[Technical Difficulty]. During the call, we'll make forward-looking statements based on current expectations. Of course, actual results may differ due to the factors described in today's release and our periodic SEC filings. And finally, we'll also make reference to some non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in this morning's release and on our website. And with that, let me turn the call over to Ryan.

Thank you, Mark. Before we get into the results for the quarter, I'd like to touch on a couple of other items that are top of mind for us. The first is the war in Ukraine. In a world already ravaged by the pandemic, this unprovoked invasion is having tragic consequences as we all see in heartbreaking detail in the news every day. The bravery of the Ukrainian people is inspiring, and we pray for a peaceful resolution at the earliest possible moment. This deeply troubling war is also disrupting supply chains at a time of recovering global economic growth and energy demand. It is affecting every aspect of the global economy and impacting the energy security of our allies in Europe, and it's driving significant volatility in commodity prices. We are fortunate that the United States has abundant resources to ensure our own energy security. These resources also provide vital geopolitical benefits. Secure U.S. energy exports serve as a market stabilizing factor, enabling our allies to better withstand energy blackmail by hostile and unreliable resources. Like the rest of industry, we've quickly restored activity levels from the lows driven by the pandemic-related energy price collapse despite lingering service and supply chain shortages, infrastructure permitting delays and lag time required for workforce and equipment redeployment. As a result, total U.S. oil and gas production is growing meaningfully despite these headwinds. And ConocoPhillips will continue to do our part as we fulfill our triple mandate of reliably and responsibly meeting energy transition demand, delivering competitive returns on and of capital and achieving our net zero ambition. Now the other topic I'd like to touch on are the leadership changes we announced a couple of days ago. I suspect you all saw the release on Monday, but for those who might have missed it, Tim will be transitioning from leading our Lower 48 business, which he's done incredibly well since we combined companies a little over a year ago, to serving in an advisory role to myself and the entire leadership team. Tim has truly been an industry visionary founding Concho almost 20 years ago, and growing it into one of the Permian's largest and best run companies before joining ConocoPhillips. He's also been instrumental in driving value realization as we've integrated the assets into the company. I'm appreciative that we'll continue to benefit from Tim's significant experience and strategic relationships in his new capacity and of course, as a member of our Board. I'm also very pleased to welcome Jack Harper, who most of you know, to our leadership team as Executive Vice President of our Lower 48 business. Jack is an experienced proven leader who will help ensure that our Lower 48 business fulfills its key role in delivering on our triple mandate. Reflecting now in the quarter. Once again, we've made significant progress working on all levers across the company. We efficiently and safely delivered our capital scope globally and successfully integrated the Shell Permian assets. We also took important steps to further strengthen our balance sheet and continue to upgrade our portfolio, with the sale of our mature Indonesian business and the acquisition of an additional 10% stake in our long-life, high-quality APLNG business. We're running well and with very strong financial performance. Now building on 2 very successful Permian transactions, we have truly transformed ConocoPhillips. We're a premier E&P company with a large low cost of supply, low-aged GHD intensity resource base, returns-focused strategy and the balance sheet strength to thrive through the price cycles of the evolving energy transition. And underscoring this last point, we also recently published our plan for our net zero energy transition, which is available on our website. I'm going to let Bill cover the first quarter results. But before turning the call over to him, on the topic of returns, I want to highlight the fact that for the second consecutive quarter, we've again increased our targeted 2022 shareholder distributions, this time with an incremental $2 billion or a 25% increase to be distributed through the blend of share repurchases and additional variable cash return. We continue to make significant strides in all elements of our triple mandate. And as you know, we have now a 5-plus year track record of returning well over 30% of our CFO to our shareholders. The increased $10 billion target for 2022 further demonstrates our commitment to return significant value to investors through the price cycles. So now let me turn the call over to Bill, and he'll cover the results for the quarter, starting with our returns on capital.

Picking up where Ryan left off, we generated a return on capital employed of 19% on a trailing 12-month basis. That's 21% on a cash adjusted basis. We understand and appreciate that returns on and of capital matter to our investors, and we are fully focused on delivering to our shareholders. In the first quarter of 2022, we generated $3.27 per share in adjusted earnings. That's driven by strong realized prices and production of 1,747,000 barrels of oil equivalent per day, a record level of production since we became an independent E&P 10 years ago and is bolstered by our 2 highly accretive Permian acquisitions over the past 18 months. Lower 48 production averaged 967,000 barrels of oil equivalent per day for the quarter, including 640,000 from the Permian, 208,000 from Eagle Ford and 97,000 from the Bakken. Operations across the rest of our global portfolio also ran well, allowing us to generate $7 billion in cash from operations, excluding working capital in the quarter. We also continue to enhance our low cost of supply, low greenhouse gas intensity portfolio, closing on both the sale of our Indonesian assets and the acquisition of an additional 10% of APLNG, taking ownership there to 47.5%. Both of these transactions enhance our overall margins going forward. Illustrating this point, we realized roughly $500 million in cash distributions from APLNG in the first quarter, and we've already received $400 million so far in the second quarter. While the full year distributions will continue to depend on prices going forward, if you assume Brent averages $100 per barrel for the year, we would expect roughly $2.3 billion of total distributions from APLNG in 2022. Turning back to focus on the first quarter. In addition to the $7 billion in CFO, we generated $1.4 billion in cash to the sale of our remaining 93 million shares of Synovis. And this $1.4 billion fully refunded the share repurchased here of our $2.3 billion total returns to shareholders in the quarter. We also made significant strides toward our $5 billion debt reduction target, executing a successful refinancing through which we reduced our total debt by $1.2 billion. We decreased our annual interest expense by about $100 million and extended our overall debt maturity by 3 years. Also in April, we called our $1.3 billion note, which was due in 2026. So we'll have achieved approximately half of our $5 billion debt reduction target by the end of May. And with the progress we've made in the first 2 quarters of this year and our remaining natural maturities, we'll reduce our debt by $3.3 billion this year. We are now positioned to meet our overall $5 billion reduction target in 2025. That's 1 year earlier than our prior projections. As you will have noted, we also invested roughly $1.8 billion back into the business in the first quarter of the year. While this is ratable with the $7.2 billion full year capital estimate we provided last December, we're increasing our guidance to $7.8 billion. About half of the increase is due to additional low cost of supply drilling and completion activity in some of our partner-operated areas in the Lower 48. And the rest is modestly higher inflation, as we believe such supply chain constraints will be prolonged as a result of the ongoing conflict in the Ukraine. From a reduction standpoint, we've adjusted our full year target from an approximate 1.8 million barrels of oil equivalent per day to roughly 1.76 million per day. That's reflecting the net impact of closed A&D activity through this point in the year as well as some expected impacts from weather and well timing. So we've had a strong quarter to open the year. We've returned $2.3 billion to our shareholders and ended the quarter with $7.5 billion of cash and short-term investments. We further enhanced our low-cost supply portfolio, and we strengthened our balance sheet. And of course, our operations around the globe are well positioned to deliver on our commitments through the rest of this year and through the energy transition that's ahead of us. With that, let's go to Q&A.

[Operator Instructions]. We have a question from Jeanine Wai from Barclays.

Our first question, maybe to you is, we know you're committed to returning at least 30% of cash flow every year, year in, year out. Can you talk about how you decided on the new $10 billion level for the total return this year? I guess just assuming strip prices that equals to 35% of at least our forecasted cash flow and that's below the 2021 level of 38% and it's below the 5-year average prior to that. We know cash balances look very, very strong, and they're growing throughout the year. and that will probably be supplemented by some divestiture proceeds as well.

Yes. Thanks, Jeanine. No, we look at this quarterly review with the Board quarterly. We take an informed view of what we think the macro and the outlook for commodity prices is going to be for the rest of the year. I'd say we're -- we moved to $10 billion because we certainly felt like commodity price outlook is going to be probably above $90 a barrel and depending on where things end for the year and that supported going from $8 billion to $10 billion. And again, that's anchored in our commitment to return at least 30% of our cash flow back to our shareholders. And as you noted correctly, over the last 4 to 5 years, we've delivered even more of that and prepared to do that, should the market support that as we go forward. The other I can say is you can see that cash is rebuilding on the balance sheet a little bit as a result of the check we wrote at the end of the year. We have a desire, we want to put some more cash on the balance sheet to do that. So at the same time, we want to keep funding our stable capital program. So as we looked at it, we certainly thought we could afford moving to $10 billion. And that's supported by even if prices were to fall below $90 for whatever reason or if they continue to stay strong, investors should expect, calculate our cash flow, and you should expect to get a minimum of 30% of that back as we go through the year. That's been our commitment for many, many years now, and we're just living up to that commitment via these strong prices we see in the market.

Okay. Great. Our follow-up question is maybe moving to natural gas. So Conoco, you're in a unique position among your E&P peers in that you've got a lot of scale and also the location of your resource base, especially what you have in the Permian with your really strong marketing and takeaway position there. So maybe can you discuss how your view of Conoco's role in both the U.S. natural gas market and on the global scale? How that's really changed over the past 6 months or so? And perhaps any color you might have on your opportunity set as it relates to that would be really interesting.

Yes. Thanks, Jeanine. I guess, long term, today, we're about 30% of our portfolio is natural gas. If you look at our global position, a lot of that here domestically in the U.S. and then globally with our LNG exposure. We're pretty big fans of LNG. We think the Asian market and the European market, obviously, as a result of this invasion of Ukraine, has bolstered sort of the international gas side of it, which is why you see us doing things like competing for another train in Qatar and why we preempted on our APLNG interest in Australia. So we understand LNG and we'd like to get into that full value chain of that LNG. Here domestically in the U.S., we have a large gas position as well. And the beauty of our cost of supply model is it's a bit indifferent to gas and oil, but we are asking ourselves, has there been a disconnect on the gas side and what do we -- what should we be interested in. And certainly, LNG from the U.S. to Europe or other places is something of interest as long as we can be in that full value chain. We're not necessarily interested in just being in the liquefaction tolling business, that if we get exposed to that full value chain, that's something that we would be interested in looking at, given the nature of the gas business that's out there today.

Our next question comes from Neil Mehta from Goldman Sachs.

The first question is around the capital guidance moving from $7.2 billion to $7.7 billion. I think this was well telegraphed and certainly, we're in an inflationary environment. But would love your perspective on the components of some of those moving pieces. And as we get an early thought into 2023 and normalized spending levels, how much of this does carry forward?

Yes, Neil, I think what Bill tried to describe in the call transcript a little bit was we've upped our capital from $7.2 billion to $7.8 billion. And roughly half of that is extra activity that's ongoing across our Lower 48 by other operators. And these are good opportunities that are low-cost supply, very competitive in the portfolio, and we certainly don't want to be drilled out of any opportunities. So we are funding those kinds of opportunities as we go along. The other half is inflationary driven. And I would take you back to -- we set our budget at the end of last year in December. We talked about it in our fourth quarter call, where our view of the world at the time was coming out of the pandemic, we thought we were seeing some elevated inflation rates, primarily in the Permian. But the rest of the portfolio, we didn't see as much impact. So we were thinking in the order of mid-single digit kind of inflation rates across the whole global portfolio. And currently, since the Ukrainian -- and we also thought at the time that, that would abate itself in the last half of the year, as supply chains got renormalized coming out of the COVID pandemic. And certainly, after the Ukrainian invasion, we're seeing now inflationary forces across the entire global portfolio, with certain hotspots clearly still in the Permian and on certain categories of spend like labor and rigs, steel, pipes, chemicals, and some of the key categories of spend that our industry relies upon. So -- and I guess whether it mitigates as we go into 2023, is really a question of when does this -- all this turmoil that's going on around the world start to renormalize and get back a little bit. And at this 10 seconds, it's hard to say that that's going to renormalize anytime soon. So I think it's here with us for a while. I don't think it's transitory, and we're going to have to deal with it. The last thing I would say is we could have chose to cut scope. We could have cut our operated scope in order to try to manage to a number. And given the current macroenvironment, that didn't make sense to us. So that's why we have raised our capital guidance for the year to $7.8 billion.

Makes a lot of sense, Ryan. And that's the follow-up, it's on Russia and the Ukraine war. How does this structurally change the way that you think about the company and the oil and gas industry? And there are a couple of components to that question. Does it make it more likely that the market is going to be more accepting of sanctioning of long lead time projects, whether in Alaska or elsewhere? Does this change -- does it change where you ultimately want to invest? And then can you talk real time about what you're seeing in terms of Russia volumes as you guys explore -- follow the oil macro really closely? And how you see that playing out in the back half of the year, recognizing you don't have frontline operations, but you follow the situation very closely?

Yes. I think we all are, Neil, trying to figure it all out. I think we've seen sort of an immediate 1 million barrels a day of Russian crude off the market. Our expectation at this juncture is we're expecting probably 2 million to 3 million barrels a day of Russian crude with all the conversations going on in Europe right now to stop both products and oil imports into Europe. We're expecting that 2 million to 3 million barrels a day being taken off the market. And that's going to be tough for the supply to ratchet up. So we think about that, that's happening on the supply side. While on the demand side, there's a little bit of uncertainty with what's going on in China and another COVID. Our view of the demand side is we'll probably average close to 100 million barrels a day this year, which is kind of that pre-pandemic demand level, but we see growth in demand coming. Now that could be -- that could get slowed if another wave of COVID impacts the whole world. We don't see that as part of our base case. So we see demand continuing to grow over the next couple of years. And it will be tough if we take 2 million to 3 million barrels a day of additional Russian supply off the market, it will be tough for supply to keep up in the short and medium term. So it does have an impact as we think about the need for medium- and longer-cycle projects, the need for a call on more U.S. growth, which I think is coming this year. We think probably 1 million barrels a day and something similar next year. And I think it does kind of change the view angle on medium- and longer-cycle projects long term because of the underinvestment in the industry, with the demand growth continuing and supply being challenged to keep up with that. And then what that means back for the company is we're spending a lot of time rethinking a longer term or medium and longer-term macro, what the energy transition has in store and how quickly that might start to abate demand. And I think the immediate manifestation is what is your view of mid-cycle pricing over the short, medium and longer term right now. And while I don't think that impacts our capital allocation scheme and our cost of supply methodology and how we think about allocating capital, it does maybe at the broader level when you think about how much you have available for distributions and then what channels should you be distributing that capital to. And we have a three-tiered system, as you're aware of, our ordinary -- we'd like to ratably buy shares through the cycles. And then we introduced our third tier, the cash return VROC to supplement that in these times when prices are well in excess of what we think a mid-cycle might be.

Our next question comes from Phil Gresh from JPMorgan.

My first question is just on the Permian. In the first quarter, the quarter-over-quarter increase in production looked to have been below the amount of the acquired volumes from Shell. And I recognize there's quarter-to-quarter variability, but I was just wondering if you could talk about some of those moving pieces, but also more importantly, just how you're thinking about that cadence of activity for the rest of the year, given what you're talking about around OBO activity and other factors?

Yes, Phil, this is Tim. I'll take that one. we've been really pleased -- let me first say, I'm really pleased with the way the team has integrated the Shell assets into our overall company and activity. They've done a great job. It's been a safe combination. And we have just now begun bringing wells online with our vendors and our style of completion and things like that. So if you look at the pace of activity in the Lower 48, we were going to bring on 500 completed wells throughout the year. I think we brought on 90 in the first quarter. And so it's always been back-end loaded and building on a ramp of -- we closed the quarter with 22 drilling rigs in the Lower 48 and 8 frac spreads. And we planned -- when we rolled out our 10-year plan and guidance, we were going to build that over the next 10 years. And we're still on track to deliver all that type of activity. And so that's the plan we're on. That's what Ryan described as not cutting our capital back, but trying to run a steady ship and get the most efficiency out of it. So if you look at the ramp in activity throughout the year, that's true across our asset base, especially true in the Permian, 500 completed wells brought on throughout the entire year, but 90 in the first quarter. So it's going to build and be back-end loaded.

Okay. Great. That's helpful. Second question, I think, would be for Bill. Clearly, significant reductions in net debt in the first quarter. You talked about the pay down of the gross debt and the targets you have there. I'm curious how you think about the right levels of net debt or cash that you're holding because I think you also have, what, $2 billion to $3 billion of asset sales still coming here. So it just seems like you -- even with the $10 billion return of capital, there's a lot of cash building up. So any additional color there?

Yes. Sure, Phil. So I think that you can see it manifesting itself in the rebuild of our balance sheet with our cash growing to $7.5 billion. I think we're pretty happy right now with our pace in terms of debt reduction and how the program is set up. We've got our glide path set up for the next 5 years. So I think you can look at just the natural maturities as we go through time. And I think we've been pretty opportunistic in the market to set that up and are quite happy with where that's at. But I think as you rightly noted, that we'll be continuing to build up cash on the balance sheet. We're looking forward to some asset dispositions here later part of this year, and that's going to be going to generating cash.

Our next question comes from Doug Leggate from Bank of America.

May I first say, Tim, it sounds like we're going to hear a little less from you in the future. And whatever you do next, I just want to say good luck, it's been great getting to know you over the last 10 years. So with that, I have 2 questions, if I may. My first one is probably for Bill. And I just wonder if you could give us an update, Bill, with all the changes, given the Shell acquisition and obviously Concho, what is your current deferred tax position in the U.S.? When do you expect to see full cash taxes there? And my second question, if I may, is a big picture question for Ryan. Ryan, there's been 2 things came out, I guess, climate-related recently. One is the proposal from the SEC on climate disclosure and the second is the API's suggestion of a carbon tax. I'm just wondering if you could offer Conoco's perspective on those issues, please.

Great. I'll let Bill talk about the cash tax, and then I can address the last part. But I would say, Tim is not leaving us, Doug. We look forward to his continued involvement in all the key decisions in the company. So -- but let me turn it back to Bill first.

Yes. Sure, Doug. Assuming that current pricing continues, we would expect to be moving into a U.S. tax paying position this year with payments beginning quarterly starting this quarter, in the second quarter. Of course, the amounts and timing are going to vary depending on pricing and other market conditions, but we do expect to return to a cash tax paying position this year and starting to make estimated payments in this quarter.

And with respect to your last part, Doug, certainly, we're all kind of reviewing in quite a bit of detail what the current climate suggestions that have come out of the SEC in the rule-making process. We'll be commenting on that as part of industry as well. They're a bit problematic. I mean, we said all along, we're supportive of doing everything a company can do on Scope 1 and Scope 2 reductions as a company. And we came out with our ambition to be Paris aligned and net zero by 2050 with respect to the emissions that we produce as a company. And all companies ought to have a Paris-aligned climate risk strategy in order to address that to deal with the emissions they create. I guess the problematic piece has always been the Scope 3 because of the double counting, because of who's responsible for that, and should you hold a company like ConocoPhillips responsible for a consumer's decision to buy a pickup truck versus a Toyota Prius. And I think those are things in the Scope 3 side of things that we think are problematic. If you report them, they change. They're subject to double counting. And they have a lot of problems associated with how you might actually report against those certainly in an SEC sort of document that has to be included in your Qs or your Ks. It's, we think, quite problematic, which is why for quite a while as a company, we've been supportive of if you want to impact the demand side of the equation, you need to do something like a carbon tax. So we've been a part of API and a part of that decision process within our industry association to say the best way to deal with this on the demand side is to have a heavy carbon tax. So we were a founding member of the Climate Leadership Council with the dividend back to offset the regressive nature of attacks. But -- so consumers can make choices and decisions around the kinds of services and goods that they supply and understand what the carbon impact of that might be. We understand that that's a political hill to climb, and it's tough. But it makes more sense to us than trying to regulate your way to a solution that let the markets work and price carbon into the market, which is why we've been supportive of that as a better way to deal with the energy transition.

You've been leaders on this topic, Ryan, so I appreciate the answer.

Thanks, Doug.

The next question comes from Paul Cheng from Scotia Howard Weil.

Two questions. I think it's actually really short. First one, I want to go back into the cash tax. Bill, from an accounting standpoint, do you estimate the full year cash tax rate and then apply throughout the year in each quarter until the full year estimate has been changed over each quarter that's being estimated? That's the first question. The second question, I think, is for Tim. Also real quick, what is the first quarter weather impact on your production by region or by the different play? And also that what's the second quarter weather impact in Bakken that we see so far?

Yes, sure, Paul. So for U.S. cash tax paying position, we estimate our annual taxes on a yearly basis and then we pay quarterly on estimated taxes. And as I indicated, we expect to start making those quarterly payments in the second quarter of this year.

Yes, Paul, on the weather question, we had weather impact in all our major basins in the first quarter. It was -- I'm really proud of how the team responded to that. We got things back on fairly quickly. I would say the weather impact, while it affected almost all of our production, it was rather nominal, and we were able to overcome that. As to the second part of your question about up in the Bakken. I think everybody is aware that is probably the most severe winter in recorded history up in North Dakota, and we're still assessing the amount of time it's going to take to bring that back up to full production. So I think the assessment is still going on there.

Paul, this is Nick, too. I'll just add on to what Tim was saying related to turnaround impacts for Q2 and Q3. So Q2, we've got a fairly large turnaround activity, both in Norway nonoperated and operated as well as Surmont. So that will average about 35,000 barrels a day for Q2. And then we have less activity in Q3, and that's focused on Alaska, Train 2, APLNG, and then Montney and Canada and that will be 15,000 for Q3. So 35,000, Q2; 15,000 for Q3.

Our next question comes from John Freeman from Raymond James.

First question, Ryan, when you were talking about just given everything that's happened in the market, how you have to constantly kind of be evaluating the sort of a 10-year sort of macro and energy transition, demand impact, your view of mid-cycle pricing. And then one of the things that you mentioned that I was hoping you maybe expand a little bit on, as you said, maybe it would possibly change the view of how you think about kind of short cycle versus long cycle production?

Yes, John, I'm just trying to make the point that I think the transition is not going to be a cliff transition. It's going to be a drawn out one and the pace of that -- the slope of that curve is pretty unknown. So the way you react to that is have the lowest cost of supply barrels that you can supply whatever that transition demand is going to look like and make sure that they're giving an adequate and competitive return. And I think we're well set up to go do that. And the point I was making is that the -- in all these scenarios, even some of the IEA scenarios that they look at and we monitor 4 or 5 different scenarios internally to the company, most of those suggest that there's going to be a need for oil and gas long past 2050. So -- but we have to supply that sustainably. We have to supply that with a low GHG intensity going to net zero by 2050 but we also have to supply low cost of barrels. So when you look at that, it's going to be around a long time. So sure, medium- and longer-cycle projects are going to be needed in this industry. We just have to assure ourselves that they're competitive on a cost of supply basis and then they have a competitive GHG intensity as well. And so projects like Willow and Alaska fit that mode. They're well under a $40 cost of supply. They are less than $10 a kilogram per barrel of CO2 intensity. So they fit well within what the world is going to need in order to ratably and reliably supply the energy to a growing world where energy demand is going to be increasing over time. We have to figure out how to do that more sustainably.

And then my follow-up question for Tim and Jack. I know on the Shell assets, you all stated in the past that the biggest opportunity there is transitioning from the 1 mile of the 2-mile laterals and to accomplish that, that's going to require coring up a lot of that acreage with some of the partners. And just kind of wanted an update sort of how that's progressing. And then if all sort of goes according to plan, kind of what would be a reasonable amount of that acreage that could be done with 2-mile-plus laterals?

Yes. Thank you, John. We're -- these trades and swaps are a core competency of the team. So we're continuing that. The -- we've seen good opportunity there, and it's starting to manifest itself in some longer laterals, both on the operated and the nonop on the Shell assets, and I expect that to continue.

Our next question comes from Leo Mariani from KeyBanc.

Just wanted to follow up a little bit on some of your comments around LNG here. Really, what I'm just trying to get a sense of is, do you all at Conoco, through your kind of extensive global marketing footprint, think can the U.S. really do anything in the next couple of years, say, '23 and '24 to add any incremental LNG export capacity at this point in time? Or are those adds more kind of mid-decade and beyond? Just trying to get a sense of whether or not there can be more material connectivity between Europe and Asia and the U.S. in the next few years.

Yes. Sure, Leo, this is Bill. I think that if you look at LNG export capacity today, it's running a little over 12 Bcf a day. The U.S. export terminals are running effectively at capacity or slightly above nameplate. I think that you've got several folks who are out in the market who are looking at taking FID, but there's a practical reality that once you take FID, it's several years to build these terminals. So I think if you're looking at impact in terms of immediate term or mid-decade, I'd say it's closer towards mid-decade before you start seeing these new import -- these new export facilities online.

Okay. That's helpful for sure. Just wanted to ask a brief question on your Canadian production, I guess, primarily in the Montney here. As I'm kind of looking at your conventional non-oil sands volumes, it looks like they've kind of been dropping for the last 4 quarters based on the data you all provide. Do you expect those volumes to start growing at some point, maybe in the back half of the year or '23? What can you kind of tell us about the trajectory of the Montney there?

Yes, Leo, this is Nick. One of the factors that we have to look back at as we took a fairly large capital cost, obviously, in 2020, and then we're in maintenance mode in 2021. We didn't have any rigs or frac crews. So we've restarted that program earlier this year, we started fracking the wells. That's Pad 4, and then we're also drilling Pad 5 and Pad 6. So that drop that you're seeing over the last 4 quarters is really just a lack of work that we're doing up in Montney. So we're started back to drilling both, like I said, Pad 5, Pad 6, we'll see some of that production come on stream in Q3 and Q4. And then another thing, Leo, that we're doing is we're working on our CPF2 facility expansion. That's where we're adding both gas handling, our condensate recovery and then water handling. We're about 30% complete on that, and that's on schedule and that will come on stream in 2023 as well. The condensate recovery unit will allow us to really monetize on that Kelt acreage that we picked up a few years ago.

We have reached the allotted time we have for questions. I would now like to turn the call back to Mr. Keener for final remarks.

Thank you, Hilda, and thanks to all who took part in today's call. And with that, I'll wrap it up with you, Hilda for any closing comments. Thank you.

Thank you. Ladies and gentlemen, this concludes today's conference. We thank you for participating. You may now disconnect.