Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2020 First 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 would now 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 first quarter conference call. This call is being webcast and the slides are available on our website at Ovintiv.com. Please take note today of the advisory regarding forward-looking statements at the end of our slides and in our disclosure documents that we filed. Following our prepared remarks today from the leadership team, we will all be available to take your specific questions. Please limit your time today to one question and one follow-up; this simply allows us to get to more of your thoughts and questions. I'll now turn the call over to our CEO, Doug Suttles.

Thank you, and good morning. We very much appreciate you dialing in today for our first quarter update, and I hope you're healthy and surviving while staying at home. Today we are living in unprecedented times, both in our daily lives and in our industry. Over the last two plus months, we've been managing through a challenging combination of events that is truly one for the ages. As shareholders, it's important that you know we are in a very good position, and I’m very confident we will come out of this even stronger. While we didn't predict this situation, we did plan on volatility. We deliberately built a business that has massive flexibility, allowing us to be dynamic in how we respond. The immediate actions we are taking position us very well for 2021 and we will talk more about that on the call today. Our first quarter financial and operating results were very strong. We delivered higher than expected production for less capital. But clearly a lot has changed in our sector since we closed the books on the quarter. We will focus this morning on how we're effectively using the flexibility we built into our business to manage through these challenging times and how we see ourselves positioned for a recovering world. We will not only survive, but will be positioned to thrive, and I know we all hope that day is very soon. I'm joined today by other members of our team who will help with the presentation and be available to answer your questions. We will reference slides we issued yesterday and take your questions after our prepared remarks. The market is certainly challenging and something none of us could have predicted. I told someone recently that while we prepared for a black swan event in our risk management process, we never thought we had to prepare for a whole flock of them. Fortunately, we have the flexibility to rapidly adapt to changing market conditions without incurring fees or penalties. We are adjusting our activities in real-time to ensure that we get optimal outcomes today as well as position us for 2021 and beyond. You will find in today's deck that we have outlined potential scenarios for the remainder of 2020 and for 2021. Although we are not issuing formal guidance, it's important that you understand what our business can deliver. The recent reductions to our cash cost and the meaningful gains in capital efficiency have enhanced the cash flow outlook for 2021. Our stay-flat capital at a $35 oil price is about $1.5 billion. You'll recall that this is about $700 million less than previous estimates, more on how we get there later in the call. As the COVID-19 demand impact became apparent in oil markets, we immediately announced a series of actions to protect the health and safety of our workforce, maintain balance sheet strength, and preserve liquidity. Over the next several months, we expect that oil prices will be weak and volatile, although we are encouraged by OPEC plus cuts and the swift actions being taken by producers to cut capital to FERC completions and shut-in production. The COVID-19 driven demand loss is too great to quickly overcome, but it is encouraging to begin to see the green shoots of returning demand. We are laser-focused today on the things we can control and are using the tremendous flexibility we've built into our business to make sound decisions consistent with our market views. Our priorities today are crystal clear. There has never been a more important time to focus on efficiency, both cash costs and capital efficiency; getting the most out of every dollar we spend. This is something we are very good at, and we have a longstanding track record when it comes to innovating and creatively finding new ways to enhance margins and reduce capital costs. The entirety of our workforce is solely focused on safely achieving this. When this crisis began, we announced we would reduce cash costs by $100 million, and today we are doubling that to $200 million, expecting the vast majority of this to stick with us in 2021 and beyond. In addition, in the first quarter, we substantially reduced well costs versus 2019 and now we believe they will be more than 20% lower in 2021 compared to 2019. The steps we are taking today maintain our strong balance sheet and preserve liquidity. We have the flexibility in our business to do this quickly, efficiently, and without penalties. In the second quarter, we immediately cut capital by 60%, reducing from 23 rigs to the 7 we are running today. We reduced frac spreads from 8 to 0, and we did all of this without incurring penalties or termination fees. Our 2020 cash flows and balance sheet are supported by our strong hedge position. Successful risk management is a part of our track record and is designed to manage balance sheet risk. In addition to reducing cost in capital spending, we also entered the debt market and repurchased a portion of our 2021 and 2022 bonds at a discount, lowering our debt and our interest expense. Recall that this is something we did effectively in 2016. We have substantial and firm liquidity today and note that two credit agencies recently reaffirmed our investment grade rating, which we know is a key advantage in today's capitally constrained market. With the extreme volatility we've seen in oil prices, we are actively managing our production because we operate substantially all of our production. We have almost full control to shut in the right wells based on variable costs, market views by area, differentials, and the extreme contango in the market today. We have a thoughtful approach to shut-ins and are confident we can quickly return wells to production without reservoir damage or lasting impacts. Most importantly, we are protecting the health and safety of our people. We seamlessly deployed our business continuity plan and remote working, with our team effectively managing the business from home. We are now beginning to return to more normal working aligned with national and local guidance. We also implemented safety protocols in the field, where we've now completed over 45,000 health screenings. This has been very effective. We've had no known cases of COVID-19 in our field operations. Our goal was not just to maintain critical functions, but to effectively run the business. I have to compliment our team as we haven't missed a beat. These priorities give us tremendous resilience and position us to thrive during recovery, although we are certainly prepared to make additional cuts to preserve our liquidity and protect the balance sheet. We also believe we have to do this in the context of recovery. I'll now turn the call over to Brendan McCracken to discuss our first quarter results.

Thanks, Doug. We had a very strong start to 2020 with production ahead of plan and both capital and cash cost below budget. Our first quarter cash flow was $535 million and operating earnings were $27 million. Our production was 19,000 BOEs a day higher than expected at 571,000 BOEs per day. This outperformance relative to our budget was primarily due to strong well performance and faster cycle times. Our first quarter crude and condensate production of 215,000 barrels a day was above budget by 7,000 barrels a day and was up 4% year-over-year. We also produced over 1.5 Bcf a day of natural gas in the quarter. We remain one of the largest independent crude and condensate producers in the sector today. One way to think about our production mix is that we produce the same amount of crude and condensate as Concho, and the same amount of natural gas as Range Resources. We firmly believe our diversified portfolio is a real advantage through the cycle. Our original 2020 budget plan was to invest $865 million of capital in the first quarter. As a reminder, our original guidance called for us to front-end load activity in our base assets to maximize operational efficiency. With continued efficiency gains, our actual investments in the first quarter came in 9% under budget. Total costs in the first quarter were lower than expectations at $12.17 per BOE. As we'll cover a bit later, we expect to continue to drive savings in both capital and cash cost through the rest of this year and beyond. Our realized hedge gains in the first quarter were $150 million. Our total liquidity today is at $3.4 billion. During the first quarter, we went into the open market and repurchased $100 million of our 21 and 22 notes for $89 million. These transactions included $90 million of senior notes with fixed rates of 5.75% and $10 million of notes with fixed rate of 3.9%. The impact of these repurchases reduces debt, lowers our interest expense, and extends term. In early March, we immediately adjusted our investment levels, dropping second quarter capital by 60% or $500 million. We understood the importance of moving fast and we have the flexibility to do so. As Doug mentioned, we did not incur any penalties or costs to make this change. In April, we restructured our hedge book to further insulate us against the lower oil prices. Today we are fully hedged on oil for the second quarter with more than 200,000 barrels a day hedged at an average price of about $42 a barrel. The majority are in fixed price swaps at $41.50 per barrel, with the remainder in costless collars between $50 and nearly $70 per barrel. Therefore, we have a hard floor at $42 per barrel. We also have 1.2 Bcf a day of natural gas hedged at attractive prices. Today's strip our hedge book has approximately $1.1 billion of value for the last three quarters of 2020. We traditionally hedge WTI roll as part of our risk management process. As a result, we have mitigated more than 70% of our roll exposure for the balance of 2020 with financial hedges at plus $0.25 per barrel. This is quite favorable relative to the current market. Our teams have a history of effectively managing risks in our business and this year's hedge book will generate critical cash flow through this period of low prices. Given ongoing uncertainty, continued market volatility, and the potential for production shut-ins, we have suspended our 2020 guidance. However, in today's presentation, we provide some near-term scenarios to help you better understand how we are managing the business. These scenarios show a compelling case for 2020 and 2021 and are supported by our performance and the decisive actions we've taken. These are difficult times, but we are well positioned with a strong culture of innovation, a track record of delivering on our objectives, financial strength, and significant flexibility. In particular, we have a well-established capability to drive down costs and relentlessly enhance efficiency. I'll now turn the call over to Mike to further discuss our cost reductions.

Thanks, Brendan. We have pushed on all parts of the organization to safely reduce costs. We have a track record of constantly innovating to find efficiencies that drive down costs and enhance margins. Over my career, I have seen our industry get incredibly efficient during downturns, and we are doing it again. Our company has a culture of operational excellence; this extends across all aspects of the business. For those of you that have followed us for some time, you know that if we put a cost target out there, we hit it; our track record here is second to none. Our teams came through for us again in the first quarter. This is a direct result of our culture, which is unwavering and defines who we are and how we operate. In our appendix, we have summarized the key elements of our culture on a few slides as we believe this is an often understated advantage; check them out when you have a moment. Here's the big takeaway. The cost savings we've generated to date, when coupled with the reduced legacy costs in our business, translate into an incremental $300 million in 2021 cash cost savings. These legacy cost reductions have no risk; there are simply expiring contracts and commitments. It's important for you to understand our ability to generate free cash flow in a low commodity price environment, and today we're providing some information to help you get there. We deploy cutting-edge technology with an unrelenting focus on innovation. This could not be more important as we fight to reduce costs and increase margins; at the end of the day, besides some low-cost operators with scale, will win. Our proven ability to constantly innovate to deliver improved results is core to our culture. The key is to make sure our near-term gains translate into permanent economic advantages for us over the life of the assets. Our first quarter operating performance was exceptional. With today's focus on macro events, it's easy to overlook the good news occurring at the field level. Ovintiv is a world-class operator everywhere we operate. We're consistently at the front of the pack. We lead the industry in terms of cost per foot and well productivity. We have consistently achieved this without upspacing infill locations and sacrificing future inventory. We had a great story of progressing efficiencies in the first quarter; in fact, our drilling completion cost performance was 9% better than our 2019 average. It's critical to note that we achieve these efficiencies before the recent oil price slide. We are now forecasting an additional 10% improvement on cost in the second quarter and throughout 2021. Much of the savings we've seen to date are expected to be permanent, leading to lower breakeven projection and our higher cash flow outlook for 2021. In each of our core regions, we have lowered our cost to drill, complete, and equip our wells, and reduced cycle times. This means we're stretching capital investments further, pushing down breakeven costs, expanding margins, and enhancing returns. Our new lower expected well cost for each of these plays is shown here. Notice that we have also shown our pacesetter costs. We're using well costs for our planning purposes that are higher than our pacesetter results. In other words, we have high confidence we can deliver these estimates because we've already done so. I will now turn the call over to our COO, Greg Givens.

Thanks, Mike. We saw impressive gains across the portfolio. In the Permian, our well cost dropped to $700 per lateral foot and we expect them to be just above $600 per foot going forward. These costs are industry-leading. One exciting innovation on our Permian operations is the adoption of Simul-Frac completions. This involves fracing two wells at the same time using a single frac spread, which reduces cycle time and saves costs. More than two-thirds of the wells turned in line in Q1 were completed with this technology and we achieved an 18% decrease in our frac cycle time compared to 2019. We continue to see big gains in the Anadarko. The rate of change in this operation is nothing short of phenomenal and clearly demonstrates what an experienced operator with the right culture can achieve. We have recently turned in line 13 STACK wells, with drilling and completion costs of less than $5 million, which is $3 million less or nearly 40% lower than Newfield's legacy well costs. These cost reductions are a result of faster drilling times, increased pump rates, and innovative supply management solutions. I applaud the team for continuing to drive down costs and improve margins in this important play. Our capital efficiency story is also evident in the Montney; we are optimizing our wellbore construction, increasing time spent pumping, and reducing downtime in our operations. We've put a lot of thought into how we are shutting in wells to preserve future economic value. We are voluntarily electing to shut in production rather than selling at the low netback prices offered in the market today. It is important to note, we are not using the value of our hedges in our shut-in analysis. Today, we have about 65,000 BOE per day shut in, of which about 35,000 barrels per day is oil and condensate. This is a combination of shutting in wells and deferring production in recently completed wells. We expect this number could rise in June. Our multi-basin portfolio is an advantage here as we manage curtailments in real-time, recognizing not only benchmark prices but also regional differentials and differences in the product mix. It is a highly integrated approach between our operating and marketing teams. We are simply electing to store our oil in the reservoirs. We do not expect any detrimental impacts when we turn these wells to production, and that's something we can do very rapidly once pricing conditions improve. I'll hand the call over to Corey to discuss our liquidity and financial strength in more detail.

Thanks, Greg. It's extremely important that you leave today's call with a firm understanding of our credit facilities and the bulletproof nature of our liquidity picture. We've seen some recent sell-side reports that don't quite capture this accurately, so we've provided a couple of informative slides and we'll spend a few minutes on this topic today. We have two facilities with substantial headroom, one in Canada and one in the US, that provide total capacity of $4 billion. These facilities were just renewed in January and are not subject to any changes through mid-2024. As we can attest from past cycles in energy, there is no greater asset than liquidity; it is the oxygen that provides the staying power to the business and will get us safely to the other side. Here are the facts. We do not have a borrowing base or annual redetermination process that is underway today with many other companies. Our facilities are unsecured and are not reserve-based lending facilities. We have no cash flow, EBITDA, or leverage covenants, which in today's period of low prices could make reductions in activity levels and supply curtailments very difficult. We have no onerous covenants, and this provides great certainty and optionality to effectively manage our business like we're doing today. Although it's a great advantage to be rated investment-grade in periods when access to capital is constrained, access to our facilities are not contingent on this rating. We assure you we will work very hard to keep this rating and our actions to date demonstrate our resolve. Our market capitalization has no impact on the facilities. These facilities are backed by nearly two dozen of the world's largest global financial institutions, all of which have an A minus credit rating or better. These facilities have a financial covenant adjusted debt-to-book capitalization based on book capitalization with a $7.7 billion permanent add-back for non-cash write-downs. This add-back is locked in and is not subject to redetermination. The tables on this slide show the calculation and the ratios at year-end 2019 and at the end of the first quarter. Our balance sheet is strong and resilient, backed by the deep liquidity profile I just highlighted. By design, our maturity profile is long-dated and staggered, with more than 80% of our long-term debt due in 2024 or later. It is an advantage today to be investment-grade rated and two rating agencies recently affirmed us as an investment-grade credit. Our two maturities in late 2021 and early 2022 combined total about $1.25 billion. There may be opportunities to refinance these maturities if attractive rates are available for an investment-grade credit like Ovintiv's; however, our facilities have ample capacity to take out these maturities while both extending term and lowering our interest expense. Maintaining our significant liquidity and limiting the use of our facilities to run the business is extremely important to us. As both demand and commodity prices recover, we fully intend to run our business free cash positive. Longer term, we are committed to running our business with a lower level of absolute debt. I'll turn the call back to Doug.

Thanks, Corey. Let me discuss our scenarios for the remainder of 2020 and 2021. The capital efficiency improvements, reduced cycle times, cash cost reductions, and outlook for lower legacy costs in 2021 have significantly enhanced our future outlook. Recall that we used to refer to our stay-flat capital case in the low $2 billion range. Today, this number is much lower, around $1.5 billion. Although we are using the flexibility in our business to manage shut-ins, we are confident in our ability to exit 2020 at about 200,000 barrels a day of crude and condensate production. Under this scenario for 2020, we would invest approximately $1.8 billion to $1.9 billion. That's more than $800 million less than our original $2.7 billion budget. This is a significant reduction but maintains scale in our business, and when coupled with lower costs and better efficiencies in 2021, results in a strong trajectory for the company. I should note that these investments generate quality returns in a $35 WTI oil price and $2.75 NYMEX gas price environment. For 2021, this scenario has us investing about $1.5 billion, maintaining 200,000 barrels a day of crude and condensate production. At $35 WTI and $2.75 NYMEX gas price, this scenario would put us free cash positive, including our dividend. It is important to understand how we are thinking about the future and that you know just how resilient our business is. This is not formal guidance, but this should give you a sense of how we're positioning the business, not only for today but also for 2021 and beyond. Before opening up for questions, I'll quickly summarize today's key messages. First, we think it's important to balance the challenges of today with positioning for tomorrow, and the scenarios we've highlighted certainly do that. We are confident in our ability to exit 2020 with 200,000 barrels a day of crude and condensate production and then maintain that level through 2021 with far less investment than previously thought. We can do this because of the substantial efficiency gains we've captured, and our continued improvements driving down costs like we demonstrated in the first quarter will increase our 2021 cash flow and enhance returns. Our track record here is quite strong, and I know we can deliver. Third, we are advantaged due to our flexibility. We intend to use this flexibility as options weaken; we have across our multi-basin and multi-product portfolio to make the right near-term decisions that will put us in the best place for the long term. We are laser-focused today on preserving liquidity and maintaining our strong balance sheet. Although the timing of demand recoveries is uncertain, we do know that it will occur. The world needs our products, and we intend to be positioned to thrive on the road ahead. Lastly, our team has a strong track record from the field to the office. We have a tremendous history of improving efficiency and hitting our targets, and I'm firmly convinced we will do so again. That now concludes our prepared remarks. And operator, we're now ready for questions.

Your first question comes from Asit Sen from Bank of America. Your line is open.

Thanks, good morning. This Slide 10 is very useful. I just wanted to circle back, Doug, on the scenario you highlighted on maintenance capital of $1.5 billion. Could you share with us again broadly what the split would be between Permian, Anadarko, Montney, and the base assets, perhaps a decline rate improvement embedded in that and a level of DUC assumed at the beginning of the year?

Yes. So that was quite clever. I think you've got about four or five questions in there. But let me see what I can do with them. First on the distribution of capital, at this point, I wouldn't want to guide or give you any indication where that stands because we have a lot of flexibility. I mean we have a portfolio. I think that Brendan highlighted that produces not only a lot of crude and condensate but a lot of natural gas and NGLs as well. So there are a number of different distributions across the portfolio to get to that outcome. Of course, it's a bit early to make that decision. But when we've modeled it, we can see multiple ways to get there. Probably your DUC question is very important as well because we actually envision exiting this year with a fairly normal number of DUCs. Currently, we are building them because we've shut down all completion activity, but we would expect to roughly exit this year in that scenario with about 30 DUCs, which would be what we would typically do year-over-year. I may have left something out, so if I didn't cover anything, please do let me know. Decline rate, we actually see it moderating both on BOEs and on crude and condensate production by about 5 percentage points; it varies a little bit between gas and oil. But clearly, when you move off of growth into a stay-flat case, your underlying decline starts to moderate as you have fewer newer wells in the portfolio.

Thanks, Doug. And a big picture question for you, if I may. In a low-price environment, would you be reevaluating your well spacing and/or completion designs?

It's a good question, but I think it’s highlighted in the prepared remarks. What we've been able to do across the portfolio is actually demonstrate that we can give very competitive well results while actually using our cube approach, which doesn't sacrifice both future locations or this valuable land that we hold. So I don't believe it is, it's constantly shifting and moving as we learn. And then on completion design, I think what we've shown, typically, our completions have been staying the same or growing, yet we're still driving well costs down. An example of that would be Greg highlighted with the Simul-Frac approach, we're now using where we complete two wells at the same time using one frac spread. So I don't think it would; in fact, in a few areas, we're still looking at increasing the size of the jobs and we think we can offset that cost with efficiencies.

Yes, thanks. Good morning. Definitely, a number of my questions have been taken; that first one was a good summary. Maybe just a couple of follow-ups. Just on the decline rate, Doug, the 5% reduction. What would the reference case be there, like 36%, 37%?

Yes. Greg, we've historically talked in the high 30s. It varies a little bit by product, but for instance for oil, it would fall from the high 30s to the mid-30s, and for BOEs, it falls from the middle 30s to low 30s. So it does vary a little bit by product, part of that is some of our legacy gas production is on lower decline because it's older.

Okay. And in terms of the sustained account, it's kind of a dumb question, but that's on a BOE basis, or is that really just targeting the oil and condensate that you mentioned?

Yes. Today, it's really targeting oil and condensate. We might have very, very small gas decline in there, but there isn't a huge difference in that scenario between BOEs and crude and condensate. However, because we have quite a bit of flexibility in there, and that's why the question about the distribution of that capital across the portfolio, we can get there in a number of different ways depending on what commodities and regional pricing are doing.

Thank you. Good morning. Can you give us a little bit more color on where the shut-ins are by area and/or what the proportions are? And then what oil price would you need to see to both reverse curtailments but then also go into growth mode, relative to the 200,000 exit target?

Yes, Brian. Once again, one of the advantages of having a multi-basin portfolio is we can use not only what the benchmark prices are doing but what regional differentials are also doing. Today when you look at what shut-in, a much larger percentage of the Uinta, Bakken, and Eagle Ford are shut-in compared to a much smaller percentage of the Permian, Anadarko, and Montney. So the biggest chunk is in our base assets, and largely that's just driven by regional differentials, a little bit by the cost profile. As to what price we would return activity? Well, it’s two things, on shut-ins today, most of our production that is shut-in is clearly doing more than covering variable costs today. But we've just decided not to sell those barrels at today's prices and effectively store those for the future. As Greg mentioned, it's not only shutting in wells that were already producing; we've chosen not to bring on some wells that we've drilled and completed. Other wells that we've recently drilled and completed, we are producing at very restricted rates. It's hard to put a precise number because differentials play a very big role in this conversation, and also the product mix plays a very big role, and as you know our portfolio has everything from wells that produce 80% of their production as oil to in other places, it’s 15% or 20%. So it's hard to give you an oil price because it matters wet gas and NGLs are doing. When we restart activity, it’s also the same answer. At today's prices, we wouldn't do that, but it's going to vary by region and it is not just oil price dependent; it will also depend on what gas and NGLs are doing.

Thank you. I have a follow-up question. Can you discuss the oil mix in the Permian and Anadarko Basins, particularly how well performance is changing as improvements are occurring more on the wet gas side compared to the Black Oil side? Additionally, with rising natural gas prices in those basins or in the Montney, does that affect your interest in exploring more gas-focused projects, or is there a shift in capital towards that?

Yes, Brian. In terms of the product mix in the Permian and the Anadarko, it's relatively stable. It's not moving around a lot. It does vary a little bit by zone and by county in the Permian and of course as you move across the window. But that's not shifting dramatically. Your question on gas prices is interesting, and we're currently studying that at what point would the wells you target shift based on product pricing. I don't want to give you a precise number, but clearly there are several people who are getting more bullish on natural gas prices, and of course what that does in a play like the Anadarko or the Montney, it just makes some more attractive because we would still get the liquids production, but would get an even better price for natural gas. It could make a difference on capital allocation at the margin; we’re studying that today because as you probably know, Brian, as you move into particularly in the Montney into some of the different type curve areas, you actually get higher rate wells. You get a lot more gas and you may not be giving up much on the condensate side. So it could drive it at the margin; I don’t think it will be a huge effect, but at the margin, it could make a difference.

Good morning, Doug. I know you guys employ a rigorous capital allocation process. I just wanted to see if you could give some more thoughts on the 2020 scenario that you outlined today, the $1.8 billion to $1.9 billion. What kind of oil price are you thinking about to support that level of investment this year, and maybe talk about what would drive that to be a lower level of spending if prices don't show some recovery in the back half of the year?

Yes, Arun. If you look at that scenario, it would broadly be supported by something we see in the strip today, but I think, as Corey highlighted, if we see weaker prices, we're clearly going to focus on the balance sheet. The intent here is not to use up our liquidity. In a scenario that looks not too broadly different than you see in the forward curve, it feels reasonable. But if we found that prices aren't recovering and they're weaker, we would ultimately pull capital back, and that's why we've described it as a scenario as opposed to guidance. We have to see, but I think it's not broadly different than what you see in the forward curve at the moment.

Yes. The second question is, could you talk a little bit more about your well costs that are now trending below your peers by quite a good margin as we study this on a per foot basis? Could you talk about what’s driving that and just broadly what’s influencing the sustaining CapEx to be $1.5 billion versus a $2 billion rate before the downturn?

Yes. Arun, I thank you for the question. First of all I’d highlight that there's only one company in the world who has drilled and completed more horizontal wells with a multi-stage frac than us. So we have incredible experience. We think one of the advantages of being in a multi-basin is the ability to learn in lots of places, then apply it across the portfolio. Tied to that, which I think Brendan highlighted, is our culture. This is all about innovation and constantly challenging what we do and how we do it. I think if you look at our track record, we’re always changing, always driving it forward, and always looking for the next improvement. Some of that is technology-driven; some of it's within the supply chain. You might remember, while others were thinking they should own sand mines, we were working on local sand. And while others were spending large amounts of money on water infrastructure, we came up with a very creative solution to that problem. It just doesn't stop. I remember in 2015 and 2016 many people were saying the cost reductions we delivered then would reverse in 2017 and 2018. If you look at our costs, they went down year-over-year. We firmly believe they're going to go down in 2021, and I think Mike highlighted in his comments that the numbers we're using in the forward look scenario are actually higher than cost we've actually delivered today. Our pacesetter well which is our well with the lowest cost is actually less expensive than what we've used in that planning scenario. Quickly, our pacesetters become our average and we have established a new pacesetter and continue to drive down costs. So a lot of it is technology-driven; it's not based on massive assumptions about lower service pricing. It's really driven by the innovations we're going to do in our operations.

Good morning, everyone, and thanks for taking the questions. I wanted to ask one on the 2021 commentary. So you note a potential scenario in which you're free cash flow positive next year, post dividend at a commodity price not too dissimilar from the current 2021 forward curve for both oil and natural gas. I'm curious about your hedging thoughts or hedging strategy given that backdrop. At what point would you look to layer in hedge projection on that 2021 plan versus targeting further free cash flow upside and net debt reduction potential if commodity prices were to continue to improve?

Yes, Brian, that's a good question. If you look at our history, we always enter the current year with a strong hedge book. Remember we do this to protect our balance sheet, which you are seeing the effect of that this year. We also use a variety of products based on our views in the market and the risk that's out there. Everything from fixed price swaps to three-ways. There was some commentary not very long ago that our three-ways weren't providing protection, which actually wasn't true because I think people failed to understand that you can convert those and spread value, and it does have value. We'll build the book as we go through the year, and as we firm up our plans for 2021, it will be underpinned; the balance sheet would be underpinned by hedge book. But at this point, I wouldn't want to indicate what the price is. I think it's too early to do that. At the moment, we're not out in the market hedging all at the current strip. As we get closer to the end of the year and begin to firm up our plans and see how 2020 finishes, we'll end up with a strong hedge book for next year, which is consistent with our plans.

Okay. I appreciate it. And then as a follow-up, you disclosed purchasing roughly $100 million of 2021 and 2022 senior notes in the open market. I'm curious how much additional runway you may have there in the open market. It seems as if you are prioritizing the '22 based on the combination of interest rates and percent discount to face value, but any thoughts on strategy and whether there is a limit to how much you do in the open market?

Yes. Maybe I'll let Corey pick that up.

Hey, Brian. Yes, thanks for noticing the repurchase. Obviously, when we were targeting the '21s and '22s, it was really just an ability to extend maturity as well as capture some of the discount. I think what we saw initially anyway on the trading was the '22s traded a bit wider than the '21s. So we just preferentially went for those based on price.

Hi, good morning everyone. This is Jeanine Wai. My first question is on debt. And I guess just following up on Brian's question. We recognize that you have revolver capacity for sure. But in terms of maturities that are coming due over the next two years, is the plan to pay strictly out of free cash flow? And if that is the plan, is the stay-flat scenario something that's likely to get pushed forward? And what WTI price do you think is required to cover those maturities out of the free cash flow? I think we saw the unhedged pricing activities that you provided, which are really helpful, and we think that the sensitivities imply that WTI needs to probably average something closer to $45 over the next couple of years to cover those maturities if you go ex-growth. So we're just wondering if you're thinking about that? Thank you.

Maybe I'll make a couple of comments and ask Corey to add some more detail. You know what we've outlined when we've looked at various scenarios, we've taken a very conservative view on our projections on liquidity. As Corey indicated, we can repay those maturities with our credit facility if we need to. But you also are probably aware that the credit markets are slowly opening up, and that provides another option. As prices improve, we'll generate more free cash flow, which can also contribute to that. So I think we have a number of options here as we look forward. But, Corey, is there anything else you'd like to add?

Yes, I think the immediate clarification I’ll make is the comments we also highlighted; as Doug alluded to, the option to refinance is one that in a more normalized open market for our investment-grade credit we would entertain that as well. To the extent we want to reduce overall debt, we also have some short-term borrowings on our credit facility that can be repaid easily as well, so we've got lots of flexibility on that, on the capital structure front as well.

Yes, it’s important to understand the second question is moving on to operations on the assets. In the past, you've mentioned that your core three plays all have very similar returns. In today's oil price environment, with the differentials and your cost improvements, is this still the case? If it's not still the case, at what natural gas and NGL prices do the STACKs exceed the Permian on returns? Thank you. Yes. It's interesting insight, and I think what we have to be very cautious about right now is that this has been an unprecedented set of conditions where you had massive demand destruction that happened very, very quickly, and the supply response is taking some time, but now you’re seeing that it’s also quite strong. In fact, there are even some indications that at these points may cross in the not too distant future, but that varies a lot by region. We've seen differentials in areas move radically to the tune of $15 or more per barrel over the course of days or a week. I don't think when we look at making capital investments, we would use that sort of volatility in today's market to influence. We are going to take a longer-term look; so in the longer term, we're not that concerned that the big historic differentials are too different in the future. In fact, if anything, because of lower production levels and lower growth levels, it’s going to tighten those in. I don’t think that will drive it, but your comment about natural gas mix and even NGL mix, because there are some encouraging signs on the NGL side out there as well, that at the margin it could shift some capital around. As I mentioned, this is the advantage of our portfolio. We have that ability to do that and respond to both fundamental prices and regional differentials, but you shouldn't be concerned about the new gas plant creating any capital or cost drag on the business.

Good morning, all. My first question is on Doug, on your operational efficiencies. I just want to very briefly, can you continue to see with these what the kind of the minimal D&C that you all are planning for the remainder of this year and then what you're thinking about into 2021?

Yes, Neal, it's a great question, and scale does help here, but the environment is quite a bit different right now than it was just a few months ago. I think we're firmly convinced we can, but it is clearly when you're doing more, it's easier to do a bit more experimentation and test new things, but many of the things we've been implementing over the last six to nine months, we're continuing to scale up. I'd reference the Simul-Fracs, which is something we've started in the Permian and are now beginning to spread across our portfolio. So I believe we will get there even at a lower activity level. Our teams are thinking about while we're in this pause phase right now how they can take further costs out of the business and drive further efficiency savings; I believe we can do that. But you're right, it is a little more challenging at a lower activity level.

It's a great detail. My follow-up relates to the Anadarko Basin presentation you shared earlier this year, where you mentioned being ready for full-field development. Given that you are currently operating two rigs there, I'm curious about your plans to approach that compared to the discussions from earlier this year about possibly moving towards full-field development. How are you currently thinking about this play?

Yes, and I think if you look at the spread of the 7 rigs, the 3, 2 and 2, what it still allows us to do is efficiently do these larger pads that we do today, which we typically use multiple rigs on a single location and that's partly what drove that decision. So I think we will still be able to deliver those efficiencies there. In the Anadarko, one of the things we talked about coming into the year was how we would be doing a bit more activity in the SCOOP, which we have been doing because we do have quality acreage down there, and you’ve seen us mixing those two pieces, this year, and we continue to do that. It’s an area where we’ve also seen radical cost savings improvements, particularly in drilling time. I think the team, I mean these numbers are incredible where we've now got wells at less than $5 million, where just slightly over a year ago, these costs almost $8 million. I don't believe the team is going to stop where they are today.

Good morning, thanks for taking my questions. I might have just the two-parter on the Montney. First, can you just comment on the capital outlook you're envisioning there when it comes to meeting plant expansions coming up, and then bigger picture, what the medium-term outlook is for the region overall at this point in time?

Yes, good question. We are working with Keyera; we are building a new gas plant in the Pipestone area, which we've been consistently talking about coming online early next year. That plant, as you know, is a similar arrangement to what we did in Cutbank, where we're actually building the facility and we'll operate it, but it's owned by Keyera. So we're working quite closely with them; I think we have some really good practices and a great team there delivering results. The most interesting thing about that, though, is when we start that up, we haven't been drilling wells to pre-drill wells for that facility because we can divert existing production into that plant when it becomes available. We don't have take-or-pay commitments there. So it isn't going to create a drag on cash flow, depending on how we allocate capital across the business, so it doesn't create any additional capital strain on the business and has a little bit of incremental upside because it will reduce the gathering pressures in that area, which will enhance our base performance. On the allocation of capital, I kind of tried to cover that earlier; it's a bit early to tell. The improvement in gas prices, and you've probably seen the differentials in Canada have tightened considerably. As I mentioned, we’re looking at that to see how it might shift some capital allocation in the company. Once again, I'd just highlight this is the advantage of our portfolio. We have that ability to do that and respond to both fundamental prices and regional differentials, but you shouldn't be concerned about the new gas plant creating any capital or cost drag on the business.

Good morning. Doug, I was wondering in the 2020 stay-flat. Can you disclose how you want to the relative capital allocation between the core three plays based on the benchmark that supplied on slide 10? And I was also wondering if there would be any significant differences in allocation in stay-flat versus the pre-COVID plans?

Yes, Jeff, I think at this point it's hard, I wouldn't want to get very precise. I think all three will attract capital; exactly what the proportion is will be dependent on the various products and what the fundamental prices are doing. But all three will attract attention. We also do have about half of our current DUCs on our base assets today. We have DUCs in the Eagle Ford, the Bakken, and in the Uinta to complete, which we'll look at how we do that. So it's a bit early to tell. The good news is, as we've shown, we can move capital around rapidly in the company; we can both stop it, start it, and shift it, and we’ve done that through a combination of how we're organized and how our supply chain team works. While others have talked about penalties and termination fees they've incurred, I’d highlight we didn't incur any of those; that’s some fantastic work by our supply chain team. And that's helpful. The other question I want to ask is referring to Slide 7, the $400,000 per well of D&C costs in the Permian. That's really low. I was wondering, first of all, do we have an average length for these laterals, and is it a fully loaded cost? If it's not, what do you think that would add to it? Yes, I think when we talk about this, this is against our standard well and it’s a number of things which have gone into that. We continue to reduce drilling time; I mean, rotary steerable tools now have gotten into a pricing zone where they make sense and reduced drilling time and cost; the completion concepts that Greg mentioned. Our average wells' lateral length is getting longer as our land team continues to work to consolidate our acreage. So when you look at those savings of $400,000 per well versus 2019, a number of things go into that. But it feels very repeatable, and we think they're going to go down further.

Thanks, operator, and thank you everyone for joining us today. Please stay healthy, and we look forward to seeing you on the road in person very soon. Good day.

Thank you, everyone. This will conclude today's conference call. You may now disconnect.