our operating base in 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 towards our onetime leverage ratio.
Lower absolute debt only strengthens our shareholder return program should there be another correction, we are well positioned not only to buy back shares on 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 begin this new era at PDC.
Last.
Differentiation free cash flow of approximately $100 million looked for this not only to cover our working capital needs such as our P&A program, but the flex between further debt reduction and opportunistic shareholder returns.
Today, we highlighted our assets our operations, our financials and our long term plan.
It altogether is a track record of transparency operational excellence and execution.
But the key ingredient and 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.
Sure.
Sure.
Thank you at this time I would like to remind everyone in order to ask a question. Please press Star then the number one on your telephone keypad again that is star then the number one on your telephone keypad, we'll pause for just a moment to compile the Q&A roster.
Yes.
We have our first question coming from the line of Arun <unk> with Jpmorgan Chase Your line is open.
Yeah. Good morning, Barton team really appreciate all the detail and this mini analyst day, a lot of great detail.
My first question, perhaps for you Scott.
At the bottom of slide 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.
Free cash flow generation between 21% to 23.
What are these numbers will look like in terms of debt pay down.
Cash return.
Additional discretionary free cash flow if were going to model something closer to the strip versus <unk> 45.
Yes.
That's great question and right now until we get our debt balance below a 1 billion our debt payment plan will be the largest wedge of our free cash flow I would say that once week. So this plan what you could see in that current commodity price environment instead of it being a three year plan, we might be able with it.
<unk> these potentially in two years or a little bit more than two years I think after we get to $1 billion of debt will continue to pay down.
Debt, but at a slower pace, because I still think having a mix of debt and a program or what the company is still good. We just wanted to get that balance under $1 billion. So I would say when we start reducing the speed of the debt Paydowns obviously.
We would be increasing our opportunity to return capital to the shareholder.
That's helpful.
And maybe one for you Lance I was wondering 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 and in the new completion design was was a help.
Helpful to increase the number of locations and in and I guess, one other question that we've been getting from investors is hey.
Generally thought that there was.
A wide delta between our wider delta between.
The economics that kersey versus.
Summit.
Et cetera.
And if you could just maybe talk about planes.
What is narrowing the relative economics there.
So great question. So so in general our spacing in the Wattenberg ranges from 16 to 24 wells per section really depends on what part of the field you're in I.
I'd say, our sweet spots around 20 wells per section equivalent. So when you look at the increase of approximately 300 wells a year over year, that's from tighter spacing within a few of our specific areas.
Of the field and these are areas that were originally tested by Src and really if Arun. If you look back on that slide nine you see that outperformance there that pad itself. The <unk> pad is 12 wells total, but it's a 24 well per section equivalent test.
And so what we're finding is there are certain areas of the field that Src has successfully tested and we're continuing with that additional tests and Thats why we are taking what we've learned so far and we're applying it 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 didn't.
Asked the question around sort of some of the differences and you look sort of in.
The kersey area kind of comparing it to the rest of the areas I think the thing that we're seeing more than anything is debt 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 <unk> differentials have really closed in a lot. We've got a lot of net that coming from our gas prices along with the strength in under 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 you know.
The ability for us to continue with this and continue to improve these economics over time is really based upon foundation on the fact that we now have a much lower midstream line pressure and enable us to do more and more of these tests over time.
Great That's Super Oh go ahead.
Just a couple a couple of ads to Lance if you look at slide eight in the plains area and we couldnt be more pleased and the opportunity here and yes to lance's point its gas here, but if you look at the the EUR.
On that table.
One other big drivers you're on the Youre on the deepest hottest gas year portion of the base on the reserves per well are tremendous and this goes back. It just goes back into the mid eighties. 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 per well to drive the really quality returns.
Great. Thanks, a lot gentlemen, really appreciate it.
We have our next question coming from the line of Omar <unk> with Goldman Sachs. Your line is open.
Hi, good morning, and thank you for taking my questions.
Wanted to follow up on the free cash flow per IV.
But I think once you achieve that objective of 1 billion how.
How do you plan to allocate the incremental free cash flow.
On with shareholders.
On a beachhead any thoughts you might have on <unk>.
Yes.
Okay.
On the.
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 theyre, both shareholder returns, it's going to be meaningful.
And so I wanted to make sure that you understand that it is a multifaceted approach that we think is important and differentiation.
Right now I would say that when we look at it.
You look down the line once you hit that $1 billion.
And then that becomes less of a focus we would open up to other forms potentially of returning capital to the 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're 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 its still reflected in the stock price. So right now we will we're excited about the the base dividend starting this summer.
And we're really looking forward to being able to execute on a share buyback program. The one after we finish that we can look down the line and maybe consider a variable but right now it's.
It's not in the cards for the foreseeable next couple of years.
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 Florida would UBB.
The company is taking it up on that.
<unk>.
Thanks for the question so.
The philosophy, we've kind of adapted and are planning on the development group is.
Preferred by the oil and gas Commission and these are the larger development plans and they consist of an O GDP, which is the smaller scale. Good for three years that can be a single well pad and facility, where 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 blocks two to apply for an application on knees.
Involving the state and local approval there too we've identified early on we're taking a three pronged approach of smaller Oh GDP with a.
Eight wells three mile laterals, we have a larger volume of 70 wells and then we have our cap, which is going to incorporate about 450 wells.
Large area.
It's going to incorporate over 32000 sections and we just made our first.
Step in applying for that cap process earlier, this week and the oil and gas Commission.
Static of us getting the first.
What we call our stay application in and they're really excited to work with us.
Hopefully that answers your question.
Hey, guys. Thank you.
We have our next question coming from the line of Dun Mcintosh with Johnson Rice. Your line is open.
Good morning Barton.
Maybe for David just digging in a little more on the permitting front.
Let's assume that you are successful on acquiring these caps on these earlier.
That gives you inventory through 2027, which is obviously a long way out there today, what's what's kind of the next step beyond that I mean, do you plan to focus solely on putting caps together from there on out it seems to make the most sense that you can kind of lock up the longest term there.
And pick out the most are and you know walk into most inventory, but just curious how you're thinking about that scene. If these things are successful you you'll be pretty good to go for six years or so.
So after those three initial permits to be in an O GDP and one being on the cap.
The teams kind of identified we've had.
No.
Preliminary we're looking at 10 to 12 more cap sorry behind that I'm sorry, Tim.
10% to 12 O G D. PS four to five caps that were just starting to look at and put those development plans together.
On 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 towards it seems like the best way it simplifies the process.
Sure.
I said before the oil and gas Commission is just static that we continue to work with them almost weekly on going through our plans. So that's kind of our our future philosophy.
Okay, great. Thanks, and then maybe maybe for you Lance on the.
The NGL front, if you could just give some color on what youre seeing in that market you know it looks like in the fourth quarter. There could have been some 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.
Yes on this land. So we are seeing definite strength in sale price is actually.
Much higher than the $12 that we have on our case currently.
We are seeing that.
Due to supply and demand and what we're seeing sort of all the storage for Ngls on use of the products in all every month done we will do an assessment on.
On our Delaware areas, where we look at rejection versus recovery other than <unk>.
And what's the best Netback force, there and so that will factor into our budget throughout the year.
And once you put all those numbers together right now that we're sort of budgeting that we're going to be more in a rejection mode per seat to versus out of recovery and Thats, where we sit currently at least what we've modeled within our budgeted process.
That same process and analysis on a monthly basis is done by DCP for us in the Wattenberg field and because we have the percentage of proceeds contracts here they make that determination for the best net back prices and then because as a percentage of proceeds we participate in that election.
Alright, I appreciate it and thanks, congrats on another strong quarter in a really really solid outlook.
Thank you.
Thanks, Don.
We have our next question coming from the line of Brian Downey with Citigroup. Your line is open.
Hey, good morning, Thanks for taking the question Hey, good morning on the.
Following up on the questions on the other comprehensive area plan could you update us on base case timing there I know it's hypothesizing at this point, it's the process is new for everyone, but if all goes as planned when do you think you.
So we might see those 450 wells with with final permit approval in hand.
That's a really good question as we continue to work with the oil and 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 are several.
Other steps to applying too to get all the permits in.
We really don't have a good feel on how the oil and gas commission is going to be turning that around for us.
We're hoping sooner the better but as I as I mentioned, we have over 200.
Ducks and 300 approved permits out there to bias time, so we're really not too worried about the timing at this point.
And Brian we actually were really encouraged that we had the first step.
Kicked off.
<unk> ahead of our expectations with the.
The outlined 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 with that first step probably was expedited sooner than we ever anticipated.
Very difficult to all the other steps to predict.
Because theres a lot of technical on land work to be done so.
But.
The first step is any indicators moving along at a decent pace.
Great I appreciate that and then Bart for you Scott or Lance you you listed business development initiatives as the last night on within your 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.
That's a great question, Yeah, it's just sort of a normal course type of landmark so were mostly focused on sort of trades.
Always such a very efficient way thats win win for both parties to make the longer laterals and like we've talked about in Delaware. We've got several one milers that we're trying to block up and make two mile or so we're talking with parties. There and then I think the other one that is more along the lines of sort of a joint venture. We are open to some types of structures, where we might bring.
Capital to another person's and other companies' 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 on 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.
And Brian just to restate.
<unk> are the execution of our plan that we outlined.
The free cash flow uses that Scott Meyers covered so I just wanted just wouldn't be clear on that.
Great I appreciate the comments thanks, everyone.
We have our next question coming from the line of Neal Dingmann with true as Securities. Your line is open.
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 it kind of on second half and how that will translate into 2021.
Yes, so when youre talking about cadence you talk to you more.
Production free cash flow kind of numbers.
Yeah, Okay. So when you look at it for a capital spend for the year.
You can figure about 60% of its probably in the first half net here.
The third and fourth quarter should be relatively flat from a Catholic acquisition perspective.
Second quarter is definitely going to be our highest capital because thats. When we will 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, our low watermark, we're going to have some nice growth in the second and third quarter and fourth quarter will be relatively flattish is the way. We're modeling now clearly when you have that completion crew running in the Delaware and starting to turn those lines on.
It really gives you a production on 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.
And then just one follow up you guys are I guess, one of few that still kind of where the priorities you're talking about once you get leverage down.
I guess continue to talk more about sort of.
Shareholder repurchase common share repurchase than some others, others, maybe have turned much more debt certainly dividends you have mentioned that no. So I'm. Just wondering is it just a level of where your stock is now and you still think obviously given these levels where it's at the return makes sense is that why.
That's still on that priority list I'm, just wondering if debt is.
I know.
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.
I think you are right, we still look at our shares as undervalued I mean, you can look at the call. It half the call questions are usually on the on the Colorado permitting process and so I think we have an opportunity here that debt. While we are still not trading at multiples that we think that would be more reasonable lever. 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.
Okay and can I ask Scott just would you all continue to keep hedging.
Leverage certainly is going to be dropped into 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.
Yes, I think.
Yes, absolutely we continue to layer in hedges ultimately as the balance sheet strength and 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 run room.
So when you look at our 21 program on <unk> 21 programs, probably basically done R. 22 program, we're getting close on the base layers and probably would look more colors on the future and 23, when we start that program.
We're just getting ready to start looking at some of that so I think consistently small little wedges over time is still the best practice for us Thats worked over the years.
Makes sense. Thank you.
Yeah.
We have our next question coming from the line of Michael CLO with Stifel. Your line is open.
Hey, good morning, everybody.
David I know you said the C. O GCC has indicated they're very excited to work with you on these these.
<unk>.
I know you didn't just spring those projects on them I'm sure you've been talking to them about those projects 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 see within that Gonnella cap, where you've got more than 10 building units within 2000 and.
<unk> or any other.
Things that the commission might want to push back on.
I think it's going to be a mixed bag of challenges. We have went through the whole process. Yet. So we're still learning I think the oil and gas Commission still learning at the same time.
There's a couple of new forms the alternative location analysis and the accumulative impacts analysis, which you put together for the entire area.
Working with local government use and best management practices.
You know I can't really comment on what is going to be our biggest challenge on knees.
Coming up so far what I do know is we've worked very well with them. We meet almost weekly is on operator meeting, making sure that we have the proper forms in place we want to make sure. Our first applications, a very clean and precise so that we don't have to go back and do them.
We're really working through that with the local governments, we've been working on the logo a process out there for for locations in and these are very similar what they still want so.
At this point I can't give you a precise.
Clarification on what are the risks or what's the biggest hurdle is but I think it is going very well at this time.
These rules have only been in place for a very short period of time, So hey, Mike.
I think Dave's answer in my mind is the biggest risk.
We've got a process that's being 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 or going through and working with the commission constructively.
And kind of saying Hey, here's the next steps here are the next steps here over the next steps our confidence level on the end game is very high and that's because almost all of 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.
I think the biggest thing is we're in the middle of a new rulemaking on new Reg.
Biting off a big big block of acreage and a large number of wells in the state's learning as we're learning so.
Hopefully we provided clarity here.
Yes that definitely helps.
Lance I wanted to follow up on your you mentioned on the spacing some areas going up too.
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 it.
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 the.
The wells that are outperforming on slide nine.
They are actually were targeted for the Niobrara, a b C and codell so you've got.
A real stacked test there.
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 tests and all four of those benches, if you will.
Got it Okay and last one I just wanted to ask about Dave.
Dave You mentioned, Doug talked about cash on the operational efficiencies in the Delaware.
I guess in my mind, that's still kind of seems like a subscale assets there given that.
You are not maintained on a completion crew all year I'm just wondering.
With the improvements Bart in oil prices.
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.
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.
We're focused on execution there.
<unk> comments, we've got some really creative ideas on that.
Adding to that five to seven years through some joint ventures, and trades and things. So that's.
Thats the focus right now.
Along with execution in both basins.
Very good thank you.
Again in order to ask a question. It seems new press Star then the number one on your telephone keypad that Istar then day number one on your telephone keypad.
Our next question coming from the line of Noel Parks.
<unk> Your line is open.
Good morning.
Good morning.
Back on slide nine.
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 our or modified the practices you on.
Using petroleum choke management.
You know, we're very fortunate with the leatham two facility coming on that are that our midstream provider has lowered our line pressure K.
We've over the years had different choke management practices base.
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 are consistent our choke management that we've been using for years here.
So.
Lance you got anything else on our choke management.
I think as we have on it very well David I think.
With with Dcp's plant in service life them too and now 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.
We have designed around the facility et cetera, but that's something we'll continue to watch and we're happy to be able to do that now.
Just one more comment on this question.
I think one other things that we're really pleased with with both basins on the operating teams is.
The per.
Practice of trying new things.
And whether it's choke management completion design proppant design per.
<unk> schemes you name it.
We have.
On a focus of innovation.
Improving efficiencies and trying to improve our reserves per lateral foot on on our drilling and completion program. So.
You can always expect to see.
See things that we hope we generate curve similar to the one on slide nine.
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 than 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.
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 addition 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.
Thanks that helps a lot.
It's really interesting.
No.
It's sort of a related question on around just.
Continuing to experiment with in this case I'm thinking about on that.
On the completion side.
As I listen to different companies talk about their plans across different basins during earning season I can't think of a time when I've heard.
So many different.
Directions for that people have been going with Frac intensity.
<unk>.
Certainly.
When times are tough and prices were low I think everyone was especially motivated to see you know.
Could they could they ease up on on.
Profit loading and.
Maybe just the returns a bit and I was just curious about.
Both basins for you.
Where you stand on that is your is your sort of biased more towards 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.
In Wattenberg, we have tried several different.
Pounds per foot of sand.
And in recent years, we've had so many fluctuations on line pressure and there was so much noise about looking through the data on which was working on really on what wasn't working.
Finally to a steady state where we have our line pressure.
Stabilized and we're starting to do some of these tests, we're testing lower profit loadings higher proppant loadings were using micro profit some 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 sensing wireline and then in the wellhead, we've reduced MPT 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 theres not a lot of noise around it and we're finally to the point, where we have consistent line pressure on our teams are excited to try some of these new new ideas that they've been trying to do in the past.
Bob.
It's conceivable that <unk>.
You know six months from now a year from now you might've actually.
Found new efficiencies.
Get them on a more stable environment to test again.
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.
Wow, great. Thanks, a lot appreciate the dancers.
There are no further questions at this time I will now turn the call back over to CEO Bart Brookman.
Yes, Thank you zone.
And thank you everyone for the.
The time to day little longer than normal, but we really appreciate.
<unk> and just listening in on what we think is a terrific story.
Probably probably most important on a terrific outlook for PDC. So again, thank you.
This concludes today's conference call you may now disconnect.
Yeah.
[music].