Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2020 fourth quarter and year-end 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 1. 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'd advise you to 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 will now turn the conference call over to Steve Campbell from Investor Relations. Please go ahead, Mr. Campbell. Good morning, everyone, and thank you, operator. We appreciate you guys dialing in today for our fourth quarter and year-end 2020 conference call. This call is being webcast, and the slides are available on our website at ovintiv.com. Please take note of the advisory regarding forward-looking statements at the end of our slides and in our disclosure documents filed with SEDAR and EDGAR. Following our prepared remarks this morning, we will be available to take your specific questions. Please limit, as always, your time to one question and one follow-up. This simply allows us to get to more of your questions on today's call. I'll now turn it over to our CEO, Doug Suttles. Thanks, Steve, good morning, everyone, and thank you for joining us. We have a lot of exciting news to share with you today, and following our prepared remarks, we'll be available to answer your questions. As you saw in our press release in early January, and again in our report yesterday, our business is performing exceptionally well. We are firing on all cylinders. We posted a strong finish to 2020 and ended the year with less debt, greater efficiency, and higher free cash flow outlook for 2021. We're well-positioned to execute our 2021 plan and have very strong confidence in our ability to deliver on our targets. Our 2021 outlook remains consistent with our investment framework and reiterates our key priorities around debt reduction, including raising our organic year-end 2021 target by 25%. We announced the sale of our Duvernay asset, which is demonstrable progress on our year-end 2022 debt objective. We have an active shareholder engagement program, you can see elements of that in the governance changes included in today's material. Before we jump into what's new, let's quickly recap 2020. More than ever before, 2020 proved the value of flexibility and optionality that we intentionally built into our business. At the onset of the pandemic, we acted quickly and decisively to protect employees through a cross-functional pandemic response team. We used risk-based procedures that enabled field employees to safely work and employees to return to the office. We immediately focused on reducing cost and implemented a dynamic production shut-in strategy. We also rapidly adjusted capital spending and activity levels to protect the balance sheet. Flexibility intentionally built into our contracts meant that we incurred zero penalties as we adjusted our business to market conditions. Our hedges protected our cash flow and our balance sheet and generated more than $700 million in benefits. I couldn't be prouder of our team and their efforts to stay focused, keep us safe, and push the boundaries on innovation. Our industry-leading efficiencies, sophisticated risk management approach, and our culture of innovation were crucial to our success. Our people found cost savings across every part of our business, and we exited 2020 a leaner and more profitable company. For the year, we generated total cash flow of $1.9 billion, and for the third consecutive year, we generated free cash flow, coming in at $193 million, or about $285 million if you include the one-time restructuring cost. We were able to deliver more with less, and total capital came in below expectations at $1.74 billion. Total debt was reduced by nearly $500 million from mid-year 2020 levels, and we maintained liquidity of $3.3 billion. Dislocations in the credit market allowed us to repurchase debt for a discount, resulting in $30 million of gains and lower future interest expenses. We cut more than $200 million in cash cost, and the reductions will be durable and sustainable as commodity prices strengthen. We also benefit from significant legacy costs rolling off in 2021. Our teams again showcased our culture of innovation and did an outstanding job of reducing well cost. We surpassed our targets, and our 2021 well cost will be 20% lower than 2019 averages. Greg will cover more on this in a moment. Not only did our resumption of completions late in the year come off on schedule and on budget, but we also saw strong well performance in every area. Production came in significantly higher than guidance and gave us good momentum going into 2021. We did all of this without losing focus on safety, with 2020 being our seventh consecutive safest year ever, with total recordables for employees and contractors dropping to 0.19. Today, we reinforced our priority on debt reduction by increasing our year-end 2021 target and setting a clear target and timing for reducing total debt to $4.5 billion and leverage to 1.5 times. Debt reduction is our number one priority. Our $4.5 billion target by the end of next year includes $1 billion in divestment proceeds. Today, we're about 25% of the way there with the announcement on the Duvernay. Using our planned price deck for $50 oil and $2.75 gas, our strong performance on cost, we have increased our organic debt reduction target for year-end 2021 by 25% to $1.25 billion using midyear 2020 as the starting point. With this plan, we expect to generate about $1 billion of free cash flow at the 50 and 275 price deck. The longer-term framework for our investments remains intact with a leverage target of 1.5 times net debt to adjusted EBITDA and a reinvestment rate of less than 75% of annual cash flows. This provides a clear framework for the future. As you know, we have a robust annual shareholder outreach effort where members of our board interact directly with our shareholders. In 2020, this represented ownership of about 40% of our shares. These conversations help us to evolve best practices and incorporate their ideas and feedback. As a result, we've made several important changes to our compensation plan. Recent changes include reducing our target LTI compensation for the executive by 15% in 2020, settling LTIs and shares to build insider ownership, including the S&P and XOP indices to our PSU peer group, adding return on invested capital to our LTI metrics, and including a methane emissions intensity reduction target for all employees. Our priorities today are crystal clear, reducing debt while maintaining our scale and driving efficiency across our business. We laid out a multi-year plan to reduce debt driven by capital discipline, free cash flow generation, and $1 billion in divestment proceeds. Strong environmental performance and continuous improvement is part of who we are, and we clearly demonstrated this with our venting and flaring performance, which was below half of 1% of sales gas in the fourth quarter. Additionally, we have added methane emissions reductions to our compensation program. We intend to maintain the scale of our business while using all available free cash to reduce debt. We expect crude and condensate production of approximately 200,000 barrels a day over the next two years. With 2021 capital investments totaling $1.5 billion, this screens as one of the best capital efficiencies in E&P today. We've made incredible progress in driving costs out of the business and holding on to those savings. As legacy costs roll off over the next several years, this is a tailwind to our cash flows and our debt reduction efforts. Lastly, we know the importance of returning cash to our shareholders. Since 2018, we've returned more than $1.7 billion through dividends and buybacks. While many canceled or cut dividends in 2020, we maintained ours. We believe this consistency is important to our shareholders. Now I'd like to turn the call over to Corey. Thanks, Doug. Our business can generate substantial free cash flow in 2021, about $1 billion at prices of $50 oil and $275 gas. We've been closely monitoring the bond market and see strong pricing available to issuers with similar credit profiles, our preference is to pay down debt, not push it out further into the future. Including the proceeds from the Duvernay sale announced yesterday and the free cash flow this year, we should have enough cash to pay both of our upcoming debt maturities. Over the longer term, we believe that a leverage ratio of 1.5 times net debt to EBITDA or less is appropriate and reflective of an investment-grade credit rating. Our 2021 outlook equates to a reinvestment rate of about 60% of cash flow at the 50 and 275. At current strip pricing, the reinvestment rate is just above 50%. A secure and sustainable dividend is a key part of the new E&P model. You will have noticed that despite conditions in 2020, we remain committed to our dividend. Importantly, our 2021 program is highly repeatable. With the same amount of capital or less in 2022, we can maintain our crude and condensate production. With proceeds from asset sales, we're confident we can hit our debt target of $4.5 billion by the end of next year. Our legacy costs are lower this year and moving lower over time. On a cumulative basis, we will see $1.8 billion of legacy cost reductions from 2021 to 2025 when compared with 2020. This is a big tailwind for our cash flows. There is no execution risk associated with these cost reductions as they simply roll off with the passage of time. This year, we will see a $250 million reduction in legacy costs compared to 2020. The primary components of these reductions are attributable to the completion of our decommissioning activities at Deep Panuke over the last two years and the expiration of various transportation and processing contracts across the portfolio. I'll now turn the call back to Doug. Thanks, Corey. We have a strong track record of leadership in ESG performance and transparency in reporting. We have been publishing a sustainability report for the last 16 years. We realize the industry needs to do more to reduce the environmental impacts from our operations while providing the safe, reliable, and affordable energy the world needs. From the boardroom to the field, we all know the importance of this to our stakeholders. We are focused on reducing emissions and recently announced a methane intensity reduction target linked to compensation for all of our employees. We plan to reduce our methane intensity by one-third from 2019 levels by 2025. This target will be benchmarked against the 2019 actual methane intensity of 0.15. We do not routinely flare gas or drill wells in areas lacking infrastructure. Our performance in this area is industry-leading, and in the fourth quarter of 2020, flared and vented volumes accounted for just half of 1% of total gas production, down significantly from 1.2% in 2019. We're proud of this result and are focusing on continuing to reduce these volumes. We have taken, and will continue to take, a leadership role within our industry trade associations on climate-related issues. We believe that transparency, consistency, and continuous improvement from the entire sector are very important to drive down the emissions from our operations. Our performance in this area is being recognized, as you can see here in the rankings from independent third-party ESG rating agencies. Our board human resources and compensation committee regularly reviews executive compensation. Through our annual board outreach program, they interact directly with investors, seeking their input and feedback, including on compensation. The committee also has an external compensation consultant to ensure they stay well-informed on the latest practices in our industry and the broader business community. Changes to our compensation practices include enhanced rigor in aligning our annual incentive payout curves with the broader market, linking our methane intensity reduction to the annual incentive pay for all employees, the inclusion of key financial metrics in the 2021 scorecard, which include debt reduction, free cash flow, capital efficiency, and total cost, the addition of the S&P 400 and the XOP indices to our PSU peer group, and the inclusion of return on invested capital in the 2021 LTI program. This builds on other recent changes to our compensation practice, including settling our LTI payouts in shares to build insider ownership, reducing the target value of LTI grants to NEOs by 15% last year in 2020, capping the payout of PSU awards at 100% if our three-year total shareholder return for the performance period is negative, and broadening the company scorecard with enhanced focus on financial metrics. We have an independent and engaged board with a healthy and ongoing refreshment process. Since 2019, the board has added three new directors, announced the retirement of two long-tenured directors, named a new independent board chair, appointed new chairs to three of our committees. At year-end, average board tenure was approximately six years compared to the S&P average of 10 years. In early 2020, the board retained an independent consultant to help the board consider its needs, not only for today, but in the future. Our board recently heightened its commitment to promoting greater diversity by amending its director recruiting guidelines to ensure candidates of gender, racial, or ethnic diversity are sought out and included in our search process. Something that is commonly referred to as the Rooney Rule. I'll now turn the call over to Greg to cover some of our operational highlights. Thanks, Doug. From an operations perspective, 2020 was one of our best years ever. We made step changes in cost reductions and efficiency gains across all our assets. Our fourth quarter well costs set new records across the portfolio, and our 2021 costs will be at least 20% lower than our 2019 averages. We continue to see strong results in consistent well productivity rates, showing that our learning curve is far from over. Our culture of continuous improvement and innovation is unique and creates a competitive advantage, which is not easily replicated. The ability to lead in every basin we compete in defines us as a world-class operator. Our multi-basin portfolio allows us to rapidly transfer new ideas across the business to get real-time results. A great example of this is the rapid implementation of simul-frac across the company, which will be implemented on more than 80% of our 2021 program. The pie chart depicts our upstream free cash flow by asset for 2021. This demonstrates the breadth of the portfolio and contribution to free cash flow across all the assets, the strength of our portfolio. Cost reductions last year were driven by gains in a number of areas, including completion efficiency using simul-frac and wet sand, faster drilling and completion times, optimized wellbore designs, and adaptable service provider contracts. Our cost savings are expected to be highly durable through cycle and are related to innovation and process changes that drive down cycle time, not simply lower service costs. In 2020, the Permian team delivered dramatic well cost reductions alongside strong well performance. There's an interesting slide in the appendix today that shows how we make today's pace setter tomorrow's norm. Our cube approach continues to demonstrate value and support efficient execution of our acreage. One example of this operational excellence is where we have drilled 55 wells without a sidetrack. That's one million feet of drilling. Fourth quarter drilling and completion costs per lateral foot were $470, down more than 30% compared to our 2019 average D&C cost. We plan to spend roughly $600 million-$650 million to run three rigs in the Permian in 2021. In STACK, not only did we deliver new pace setter costs, we also drilled and completed five wells under $4 million. That's half of the New field's legacy well cost. We also demonstrated that this efficiency works in the SCOOP, where we completed six Springer wells with record drilling pace and basin-leading cost. These wells average $6.1 million in D&C costs, nearly $3.5 million lower than our January 2020 guidance. Although the majority of our 2021 program will continue to be in the STACK, we will have roughly 15% of our development in the SCOOP/Springer. The Anadarko will be the largest contributor of free cash flow in our company for the third consecutive year. We plan to spend roughly $300 million-$325 million to run two rigs in the Anadarko in 2021. We have delivered on our promises in the Anadarko, cutting costs and making the economics compete for capital in our portfolio. This is a great story of how we've used proven practices to rapidly change results. The tremendous cost reductions we've achieved in the Anadarko really have changed the game for the returns it generates. It's important to realize that although the D&C cost reduction is significant, it isn't the whole story in the Anadarko. We have seen cost savings across the entire supply chain, including an estimated 20% reduction in facility costs for 2021, and an 11% reduction in year-over-year operating expenses, now at a very low $2 per barrel of oil equivalent. It's not just a cost story. We are also innovating to make better STACK wells. As many of you have noticed, we continue to evolve our completion designs, which have led to very strong production results in our recent wells. We expect our 2021 program in the Anadarko to deliver a 65% internal rate of return. This asset not only competes for capital, but it is a significant driver of our de-leveraging plans in 2021, with the highest expected free cash flow generation of any asset in the portfolio. In the Montney, we demonstrated even lower D&C costs. About 85% of our wells were completed with simul-frac in the fourth quarter, and we averaged 19.5 hours of pump time per day, up 25% from 2019. Fourth quarter drilling and completion costs were $380 per lateral foot, down 25% compared to our 2019 average. We've now drilled wells at less than $300 per foot. When combining with low royalty rates and low operating costs, this asset delivers great returns on the capital we invest. Our 2021 program will be largely balanced between the Cutbank Ridge portion of the play in British Columbia and the Pipestone portion of the play in Alberta. We continue to see benefits from the Pipestone processing facility that came online late last year. We plan to spend roughly $375 million-$425 million to run three to four rigs in the Montney. I'll now turn the call back to Doug. Thanks, Greg. We've been at the forefront of the shift to the new E&P. We've been describing our approach and delivering on this model for several years now. Before opening it up to your questions, here are a few key takeaways. First, we're incredibly clear on how best to create shareholder value today, and that is to reduce debt. Second, amongst many attributes, we believe the new E&P must have size and portfolio diversity for future success. We have that today and are well-positioned to prosper. Ovintiv has been at the forefront of our industry's transition to the new business model. We are focused on generating free cash flow and delivering quality returns. We've done that for the last three years and are well-positioned to do that again in 2021. At 200,000 barrels of crude and condensate production and roughly 540,000 barrels of oil equivalent per day of total production, we clearly have the scale to be an industry leader in efficiency, risk management, and innovation to generate free cash flow and deliver quality returns. In fact, the rationale for much of the recent consolidation across the sector has been aimed at creating the scale we already have. We have proven that multi-basin provides a sustainable model to manage risk. Our world-class core three assets, the Permian, Montney, and Anadarko, provide operational and commodity diversification, cross-basin learnings, and more than a decade of inventory at our current development pace. We have the proven ability to drive leading innovations and generate significant free cash flow. Our operational execution and sophisticated risk management are differentiated. Our teams did a great job of safely reducing costs in 2020, and their efforts have set us up for a very strong 2021. Finally, we remain committed to returning cash to owners. We have a track record of doing so. It's how we are running the company. Our near-term focus on reducing debt is the best value add for our shareholders today. Thanks for listening to our prepared remarks, and operator, we'd be happy to take questions now. We will now begin the question-and-answer session and go to the first caller from Jeanine Wai at Barclays. Please go ahead. Hi. Good morning, everyone. Thanks for taking my questions. Good morning. Good morning. My first question is on 2022. I know we're getting a little ahead here, but the plan is to hold in maintenance mode through the end of next year at the 200 a day. Do you have any kind of directional commentary on what CapEx in 2022 could be relative to this year? I know there's a lot of moving pieces with inflation and divestitures, but it also looks like a lot of the efficiency gains that you achieved in 2020 are very structural. Yeah, Jeanine, great question. First thing I'd say is it is a little early, but I will tell you that first, to achieve that $4.5 billion debt target, we've built in no additional efficiencies beyond what we're delivering today and in 2021. It's a little early to guide on capital, but I would expect it to be similar to this year. As you've seen, we've been running at a fairly level-loaded program actually for several quarters now. I expect us to be able to maintain, if not improve, that capital efficiency. So I don't want to give you a precise number, but I think it will be very similar to what you're seeing this year. Okay, great. Thank you. My second question is just on the divestiture side. Can you talk a little bit about what your criteria is? For example, are you thinking about outright sales, or are you open to JV structures, and should we be thinking about potential candidates as primarily being the base assets, or are you potentially considering any longer-dated inventory sales from any of your core three plays? Obviously, today we're very pleased with the announcement on the Duvernay because that takes us more than a quarter of the way towards that target. We have a number of pathways to finish on that program. It doesn't involve our core assets. We have a number of options here as we do it. No, we're not looking to partner as part of that process. Next question comes from Brian Singer at Goldman Sachs. Please go ahead. Thank you. Good morning. Morning, Brian. If we net out the asset sales and asset sale objective, you're projecting about a $1.4 billion or so in debt reduction through 2022, and I think you mentioned you see $1 billion or so of free cash flow this year. Are there any reasons why, at similar oil prices, 2022 free cash flow should be meaningfully lower than 2021? Either the need to ramp up CapEx, which it seems like in response to Jeanine's question, you said not that, or any loss of free cash flow associated with assets being divested. If not, could there be upside to where debt reduction could end up by the end of 2022? Yeah, Brian, there's a number of upsides to this. Clearly, we announced that $1 billion target, I think it was in May of last year. Obviously, we've almost, before even the announcement today on the Duvernay, had already achieved about a half a billion of it. The other thing I'd just highlight here is the price deck used associated with that target is $50 WTI and $275 NYMEX. Clearly one of the upsides is if we see prices similar that we see on the screen today, that means we're going to get there even faster. The other thing I'd just highlight is, as you know, we've been working quite hard for a number of years now to eliminate some of these legacy costs, which actually don't add any value, have just taken value away from us. We have a tailwind from that coming for 2022. The last of the Panuke cost, which is the lease payments, end this year, and that'll be an $80 million tailwind as we go into next year. I think there's a great chance to deliver very similar free cash flow at the same price deck in 2022 as 2021. We'll need to see the net effect of any divestments. Today's announcement on the Duvernay, it's only 10,000 BOEs a day. It's less than 4,000 barrels a day of liquids, very modest cash flow. It's not really material to the cash flow side of the equation, but it clearly is material to the debt side. Great. Thank you. My follow-up, you discussed the resiliency of your drilling and completion cost reductions was notable in the fourth quarter relative to the first three quarters of 2020. At your 2021 plans base case, most, but not all of the reductions seen during the fourth quarter, can you talk about the upside risks and downside risks to achieving the D&C cost targets that you've highlighted in the Permian, Montney, and Anadarko for 2021? Yeah, Brian, great question. I'm looking over at Greg right now kind of smiling because you're going to help me set new targets for him here. You can see from the numbers we presented that we're not baking in better performance than we actually delivered in the fourth quarter. Clearly, the team's focused on upside. Maybe Greg, you might just highlight what's been driving some of these efficiencies and any risk you're concerned about in 2021. Yeah. Thank you, Doug. First off, really proud of the accomplishments of the team in 2020. We saw great efficiencies. One real example of that was how we rolled out simul-frac that, as you know, started in the Permian, and we moved that technology up to the Anadarko and up to the Montney and used it in essentially all of our plays, and that's going to be a big part of our cost reductions going forward. That, along with some of our slim hole designs and change well bore architectures, are going to allow us to drill our wells faster and complete our wells faster. As you know, time is money in this business. The fortunate thing is those are all structural changes, and those should be durable over time. We will see some headwinds on certain commodities, such as diesel and tubulars. We really have always counted on our efficiency gains to offset those inflationary pressures. We feel really good about what we've accomplished in 2020, and that strong tailwind at the end of the year just makes us more confident in our ability to deliver on 2021. The next question comes from Asit Sen at Bank of America. Please go ahead. Thanks. Good morning. I have one for Doug and one for Corey. Doug, you've been very clear on your capital allocation framework. Once you achieve or attain your debt level, just wondering your thoughts on the three options of returning cash to shareholders, growing fixed dividend, how do you feel about variable dividend, and then share buyback? Yeah. By the way, Asit, I appreciate the confidence you have on hitting that $4.5 billion target by asking us to get even farther than that. Look, right now. We've been very clear for a long time that we think the base dividend is an important part of the offer to shareholders, particularly in an industry like ours. As we've said, as the cash flow, and the cash flow at modest commodity price estimates grows, the dividend should grow alongside it. Beyond that, I think we need to see as we get closer to then, which are the best options to return cash to shareholders. Everything's still on the table, but we have a bit of time to think about that and to understand views of shareholders as we get there. I can promise you the base dividend will be a big piece of that offer. Great. Thanks. Corey, you highlighted confidence in dealing with the upcoming debt maturities. Just wondering, how does asset sale fit into the equation? You did Duvernay, and you have Eagle Ford on the hopper. What else is baked in that confidence? The REX contract, can you remind us when that rolls off? Yeah. Hey, good morning, Asit. In terms of the next two maturities, it's just over $1.1 billion. If you think about the free cash we talked about this year plus the $250 million from Duvernay, that's more than enough to deal with both of those. That's really the confidence in dealing with the next two debt maturities. Really part of the commentary there is the acknowledgement that we want to reduce overall debt and not just refinance and extend, even though those rates are a lot better than they used to be. I guess your second question was REX maturity. When does that roll off? Yeah. Randy, you want to pick that up? Sure. REX rolls off in mid 2024. The next question comes from Greg Pardy at RBC Capital Markets. Please go ahead. Yeah. Thanks. Good morning. Doug, I wanted to come back just to the dispositions, and I know there's been a couple of questions on it already. It's unusual for you guys to lay out a targeted disposition number. I'm just wondering if you can frame that a bit, maybe in the context of what the A&D market is looking like right now in your eyes. Yeah, Greg, it is a little unusual. The details on that, as you know, we never talk about assets that we may be selling until we've got a PSA in our hand, and a deal in place. In this case, we have a lot of dialogue with shareholders ongoing, and I think we have, and you've seen the market response to it, incredible support for maintaining scale and reducing debt as priorities of the company in laying out the $1 billion. The request we constantly get is that they know we've acknowledged that level still is higher than we wanted. Where were we aiming and when could we get there? One of the things that did concern us is many people that were modeling our company didn't believe we could get to something like a leverage ratio of 1.5 times at a modest commodity price at something like $50 a barrel until 2023 or even 2024. We felt it was important to give that guidance, because when you add that to reinvestment ratio of 75% or less, it gives a clear picture of the future. That's why we laid it out. We felt the market needed to understand not just what we were going to do in 2021, but when we would get to that target. On the A&D market, you've seen quite a bit of activity. What you really need, we've talked about this for a long time, is when prices are quite volatile, it actually tends to put a pause into that market because buyers and sellers fundamentally need to have some form of alignment in how they see the commodity within a reasonable range. Otherwise, getting to a deal is difficult. With the strengthening and the stability we've seen over the last several months, you've seen that come up. We're very pleased with the deal we've got with Pat and his team. It's a strong asset. I think it'll make a great foundational asset for them. Of course, we also saw another announcement on the Duvernay yesterday as well, which I think was a strong result. I think that shows that market is coming back. There is capital to be deployed, both from strategics and from privates, which is great to see because that's part of a healthy sector. Okay. Thanks for that. The second question is really shifting gears, but obviously big changes in terms of governance and compensation and so forth. Does that mean that, or should we read this as direct stock ownership amongst management and directors moving into sharper focus as opposed to just the LTIs settlement? Yeah, Greg. You know what I'm getting at, right? Yeah. It is. This is more complex than I think some people make it out. There's a great deal of views here. One of the things I'd just highlight, the LTI settlement and shares is something we established because you have to put this in your program way in advance. We started working on this three years ago. This year is the first year because we had shareholders pass an omnibus plan for us, I think it was a year ago, which allowed us to do that. These changes have been at work for quite some time. Of course, we also have to recognize that shareholders, the board, and management, in fact, all of our employees are exposed to the equity performance of the company. There's a great deal of alignment. The majority of our executive comp is in share-based units. They benefit when the shares are strong, and they see the downside. This further reinforces that. It's a practice some follow. We believed it was the right thing to do was do share settlement. This is the first year we're able to do that, but we put the program in place several years ago. The next question comes from Neal Dingmann at Truist Securities. Please go ahead. Morning, all. Doug, first question for you or Greg. It centers on the Anadarko Basin, specifically, you've got that plan, I think, in the slides, the two rigs, one and a half fracs. I'm just wondering, could you talk a little maybe about cadence or specifically how you're thinking about targeting? I like the returns both in the STACK and SCOOP. Just wondering how you're thinking about targeting those plays this year and into next. Yeah. At a high level, I think first I'd even take it up a level, because I know some people are wondering about the cadence of activity across the company over the year, because for a number of years we were front-end loaded. It's incredibly level loaded. In other words, almost take capital, divide by four. It's at a pace of activity we've now been running for a while, starting in the third quarter of last year and all the way through the fourth quarter. That's largely true right across the asset base, where we're doing activity. Greg, maybe you want to pick up the split between kind of STACK and SCOOP/Springer. Certainly. Just to reinforce Doug's comments there around level loading, we'll be level loaded in the Anadarko, as our other assets as well. As I said in my prepared remarks, about 15% of the program will be down in the SCOOP, so the remainder will be in the STACK. We feel like with two rigs, we can run those all year long and very efficiently develop that asset. As I said in my remarks, it's throwing off more free cash than any of our other assets in the portfolio. We're seeing really strong well results, and the team continues to impress with lower costs that we've seen not only in the STACK, but down in the SCOOP now. Feel really good about what we're accomplishing in the Anadarko. No, great details, Greg. Then follow-up, Greg, for you or Doug, again, just on that slide 11, it's really interesting on the performance and just the improving sort of D&C. My question is around the Permian in that slide. Could you talk a bit more just on sort of scale, size, scope of the completions, and including some of the simul-fracs? I'm just wondering, is there more to go, and will the slide another year from now will continue to show that kind of drop like you showed from fiscal year 2019 through end of 2020? Again, very nice performance there. I'm just wondering is there more to go there based on what you can do on size and scale, et cetera? Let me add a couple of comments and let Greg also jump in here. First of all, I just want to reinforce a point Greg made. The Anadarko at our 50,275 price deck is going to generate more than a half a billion dollars of free cash flow this year. I'll kind of repeat that. More than a half a billion dollars of free cash flow this year, still be the second-largest producing asset in the company. It shows what we've been able to do with efficiencies there. We should also highlight, Greg mentioned in his comments that we're talking about operating cost of $2 a BOE. These are incredibly low numbers compared to many plays in North America. I think on the Permian and elsewhere, just one comment I'd make, and want Greg to jump in here, but the simul-frac, I mean, we all talk about technology, and we have images sometimes of huge amounts of complexity and digital and all sorts of things. This idea of simul-frac is incredibly simple. It's one of the biggest improvements in a number of years we've seen in efficiency in our business. It just shows that innovation sometimes isn't all that sexy. Some of it's just thinking this is really about plumbing, is what this was really about. The other comment I'd just make before I hand it to Greg is one of the things we're most proud about, we first did that in the Permian, and literally weeks later, it went right across the company. This is something I think is pretty unique to us, is that we've got this culture of innovation, and we've got this culture of teamwork where the various operating teams, because we have an asset-based structure, where they learn from each other, they learn from our competitors, but they're constantly trying to drive better results. At a very high level, without setting Greg's targets for 2022, I absolutely believe we'll have greater efficiency next year than this year. Greg? Yeah. Thanks for that lead in, Doug. Just to build on first the question around simul-frac. I think it's really important to remember that when we're using simul-frac, we're fracking two wells at the same time, but we're not changing the scope. We're still pumping similar fluid, similar sand rates per foot, and pumping at a similar rate per cluster into the well. You're seeing the same intensity downhole that you would if you were fracking those wells independently. The scope of our jobs is not changing. Shifting to the continuous improvement, we've established a culture of continuous improvement here at the company. You're not going to ever hear me sit here and say that we're done, that we've done the best that we can do, and that things aren't going to improve. Not ready to set new targets here on the call, but I do feel like the teams will continue to innovate, will continue to bring out new ideas, will continue to have new things that we bring forward and talk about. I think the company and the asset teams will continue to get better and better over time. The next question comes from Josh Silverstein at Wolfe Research. Please go ahead. Yeah, thanks. Morning, guys. Just following up on some of the comments there on the Anadarko Basin. You mentioned how much free cash flow it's going to be getting this year, and yet the allocation is half of what the Permian is getting. Can you just walk through why that's the case, why you're taking capital from your best free cash flowing asset and putting it into another asset? Yeah, Josh, we've talked about this for a while. The good news in our portfolio is we have strong returns right across the portfolio. We don't feel like as we distribute capital across the asset base, that we're actually trading off returns as to do that. As you've seen, we've seen it again with these weather events this week, that there is real risk-based benefit on having a multi-basin portfolio. Obviously, operations in Texas have been impacted, but other assets of the company are full steam ahead today. I should just mention, by the way, because I know it's a big topic, we're already bringing production back online in parts of our Texas and Oklahoma operations. The areas outside of those were not impacted by this weather and have continued to produce strongly. The full impact of that, I do not expect it to change our guidance for the year. That will be the approach we take, but I'm confident we'll find our way through that. I think as we think about allocating capital, we do need to allocate capital across our core assets, otherwise we aren't a multi-basin company, and we're not extracting the full value from it. Of course, it also allows us to get these other benefits of shared learnings. The learnings don't just come from the Permian, they come from across our asset base and are quickly spread. When we look at the total company result, we feel very comfortable with it, and it's also consistent with our risk-based approach to multi-basin. No, thanks for that. Then, I do appreciate the changes on the compensation structure as well. I was hoping maybe you can provide a little bit more detail just around some of the targets in there. You mentioned free cash flow and debt reduction is going into the annual numbers here. What are the targets for that? I'm just curious if they're the same as the billion-dollar free cash flow level, billion-dollar debt reduction that you guys are looking at. I'm just curious if you're able to provide some more detail there. Yeah, I'll just make a couple of comments here. First, this goes back, I think, seven years ago now. We radically simplified our scorecard for the company. We typically only have four or five measures, and usually we only have one operational measure. All the rest are financials. That's been in place for a long time. What we actually work hard to do with the board is align the annual incentive, the bonus scorecard, not only with the objectives that particular year, but they need to be also linked into the longer term. There needs to be some connectivity. Yes, there is strong linkage in all of those measures to the guidance we've given you today. That's where it is. The other thing I would say here, because there has been a lot of dialogue for several years now with investors about bonus payouts across the sector, and our board, working with their compensation consultant, did a piece of work last year which actually showed that our sector did have a bias to pay out more than target compared to the broader marketplace. That was just fact. It's just analytics. It's just data. What they did is we've taken that on now, and it substantially enhanced the rigor because you just can't deny it that our industry was paying higher than typical bonuses for the broader marketplace, which says something about the rigor and toughness of those targets. That's now been built in. For us to achieve better outcomes, we have to even achieve better performance, and poorer outcomes will actually receive less reward. I think that's all very healthy, and I think it's recognition of just actually taking a broader look and not just looking across our sector, but looking at the broader marketplace. The next question comes from Richard Tullis at Capital One Securities. Please go ahead. Hey, thanks. Good morning, Doug and the team. Congrats on a good quarter. Interesting free cash flow pie chart on slide 10 of the presentation using the $50 oil and $2.75 nat gas. How does that allocation change using something closer to current commodity outlook for 2021, say $60 oil? I'm guessing the base contribution maybe gets a little bit larger given the highest overall oil mix there. I don't have the exact details, but I can tell you in total, I think Corey mentioned this as well, that at the $52.75 deck, we expect to generate around $1 billion of free cash flow this year. At the current kind of strip you see, that number jumps to almost $1.5 billion. We clearly have access to the upside. Given the shape of that curve, it's going to be more weighted towards the oil assets than the gas assets because there's clearly about a $10 difference in the strip on oil and a smaller difference, about $0.20-$0.30 on gas. You're going to see the oilier assets do a bit better. I don't have the exact split for you. Okay, that's fine. Kind of just keeping with the theme of comparing the different areas. You discussed the highest rate of return for the Anadarko Basin asset on $50 oil. How do those assets kind of rank using $60 oil and, say, $3 gas? Yeah. It kind of floats all boats here, actually. It moves a little bit around because the other thing, of course, as I know you know, basin diffs play a role in here. Of course, the nice thing about our portfolio, the three core areas receive very good pricing. I haven't talked about it a lot on the call, you probably have noticed we've been receiving WTI plus for condensate in Canada this year. Of course, our Permian and Anadarko assets are very well positioned in the market and with our transportation agreements. You have to look at it carefully, I think the thing I'd stress here is it's not just about the price at the moment, because obviously when you make these investments, the return isn't just what happens in the first few months, it's over the life of that investment. I know that there's been a great deal of talk over the last six months about natural gas prices, and we were fairly optimistic for 2021, but we actually think that it's very difficult for the market to break out much different than we actually see longer term in that price deck we're using for this year. It isn't just the price on the screen at the moment that we have to think about, it's about where they're headed. I guess the last point, I think, not only are we one of the largest crude and condensate producers and one of the largest natural gas producers, and we also produce 80,000 barrels a day of NGLs. You may have been watching prices of propane, which have been very strong for quite some time now. The final question comes from Noel Parks at Tuohy Brothers. Please go ahead. Good morning. Morning. Just wanted to follow up to some of what you're talking about on the gas environment. If we look bigger picture, I've definitely heard some commentary that lack of liquidity in the further out months of the strip, months and years, sort of understates the demand drivers we have ahead. Do you think we are more in a time looking toward, if anything, especially as you de-lever, letting more volumes go out to the spot market, as opposed to hedging? Are we more at the end of the spectrum where this is the time to be thinking about incremental long-term gas agreements, gas purchase agreements, for example, to support further growth in LNG? Are we kind of looking at just a year or two ahead spot world? Are we looking at more transitioning to five, 10-year locking in those sorts of arrangements? Yeah. It's a good question. I take you back to the fall of 2013 when we laid out our strategy, and we said that there were four things we felt were crucial to have a sustainably strong performance in this sector. I'd highlight that one of those was markets and fundamentals, that you need to think you obviously have to have quality assets. If you don't have quality assets, it's very difficult. You also have to think about your access to markets, your commitments and cost to access those markets, and the risk you take with them. That's been built into our thinking all along. Where gas goes, the dilemma here in North America is there's a great deal of low-cost gas. There is a huge amount of low-cost gas. It's been great to see the export markets grow. I think we're at about 11 Bcf a day of LNG leaves the coast. We're about six Bcf a day that goes into Mexico. That's massive growth. Despite that, it's been difficult to move the domestic price. The reason for that is this industry's really good at finding in low-cost development of natural gas, which is what we think binds the price. The LNG market, as we've seen, has got new volatility in it because of this 11 Bcf a day. In the past, you might have felt like accessing some of that market could provide upside. Of course, last year it was just the opposite. It was considerable downside as affected. It's something we look at carefully, but I think we also have to be careful that normally those agreements require long-term commitments. The hardest part about prediction is predicting the future. We just have to consider that risk. It's something we do talk about and look at on a fairly regular basis. Got you. Thanks. I apologize if this has been touched on before, but I wonder if, especially after we've seen sort of this extreme weather that's kind of brought a force halt to a ton of industry activity across multiple basins. Have we finally hit the trough, would you say, in service costs at this point? I was wondering in your reserve assumptions, both on the five-year SEC rule on CapEx or in just what you've embedded in the PV-10 from operating expense assumptions. Did you assume a flat service materials cost scenario going forward? Or did you turn to putting in some inflation there? Yeah. What we actually did is assume we'd have total cost of the wells would be the same as today. In some areas we know, for instance, diesel costs are going to go up as the price of oil goes up. Greg also mentioned steel. Overall service cost, I think if you look back at 2015 and 2016, obviously, the industry recovered strongly in 2017, in 2018, and 2019. Service costs really didn't go up significantly. In fact, in many cases, they went down. Because I think one thing we forget about is just like we try to drive our efficiencies, reduce our costs, provide more efficient operations, the service guys do that too. As Greg said, even if there is inflation there, we're confident we can deliver on those numbers because the biggest single driver for us now going on almost eight years on cost reduction has been innovation. It's been constantly innovating on how we drill and complete wells. The idea that we drill some of these wells in five or six days, we're now completing almost a mile of a lateral in 24 hours. These were unheard of just a couple of years ago. Those aren't service cost related. That's the execution and the design of the activity. I do not believe that will quit. I know it's not going to quit here. I don't think it'll quit in the industry. The short answer to your question is we've assumed the same well cost in next year as this year in that debt target. The exact mix of what innovation will do for savings and any cost inflation, we believe that's actually a safe estimate because also our numbers this year in our budget are slightly higher than we delivered in the fourth quarter. We've actually been at lower costs than we've used in that planning forecast. At this time, we have completed the question-and-answer session, and we'll turn the call back over to Mr. Campbell. Thank you, operator, and thanks everyone for dialing in today. We appreciate your questions. Stay warm, stay safe, and we look forward to seeing you soon. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.