Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2020 Second 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. Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Ovintiv. I now would like to turn the conference call over to Steve Campbell from Investor Relations. Please go ahead, Mr. Campbell.

Thank you, operator, and welcome everyone to our second quarter conference call. This call today 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 which we filed with SEDAR and EDGAR. Following today’s prepared remarks, we will be available to take your specific questions. Please limit your time to one question and one follow-up as always; this allows us to get to more of your questions today. I'll now turn the call over to our CEO, Doug Suttles.

Thanks, Steve, and good morning. We appreciate you dialing in for our mid-year update. What a quarter the second quarter was. Clearly it wasn't typical or normal, at least I hope not. What did we accomplish? Well, first I have to say that the list would be impressive if it represented the whole year, but it was all completed in three months. To begin, and most importantly, we delivered outstanding safety performance. Second, we effectively managed COVID risks with the vast majority of our workforce back in the office since early June. Our protocols have been highly effective. We've had zero instances of the virus being transmitted in either our offices or field locations since the beginning of the pandemic. We delivered strong financial and operating results given the environment, probably highlighted by the fact that we generated free cash in the quarter. We rapidly reduced capital spending with no penalties—maybe unique in the sector. We created a dynamic, real-time shut-in strategy that enhanced revenues and cash flow. We realigned our workforce to our view of future activity and to drive further organizational efficiency. We continue to set efficiency records in our development programs with industry-leading cost and capital efficiency. We highlighted the resiliency of our business through our six-quarter stay-flat scenario, which shows how we're positioned to thrive as a recovery happens. And we've made it very clear that excess cash flow over the next six quarters will flow to the balance sheet and debt reduction. Our business and our culture were purposely built with flexibility, as we fully recognize the importance of being able to respond to the dynamic world we live in. I'm joined today by other members of our team who will help describe how we're performing and where we are headed. But I have to say to our organization that I could not be more proud of your resiliency and your accomplishments over the last few months. As you, like everyone else, had to live with the incredible uncertainty and stress that COVID-19 has created. So thank you. During one of the toughest times in our industry, we adjusted rapidly and generated free cash of more than $50 million in the second quarter. We had very strong operating performance and today we're providing a stronger outlook for 2020. Importantly, the momentum we're generating to lower cash costs and drive efficiencies provides high confidence in the 2021 scenario we shared with you last quarter. Our 2020 well cost across our three core plays are now down 15% when compared to 2019 averages. Well costs were down 9% after the first quarter and now 15% at mid-year. We have near-term line of sight to additional savings. You'll hear more on this from Greg in a moment. The majority of these savings are durable and are a result of our team's constant innovation. We have extremely high confidence that our objective to lower well costs by 20% over the next six quarters will be achieved very soon. Although not formal guidance, our 2020 and 2021 scenarios showcase the flexibility we've built into our business and our ongoing progress to reduce costs so that we can maintain scale and generate free cash, as we did in the second quarter. Our strategy is intact. But clearly given the impacts from the pandemic, it is appropriate to hit the pause button, focusing on generating free cash while maintaining scale. And that is our plan. Note that in the past two months, our passive ownership has nearly tripled from where we started. As a product of our domicile move to the U.S. earlier this year and our addition into important indices like the Russell. This move was clearly good for all shareholders, regardless of which side of the border you reside. And lastly, you'll notice today that we're committing that all excess cash flows over the next six quarters will go to debt reduction. Even if commodity prices are much higher than we currently see, we will continue to direct that additional cash flow to debt reduction and not to additional drilling. Our second quarter achievements have strengthened our 2020 original scenario; we lowered total CapEx and raised fourth quarter average production. We're on track for our 2020 stay-flat scenario that generates free cash inclusive of our dividend at a modest $35 oil price. Maintaining 200,000 barrels a day of crude and condensate with an investment of $1.4 billion to $1.6 billion screens as one of the best capital efficiency scenarios in our peer group today. This slide makes note of the key ingredients behind that scenario. Capital efficiency gains are well in hand, and our multi-basin portfolio offers multiple ways to win. But there are some additional improvements also worth mentioning today. We expect that our base decline will improve by about 5% to the low 30% range in 2021, adding material production and cash flow. Our cash cost savings this year estimated at more than $200 million increased by an additional $100 million next year, as our legacy costs are down significantly. And please take note of the commodity price sensitivity shown at the bottom of this slide. We generate an incremental $375 million of cash flow for every $5 move in oil price. Because of our legacy dry gas production, a $0.25 move in gas price yields an additional $140 million in cash flow. Stronger oil and natural gas prices could significantly accelerate our debt reduction plans over the next six quarters. In fact, the current strip would have us generating significant excess cash flow next year. Our priorities for the next six quarters are crystal clear and can be categorized under these four key buckets. First and foremost is financial strength and debt reduction. We have made important adjustments to our business to ensure we maintain a strong balance sheet with deep liquidity. This is critical in volatile times like today, as we focus on generating free cash flow; we're committed to preserving liquidity and further strengthening our balance sheet through debt reduction. We're confident in our ability to generate free cash flow as we continue to push the frontier of capital efficiencies and cost structure. Our focused efforts on margin enhancement and innovatively creating new ways and durable efficiencies will be critical over the next six quarters. We also know that maintaining the scale of our business is important and will allow us to participate in the recovery as global demand for our products return, and it will return. We ran numerous scenarios to optimize our activity levels, investments, managed declines, debt levels, costs, and a host of other factors. This scenario we've shared with you for the next six quarters is the product of that work. Obviously, our second quarter production was impacted by our voluntary shut-ins, dropping two-thirds of our rigs in all of our frac spreads. But we were able to maintain our significant scale and position us for a fourth quarter average production of 200,000 barrels a day of crude and condensate. We can't achieve any of this without our team. Ensuring their health and safety is a deeply held value. We reacted quickly to COVID-19 to protect the health and safety of our workforce in the field, and we use those learnings to safely return to the office. I'll now turn the call over to Corey to discuss our financial results.

Thanks, Doug. Our business performed very well during the second quarter, which led to the stronger outlook we just issued for the second half of the year. We again demonstrated our ability as a world-class operator and delivered solid execution during a very challenging time. Our second quarter capital investments were just over $250 million, at the very low end of our guidance range. In addition to outstanding second quarter capital performance, we revised our 2020 capital scenario to $1.8 billion, the low-end of the $1.8 billion to $1.9 billion range highlighted last quarter. Our reported production was 537,000 BOEs per day, and 198,000 barrels per day of oil and condensate. Reported production was impacted by voluntary shut-ins due to extreme commodity price volatility. When normalizing for second quarter shut-ins, our production would have been 569,000 BOEs per day and 216,000 barrels per day of oil and condensate. We remain one of the largest independent oil and condensate producers in the sector today. Our strong operational performance and continued capital efficiencies are once again proven by our second quarter performance and demonstrate our organization's flexibility and optionality. Through the second quarter, we delivered free cash flow during a very challenging period. We made the right decisions early to reduce investments and ensure we preserve liquidity. We generated $385 million of cash flow or $1.48 per share, if you exclude one-time costs. Our total cost per barrel of oil equivalent were down 8% quarter-over-quarter and reflect the continued cost reduction efforts throughout the company. At quarter-end, we had $3 billion in liquidity under our credit facilities. And as I've mentioned before, these are locked in until July 2024 at favorable terms. While our net debt increased during the second quarter, this was largely due to expected one-time items. We had a few non-recurring items such as the $81 million in restructuring costs following our workforce reduction and $62 million associated with the abandonment of our Deep Panuke wells and offshore facility. As you know, we've been decommissioning this platform over the last few quarters, and I'm happy to report it has now been removed and delivered safely to shore. The remaining item is related to a decrease in accounts payable owing to our significant activity slowdown in the second quarter. We expect this impact to reverse as we return to our normal activity levels over the third and fourth quarters. I'll turn the call back to Brendan to provide additional insights around our scenarios over the next six quarters.

Thanks, Corey. Our outstanding results through the first half of 2020 have further strengthened our confidence in the scenario we've outlined for the next six quarters. Capital efficiency, cash cost reductions, and production are all moving in the right direction. This has caused us to lower our capital and increase our production estimate for this year. For the second half of 2020, we expect to invest about $760 million resulting in a lower full-year expenditure of $1.8 billion. This is nearly a $1 billion less than our beginning of year budget. Today, we raised our 200,000 barrels a day oil and condensate exit rate to a fourth quarter average rate. These data points again prove our top-tier operational excellence and capital efficiency performance that continues to differentiate us from many of our peers. Due to our second quarter frac holiday, third quarter production will mark the trough for the year. As we prepare to resume completions in the third quarter, our oil and condensate production will average 200,000 barrels a day in the fourth quarter. As we look out to 2021, our scenario gives real insight into just how efficient we have made our business. It is not enhanced by carrying in a big batch of ducks; it reflects a low level program. This is important because it means we can repeatedly hold scale and generate free cash flow from our business at very low commodity prices and obviously can generate a lot of free cash flow if prices stay where they are today or even move higher. You'll hear more from Greg but midway through this year, we've already achieved about three quarters of the capital savings built into our 2021 scenario and nearly half of the cash cost savings. I'll now turn it over to Greg.

Thank you, Brendan. We expect to deliver more than $200 million in cash cost savings this year. That's more than double our original estimate. At mid-year, we're about halfway there. These savings are being derived from the hard work of the team, leaving no stone unturned to enhance margin and optimize cash flow. Reduced operating and midstream costs, lower G&A, and other initiatives are coming through in second quarter results. More importantly, the majority of our savings are durable and not subject to change as oil prices strengthen. For 2021, we expect to see an incremental $100 million of cash cost savings as we benefit from lower legacy costs, reduced midstream commitments, and lower G&A, among other items. We posted some significant reductions to our completed well costs again in the second quarter. The teams are getting it done today. Their hard work and ingenuity are really making a positive difference in our outlook for the next six quarters. We updated the slide from the first quarter earnings deck to reflect our latest accomplishments. As you can see, our updated go-forward well cost table in the upper right, we continue to meaningfully drive down our drill, complete, and equip costs in our active areas. We posted $400,000 less in the Permian and $200,000 less in the Montney. In the Anadarko, our costs are now 40% lower than Newfield's average cost at the time of the acquisition. Our second quarter costs were 15% lower than our 2019 average, showing another gain from first quarter. We have set new pacesetter results in each of the plays and have high confidence today that our 2021 costs will be at least 20% less than our 2019 actuals. Importantly, we view our well cost reductions as highly durable. These are through-cycle savings or in large part due to our unique innovation and process changes, not simply lower service costs. In the Permian, our leading edge Simul-Frac completions are saving $350,000 to $400,000 per well and given our multi-basin portfolio, we plan to apply Simul-Fracs in our other drilling areas in the near future. In the Anadarko, performance continues to get better and better. We have rapidly achieved best-in-class Springer drilling results in the scoop, and are now averaging over 20 hours of completion pump time per day, significantly above historical basin performance. The Anadarko is prime for additional capital cost initiatives such as Simul-Frac facilities and savings in water sourcing and disposal. This will continue to push costs down and enhance our rates of return. In the Montney, we set a completion record in the second quarter with almost 35,000 feet completed per day. The team continues to push the efficiency frontier, solidifying our position as the clear leader in the basin. In total, our well cost facilities are down over 15% since 2019. These savings are driven by the collaborative efforts from an innovative multi-disciplined team dedicated to optimizing the scope and design of our well facilities across the company. Before I turn the call back to Doug, let me take a moment to commend the great work our team has accomplished. Recent volatility related to COVID-19 and lower oil prices created some unique challenges for all of us. But our teams have adapted and persevered to perform at their best while instituting new protocols to stay safe in the office and in the field. This agility led to our strong results in the second quarter, and will generate differentiated performance as we return to completion activity in the second half of the year. I will now turn the call back to Doug to close this out.

Yes, thanks, Greg. Let me comment now on how Ovintiv is positioned with some big industry narratives that are more frequently discussed today. We have scale in our business; we are efficiently holding our position as one of the largest crude and condensate producers in the sector. Across our core three assets, less than 1% of our acreage is located on federal land. We have a multi-year track record of both superior execution and returning cash to shareholders. We generated over $50 million of free cash in the second quarter in arguably one of the toughest quarters our industry has seen. Over the last four quarters, we generated $290 million of free cash. This is how we are committed to running our business. Our multi-basin portfolio provides shareholders with multiple ways to win. Although our strategic focus is on liquids and crude and condensate in particular, we do produce 1.5 BCF per day of gas and will clearly benefit from strengthening natural gas prices. Before opening it up to your questions, here are just the key takeaways from today. First, we know how important it is to maintain our business scale, and you should have confidence that we've put a lot of thought into our stay-flat scenario, which we highlighted today. Hopefully, you've seen the progress we've made in underpinning that case. Our performance is a continuation of our track record of excellence and capital efficiency. Simply put, we are finding new ways to safely stretch our dollars and deliver more for less. Our increased fourth quarter 2020 crude and condensate production will now be generated for $1.8 billion, the low-end of the previous capital range. Third, our massive flexibility and our culture is an asset that provides us with options many don't have. When coupled with our multi-basin portfolio, we're using all options to make the right decisions today that will put us in the best place for tomorrow. And finally, we know the importance of a strong capital structure and are laser focused on preserving liquidity, maintaining a strong balance sheet, and reducing debt. Just to be clear, over the next six quarters all excess cash flow will go to reducing debt. Although the timing of oil demand recovery is uncertain, we know that it will recover. The world needs our products. Our products make modern life possible, and we intend to be positioned to thrive on the road ahead. That concludes our prepared remarks, and we'd now love to take your questions.

Thank you, sir. We will now begin the question-and-answer session and go to the first caller who is Brian Singer at Goldman Sachs. Please go ahead.

Thank you and good morning. Doug, you are very clear about where the free cash flow is going over the next six quarters. I just wanted to ask, it's more of a follow-up on that, more philosophically—and maybe even beyond those six quarters—what net debt or leverage is sufficient for Ovintiv, where you would drill again, and what net debt or leverage is sufficient where you consider incremental return of capital to shareholders?

Yes, Brian, thanks and hope you're doing well. We've been talking about this for a long time, and if you go back to some of our conversations just a couple of years ago, we said that targeting something like a leverage ratio of around 1.5 at mid-cycle pricing was right. I suspect off the back of what we've all been through this year that that target number is dropping over time; we'll see we obviously have some room to go to get there. One of the comments I made in the remarks was that we still believe our strategy is intact, and it's the right strategy. We have been strong advocates for quite some time. That modest growth with free cash generation that would be distributed back to shareholders was the right way to run an oil and gas company. Clearly, what we've said is it's appropriate to take a pause; the demand for our products is taking a hit. It's obviously recovered quite well over the last few months, but still has a long way to go. So for the next six quarters, any and all free cash we generate—and of course, we've highlighted that $35 oil—we can actually hold the business flat, pay our dividend, and at prices above that, we can generate significant cash flow which would go to the balance sheet. As we go to 2022 and beyond, we need to see where we're against that objective. At what point we return to modest growth with the return of cash to the investor, but that strategy is still our strategy. So I think it's a little premature to speculate beyond the end of next year. But clearly, I think we've articulated how we're going to run the business over the next six quarters.

Great, great, thank you. And then my follow-up, you talked in your comments about the underlying decline rates of your base declining. I wondered if that's just a result of a reduced drilling program, playing out after a year as a lower percentage of production comes from wells in their first year, or as you look across the portfolio in the major fields, are there measures you are taking to lower the decline rate or wells that are declining at lower rates than expected?

Yes, Brian, great question. It's largely the effect of obviously, when you're in lower growth or no growth, your decline shallows out every year. I would say we're having exceptionally strong base performance right now. But that really isn't what's driving that number; if that's sustained year-over-year, that could actually represent some upside. This is largely the effect of slower growth rates; you end up with a shallower total base decline.

Thank you. Next question will be from Greg Pardy at RBC Capital Markets. Please go ahead.

Maybe just as a follow-up and team, sorry. As a follow-up to what Brian was asking, so how are you thinking about mid-cycle oil prices now? Is that still $40 to $50 in your world, or has it shifted down?

Yes, Greg. I think our team still believes that that mid-cycle pricing probably still is around $50. There's lots of discussion and a lot being written about the longer-term impacts of the significant reduction of capital. Clearly, shale has shrunk a lot over the past few months and I think plans like ours will be relatively common and some people may even have plans to shrink over the next six quarters. Activity outside of shale is very low globally around the world. So we still think that mid-cycle pricing is probably somewhere in the low to mid-50s, and natural gas prices, which clearly are looking like and setting up fundamentally to be potentially very strong next year. Longer-term, we still think that $2.75 range is probably more the mid-cycle. Obviously, we've got a ways to go, and this is all going to be predicated on in the near term about economic recovery around the globe and dealing with COVID, and after that, it's really about what happens to capital investment not just in shale but around the globe.

Okay, thanks for that. And then really switching gears and going just back to the Anadarko, where you guys have done a tremendous job in terms of driving down your D&C costs. Greg, you mentioned further inroads in cost in terms of simultaneous fracs, and then just the water disposal. So I think the pace that the wells are 4.5 million, I mean is 4 million in your sights? I'm just trying to get a sense as to what might be possible if you implement those changes?

Greg, thanks for noticing the continued improvement we've had in the Anadarko. I think the first thing I'll tell you is that the team is relentless in driving out costs and will continue to turn over stones to find ways to get costs down. We have not implemented Simul-Frac there yet; that is something that we're going to be trying later this year. We've reduced costs on our water, both delivery and disposal. We're still pumping our jobs at faster and faster rates, which make our cycle times go down—all of which will be durable savings. I think if we were to challenge the team, you've taken out $3 million; how much more can you take? I don't think wells with a four handle are unrealistic at all.

Greg, I would just add one comment to Greg's. We were speaking not too long ago with one of our biggest shareholders, who said we had publicly said we were going to take those well costs from 7.9 to 6.9. He was kind of probing on what was our real internal target and of course, we've now delivered 4.9. I don't know if we can get to 4, but 4.9 is kind of in the pacesetter zone, so clearly making that the average well is the next target. I did tell him this team has shattered every record and every objective we've had. The pace of innovation, the building on the learnings and experience we had around our portfolio, put us in a very advantaged place to do business. There's a very talented labor pool in Oklahoma and very good contractors. We operate in a very good market, with water costs pretty low. So applying these practices, I have to say I never dreamed that we would have a four handle along our wells, and I'm pretty confident that's going to be the average well pretty soon.

Thank you. Next question will be from Josh Silverstein at Wolfe Research. Please go ahead.

Thanks. Good morning, guys. Just a question on the debt. You're up to $7.4 billion right now. I know you mentioned wanting to get to a 1.5X leverage target, but I wanted to see why not think about this in absolute terms. As you've seen this year, the EBITDA can obviously move much lower while the debt stays the same or goes higher. Just wanted to see what the next target is—that certain debt level from your free cash flow and/or asset sales underlying?

Yes, Josh, I think that that some degree, these are somewhat hypothetical questions or at a minimum, they're questions way out into the future, given the current environment that we're in. Of course, the problem you have is the only dimension in the business is debt reduction. If you're prepared to do anything just to get that number down, I'm not sure you'd have a relevant company. Clearly, the world is going to recover, demand for our products is going to return. What we've done a lot of work on, and Brendan referenced this, is trying to figure out how to balance and aggressively go after debt reduction, without doing it at the expense of having a robust business that can participate in recovery. What we've highlighted is that even if you use the current strip, we're going to generate substantial free cash flow next year. Every bit of that will go to the balance sheet. You may have noticed we've also begun to build our 2021 hedge book, which has got a price today considerably above $35. Many people, including our team, believe there's considerable upside on natural gas prices next year. We have to be careful in today's environment, so setting out that one-dimensional target is a concern. But I do hope you've heard that we're laser-focused on this. It's not a threat, but it is something we're very focused on getting down both the leverage and the absolute debt level, but it's somewhat theoretical just to look at that number in isolation.

Understood there. And then just a question on the DUC, I know you're going to be drawing some data now in the back half of the year. You said you plan to exit 2020 with a normal DUC backlog. What is that backlog you expect at the year end? Also, as you look into 2022, would you expect it to be the same level based on the $1.5 billion spend next year?

Yes, Josh. Great question because one of the things we're stressing, because I know people are trying to understand, is that capital efficiency for companies driven by just completing DUCs isn't sustainable. We expect to exit this year with 20 to 30 DUCs, which is pretty typical. We would expect to exit next year at the same number; this is a very sustainable level. A loaded program, and the capital efficiency is not driven on DUC completions; it's actually driven, as Greg said, with innovation, technology, and the incredible transfer of ideas across our teams, which is leading us to be essentially the most efficient operator in every place we operate.

Thank you. Next question will be from Arun Jayaram at JPMorgan Chase. Please go ahead.

Yes, good morning. Doug, you clearly have put a lot of pen to paper on 2021; it sounds like we should expect a pretty level-loaded program. So I'm wondering if you could maybe give us some thoughts on just capital allocation to your different plays—obviously, probably focused in the core three—plus kind of a sense of activity levels on the drilling and frac spread side?

Yes. Now that we've got the big frame landed, we'll be working on the detail. Oddly enough, it's not even August here, but this is the time of year we start refining our budget for the following year. I would say that it probably will look similar to how we've been, where the vast majority of capital would be distributed to our core three. As you know, today, we're running seven rigs, three of those in the Permian, two in the Anadarko, and two in the Montney. We did drill some wells in the Bakken, in the Eagle Ford, and in the Uinta earlier this year, and we'll be completing those here starting later in the quarter and into Q4. But I think the bulk will be across those three, and it'll probably be similarly situated to what we've been running recently. But just want to caution you, we haven't done that full optimization yet. But that's, I think, where your expectation should be.

Great. Just a follow-up for Corey. Corey, could you just maybe elaborate on the impacts from the accounts payable on the debt balance in the quarter and maybe run through— you've added some hedges; we kind of know what your capital is going to be next year—but any thoughts on free cash flow generation over the next six quarters if we use the strip and think about your hedge balances today?

Yes, hi Arun. I think on the second part of that question, we've laid out the scenario for 2021 that we've said covers the dividend at $35 and $2.75, and pointed to the commodity price sensitivities there as well. I think with the language we've used as substantial free cash flow and significant free cash flow at today's strip. So obviously, we see that shaping up pretty well. And we started to layer in some protection to that end. I think on your—on the first part of that question, if you remind me, I forgot what you're asking about in that.

When you put this in the release, just the debt balance did go up. And it's just a function of the reduced activity levels and you're paying some of your bills; just wondering if you could talk about the specific impact and thoughts on that on a go-forward basis?

Yes, in real simple terms, we tend to pay our invoices on kind of a 30 to 45-day cycle time. If you think about our activity levels, we dropped from 23 down to seven rigs; so a lot less activity, a lot less payables accrued. As we continue to pay our bills and slow down the activity, that balance was just drawn down over the quarter. The explanation that I gave in the prepared remarks, really, that's just referencing how to get back to a normal level of activity and creating a normal level of accounts payable is all that is.

Thank you. Next question will be from Asit Sen at Bank of America. Please go ahead.

Thanks. Good morning, two unrelated ones. Doug, just coming back to the earlier answer on essentially sustaining production, let's say in the $1.4 billion to $1.5 billion CapEx level, should—in terms of rig count—should we expect similar rig count seven, eight, nine, and in terms of allocation, three, three in the Permian? Is that conceptually how we should think about a sustaining world?

Yes, I think if you look at it, we've given that $1.4 billion to $1.6 billion capital range. If you cycle it around $1.5 billion, it looks like seven to 10 rigs. Of course, that varies a little bit because of different net interests and other things. Roughly, it'll be concentrated in the three with proportion; I think the split is a good place to start. What we'll always do is go refine that and look to optimize that as we go forward. We haven't gone through that step; that's the next step at this point, but it's not a bad place to begin. I think seven to 10 is a little more active than we were during Q2, but not a lot.

Appreciate the color. And then my follow-up is you've completed your domicile change a few months ago and it looks like passive ownership has gone up. Just wondering if you could update us on your thoughts and conversations with indices, et cetera?

Yes, this has largely played out like we expected because it varies by which index you're referring to. Some have fairly prescriptive processes on when and how they do it, and others have a bit more flexibility built in. Whether it's MSCI or Russell or others, we've been included in all of those. That's driven us from 7% passive to 22%, and as all the filings come out, you'll see that some of the big index institutions are now some of our biggest shareholders. We're in the S&P, TMI, but you may have seen the rebalance in the Ford-600 come out yesterday. There was no movement in energy. That wasn't a surprise given what's happened in energy. It's a further upside for us because at some point, we fully anticipate being included in the S&P 1500, which piece we'll have to see. So we're pleased with the substantial progress, and there's still a fairly big piece yet to come.

Thank you. Next question will be from Jeanine Wai at Barclays. Please go ahead.

Good morning. My first question is, I saw in the follow-up on Arun's question on 2021 and free cash flow, in the 2021 maintenance case and the unhedged price sensitivities, given the amount of natural gas that you're producing in Canada—and the focus on free cash flow for the company, I think is great. What AECO pricing are you assuming and appropriate breakeven forecasts, and what's the sensitivity on that? We've seen the WTI and the NYMEX gas sensitivities and they're all really helpful, but I'm just trying to tie things together.

Yes, good question. Of course, I know you follow it. AECO has been performing on a relative basis quite well. A number of things are driving that, including record low rig levels. Even with some of the seasonal comeback, we still think the activity—which we don't focus on gas obviously, we produce gas there, but we think the activity level would probably have to quadruple just to hold production flat in Canada. In these forecasts, we're using AECO at about $0.80. So we'll have to see how that plays out. But you're actually watching Canada's gas production is on decline.

Yes, and the only thing I'd add to that is we're looking at AECO at minus $0.80 off of NYMEX.

Okay, great, perfect. Thank you very much. My second question is just on kind of operational momentum on the production trajectory for the rest of the year guidance. It implies a pretty significant 17% decline in liquids in Q3 and then a nice 11% ramp back-up in Q4. Assuming this is primarily related to timing, could you provide any commentary beyond that which would be really helpful? And how should we be thinking about operational momentum heading into 2021, given this kind of big down-up and then you're kind of trying to flatten out next year?

Yes, it's literally just the timing of when we're restarting completions; we actually haven't restarted them yet. We'll be restarting them very soon. Effectively, we'll be picking up completions here in the back portion of Q3. So you'll begin to see the production effect as we move into Q4. As we've indicated, we expect fourth quarter average crude and condensate production to be 200,000 barrels a day, and that's the same as we see throughout 2021. You'll see us getting to a more normal cadence. The third quarter is just quite simple because we really have no wells coming online until the very end of the quarter. This is really just the effect of that timing, kind of fully expected from our point of view.

Thank you. Next question will be from Gabe Daoud at Cowen. Please go ahead.

Hey, good morning, Doug and everyone. I just want to circle back to what you guys have typically quantified the amount of free cash flow that you see over the next year, so just curious if you can maybe quantify what substantial free cash flow looks like in your eyes for next year on pricing?

Well, Gabe, if you use what's in the table in the deck there, which is kind of every five bucks for oil is $375 million in every quarter, on gas is $140 million. If you look at it right now, the forward curve, if I remember right, it's about $43 on oil for next year and just about $2.70 on gas. If you do that math, that's about $500 million. It clearly is going to vary. We've also disclosed in our materials today that we've started to build a book, which is normal for us. But it does expose us or gives us exposure to these pricing while giving us what we believe is an important solid floor in that $35 range. Of course, if it goes up from there, it could be considerably higher, because right now the forward curve on gas isn't reflecting what many people believe is the fundamentals for 2021.

Great, got you. Thanks, Doug. And then just a follow-up or I guess the follow-up to an earlier question. Next quarter, if you target debt reduction if the A&D market maybe closes out a bit, your asset sales perhaps represent a lever for you guys to bolster further enhance the balance sheet? Thank you.

Yes, Gabe, we really don't talk about that. I mean today, that market is largely closed, but I think as commodities stabilize, you may see that start to come back a bit. That's the first step. Obviously, potential buyers have to have access to capital as well. Anything we might do on the divestment side would clearly be additive to our debt reduction. So that's all I'd say at this point.

Thank you. At this time, ladies and gentlemen, we have time for two more callers. The next question will be from Jeoffrey Lambujon from Tudor, Pickering, Holt & Co. Please go ahead.

Good morning. Thanks for taking my question. I just got one as a follow-up to some of the growth versus no growth longer-term discussion from earlier. I know you said a bit early to kind of speak to plans beyond next year. I was hoping to get your thoughts on how OPEC might just play into consideration. Significant OPEC volumes are offline to the first half of 2022, for example. Could growth still make sense for you all? Or would you feel better about waiting until OPEC potentially fully reverses before considering growth more seriously again?

Yes, Jeoff, I think it's kind of hard to build your strategy and your plans on very specific OPEC actions because, obviously, those can change at a moment's notice. Most of us will never forget Thanksgiving of 2014, actually Thanksgiving Day of 2014. They do influence supply and demand fundamentals. But I think as you're already seeing, there's been a significant rebalance already. In fact, you're now starting to see global draws because you had a very strong supply response, and it wasn't just from OPEC Plus. Obviously, a lot of production has fallen off here in North America. It's mainly dominated not by shut-ins, but the fact that the capital tap was turned off. I think it doesn't feel to me very likely that there will be many growth stories during that period; macros suggest many are projecting declines next year. Of course, globally, other than just a couple of spots in the world, there is no capital being invested in the sector. We have to watch all of that. We have significantly reduced the cost of our business. We can now deliver the sort of financial results in the $35 to $40 range that we used to talk for $50 or $55. The sector needs to think about low to middle single-digit growth rates, generate free cash, and needs to be distributing sizable chunks of that back to shareholders, recognizing the volatility and certainly that’s in the sector, and that's our strategy. At what point we turn back to growth is a little hard to predict. But what we have hopefully been clear on is how we will manage the next six quarters.

Any follow-up, Jeoffrey?

No, just the one.

Thank you. Next and last question will be from Neal Dingmann at SunTrust. Please go ahead.

Thanks for squeezing me in. Doug, my question is just it sounds like you're pretty positive on what your PDP decline you're expecting for baseline decline. Could you just talk about—is there a difference between Permian versus Anadarko? How do you see that decline factoring out? And then, just is that driven more on a more stable plan or what really is driving that, that is certainly lower than to your result would be good to see?

Yes, that piece is roughly similar. I think when we look at optimizing capital, we're really looking at the cash flow and financial benefits from it. The Permian is an oil area, but the wells are more expensive. The royalties are higher than that. Also, we get a different mix of production products. If I flip up to the Montney, you've just seen another company kind of reinforce our view of how competitive condensate-rich Montney is. These wells have a very low cost, we have low royalties, and they have a very attractive condensate production profile. Very high rates early; they do decline, but you capture a lot of that benefit quite quickly. As we've seen, condensate pricing has remained firm. Its relationship to TI has held in there throughout this period. When we optimize, we try to look at the financial; the financial benefits for the capital we invest. But we’re staying committed to our multi-basin portfolio, which we think is a big risk reducer. So that's how we'll optimize that, but the decline piece isn't really a big driver in that story.

Okay, very, very good details. And then just lastly, just want to make sure I'm certain you guys definitely pointed to and I think it's obvious that the free cash flow to bring down debt coming forward. I just wanted to make sure with Corey; Corey was that just sort of what you talked about in prepared remarks? You mentioned, I think in one of the questions today, was that just sort of one-time on the payables? I mean what caused the debt to go up for the quarter? Should we think about that as more just a one-time payable, and you'll be seeing more free cash flow going forward?

Yes, exactly. As I alluded to, there are kind of three one-time items which we pointed to in the call, which was the accounts payable, the new costs, and some of the restructuring costs.

Thank you. At this time, we have completed the question-and-answer session. We’ll turn the call back to Mr. Campbell.

Thanks operator, and thanks everyone for joining us today. Please stay safe. We appreciate your investment. Look forward to seeing you on the road in person very soon. Thank you.

Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending, and at this time, we do ask that you please disconnect your lines.