PDC Energy Inc (PDCE) 2020 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the PDC Energy Second Quarter 2020 Earnings Conference Call. (Operator Instructions) As a reminder, this conference call is being recorded.

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

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; Chief Operating Officer, Scott Reasoner; and Senior Vice President of Operations, Dave Lillo.

Yesterday afternoon, we issued our press release and posted a presentation that accompanies our remarks today. We also filed our Form 10-Q. The press release and presentation are available on the Investor Relations page of our website www.pdce.com.

On today's call we will reference both forward-looking statements and non-US GAAP financial measures, the appropriate disclosures and reconciliations can be found on slide 2 in the appendix of that presentation.

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

Thank you. Kyle, and hello everyone. Today, I hope we can effectively communicate our exceptional quarterly results and an outlook, I believe, clearly differentiates PDC. Throughout the call, we will highlight a multi-year business plan capable of generating significant and sustainable free cash flow in this low-price world.

That is complemented by an enhanced midstream and operating environment in the DJ Basin and an improved Colorado political and regulatory backdrop. As a company, we have adapted and made the necessary and at times difficult changes, but we are positioned to endure as we look to the future.

As we finalize the integration of SRC Energy, our vision of improved scale and efficiencies is evident in our operating and financial results. Some themes to note, as we go through the call today: absolute free cash flow, free cash yield and free cash flow margin for the quarter and within our outlook; improved capital efficiencies and improved per well costs; the tremendous progress in the cost structure of the company, both LOE and G&A; strong production levels, a result of both the merger and dramatically improved line pressures on the DCP Midstream system; and last, our commitment to strengthen the balance sheet this year and as we go through 2021.

Let me hit some quarterly highlights. For the quarter free cash flow of approximately $60 million, that is on a capital spend of approximately $120 million. We exited the quarter with one rig running in Wattenberg, no rigs in Delaware and no completion crews for the company. Production for the quarter was 17.2 million barrels of oil equivalent or 190,000 BOE per day, a 39% improvement from the same quarter in 2019, this growth primarily due to the SRC merger.

From a financial standpoint, the leverage ratio at the end of the quarter stood at 1.8 and liquidity remained over $1 billion for the company. And last on the operating cost structure lifting costs of $2.08 per BOE and combined lifting costs in G&A for the company came in just over $4 per BOE. We will give a lot more detail on the capital program and the cost structure of the company in a moment.

Now more information on what I consider an extraordinary element. Let me start with an operational perspective and build to the balance sheet. Production for 2020 is anticipated to be approximately 67 million barrels of oil equivalent a day. That is the midpoint of our guidance range. Again strong production levels due to the SRC merger and improved line pressures. Capital spend in 2020 should be approximately $525 million, this is a reduction from our last update.

For next year, we anticipate flat to modest production growth on a capital spend level of $500 million to $600 million. Combined 2020 in 2021 free cash flow is expected to exceed $550 million. This calculates to a free cash flow margin of approximately 50% and an annualized free cash flow yield nearing 20%.

Expect the free cash flow over the next 18 months to be used primarily to strengthen our balance sheet with anticipated year-end 2020 leverage ratio under 2.0 with further improvement expected in 2021. Going forward from a cost perspective, we anticipate the company will be under $5 per barrel LOE, NGO, G&A combined. I really encourage you to take time to understand these metrics as I feel they truly illustrate PDC's superior performance and outlook.

Last, before I turn the call over to Scott Reasoner, I'd like to extend a sincere thank you to all of our teams, including the field operations. Every day they continue delivering these impressive results, doing it safely from both a COVID and operating perspective. They're driving down our cost structure, both operating and capital, where we continue to deliver value to our shareholders.

With that, I'll turn the call over to Scott Reasoner, this is his last Q call at PDC as he heads into retirement and we wish him the absolute best. I have to say the operational integrity of PDC is a direct result of Scott's ongoing focus, his leadership and accomplished skill sets and for that, we thank him. Scott, I'll now turn the call over to you.

Thank you, Bart. It's been a real privilege, as I struggle with my emotions here to be a part of a great team, I really appreciate the opportunity to grow and more so appreciate all of the PDC team putting up with me. Thank you all.

I now want to echo Bart's appreciation for the tremendous work our team put in this quarter. From top to bottom and in both the field and office, the second quarter offered an extremely unique set of circumstances and challenges. I'm extremely proud of the results we were able to deliver while, more importantly, doing so in an extremely safe and efficient way.

The second quarter makes 2 years in the Wattenberg and Delaware of zero PDC lost time injuries. As we turn the keys over -- of our operations over to Dave Lillo, we're extremely proud and rest assured knowing that our culture of safe and efficient operations will remain of utmost importance.

In terms of the quarter; Bart touched on a couple of the high-level numbers, but I'm going to provide a bit more detail in a few that you see here on slide 8. First, LOE for the quarter was extremely impressive at just over $2 per BOE. It's important to realize that we made multiple decisions, including delaying maintenance and adjustments to staffing that we deem necessary in the short term, but are unsustainable moving forward.

Given that we project full-year LOE of approximately $2.65 per BOE, you can see that we expect some of these costs to come back in the second half of the year, but are still pleased with the overall low-cost nature of our operations, which includes drilling, completion and facility well costs of approximately $400 per foot in the DJ and approximately $850 per foot in the Delaware.

From a production standpoint, it's important to remember that we entered the quarter operating 2 Wattenberg completion crews and continued at that pace for a period of time before exiting June with no crews, hence the relatively high level of turn-in-lines given our curtailment decisions.

Given the ratio of oil and gas pricing specifically in May, you can see that our curtailments in the quarter were a bit biased toward oil as we curtailed some approximately 15% of our oil production compared to only 10% of our total production. As it stands, nearly halfway into the quarter, we're now essentially un-curtailed. And that includes pulling up the turn-in-line of our Tinman pad in the Delaware, which was done in June.

Moving to slide 9, we outline the improvement we're seeing in the Wattenberg line pressures and highlight the positive benefit. This is having both on a per well basis and overall operating environment. As Bart mentioned, this has been a major headwind over the past several years and we're extremely excited to have line of sight on improved conditions for the foreseeable future.

The line graph on the bottom left of the slide, clearly shows the improvement in line pressures as the past 6 months have averaged approximately 230 PSI, a 25% improvement from the back half of 2019.

Obviously, there is a benefit from curtailments factored into the recent pressure data, but generally speaking field wide activity from all operators is projected to remain relatively low and we expect an incremental 225 million cubic feet a day of capacity with the Latham II plant later this year.

All in, we'd expect to see continued white space in the DCP System, which is really important in increasing our value per well, further improving our capital efficiency and maintaining consistent run times. Our team is excited to get back to testing new completion designs and well spacing initiatives in an effort to maximize both our value per well and total value field wide.

As you can see in the bar chart on the bottom right of the slide, we're already seeing an uplift in our oil productivity per well compared to prior more constrained years. There are factors such as area of the field and flow back technique that can play into these numbers, but the main takeaway is that we are once again provided the opportunity to maximize performance and returns, given the improved line pressures and processing capacity in the basin.

Moving to slide 10 but staying in Colorado, I want to reiterate the recent significant developments that Bart mentioned in his opening. 2 weeks ago Governor Polis published an op-ed, which he announced his intention to actively oppose any oil and gas related ballot initiatives in both 2020 and 2022.

While this doesn't guarantee the opposition won't attempt to gather signatures in 2 years, it is clearly the most public support the industry has had from the Governor's office in recent memory, and should go a long way in limiting the outside funding and support that is necessary to run an anti-industry campaign.

Additionally, you can see, we expect to have over 400 combined DUCs and approved permits, which equates to over 3 years of future turn-in-lines. We look forward to working closely with the COGCC and its new commissioners as Senate Bill 181 is implemented and the rule-making process continues forward. In fact, we had an additional 10 permits approved within the past 2 weeks that are not included in the numbers on the slide.

The takeaway here is that the recent news from the Governor's office, combined with our anticipated permit and DUC count, positions PDC to safely and effectively develop our position and deliver clean and affordable energy for years to come. With that, I'll turn the call over to Scott Meyers to review the quarterly financials and updated guidance.

Thanks, Scott. As we go through the numbers, just a quick reminder that we are presenting both GAAP and non-GAAP metrics as well as forward-looking statements. I encourage you to reference our appendix for our reconciliations.

Commodity price weakness obviously impacted our realized prices and sales for the quarter as they were down 63% and 49% compared to the second quarter last year. This outweighed the 39% increase in production between periods primarily associated with the SRC merger.

Similarly, we saw a decrease in our net cash from operating activities and adjusted cash flow of 60% and 12% compared to the second quarter of last year. With all that said, we exceeded our internal expectations for both G&A per BOE and free cash flow for the quarter as production was less impacted by curtailments than we previously expected.

Our all-in G&A of $35 million, or $2.05 per BOE, includes approximately $4 million of SRC integration expense related to the transition employee and, excluding these nonrecurring expenses, would have resulted in a G&A of $1.83 per BOE, which is an impressive 40% improvement from our run rate G&A in the second quarter of last year which excludes similar onetime expenses.

We had to make a number of very difficult decisions along the way including reductions in force, furloughs and salary reductions. However, achieving these G&A levels is extremely important to the success and long-term health of PDC. For the full year, excluding SRC transaction costs, we expect to deliver G&A of approximately $2.05 per BOE which implies a sub $2 run rate for the back half of the year.

Finally, we anticipate continued reductions in an absolute basis in 2021 compared to 2020 as our initial years outlook has G&A at $120 million to $125 million range compared to $135 million to $140 million this year.

From a free cash flow perspective, $60 million generated in the second quarter exceeded our guidance of cash flow neutrality due to June's production, NYMEX pricing, oil deducts and NGL realizations all beating our expectations. As Bart mentioned, we've now generated free cash flow in 3 of the past 4 quarters and we continue to cover -- and as I'll continue to cover in a minute, project free cash flow for the next 6 quarters including in the neighborhood of $300 million in the back half of this year.

Moving to Slide 13, there are only a couple of things I want to highlight around our liquidity and hedge fund. First, you can see our revolver balance at the end of June was approximately $650 million, up slightly from the first quarter balance of $620 million. This is simply due to the slight lag in accounts receivables and other working capital changes that somewhat magnified in periods of reduced activity.

Obviously with $60 million of free cash flow in the second quarter and over $150 million projected in the 3rd quarter, it's only a matter of time for the balance to begin decreasing as evident by the fact that we were sub-600 by the end of July.

Next our hedges, you will see that 70% of our oil production for the second half of the year and approximately 45% of our anticipated 2021 oil production are protected at $58 and $45 per barrel. At this point, we consider our 2021 hedges to be a pretty solid base layer of protection and we will likely take a somewhat opportunistic approach to future hedges likely in the form of costless collars that allow a little bit more room to run to the upside yet still protect us from the down.

Moving to slide 14, much of this has already been covered. We had a substantial increase to our free cash flow guidance, decreased our CapEx guidance and increased both our oil production and total production guidance. We provided a good bit of detail around our expectations on a quarterly basis including flat production in the third quarter compared to the second quarter and fourth quarter, averaging 170,000 BOE per day and 60,000 barrels.

The fourth quarter rate represents a decrease of approximately 10% compared to the second and third quarter activity. As we begin feeling the impacts of taking 3 to 4 months off of our completions.

In terms of pricing, we once again tried to offer as much transparency as possible in terms of our expectations moving forward. The table we presented back in May proved to be a bit conservative and we will obviously take that same outcome this time around. But as was the case then, these are the assumptions that tie to our anticipated free cash flow estimate of more than $300 million for the --.

A couple of quick items to point out. First, you can see that there is a bit of softness in our oil realizations for the back half of the year compared to our historical averages. However, we continue to expect to see improvement and continuing this into 2021.

Second, you can see our TGP expense moving up from this point forward. This is simply due to the structure of a couple new contracts just shifting dollars from above the line to the below the line as evident by our buyer overall net backs realized improvement over the next year.

Rolling our updated 2020 estimates into a 2-year outlook on slide 15 shows the anticipated sustainable free cash flow generating machine PDCE has a capability of becoming. A modest price assumption of $40 oil, [$2.50] gas and $9 NGL, we project to generate approximately $250 million of free cash flow next year.

Given the price sensitivity table provided, you can see just how much potential improvement these already impressive numbers have. For the 2-year total we project more than $550 million of free cash flow combined in 2020 and 2021 on a capital investment of approximately $1.1 billion. This represents an extremely competitive free cash flow margin of 50%. And as a reminder, we define free cash flow margin as free cash flow divided by capital investment, and a free cash flow year of nearly 40% for both years.

Further, we have a tremendous ability to reduce our absolute debt level and expect to maintain a debt leverage ratio of less than 2 times through the next 6 quarters again at a very fair price deck. Given the hedge program, we just went over and the improvements to the Wattenberg operating environment covered by Scott, we feel very good about our ability to execute on these projections.

As we highlighted in our press release, our 2021 plan is relatively unchanged. Capital is projected to be $500 million to $600 million. Our initial production range of 175,000 to 185,000 BOE per day and 64,000 barrels to 68,000 barrels per day are the same as 2020.

And most importantly, we expect our 4th quarter next year to represent an increase of approximately 10% for both oil and total production when compared to the 4th quarter this year, which indicates we are well positioned to continue executing this plan into 2022. With that, I'll turn the call over to Lance.

Thanks, Scott. And in then this final section of today's call, we want to show how PDC’s impressive two-year projections compare not only to our similarly-sized peers but also to the E&P sector at large. This list includes large cap E&P companies, many of which are blue chip and investment grade.

I'd like to note that the data on slides 17 and 18 is sourced entirely from Credit Suisse Research for all E&P company projections, including for PDC, and run at strip prices. So you'll notice some differences in the Credit Suisse projections for PDC compared to our own data presented today.

Now starting with slide 17, PDC is projected to rank among the very best of this approximate 25 E&P company group on both a 2-year cumulative free cash flow yield and a 2-year free cash flow margin. Starting with free cash flow yield, Credit Suisse estimates for PDC of 44% is 4 times the median of 11% and even further above that of the general market, which historically averages in the mid-single digits.

This chart shows the extreme disconnect between our projected free cash flow generation and our current equity performance especially given our expectation for improvements in Wattenberg from both a regulatory and midstream standpoint. The same graph at the bottom of the slide 17 highlights PDC’s tremendous capital efficiency in generating our free cash flow as estimated by Credit Suisse.

As a reminder, free cash flow margin is defined as cumulative free cash flow divided by cumulative capital investments. So for PDC, Credit Suisse projects that for 2020 and 2021 combined, the Company is estimated to generate $0.59 of free cash flow per $1 of capital spent at strip pricing. As you can see, PDC’s estimate of 59% is more than double the E&P Group medium.

Now moving to Slide 18; the third-party estimates from Credit Suisse once again paint a very strong picture for PDC as we were able to couple our expected industry leading free cash flow profile with an extremely sound balance sheet at NYMEX strip pricing. In the top graph Credit Suisse projects our year-end 21 leverage ratio at 1.1 times based on their input assumptions.

From a relative standpoint, we are projected to have a leverage ratio that is half that of the median peer group and were only 1 of 6 companies projected below 1.5 times. The other companies projected to have similarly strong balance sheets on this graph include Blue Chip E&P companies like EOG, Pioneer, Concho and Conoco Phillips.

Finally, this last chart shows the estimated year-end 2021 EV for EBITDAX trading multiple for each of the 25 E&P company group also at strip pricing. PDC’s multiple of 2.6 times is approximately 50% that of the median and approximately 1.5 turns below the next lowest multiple.

Throughout this call, we've highlighted an enhanced midstream and operating environment in the DJ, improved Colorado regulatory backdrop and a multi-year business plan capable of generating significant and sustainable free cash flow in a low-price world. This all adds up to what we believe differentiates PDC and makes us an extremely compelling valuation story.

Finally, to close the call, we want to provide a concise overview of the positive story you've heard today, namely that we are consistently and successfully executing on an extremely transparent financially focused strategy. Our ability to generate both material and sustainable free cash flow at relatively modest commodity prices is due to the quality of our portfolio, the strength of our teams and our continuous focus on improving cost structure and capital efficiency.

Additionally, our continued focus on maintaining and improving our strong balance sheet and liquidity are foundational to the company. We've not only demonstrated our financial discipline historically, but we continue to prioritize further debt reduction through future projected free cash flow generation.

From an operational standpoint in Colorado, we're seeing some of the regulatory and midstream headwinds that we faced in the past dissipating, allowing us to project the safe and responsible development of our high return Wattenberg asset with more clarity and certainty.

Lastly, we believe we are well positioned to be a leader in many of the E&P industry's key value creation metrics. With that, I'll turn the call over to the operator for Q&A.

(Operator Instructions) Your first question comes from the line of Duncan McIntosh from Johnson Rice.

This is Austin on for Dun. First off, just want to say. Congrats on a great quarter.

Thank you.

And then, my first question is could you all provide a little more color on your all's trajectory [into] 2020. 3Q CapEx looks to be the trough with declining volumes into 4Q and 1Q before you all return to growth. And if you all could provide any color around rig and completion crew activity that will be great.

And lastly, I recognize that it's too early for hard numbers on 2022, but how are you all thinking about longer term activity and the balance of growth versus debt reduction.

Yes, I can take -- there is a bunch of questions in there. So I'll take some -- probably throw some to Scott, as well. Again, for CapEx for the next 2 quarters, you're going to see something around $50 million in the third quarter and around $100 million of CapEx in the 4th quarter, plus or minus with next year having that $500 to $600 million range as we talked about, with I would say more steady CapEx spending throughout next year compared to what we had this year. Obviously our summer months have with the activity have gone down.

As far as the rig cadence goes, we do have the Wattenberg operating rig, drilling rig running right now and continuing running all the way through next year. Our completion crew is coming back in late third quarter and we have Delaware activity starting again with a rig and completion crew at the beginning of next year. So I think overall that gives fairly good guidance and direction of how we anticipate spending our CapEx next year. Scott, anything else you want to add to that?

You covered it. Scott, I think the only other question was 2022.

Well, I think, what I tried to hint a little to is the way we have our gross set up for next year and our CapEx more evenly spread throughout the year. We think that 2022 is going to look very positive and continue the motion that we're creating in 2021 from this standpoint.

Thank you for the color. And I guess my follow-up question is while it could be too early, your all's cash flow, free cash flow outlook from here is not only robust but looks to be pretty steady. In particular, as we all move into the mid-2021. And that being said, is there a point at which you all would consider implementing a dividend? And what would be some hurdles you all would need to clear before reaching that stage?

Yes. I mean right now, we want the message to be absolutely clear, we are focused on debt reduction. And when we look at our company long-term health, we'd love to get our debt -- total debt balance at or below $1.5 billion before we consider other material ways to return capital to shareholders. And that's why we've mentioned that our current share buyback is currently suspended right now.

So I would say that's our number one goal. When we go through 2021, we'll start looking at other ways. We still have, as I said, our share repurchase program outstanding that we could turn back on. But right now, we need to focus continuing on paying down debt and getting our balance sheet to make sure.

I really want to get a leverage ratio back under 1.5 again, not that I'm uncomfortable at the level it is now, but I think having a great leverage ratio, a really strong balance sheet with our total debt under $1.5 billion is our #1 target right now.

Your next question comes from the line of Welles Fitzpatrick from Truist.

First off, Scott, let me say, it's been a real pleasure getting to know you, getting to work with you over these years. I don't know what you plan to do and -- in retirement, but given the level of patience and the skill at explaining even the most basic concepts to me over the years, I hope it has something to do with teaching because I know you're above and beyond at that. So, anyways.

I appreciate that.

You guys obviously you have wonderful capital efficiency in 2021. Can you talk to what happens to the DUC count in 2021? If I remember correctly, it stays relatively close to that kind of 200 number, but just want to check to make sure it's not -- it's not a rundown of DUCs that's causing that efficiency?

Yes. Well, this is Scott. And we're really looking at something around 210 at the end of this year and about 180 at the end of 2021 and that's the combined Wattenberg and Delaware DUC counts, that tells you know drawn down 30 or so with the one rig running as Scott described. And then we do have a second rig scheduled for late 2021 to start picking up and drilling wells again.

So it's really -- it's really not quite a breakeven from year to year but a little bit of a pull down. It really is a function of also we really can't drill too much faster because we'll outrun our completion crews by more and that doesn't really suit us. We really like that count being at that 200 level, probably a bit below that, if we could get it there over time.

Okay. So it sounds like '21, if that rigs coming in a little bit later, maybe '21 is not going to be front-half weighted for the first time in a while on CapEx.

Yes. No, it really will be front-half loaded, Welles, primarily because the completion crews in the Delaware, we'll have that crew for about a third of the year, 30% to 35% of the year. And then it will get released on and then we pick it up again the following year. But it will be front-half loaded because of that and the idea that we have also picked up the frac crew in Wattenberg.

Okay, perfect. And then if I could just do one follow on. You guys talk to midstream and basin, I mean it's a ton of sense. I know the issue has been perhaps spilled too much ink already, but can you talk to any potential impact from a doubtful closure?

Yes, Welles, this is Lance. Our field in the Wattenberg is really not directly impacted by the doubtful closure and I know that the judge vacated that closure for some period of time this week. There is -- there could be some additional barrels that make its way from the Bakken down to the Wattenberg, but there's only so much incremental capacity that could come that route.

And in general, every month, when we do our oil-marketing arrangements, there is always movement in different pipes and different volumes and going to different locations. So we see this more is just a continuing analysis and process of finding the best price for the best barrels on an ongoing basis.

Your next question comes from William Thompson from Barclays.

All right. Bart, Governor Polis essentially called for cooler heads to prevail by allowing Senate Bill 181 to continue to be implemented while trying to keep, obviously, the initiatives off the ballot through 2022. Can you maybe remind us what is left to be ironed out under SB181?

You pointed out that PDC expects to have about 400 plus DUCs and permits by year-end equating about 3 years plus of inventory. Can you maybe talk about how the permitting process has changed? And now you allude about those 10 recent permits, so curious to get some color there.

Yes, let me just make a couple comments. We've got a new commission that we actually feel pretty positive about based on the background of the new commissioners. We have also got Jeff Robbins who we've got a very, very good relationship, who is now chairing the commission. He reports to the governor.

And overall, the op-ed governor released, we felt very good about his position, his stance with the industry to oppose any industry focused ballot initiatives. And so we feel like all of this is a positive for not just PDC but all the operators. As far as the rule making, I am going to put that over to Scott, and let him kind of cover some of the remaining rule makings that are out there.

Yes, I guess our first pass on this was wellbore integrity, which has been completed and we're -- we feel comfortable with all of the negotiations, et cetera, that went along with that, that we're going to be able to comfortably comply. Obviously, we didn't get everything we want, but again the compliance is what we're most focused on. And so that will start in here in the very near future.

As Bart said, the professional commission is [seated] and we believe we're going to be able to work with them as well. And that's a real challenge yet for the next couple months to see that that's the case but we're hopeful around that.

And I guess the next actual rule process that they're going through is really in 2 phases and its well siting and mission change and there's a lot that go into each one of those. But it's being done in 2 phases, and it's really expected to be completed in October.

So that's – again, if everything stays on schedule, I think that COVID has made this very difficult to stay on schedule, but that's what we're expecting. We'll get a real feel for how that entire relationship goes with the commission and so on, as we go through that process.

The only other thing that's coming up in the CDPAG, call it Department of Health, is in September, we had a Reg 7, ozone rules are getting updated. And we'll be fully engaged with that as we are with all of these others as a company as we continue also combining our efforts with the rest of the industry.

And I think this is a great point to speak towards, it will be a pleasure. We've enjoyed our relationship with Noble, but it'll be a pleasure to have Chevron on board too because they are a very large company and we appreciate that.

That's helpful color. And then on Slide 18, clearly tried point out the discount on your multiple. I'll have to ask Credit Suisse for their comp sheet. But clearly part of the valuation overhang in the past was the Colorado regulatory uncertainty, and that's obviously improving while your peers are dealing with DAPL and federal land exposure.

I had you trade about 80,000 per flowing barrel. So, I mean no value to PUD. It's kind of an open question, but I guess what's the feedback, if any, that justifies PDC trading at such a deep discount? Or said another way, what would -- what do you think would rerate the stock? I guess in my view it's probably just execution on 2020-2021 outlook and chipping away at leverage, but curious to get your thoughts there.

Yes. Well, I think you're hitting it, execution, continuing to communicate what we think is an improving political and regulatory environment, getting through some more of these rule makings. Showing our capital efficiency and our free cash flow. And in this new paradigm we're in, just showing our results quarter after quarter. I believe that's what we have to do.

We've got -- we've had some really thorough and thoughtful reviews of our capital programs for the balance of this year and next year even at strip with some of the cost structure per well that Scott Reasoner rolled out. We still have substantial returns from both basins.

We've just got to -- we've got to continue to communicate that to you. And I think with time as we get permits with the Weld County, a 100% Weld County position and 181, the way it's structured to give the local communities more authority, I think we'll continue to gain momentum. So Lance, you want to add to this?

Yes. Very good. I'd just continue on some of Bart thoughts there. Yes. Historically, William, I think you're right on. I mean it's -- I think the Colorado regulatory environment has been a bit of an overhang on the stock for some time.

And I think also, just with the growth of the field itself, I think just getting the Wattenberg midstream capacity limitations out of the way to where we now have sufficient capacity for the foreseeable future. That's been a real blessing to us as well.

DCP's going to exit this year with about 1.6 BCF a day of capacity on their system with the Latham II start-up project. There is definitely ample spare capacity on that system for us going forward a night.

We touched on all the things that we think really differentiate the company and it's driven by a financially focused business model of free cash flow, top tier balance sheet and the focus on reducing debt. So bridging the gap, from our perspective, William, is we believe as we continue to execute on our strategy, quarter after quarter, delivering free cash flow, reducing debt that our trading metrics will begin to improve.

Your next question comes from Brian Downey from Citigroup.

So we've heard a lot from E&P peers on mid cycle production growth and reinvestment rates this earnings season. So I'm curious how you're thinking about that framework longer term and if that would be materially different from what you've laid out for 2021.

So your guidance figures for next year suggest 250 of free cash flow on $550 million of spending at the midpoint. So you mentioned free cash flow margin, but that sort of implies slightly under 70% of your cash flow is being reinvested next year. Should we anticipate a similar ratio longer term or any thoughts there?

Yes. When I just look at it again, we feel like we've given a lot of guidance on '21. What I want to say with '22 is we think we have the ability and we've set the company up to continue doing the same thing.

So free cash flow generation is not something that's just going to happen in '20 and '21, it's going to happen for the foreseeable future using the same plan that we have: flat to modest growth, continuing to execute on our drilling plans with the permits in [site] and the balance of Wattenberg really having put the midstream issues behind us, we think we're going to be able to, depending on commodity prices, continue to execute.

And I think 2022 you could see something similar, but it all depends on what the commodity price outlook looks like. So I don't think '21 is an aberration by any means. And I would expect similar results to continue in the future.

Great. And then, Scott, I wanted to echo, congratulations on the retirement. You had mentioned the $850 a foot well cost in the Delaware. I'm trying to get a sense of where that could go next year. I realize your Delaware Basin capital program is largely complete for the year.

So I'm curious if that's a reflection of work you've already done or if we could see further durable deflation into next year. And maybe if you could also touch on any deflation potential on the Wattenberg side. I just want to make sure you're setting a high bar before you retire so we can hold David to it next year.

I'm not sure he'll appreciate that long term. Thank you for the comments. I appreciate those on my retirement. I really look at both areas and say they've done a tremendous amount already of getting efficient. I think particularly the Wattenberg, though, we still see improvement in drill times, which some of that is associated with the spudder rig ahead of it.

But we believe, and again we're going to confirm all this over the next, over the next 12 months or so -- we believe that to be an efficiency question as well that we're answering yes to in the end. So that continues. We are drilling wells in really, really short periods of time right now, with that big rig following behind that smaller rig spudding. So, we feel good about that.

Also, the crews on the completion side in the Wattenberg continue to get more efficient. We were -- right about the time we laid that completion crew down, the Liberty team coupled with the PDC team had done a phenomenal job. So we were more efficient that -- that can only help on the daily cost at a minimum. When you're running a crew like that there's always daily costs.

On the Delaware side, similar story, the last couple of wells we drilled in the Delaware were some of the best wells we've drilled as a company. And we haven't fully baked in any of these numbers. When I'm talking about these efficiencies into the future, a portion of them, but not all of them. So there is still opportunity I think. And I'd love to hand Dave out a little bit, but I probably won't do that because he's such a good friend.

But the part of that that's really interesting is we're going with a smaller casing, a smaller hole and that's led to these faster times. And we do believe over time we'll be able to get very efficient at doing that and it will become more repetitive, reducing the number of days on the -- over the [whole].

The frac pace was already pretty phenomenal. I think it was -- it was improving somewhat as we got towards the end. But again, it's one of those things where small increments from this point going forward would be the best thing to say. And that way, like I said, I don't hang Dave out too much going into the future.

Your next question comes from the line of Michael Scialla from Stifel.

Congrats on the quarter and to Scott on his retirement. This is actually Guillermo stepping in for Mike. You had mentioned your DUC inventory declining throughout 2021. Would that change at different price levels?

At this point, we don't really look at that as something that we would -- we would initiate. We really kind of like the plan we have laid out there. And I would just caution you with the typical, we still haven't budgeted for the year though, that will be coming up in the next couple of months. So, some of this is subject to change.

But right now, we really see -- obviously, we'll pretty well use up our DUCs in the Delaware. In the Wattenberg, we just don't see picking up another crew right now. We really think we're at a good point. I think Lance's comments and Bart's comments around making sure we keep a keen eye on our spend relative to our cash flow is something that we're all very focused on.

And so that would be something I'm sure will be given some consideration, but I would expect at this point. The way we see it, that we would just hold with the one crew in the Wattenberg.

That's helpful. Thank you. And as a follow up, you mentioned the DCP system line pressures declining this year. Do the current line pressures affect your decision-making process of future development?

I guess I'll start and Lance probably will toss in a couple of comments. I think the thing that we're looking at is produce -- it gives us an opportunity to really produce what we've been capable of. And I guess that's the thing we're looking forward to the most. But would it change our plans? I don't think so at this point.

Again, we're back to so focus -- or really tremendous focus on that free cash flow. That will probably be the primary look that we take over -- over the next year or 2 years, as Scott Meyers described, is something where really that steady state of capital and free cash flow is something that we're trying to get to and feel like we can do that effectively.

The only other thing I'd add to that is that with stable line pressures in the system and with ample clear capacity in the system, it just makes it that much more clarifying for us as we project and budget going forward knowing that we've got pressures that we can see and count on with our well performance over time.

Perfect, that's it for me. Congrats again on the quarter.

Thank you very much.

Thank you.

(Operator Instructions) Your next question comes from Noel Parks from Coker & Palmer.

I just had a couple of things. I was wondering, I remember from last quarter, you were pretty cautious on differentials and just how they'd look for the quarter. And if I'm looking at my numbers right, it seems that they, along with overall commodity prices strengthening, were not quite as bad. And -- but you still seem cautious looking into the future.

I might have missed some of what you said before earlier, but improving -- improvement on the midstream situation I assume helped. But looking forward, are you inclined to just model sort of the more conservative end of differentials as you look into 2021? Or do you think we're sort of done with the worst of it or will be by then, and we'll be back to more sort of normalized levels?

Yes. No, that's a great question. So I'm referencing slide 14 here to talk and speak to this. I mean, clearly in the second quarter, we had a deduct of a little over $9 a barrel. And keep in mind the factors that go into that are the DJ quality, the roll and then our firm transportation contracts that fit that deduct line item.

As you look at the second half of the year we're projecting $4 to $5 per barrel. The big improvement there is because the roll and the DJ quality barrel has improved substantially over that of the second quarter. So that's the reason why we see that improvement here in the second half of the year.

And then just let me touch on '21 real quick. And then if you go there we got a midpoint of about $3 per barrel just under the deduct. And as Scott Meyers shared in his prepared remarks, we have more and more of our weighted average barrel that's treated for accounting purposes as TGP versus that as revenue reduction and all.

If you do look at the long-term price for say -- let's just say '21, the midpoint of both the deduct and the realized is about $3 each or about $6 per barrel total. And then you kind of go back to 2019 and those categories add up to about $5 a barrel. So we are about $1 per barrel higher going forward.

And there's 2 reasons for that. One is, through the merger we inherited a few higher-priced contracts higher deduct contracts that will work off over time. That's a key part of that. The second thing is that in the second quarter this year, our very best oil contract differential contract in Wattenberg expired. So those 2 things as they roll in is why we're at $6 a barrel in 2021 versus more say $5 per barrel in 2019.

Got you and actually that favorable contract that expired, is that with a particular vendor? I -- just thinking about and talking about it for the future as a reference point -- what was that contract named or just how would you describe it?

Well, so we can't go into the specifics of the contract that was there, but that contract was a very favorable contract to PDC, a big complement to our marketing team that was able to secure that contract and ship on that contract.

So that came to an exploration that's over with. And so, we continue to look, like we said earlier, on a monthly basis for lots of different outtakes, if you will, for all of our oil both in basin and on various pipes to maximize the monthly netback for the company.

Great. Well, actually, maybe a better way to just ask you is how long a term was that contract for? Was it a couple years, 5 years or?

It was a multi-year contract that was available to us that we were able to get the contractual arrangement on. And it was, as I said, very favorable to the company.

Great, thanks. And then just my other topic I wanted to touch on is, just curious, I mean with really confined activity levels in the basin these days, I don't know if it's a big factor -- but I started to hear a few rumblings on the service front about maybe the vendors being kind of anxious to try to lure customers back into drilling or completions on the 2020 side of the calendar year-end instead of a lot of plans I guess being set for 2021. And I'm just wondering if, as you get inbound calls from vendors, if there's much focus on trying to get in under the wire for the year-end.

I think you are making a great point of something that we look at constantly. And it's -- the teams are obviously in contact with all of the service providers trying -- even as we speak, getting ready for the fall budget process, that type of thing. And is it such that we're going to have substantial cost? Let's assume you're correct and there is somebody that wants to come back in earlier.

We earlier -- or late this year or before the first of the year, it's something that we would give consideration to. But we don't expect cost to move a tremendous amount from where we finished as we laid all that equipment down. Because it was already pretty -- it was already pretty tight for I think most of the companies out there. So really will be pushing obviously, but don't expect it to move a lot.

I think the more important question for us there is can we get the best crews with the best equipment combined. And that's something Dave and the team will be looking at as a tremendous focus towards the end of the year and making sure we do all that we can to get that efficient operation back as quickly as possible.

And I think that is the part that obviously concerns us the most is getting back to the pace that we were at, as I was describing from a drilling perspective and completion perspective, and coupling all of that with the safety side, which if these crews get away from you, you can lose focus on that. So that will be the focus for the budgeting process and for the operating teams to be sure they're doing a good job of preparing for that.

And I show no further questions at this time. I will now turn the call back to Mr. Bart Brookman for any closing remarks.

Yes. Thank you, Sylvia, and thank you for hosting the call today. And thanks to everyone for listening in; we appreciate your time, your ongoing support. And we look forward to, as a company, continuing to deliver positive results going forward. So again, thank you for the time.

Ladies and gentlemen, this does conclude today's conference. We thank you for your participation, you may now disconnect.