Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2020 third quarter results conference call. As a reminder, today's call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. Members of the investment community will have the opportunity to ask questions and can join the queue at any time by pressing star one. For members of the media attending in a listen-only mode today, you may quote statements made by any of the Ovintiv representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the express consent of Ovintiv.
I would now like to turn the conference call over to Steve Campbell from Investor Relations. Please go ahead, Mr. Campbell.
Thanks, operator. Good morning, everyone. Thanks for dialing in today for our third quarter call. Let me remind you that this call is being webcast, and the slides are available on our website at ovintiv.com. Please take note of the advisories regarding forward-looking statements at the end of our slides and in our disclosure documents filed with SEDAR and EDGAR. Following our prepared remarks, we will be available to take your specific questions. Please limit your time to one question and one follow-up. This just allows us to get to more of your questions on the call today. I'll now turn it over to our President and Chief Executive Officer, Doug Suttles.
Thanks, Steve. Good morning, everyone, and thanks for joining us. We have a lot of strong results to share with you today. Following our prepared remarks, the leadership team will be available to answer your questions. As you can see from our release, we posted very strong third-quarter results. This solidified our key deliverables for this year, 2020, and provides us with high confidence in our 2021 plan. We delivered free cash flow this quarter and made a meaningful reduction in our net debt during a very challenging time for our industry. Our results are a direct result of capital discipline and a relentless focus on innovation to drive efficiency into every part of our business. We have been very clear on how we are running the business through the end of 2021.
Today, we will be providing some additional clarity that is consistent with this framework and reiterates our priorities around debt reduction and capital allocation over the long term. In the third quarter, we generated total cash flow of $398 million and free cash flow of $47 million. We reduced net debt by $217 million and maintained substantial liquidity of $3.1 billion. We are relentlessly driving down costs, and our track record of innovation really sets us apart. As of the end of the quarter, we achieved our goal of cutting more than $200 million in costs for 2020. Most of these savings will be durable, and we will also benefit from an additional $100 million of savings as legacy costs expire, bringing the total 2021 savings to $300 million. Our teams have done an incredible job of reducing well cost. We've improved on our already best-in-class operational performance.
We have already achieved our target for a 20% reduction in drilling and completion cost. Greg will cover this in more detail. These efficiencies are expected to stay with us through the cycle. Well performance has been strong. We beat our third-quarter crude and condensate guide of 180,000 barrels per day. We are confident that we will average 200,000 barrels a day in the fourth quarter and next year. In fact, we're already at 200,000 barrels a day here in October. Despite all the challenges that 2020 has thrown at us, we are set to achieve our third consecutive year of free cash flow generation. Our debt was down over $200 million in the third quarter. We expect a similar reduction in the fourth quarter.
Our full-year capital budget is now expected to be just under $1.8 billion, which implies fourth quarter CapEx of less than $400 million. Our full-year investments will be down $900 million compared to our budget. Our completion operations have resumed, and we have largely worked our way through the DUC inventory that we built through the first half of the year. We expect to end the year with a typical number of DUCs, approximately 30 wells. Unit costs continue to trend lower. In the fourth quarter, we expect slightly lower per-unit cost when compared to the third quarter, with our total cost projected at about $11.70 per BOE. One of our most impactful achievements is the cost-cutting that came from every part of the company. We have achieved more than $200 million of cost savings in 2020, and next year, we expect that to grow to $300 million.
The value of our risk management practices has once again been clearly demonstrated. Our dynamic hedging program protected 2020 cash flow and enhanced margins through what has been an incredibly volatile commodity price environment. In the fourth quarter, we have hedges in place for 180,000 barrels a day of crude and condensate, or about 90% of our volumes. We expect to see strong price realizations across all products. Now I'll turn the call over to Greg to cover our operational highlights.
Thanks, Doug. Today, we're providing new and lower well cost forecast in each of our core areas. We've updated this slide throughout the year to show our constant progress and our pacesetter results in each of the plays. As you can see in our 2021 well cost estimates table, we continue to meaningfully drive down our drill and complete costs. When compared to last quarter, we've reduced cost $400,000 in the Permian and $200,000 in the Montney.
In the Anadarko, our costs are now more than 40% lower than Newfield's average cost at the time of the acquisition. Well costs that were $7.9 million about two years ago are now $4.6 million. As a result of these improvements, our 2021 well costs will be at least 20% less than our 2019 actuals. In the Permian, we've seen significant improvements since the second quarter. Costs were about $500 per foot, or 9% lower. Our pacesetter wells came in at $430 a foot. This was one of our best quarters ever, and the good news was distributed across Howard, Midland, and Martin counties. Our well cost reductions are highly durable through cycle. They're mostly related to our own unique innovation and process changes, not simply lower service costs. We know that our operational achievements are being recognized by investors.
We've been getting lots of questions recently about how we're able to continually take costs out of the system while delivering strong well results. At the heart of this achievement is our culture of innovation and our multi-basin model to shift ideas and technology rapidly across our portfolio. Constant innovation and our ability to significantly lower costs have been critical to our development plans. We have not up-spaced wells to generate a short-term boost at the expense of future inventory. Our cube development model is the right approach, and our operations in the field are differentiated. We use our cube development model to maximize the value of our acreage, and in each of our core areas today, we have over a decade of inventory. In the Permian, we continue to see great results from simul frac completions, providing up to $400,000 per well in savings.
We have a track record of rapidly moving good ideas throughout our portfolio and are now using simul fracs in the Anadarko and the Montney. In the Anadarko, we have seen big decreases in our cost and remain confident that we can continue to find innovative cycle time enhancements. The use of wet sand in our completions has been successful. All of our fleets are now pumping wet sand. In addition, we continue to see the benefit of self-sourcing chemicals. Our Springer results have continued to show good cost reductions as well. In fact, we have recently achieved four of the five fastest wells drilled in the play to date. We are averaging over 20 hours of completion pump time per day in the basin, which is significantly above historical basin performance.
In the Montney, we achieved record low drilling costs of under $1 million per well, and we completed our wells in about two days. This is half the time it took in 2018. These efficiency gains are the result of relentless innovation and attention to detail and will stay with us regardless of commodity prices. We've also started up our Pipestone processing facility in the Montney five months ahead of schedule, making it our fourth large project brought in ahead of schedule and at or under budget cost in the last three years. This is resulting in lower pressures in the gathering system, and the startup does not require any new drilling to satisfy the capacity arrangements. I'll now turn the call back to Doug to talk more about 2021.
Thanks, Greg. We have been delivering on the new E&P model for several years. Going forward, we are focused on four priorities. We are laser-focused on debt reduction. 2020 will be our third consecutive year of free cash flow generation, and as we have stated, all available free cash will go to debt reduction. Our plan will reduce our debt by at least $1 billion from the second half of 2020 through year-end 2021. Second, we know the importance of maintaining scale and positioning our company to thrive when demand for our products returns. We can hold 200,000 barrels a day of crude and condensate production with an annual investment of $1.5 billion. This screens as one of the best capital efficiencies in the E&P sector today. Third, we see our cost reductions and newly generated efficiencies as durable. They will stay with us even after oil prices recover.
Our teams have done a great job of safely reducing costs this year, and their hard work has us set up for a very strong 2021. Finally, we remain committed to returning cash to our owners. We have a track record of doing so. It's how we have been and are running the company. Our near-term focus on reducing debt is the best value add for our shareholders today. Our multi-basin portfolio provides exposure across the commodity spectrum. Although our focus is on crude and condensate, don't forget that we produce a lot of gas. With 1.5 billion cu ft of gas per day of gas production, a small move in gas prices makes a big difference in revenues and cash flow. In fact, a $0.25 increase in gas price is about $100 million of incremental cash flow.
We have the key ingredients for differentiated value creation on the road ahead, and our priorities are crystal clear. I'll now turn the call over to Corey.
Thanks, Doug. We've been very clear on how we're going to run the company out to the end of 2021, and today we're providing a longer-term framework consistent with these views. Our business is capable of generating significant free cash flow in the near term. We estimate $800 million of free cash next year. We're confident that our plan will lower absolute debt and reduce our leverage. We expect to reduce our total debt by more than $1 billion from the second half of 2020 through year-end 2021. Again, all excess free cash flow will go to debt reduction. Over the longer term, at mid-cycle conditions, we believe that a leverage ratio of 1.5x net debt to EBITDA or less is the right aiming point. Consistent with the new E&P model that we've been operating under for almost three years now, we are formalizing a reinvestment rate as well.
We expect to reinvest 75% or less of our cash flows, providing significant free cash for shareholder returns. We believe a secure dividend is a key part of the new E&P model, and you will have noticed that despite conditions in 2020, we remain committed to our dividend. As we've outlined before, our 2021 scenario equates to a reinvestment rate of less than 70% of cash flow. This reinvestment rate for 2021 is at or below many of the levels recently announced by our peers, which speaks to the quality of our assets and our cost structure. I'll turn the call over to Brendan to discuss ESG.
Thanks, Corey. Our approach to innovation applies across all aspects of our business. We're an industry leader in ESG performance and reporting. We recognize that investors are seeking increased transparency, more consistency, and continuous improvement from our sector and from our company. Since we began publishing our sustainability report 15 years ago, we've consistently disclosed our ESG performance, and we've continued to evolve our report to meet stakeholder expectations. We're on track to incorporate emission-related performance targets in our 2021 compensation program. We know the importance of ESG to our stakeholders, we know the power of setting targets, and we have high confidence in our ability to drive performance gains. We're also playing a leadership role in industry to encourage greater transparency and consistency of reporting.
We've been taking actions to reduce our emissions through operational efficiencies and innovation for many years, and we're pleased to report that just like our efforts to drive down well costs, our team is also driving reductions in emissions, as demonstrated by our results on methane intensity and flaring. I'll now turn the call back to Doug.
Thanks, Brendan. We have been at the forefront of the shift to this new E&P. We have been describing our approach and delivering on this model for the last several years. Before opening it up to your questions, I'd like to highlight a few things that we've mentioned today. We know the importance of debt reduction. We have laid out a plan for significant debt reduction in the near term, driven by free cash generation. We also know how important it is to maintain scale. We have put a lot of thought into our scenario, and we now have made significant progress on demonstrating the performance that underpins that plan. We continue to make incredible progress on driving efficiency. This is not a trend that is slowing down for us, but it is driven by our culture.
Finally, we know the importance of returning cash to our shareholders, and we have a strong record of doing this. Since 2018, we've returned more than $1.7 billion through dividends and buybacks. While many canceled or cut dividends early this year, we maintained ours. We believe this is important to our shareholders. Today, we believe the most effective way for us to return value to our shareholders is to reduce debt, and that's where we're focused. Earlier this year, we committed to including key emissions-related performance targets in our compensation program in 2021, and we are on track to accomplish that. This is good for the environment, and it's good business. Recent consolidation in our sector is validating our strategy. We have the proven ability and scale to drive leading efficiencies and generate significant free cash flow. Our high-quality multi-basin portfolio and sophisticated risk management are differentiated.
These ingredients comprise the new E&P model. When coupled with our world-class operations, it's a powerful combination. Thanks for listening, and now we'd be prepared to take any of your questions.
Ladies and gentlemen, as a reminder, you can join the queue to ask a question by pressing star one. We will now begin the question and answer session and go to the first caller from Arun Jayaram at JPMorgan Chase. Please go ahead.
Yeah, good morning. I had a couple of questions on the updated free cash flow guide and deleveraging target. Doug, the strip has moved against you a little bit in terms of oil. My first question is, what does the free cash flow and deleveraging outlook look like if we were to dial in the current strip versus the $45, $3 deck that you used?
Yeah, Arun. We provide some sensitivities to price because, of course, that moves around as we build our hedge book. If I could, I'll just point you to that right now. I think you may have noticed that we are about 90% hedged in the fourth quarter on crude and condensate, and we're about 40% hedged in 2021. Plus, as you've just highlighted, the strip's very volatile right now as sentiment's moving around. Maybe the last point I'd make, I think we demonstrated earlier this year, if we end up in a very tough environment, we acted boldly, quickly, and actually probably unique in the industry, we acted without creating cost. We didn't have to pay payments off of that.
Then the last thing I'd just highlight, which is a little unique, is that 1.5 billion cu ft a day of gas production, and alongside that sits 85,000 barrels a day of NGLs, which that multi-product portfolio also protects us from single product movements.
Fair enough. Just my follow-up here is, you mentioned that the cost structure on a per unit basis was $11.70 per BOE. You'll get called another $100 million or so kind of tailwind next year. Any thoughts on the per unit cost structure as you're moving into 2021? Could we use $11.70 and just back off maybe $100 million of savings on that as maybe a starting point?
Yeah. That 100 comes in a number of areas because a piece of that is related to Panuke, which Greg didn't mention, but he and his team successfully abandoned that project through COVID. No one got sick, and we executed it under budget cost. Some of that's Panuke costs rolling off next year. Arun, our costs will be lower than that. The only thing you'd have to adjust for is production-related taxes tied to price. These need to go only one direction, and that's down, and it's really driven by innovation, and I'm confident we'll get that lower as we go into next year.
The next question comes from Jeanine Wai at Barclays. Please go ahead.
Hi. Good morning, everyone. Thanks for taking my call.
Hi, Jeanine.
Hi. Good morning. My questions are on the reinvestment rate and on the new expected long-term cash flow reinvestment rate of less than 75%. Can you just talk a little bit about how this could vary at different commodity price scenarios? I guess my follow-up is, when does this capital allocation framework become more rigid? Since I think the qualifier here is that it's a long-term reinvestment rate. I know you've provided a lot of great clarity through 2021. Does this really kick in? Is it 2022, or is it more like 2025 or so? We're just looking for a little bit more detail. Thank you.
Yeah, Jeanine. Well, first of all, and I think you guys can all run your models on this, but next year, we would be investing much below the 75%, because what we've said is our priorities are holding our scale at essentially what is now today's production rate and then generating significant free cash and focusing every bit of that on debt reduction. Of course, 75% allows at least 25% of our cash generation to go to shareholder returns. It also, when it's lower than that, creates other options. Those other options aren't on the table today. For instance, you wouldn't even consider going back to growth until we get our debt and are confident we've got our debt where we're looking to get it to, and we're confident that demand for our products has returned and will begin to grow.
What this does hopefully give everyone some insight into is how we'd run the business as the markets begin to stabilize and return, and once we've got our debt down to the levels we're targeting today. What we're really demonstrating is what we've done for three years, which is we're not going to take all of our cash flow and invest it back into the business as a capital program to grow volumes.
Okay. I guess maybe just following up on Arun's commentary on the strip kind of moving against everybody right now. I guess if the strip holds and that less than 75% reinvestment rate, are you willing to just let production decline and all of that in order to stick that number?
Yeah, Jeanine. I think it all depends on how we see the market developing. If we wind ourselves back, not that many of us want to remember what it was like back in March and April, there was all sorts of conversations going around about oil being $20 or less forever and other things. We just needed to, one, get into action quickly by pulling capital back and buy time to see what the markets were doing and then just accelerate efficiency improvements. If we end up in a world like that, we can and will reconsider those things. I think the other piece of information which is important is, as we've said, we could maintain 200,000 barrels a day and generate free cash flow more than enough to cover our dividend all the way down to $35 and $2.75.
I think it's a bit hard to speculate, and I think it's a bit early to be believing that the strip is actually right for next year, because right now it would be lower than 2020 prices, which feels a little unusual. We will act. We'll protect the balance sheet. We do want to protect the scale of the business, but we will protect the balance sheet, and we have the ability to be dynamic if that's the case.
The next question comes from Brian Singer at Goldman Sachs. Please go ahead.
Thank you. Good morning.
Morning, Brian.
Doug, I wanted to pick up on the comments that you made at the end of your prepared remarks on consolidation. Ovintiv seems to be taking the view that you have the appropriate level of scale for desired execution. Other companies appear to be sending a message via their consolidation announcements that greater size and scale are needed to be competitive. You highlighted in your remarks risk management, multi-basin portfolio. Can you talk more to what you see as the reasons for this difference and how you expect that at Ovintiv to translate into differentiation, whether it be in financial metrics, well performance, inventory longevity, et cetera?
Yeah. Thanks, Brian. You and I have talked about this many times over the years that we believe that even in the heyday of the pure-play model and others, that ultimately to be successful in a commodity that's going to see low growth globally, and volatility is going to be a feature, that a few things were going to matter. The companies had to have scale. We believe that's 500,000 Barrels of Oil Equivalent per day . Maybe that number changes, but many of the transactions you have seen have been trying to get to that scale because many of those companies were much smaller than that. You need that for a number of reasons. Organizational efficiency, cost structures, ability to apply innovation. We thought multi-basin was always a key. It's a part of risk management.
We're also demonstrating the value of being able to move ideas around in real time. In every basin we're in, we're a low-cost leader. That's not by accident. I think other skills, I think this risk management approach is key. We've all seen that in spades more recently. That's everything from things like how you think about protecting your balance sheet and cash flows with hedging programs, to how you actually do transportation and processing of your products. Many people, even recently, have been caught by that and those uncertainties. This model works. We think we're there. We think we're where we need to be. We're very clear the best way to create shareholder value for our shareholders is continue to execute incredibly well and actually reduce our debt.
That's where our focus is today, and we think that will make us very competitive going forward.
Great, thank you. My follow-up is with regards to natural gas. You highlighted the price exposure in the portfolio. Is there a situation, and you've been asked a couple of times here about strip price and strip oil price scenarios, but natural gas prices on a current and strip basis are pretty healthy. Is there a scenario where you shift capital out of some of the oilier plays and into the natural gas plays? What would be your priorities there in terms of what it would come out of and where it would go in within the portfolio?
Brian. The great thing is we do have that optionality in a number of parts of the portfolio, but obviously, more particularly up in the Montney, where we have everything from very high liquid yield condensate wells to dry gas that are very highly productive. We have that optionality. For us to do that, it would take more than just strengthen the short-term strip. It takes a more fundamental view of it. As I mentioned, we still get the benefit of that 1.5 billion cu ft today in that exposure. I don't think we've yet seen enough movement beyond 2021 to really justify moving a lot of CapEx.
We do have some concern about, in particular, what the private actors are going to do here with the movement in the strip and how they might throw capital in, which could create longer-term risk on gas prices. We have that optionality, but today we're not pulling on it. We continue to monitor it. If we continue to see demand growth and exports grow, and strengthen the longer portion of the curve, we could always go there.
Ladies and gentlemen, as a reminder, should you have any questions, please press star one. The next question comes from Asit Sen at Bank of America. Please go ahead.
Thanks. Good morning. Doug, appreciate all the details on 2021 scenario, and particularly on the $1.5 billion CapEx. I think you provided a rig scenario on your Slide 16. Just following up on that, if I'm thinking about Permian completions in 2021, would a 25 wells-30 wells completions per quarter would a good runway to use? I know you're early in 2021 planning scenario, but just completion cadence-wise, what should we think about Permian as a total?
Yeah, let me let Greg answer your question there. Thanks.
Sure. Generally, our capital allocation will be similar as it was this year, with probably a heavier focus on the core assets. Permian will be somewhere in that $25 wells a quarter, I think would be a decent average for you to assume.
Okay. Permian would be roughly, let's say, 40% of overall completion? 45%?
Somewhere in that ballpark. Again, we're still working through all of our final budgeting assumptions, and the good thing is we've got lots of different ways to get to the 200,000 barrels a day next year. We're still working through that, but I think your estimates are in line.
The next question comes from Neal Dingmann at Truist Securities. Please go ahead.
Morning. Doug and Greg, my question is, could you all speak to the 2021 DUCs you mentioned for the end of the year? I know you talked about the 30 wells. Why I ask is, obviously, you all are very active this quarter with around those 70 DUC completions. I'm just wondering, do you envision going ahead and building more DUCs next year, then knocking them out at the end of the year? Was this year unique given prices earlier in the year?
Yeah, Neal, you've really got it right there. We as a company don't find it capitally efficient to build DUC. It was a little unique this year, obviously, with what happened in 2Q. Normally we keep it at that. Around 30 wells is usually what's in the portfolio just at our current pace of development, that's what you should expect us to have coming out of this year. Right now, as Greg mentioned, we're in the final detail planning for next year, the program looks incredibly level loaded, actually beginning essentially with this quarter, 4Q. As I mentioned, we're already at that 200,000 barrels a day, which is what we've said we're going to be at next year. We think that's basically flat through the year, the cadence of drilling and completions will be pretty flat as well as we go through the year.
Of course, if we have a macro movement in the commodity downward, we'll look carefully at that and figure out how best to respond. If the commodity goes up, we'll just reduce that even faster because we're not going to move off the 200,000 barrels a day.
Okay, great details there. Just one follow-up on how you think about your inventory depth and drilling plan, I guess I'm just wondering, is the reason for your diversified D&C plan, I know what, about three rigs, I think you mentioned Permian too, and Anadarko and Montney. Is the reason for the diversified plan, just looking at the amount of inventory you have in each, or are there other factors that are to go into this?
Yeah, Neal, one of the things we think it's all about, a big piece of it's about risk management. The good news is we built a portfolio which delivers similar returns on capital in each. They get there in different ways, but they get to similar returns. By distributing capital across the portfolio, we actually don't degrade returns in doing it. What it allows us to do is avoid risks that many times are hard to predict. Historically, they were, think about the Permian not too long ago, when it was short pipe capacity to get product out of the basin. You remember not too long ago, there were some issues in Canada with AECO. There's a dialogue and some concern about federal acreage. These are examples of risks, why you have a multi-basin portfolio.
I think it's critical that you not see degradation of returns as you allocate capital across it. We think quite carefully about that. In some areas, for instance, the Montney's a classic, where actually the amount of condensate, crude and condensate out was lower than some of the other areas, but they're also very inexpensive wells, have low royalty rates. Actually right now, we're getting paid more than WTI pricing for that product. That's why we do it, Neal. It doesn't cost us in terms of returns.
At this time, we have completed the question and answer session, and we'll turn the call back to Mr. Campbell.
Thank you, operator, and thank you everyone for your interest and your investment in our company. We look forward to seeing you soon. Have a great day.
Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.