康菲 (COP) 2020 Q2 法說會逐字稿

Good morning, and welcome to the Q2 '20 earnings call. My name is Zanera, and I'll be the operator for today's call. (Operator Instructions) Please note, this conference is being recorded.

I will now turn the call over to Ms. Ellen DeSanctis. Ellen, you may begin.

Thanks, Zanera. Hello to our listeners, and welcome to our second-quarter 2020 earnings call.

Today's speakers will be Ryan Lance, our Chairman and CEO; Don Wallette, our EVP and Chief Financial Officer; and Matt Fox, our EVP and Chief Operating Officer.

As many of you have noticed, in conjunction with this morning's press release, we posted a short presentation deck of supplementary material on the quarter. Page 2 of that deck contains our cautionary statement. We will make some forward-looking statements during today's call. Actual results could differ due to the factors described on that slide as well as in our periodic SEC filings.

We'll also refer to some non-GAAP financial measures today, and reconciliations to the nearest corresponding GAAP measure can be found in this morning's press release and also on our website.

And with that, I'll turn the call over to Ryan.

Thank you, Ellen, and good morning to our listeners. We are now at the midpoint of what has been nothing shy of a historic year for our industry and for the world. I hope everyone on the call is safe and well.

Since the pandemic and the industry downturn began in March, ConocoPhillips has focused on three things: safely operating the business, including taking appropriate actions to help mitigate the spread of COVID-19 and protect our workforce. Our field and office personnel are successfully delivering the business plan. I'm very proud of how our organization has stepped up in the face of this challenging time.

Next, we're focused on executing thoughtful and prudent actions to create and preserve value by leveraging our relative strengths. And third, we're continuously monitoring the market, developing scenarios and testing our current and future plans against those scenarios.

Now here's a quick recap of our actions through the first half of the year. We reduced 2020 capital spending by about $2.3 billion, lowered our operating costs by roughly $600 million and suspended the share repurchase program. In April, as pricing deteriorated significantly, we announced that we would begin voluntary production curtailments. We laid out a clear and compelling economic rationale for curtailments. We believe we were well-positioned to carry them out because of our operational flexibility and our significant balance sheet strength. We believe this is a preferable approach for us versus hedging, because it allows us to retain full exposure to the recovery in prices.

Low realized prices and reduced volumes due to curtailments made for a tough headline second-quarter earnings that masked the underlying strength of the company. Here's how you should read through the quarter's results. We came into the year with total liquidity of nearly $14 billion, including the $6 billion available under our revolver. At midyear, we are sitting at about $13 billion despite the crash in prices, with available cash and short-term investments totaling roughly $7 billion. If current prices hold for the rest of the year, we expect to exit the year in a similar position.

Our cash position creates significant optionality for navigating the downturn. We can better withstand price volatility, elect to take actions such as production curtailments and transact on high-value, low cost of supply bolt-on deals, like we announced in the Canadian Montney.

Our underlying business is performing very well. Again, curtailments and dispositions mask the top-line production numbers, but we have a very good handle on the base business. While our previously announced capital and cost reductions have modestly impacted near-term productive capacity, we believe our lower capital intensity and portfolio diversification represent a relative advantage compared to the competition, many of whom have much higher decline rates and weaker balance sheets.

So we're set up well during this time of uncertainty and volatility. But just as importantly, we're very well positioned to benefit from the inevitable recovery in prices. We have strong financial and productive capacity, low capital intensity and we're unhedged. This should benefit us significantly when prices eventually move in a more positive direction.

Importantly, we have choices on how to manage the recovery in a way that maximizes value for shareholders. So as you'd expect, we're already looking ahead. We're actively developing our views on the short and medium-term outlook for both the path and the timing of recovery in prices.

Given ongoing uncertainty, you can appreciate there isn't a simple answer to what's next, but here are some of the questions we'll be asking ourselves over the next weeks and months. What should our capital program be in relation to expected cash flows and our balance sheet capacity? To what extent might we choose to kick start cash flow expansion if we see a recovery? How much cash do we want to carry on the balance sheet? What's the right way to think about stress testing our future? When we do distribute cash above the dividend to shareholders, and by what mechanism should we do that?

While it's too early to communicate a definitive plan for the next year and beyond, you shouldn't expect the fundamental tenets of our value proposition to change. We still strongly believe in our approach to the business: invest to generate strong cash flows and financial returns, while also returning a significant portion of cash flows to shareholders and maintaining a strong balance sheet. That's the business model we've been following for nearly four years. We launched it coming out of the last downturn in 2016, and it positioned us well for this downturn. We still believe it's the right model for the business and one we're uniquely positioned to execute as the environment recovers.

Now let me turn the call over to Don to cover the key drivers in this quarter's results.

Thank you, Ryan. I'll begin by providing a summary of the key second-quarter earnings drivers and then recap our curtailment activities before handing off to Matt for some outlook comments. We provided some supplemental slides along with this morning's press release, and they're available on our website.

If you refer to Slide 3 in our materials, I'll recap the quarter performance. The earnings variance from the first quarter to the second quarter can be explained primarily by two drivers. Realized prices fell 41%, and production excluding Libya, was down 23% sequentially.

On the lower right side of the slide, you can see the factors that caused realizations to decline from almost $39 a barrel equivalent in the first quarter to just over $23 a barrel in the second quarter. Of this roughly $16-a-barrel decrease, about 70% was due to lower benchmark prices across all products; 25% by a significant downturn in differentials in the U.S., Canada and for LNG; and the remainder was related to deficiency payments associated with unused transportation in our Canada business. And as you are aware, the primary driver of the reduction in second-quarter volumes was production curtailments, which I'll cover now on Slide 4.

Recall the rationale for our curtailment decisions was that we could create value by foregoing short-term CFO to realize better cash flows in the future. We were not willing to sell our product for the prices on offer at the time. We've estimated our curtailments for the quarter at approximately 225,000 barrels of net oil equivalent per day, roughly 145,000 BOE per day of that total was sourced from the Lower 48, and you can see the breakout of the Big 3 unconventional fields. We estimate Alaska at 40,000, Surmont at 30,000, and we had some minor curtailments in Malaysia and in Norway.

As we previously discussed, our curtailment activity was based on a clear economic framework. We view voluntary curtailments as an investment, meaning we're electing to forego current cash flows for what we believe will be more attractive future CFO.

The average realized oil price for the areas where we voluntarily deferred oil production in the second quarter was about $27 a barrel. So we would expect to capture higher prices on these deferred barrels in the future. And while we will not know the economic return on this investment for a while, we can reasonably estimate the cash flow impact of our decision on this quarter's results. As the slide shows, assuming we had produced and sold these curtailed barrels at average realized prices for the quarter, we estimate the curtailment decision represented about $250 million of cash from operations. We believe this was a sound economic decision that at current strip prices would yield a return of greater than 20%.

Marker prices have increased from the second-quarter lows and differentials have tightened as well. As we announced in our recent operations update, we're beginning to restore production in the areas where we had actively curtailed during the second quarter. Matt will describe third-quarter plans in a moment, but I'll summarize our actions with a few key takeaways.

We're taking deliberate, sound, returns-driven actions through the downturn. Our focus is on preserving the productive capacity of our company and maintaining a strong balance sheet. Lastly, despite a challenging year so far, we're in a very strong, competitively advantaged financial position, with a clear focus on value creation.

And with that, I'll hand off to Matt.

Thanks, Don. Don's already cleared a high-level view of the second-quarter production curtailments as shown in more detail on Slide 5, and I'm going to briefly add some more color to those actions.

So between the U.S. and Canada, as we safely ramped down production through our facilities, we shut in more than 2,000 production wells, roughly 1,800 in the Lower 48, 300 in Alaska and 100 in Canada. We opportunistically sheltered maintenance where we could, collected downhole pressure measurements and sustained injection in the relevant fields to maximize flush production. It was a massive effort, conducted extremely well by our operations staff.

Also shown in this chart are our anticipated third-quarter curtailments. We're still making month-by-month decisions based on the criteria we described in May. But at this time, we estimate average curtailments of about 115,000 net barrels of oil equivalent per day or roughly half the volume we curtailed in the second quarter.

Production in Alaska has now been fully restored. We're ramping up the Lower 48 over the next few months, and at this point, expect to be fully restored there sometime in September. We're also increasing production at Surmont, but that's going to be a slower ramp due to planned turnaround in the third quarter and a precautionary decision to limit staffing in the field as a COVID mitigation, and that's going to lengthen the duration of the turnaround.

There are also some minor non-operating curtailments expected to continue in Malaysia and Norway. The bottom line is, except for Canada, we expect most of our curtailed volumes to be back online by the end of the third quarter.

Now when we announced the curtailment plans, we got a lot of questions about operational risks or negative impacts from curtailments. Our answer was that we didn't expect any negative impacts due to shut-ins and that's been the case. And as anticipated, we've observed flush production in Alaska and the Lower 48 as we brought wells back online.

So now I'll take a few minutes to outline some other operational items for the rest of the year. In addition to our curtailment activity in the third quarter with planned turnaround activity that primarily impacts Alaska, at Kuparuk and Alpine; Surmont, as I touched on a few minutes ago; Norway; and Malaysia. Collectively, they'll reduce third-quarter volumes by about 20,000 barrels a day.

In the Montney, our first development pad started flow back in February of this year. All 14 of the new wells have now been tied into permanent facilities and production from Pad 1 is ramping up. We used completion designs developed in our Lower 48 Big 3 fields, which as far as we know, are the biggest jobs pumped in the Montney today. And the wells are performing in line with or above our expectations. Montney production is now roughly 15,000 barrels a day, about half of that being liquids.

Pad 2, a 9-well pad, started flowback a week ago. So we're very pleased with how operations are running at Montney and encouraged by the early well results. And we could see from our early proprietary well data that the liquids-rich part of this play held significant low-cost of supply resource, and that's what encouraged us to expand our position through the recently announced bolt-on acquisition from Kelt. The transaction adds adjacent acreage to the east, roughly doubling our position to almost 300,000 acres with 100% working interest. And like our current position, it's in the sweet spot of the liquids-rich window of Montney. In fact, the liquids content is slightly higher in the new acreage.

On a combined pro-forma basis, the Montney is producing close to 30,000 barrels a day with over 50% liquids. And the deal adds about 1,000 development well locations and over 1 billion barrels of resource, and all-in cost of supply, including the acquisition cost in the mid-$30s per barrel on a WTI basis. So we are very happy with this bolt-on acquisition.

Moving now to the Lower 48, we're currently running seven rigs, four in the Eagle Ford, two in the Bakken and one in the Permian. We expect to maintain this level of rig activity for the remainder of the year. Since May, we've had no frac spreads under contract, but we expect to add one or two crews in the Eagle Ford between now and the end of the year.

And given the changes to our capital plans, the production curtailments and adjustments to some of our other operating activity, we understand it's difficult for you to calibrate our underlying production. Because the environment is still uncertain and volatile, we're not yet providing detailed guidance, but to give you a calibration point, when adjusted for curtailments, Libya and dispositions, we expect 2020 to be about flat with underlying 2019 production.

Now I'll turn the call back to Ryan for some closing comments.

Thanks, Matt and Don. I'll close by summarizing the key messages I want you to take from the quarter.

Despite this year's low prices, we've retained our financial strength, including roughly $7 billion in available cash and short-term investments at midyear. The underlying business is performing very well, a big credit to our workforce. The actions we've taken to date will only have a modest impact on our near-term productive capacity. Our lower capital intensity, portfolio diversification and financial strength represent a relative advantage compared to the competition.

This gives us the ability to successfully navigate the environment from here. We can better withstand price volatility while maintaining exposure to higher prices. So as we set our future plans, you should expect us to remain committed to our successful value proposition that maximizes shareholder returns and that we believe is the right one for the sector.

Now before I turn the call over to Q&A, I wanted to recognize Don, whose retirement we announced a couple of months ago. Many of you know Don quite well, and I appreciate everything he's done for the company over his 39 years of service. I certainly do. So Don, we'll miss you. We thank you, and we wish you all the best in your retirement.

So with that, operator, we'll turn it over to Q&A.

(Operator Instructions) And our first question comes from Phil Gresh from JPMorgan.

Yes. And my congratulations to Don too. You will definitely be missed and appreciate all the time we worked together.

Thank you, Phil.

I guess my first question -- I appreciate all the commentary, Matt, that you provided on the third quarter, and recognizing that you're not giving specific guidance here. I guess I just wanted to clarify the moving pieces here. So obviously, we have the curtailment impact, with the positive 110,000. We have the maintenance that would be a -- I think it's a 20 KBB headwind, but I wasn't sure what the second-quarter maintenance was. So is that number you gave the absolute? Or is that a delta quarter-over-quarter?

And then, is there anything else we should be thinking about in terms of moving pieces, such as perhaps base decline rates or anything like that?

Yes. Thanks, Phil. The -- yes, for the quarter, yes, 20,000, and that's the absolute number. In the second quarter, it was about 5,000 barrels a day. So it's a 15,000 delta from the second quarter.

The -- and it's about 5,000 barrels a day in Alaska, about 7,000 in Canada, about 7,000 in APME and Malaysia, and there's a little bit in Norway. So that's the split. The -- it was -- in the third quarter of '19, it was a bit more. It was about 30,000 barrels a day. And so it's a bit less than the third quarter of '19.

No other significant moving parts, obviously, other than the return of the curtailed production, which will mostly be done in the third quarter. Is that the -- does that answer your question, Phil?

It does. It does. Okay. Second question, just a little bit further out here. How do you suggest that we should think about the 4Q exit rate for the business? And as you're looking out to 2021, Ryan, you rattled off a bunch of things you're thinking about. But I guess if we were to think of an environment like we're in today with $40 WTI, how would you think roughly about CapEx? And do you have any kind of revised view on what sustaining CapEx requirements would be for the company and/or for the Lower 48?

Yes. Let me elaborate that real quickly and then let Matt chime in, Phil. Yes, we're spending a lot of time thinking about what the trajectory of the recovery would look like, and we have a view that we see demand recovering and some supply restraints. So we do see some recovery in prices as we go into 2021, and that's what we're kind of building into our plans. But as I've said before, we're kind of in the middle of that process right now. And I mean, if we saw the case where the -- you suggest oil prices remain in the low $40's where they're at today, I think we would act differently than if we saw some ramp-up or some improvement in the demand causing prices to be a bit more constructive next year.

So we're in the process of trying to understand that today and have a different answer if we saw ramping prices, which we think is a base case versus something that's flat relative to today. And then I can let Matt chime in on some sustaining CapEx numbers and the exit rate question that you had.

Yes. So Phil, on the exit rate the -- so I said that we expect 2020 production to be roughly the same as 2019 on an apples-to-apples basis. Production in the first and second quarter of this year was a bit higher than in the first -- than last year. So it's going to be a bit lower in the second half to get the -- and to end up with that balance. Right now, from a fourth-quarter to fourth-quarter basis, we'd expect rates to be somewhere between 6% and 8% lower in the fourth quarter of 2020 than in 2019. So that's a rough sort of guide as to how we see the shape of the profile.

In terms of the sustaining capital, it hasn't changed. It's still about $3.8 billion a year. The -- having flat production from '19 to '20 shouldn't be taken with our current capital program for 2020 to be an indication of sustaining capital, because we're not trying to sustain production in this price environment. We've been stopping fracking activities and shutting production in, but it's still the case that if we wanted to design a capital program to sustain production, it's about $3.8 billion a year.

Our next question comes from Neil Mehta from Goldman Sachs.

The first question I had was just around price realizations in the quarter. They were a little softer than what we had anticipated. Was that just a function of differentials and the role in the curve, at which point it would be more one-time in nature? Or was there anything in there that you would think of carrying forward?

Well, Neil, this is Don. Yes, we would be hopeful that it would be -- turn out to be one-time in nature. I mean that's going to obviously depend on what the future holds. But we have seen -- certainly seen some improvements as we went through the second quarter. April and May were pretty tough. I think we talked about this maybe in late April. That what we were seeing physically in the field as far as differentials was quite a bit different from what everyone was seeing on the screen.

So -- but that situation did materially improve as we got into June and certainly has held up in July as far as the real differentials that we're seeing in netbacks at the lease. So -- and even in the -- we're in the trade month -- or we finished the trade month of August. So it's looking like it's holding up reasonably well for most of the second -- or the next quarter, the third quarter.

Alaska realizations were pretty weak. I mean everybody is familiar with the PAD 5 West Coast demand situation with very low refinery utilization rates there. And just to give you a point of reference, in the first quarter, let's just talk Brent because we talk WTI or Brent. But on a Brent basis, we were able to capture 97% of the Brent marker price in the first quarter as a realization. And in the second quarter, we were only able to capture 86%.

So quite a difference quarter-on-quarter. And now what we're seeing in the third quarter is more of a return to normal, and we hope that it will stay there. But we did see significantly lower realizations relative to the marker in Alaska. We also saw them in the Lower 48, particularly in the Bakken and the Permian.

And I do want to extend my gratitude to you, Don, as well and wish you well in your retirement.

The follow-up question is just kind of a two-parter here. When we think about the pushback we get on Conoco, the two areas of focus continue to be from a strategic standpoint, continue to be: one, risk around consolidation and M&A; and then, two, risk around Alaska, both from a federal lands perspective but also on the ballot initiative.

So Ryan, if you could take those two head on, we would appreciate it.

Yes -- no. Thanks, Neil. Yes, I think the M&A, I think we tried to describe in, probably, nauseating detail in November, kind of how we're thinking about the business, how we think about cost of supply, both from an all-in-looking perspective and from what the acquisition cost needs to include and what the ongoing development needs to be, to be competitive for capital inside the portfolio.

Again, we've got a 15-billion-barrel resource base. Its average cost of supply is in the $30's. So -- and it has to fit our financial framework, has to be accretive to the business. So we're patient, we're persistent. We're watching the market every day. We're looking at both asset deals. We're looking at corporate deals. We're looking across the board. But -- and I think we're encouraged today when you see the Chevron-Noble deal and the kind of premium that Chevron paid for that, I think, is encouraging because, market-changing, or the large premiums of the past couple of years just don't work in this business going forward. So we're certainly encouraged by what -- by what we see there because I think that's going to help drive some of the actions that's necessary in the market today to take some of the G&A out of the business. So yes, we're watching. We're looking at both assets and other kinds of deals, but it's got to fit the framework that we described out there in November.

On the federal acreage in Alaska, the ballot initiative is coming up for vote in November. We're working on that pretty hard. I think the citizens of Alaska recognize this is not a time to be raising taxes on the industry. And over the long term, it's going to just create more of a problem for them. It's going to represent and result in lower investment and slowing down of activity across the whole North Slope, not just maybe what we're doing but what other people are doing as well. So it's bad policy and bad fiscal policy for the state, and it's a bad way to legislate through the initiative process.

The federal acreage up in Alaska is probably a little bit different. Most of the state acreage that we're on and the big fields are on the state. The federal acreage is out in NPRA, where we're operating in the Alpine, the Willow Discovery in what we're doing out west. And despite all the rhetoric we hear from the politicians, our view out there is it's pretty safe. We've leased it up. We've leased up what we think is the prospective acreage already out there.

So then it comes a question to the -- if you are a successful explorer and you go into a development mode, does that get drug out through the permit process? And while we've been doing this for 50 years through all forms of different administrations, Democrats and Republicans, those that have said they want to shut the business down and those who want to accelerate it, and we still managed to get our projects done because we do it responsibly, we do it sustainably, and we follow the process.

So we're not too concerned if it adds a year delay to something, that's well manageable within our global portfolio.

Our next question comes from Doug Terreson from Evercore ISI.

And Don, congratulations to you. And we, too, appreciate you and all the help over the years.

Doug, thank you.

And so first, Ryan, your choice to reduce sales volumes or maybe you all's choice when prices and differentials went to record low levels, and second quarter looks like a pretty astute economic decision. And on this point, my questions regard a few of your high-level comments. And specifically, you talked a little bit about negligible production degradation. So can you just kind of give us some evidence as to why you feel so strongly that that's likely to be the case for ConocoPhillips?

And then, second, with many of your E&P peers having higher shale exposure and also weaker financial flexibility after this most recent OPEC salvo, it seems like your normalized production levels should be stronger versus peers in the future, simply. So just wanted to get any additional color that you had on those comments that you made?

Yes. Thanks, Doug. I can -- let me start. Matt may want to add a few comments as well. But yes, so the -- we have talked, and I think Matt said in his prepared comments, we see some -- we don't expect to have any issues with returning to shut-in production.

And then that's what we've seen. So we've started the process. We curtailed 225,000 barrels in the second quarter. Matt described what the third quarter has. So we're in the process of bringing on some of that production in Alaska and in the Lower 48. Alaska, as Matt described, is not curtailed any longer, and we've actually seen return to production. We've seen flush production. And in fact, I don't think -- Matt can provide some color. I don't think we've seen some of the issues that we even might have expected in terms of bringing that production.

So we feel very confident that we're not only going to come back, we're going to see the flush production and the economic analysis that Don described. Even just looking at the forward curve delivering something in excess of a 20% return, we feel pretty confident that, that's the kind of profitable economic decision that we made through the course of the curtailment discussion that we've had.

And then finally, on shale exposure, yes, we do believe we're competitively advantaged. We believe we have a lower decline rate. We're not completely reliant on the shale. The shale will have a higher decline rate coming out of the reduced CapEx and some of the curtailments that people have described, not only for us but the industry in general. But given our financial flexibility, the strength of the balance sheet that we have and the experience that we've gained from this, yes, we think we're in a very competitive position, and we've got the financial strength to respond.

Our next question comes from Roger Read from Wells Fargo.

And Don, congratulations. I hope it's a great retirement, at least from calls like this, but thank you for everything over the last several years.

Yes. He's smiling, Roger, from ear to ear.

Appreciate it, Roger. Thank you.

Just to flip back to kind of the M&A thing. You had the Kelt acquisition you announced just a couple of weeks ago, $400 million, nice bolt-on-type transaction.

I was curious, though, how that compared maybe to some of the other things you're looking at? I mean you mentioned the Noble transaction. I assume that that's probably a little bigger than you want to take on at this point, not to mention the offshore part of it. But as you look at kind of the opportunity suite that's out there, how did you compare Kelt and that acquisition at this time as opposed to something in the Lower 48 or elsewhere?

Yes. I think what we're seeing, Roger, probably is -- there's companies out there that are distressed and those that have either singular assets or even a bit more of a diversified portfolio are looking at potentially trying to transact to bolster their financial condition in their balance sheet. So we see some interesting asset deals, and we see some smaller or other kind of corporate deals that are kind of interesting. But I think we're looking at it pure and simple on the financial framework we outlined in November, and it's on an all-in cost of supply. And we had identified this acreage even a year or two ago. It wasn't until they were motivated to sell at a price that we were willing to pay that we actually transacted with them.

So again, we're pretty patient and persistent. And it just got -- it has to fit our financial framework, our cost of supply framework that we've outlined in incredible detail to you guys for the last five or six years, and that's what we're sticking to. So it's got to be competitive in that regard. Then it will attract capital within our portfolio as long as it meets that criteria.

So is it fair to say that sellers are a little more motivated than they have been?

Some certainly are, yes.

Okay. And then just to change directions a little bit with the second question. We've seen some E&P companies start to talk about a minimum price for oil before they would restart some of their drilling programs. As you think about managing the decline rates, completing the wells that were deferred earlier this year as everybody shut down drilling, and the $3.8 billion of kind of sustaining CapEx, is there an oil price lever we should pay attention to? Or marker that probably makes you more likely to drill? Or what is it that you probably need to see to feel more confident as you think about the '21 and '22 plans?

Yes. Roger, I may take that. This is Matt. The -- I wouldn't say there's a specific trigger. I mean the -- it was very clear in the curtailment discussion that there was the economic criteria, where easy to see prices in the $30's that made more sense, and then certainly below that to be deferring the production and bringing it on later.

It's a similar sort of economic calculation for adding new production as well. I mean that's one of the reasons, of course, is we've been -- we're curtailing production, of course. We weren't completing and bringing on any new wells, so that would not make any economic sense. So the criteria for bringing on new production, as long as the cost of supply is low enough and our efforts and our portfolio that we're developing is below $40 cost of supply, as long as the cost of supply is low enough, then we would use a similar sort of criteria for bringing on new production as we did for curtailments.

So if you look at the strip today, that would suggest that for our portfolio, it's okay to bring on new production into that strip if necessary.

And I think I'd add, Roger, that's when we're starting to balance all the next year is how do we think about the price, the cash flows? Where the balance sheet stands today as we try to balance all those competing things for the cash flow that we generate based on the price.

So I think Matt's right, we're not afraid. We're convinced that we'll deliver a competitive and a good ROCE and a good return on the capital investments, given the cost of supply that we're investing in. We just need to now balance that against our expectations for cash flow and the balance sheet.

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

Don, I'm going to add my congratulations as well, but maybe spin it a little differently. Thank you for putting up with all of us for the last bunch of years. I know it's not always been easy, but good luck with everything.

Been a pleasure. Thank you.

With that I -- Ryan, I'm going to kick off with -- and forgive me for being a little controversial here, but you've expressed some confidence in a commodity recovery. I don't know if that's too strong a term. But you've got smaller peers, you mentioned Noble specifically, that seems to be less confident to the point of selling out, one would argue at the bottom.

When you think about the type of -- the M&A landscape, how it's changed, what the strategic goals are for ConocoPhillips, my controversial bit is Noble followed a process. Did you look at it? If not, why not? And if not, what are the kind of things that ConocoPhillips believes would fill "gaps" in your portfolio?

Well, we did look, Doug. And I think it's -- I think, a fair question. I think when we look at it, we think about the match in our portfolio, a bit concerned about -- I mean, the gem is certainly the Middle Eastern gas position. And with some of the other things we're doing in the Middle East, that creates maybe a little bit of an issue and problems with us politically. And then the second big piece of the Noble portfolio is the Colorado, and we just got done painfully exiting Colorado and not wanting to go back. Then obviously, them being in Weld County offers maybe a little different perspective on Colorado.

But I would just say, we thought they're pretty fairly valued for even a commodity price recovery and not a great fit in our portfolio.

So if I may just -- I appreciate it. But let me just fish a little bit. What -- so long-life, low-decline growth potential assets would seem to be a great fit with Conoco. Is that -- or are you looking for -- when you look at the M&A landscape, are you more concerned, for example, as folks have sometimes asked about inventory depth in your unconventional portfolio. Where do you see the gaps, if you like, the strategic gaps?

Well, I don't think we're too worried about inventory gap in our unconventional portfolio. And I think the recent Kelt acquisition just adds some even much more long-dated position there. So again, it's quality over quantity. And we're just -- and its cost of supply. So we're firmly focused on that in the unconventional space, just like we are elsewhere. And your low cost -- your low-decline, long-life assets, that would describe another train in Qatar, wouldn't it?

Yes. Yes, I guess it would. Well, look, if you don't mind, my follow-on question is just to take advantage of Don still being here.

Don, the stock opened up almost 10% this morning, which I think surprised a lot of people. It seems that we're at a very wide range of estimates, Don. I'm not sure what exactly that was behind that. But I wonder if you could just walk us through some of the noncash moving parts? I'm thinking specifically about how you manage DD&A rates and some of the other maybe core items related to market moves and so on, just to kind of clean up what the difference between the earnings and the cash flow deltas were this quarter. And I'll leave it there. And thanks, again, for all your help in the past.

Yes. Thank you, Doug. Yes, the difference between -- of course, there was a wide range on earnings estimates, as you would expect, because it was quite a volatile quarter. And in addition, we did not provide any guidance. So I don't know that we were completely surprised there. But we can -- I can point to a number of things that we would think that it would be very difficult for folks outside the company to estimate.

I guess the first and probably the most important or significant was the -- what I talked about before with the lower realizations. Now that was a cash item, not a non-cash item. But we think that those -- I mentioned some figures as far as our percentage of market capture versus prior quarters and historic quarters. And we think that, that was probably somewhere around a 15% per-share impact, and hopefully, as I mentioned before, a temporary impact.

You mentioned DD&A, and that was another factor that probably was not expected. Of course, our DD&A fell, reduced considerably during the quarter, as you would expect, with lower production. But our DD&A rate did go up a couple of dollars per BOE. And that was a result of an adjustment that we made to the rate in anticipation of declining reserves due to the lower price that we've seen.

Now some companies wait until the end of the year to adjust their DD&A rate and to revise their reserves. We look at it periodically through the year. So we will do interim updates. You've seen us do it before. We did it in 2016, as reserves were going down. And then we went the other direction in 2017 and '18 as prices improved and reserves came back on the books. And so perhaps that will be the situation here. But we did make an interim adjustment in the second quarter that caused the DD&A rate to go up.

That wasn't the only thing that caused the DD&A rate to go up. We also had some impacts from our curtailment decisions. We were -- we had an unusual product mix, I guess, I would say, during the second quarter with low Lower 48, low Alaska volumes. And so you'll see that product mix had an impact on the rate as well.

And the third most important area that may not have been anticipated, I wouldn't think that it's something that you would normally track, is the mark-to-market movements as the stock market rebounded pretty significantly from the end of the first quarter to the end of the second quarter, and ConocoPhillips stock as well. Then we saw an adverse cost impact of -- I think it was around $50 million pretax, just on mark-to-market compensation and benefits issues.

Now from the end of the fourth quarter to the end of the first quarter. and booked recognized in the first quarter, we saw the opposite. We saw a cost benefit when you saw SG&A go negative. And we had a -- I think it was about a $90 million pretax impact on mark-to-market as the stock market went down and as ConocoPhillips' stock price went down.

So those are the three main items that I would point to that would be difficult, I think, to estimate outside the company.

Our next question comes from Scott Hanold from RBC.

And Don, congrats as well. Just a question, Ryan. You had made a comment, I guess, in your prepared remarks about taking a look at guidance for the next year and moving forward. Big picture, it sounds like your core tenets of your strategy have not changed from what you discussed over the last several years and most recently, I guess, at the November Analyst Day. But should we think about like Conoco coming up and sort of recasting what we -- some of what we heard in terms of like high-level operations on how you approach your growth strategy over the next several years, considering what has happened over the last several months? And are you guys becoming a little bit more conservative because of what we saw?

Yes, Scott. Yes, I think we'll -- I think once we get through all of the noise associated with curtailments, we'll be talking a little bit differently about guidance as we go forward. We just had a lot of uncertainty as we came into the second quarter. And then as we are working our plans and testing our scenarios against what we see, recovery or what kind of recovery it looks like in terms of timing and quantity, then we'll be -- we'll come to the market. We'll tell you what our plans are as we look forward, both in '21 and points forward and beyond that.

But I think we've got the portfolio. We've got a huge, large resource base of low cost of supply investment opportunities. You should expect us to get back on to that modest growth trajectory similar to what we described back in November. And we've got the assets and we've got the portfolio to go do that. I think the questions in front of us are what kind of recovery are we seeing in the market, if any, maybe some of the other people that think it's going to be flat forever. We don't have that kind of a view. We do see a recovery. We do have a view of midcycle prices with some demand recovery.

And then a lot of questions around what the E&P sector and the industry is going to do. Are they going to follow a rational way to invest or not going forward? And they going to repair balance sheets? Are they going to put a decent return back to the shareholders, which is a value proposition that we believe is the right one for the industry.

So I think there are a lot of moving parts, but we feel pretty confident in our plans and being able to grow the company if that's the right decision from a returns perspective, both to the shareholder returns of capital and returns on our capital.

Okay. I appreciate the color. I look forward to some of that detail.

As a follow-up, and this may be a Don and Matt question, but what we've seen from some of the more pure-play type of companies so far, are operating costs that have dramatically dropped in the second quarter. Obviously, not all that sustainable, but the view is a good portion has. It doesn't seem like 2Q that Conoco saw that same drop. Is there a little bit of a mix shift? Does it have to do with the type of production that Conoco curtailed versus others? If you could give us a little bit of color there. And I'm not sure if you can quantify some of that?

Scott, this is Don. I'll try that. And I think that I caught the question being on the quarter that our unit cost rates didn't fall as much as you might have -- or didn't fall like competitors did.

And I'm just going to speculate on that because I don't know exactly because I haven't looked at the competitors' numbers. But I would surmise that a lot of it has to do with our production plan in the second quarter and our decisions around curtailment. And if you look at the other areas where we did curtail, for example, pretty heavily in the Eagle Ford; our lifting costs in the Eagle Ford is like a couple of dollars a barrel. So if you look at our unconventionals, these are high-cash-flowing, typically very low operating cost per BOE type fields. And so with that production offline, we're not going to see the benefits of that.

I will say beyond the second quarter, looking back in recent history, ConocoPhillips has always benchmarked very competitively on operating efficiency. And as far as this year, we do benchmark against or keep track of, say, the top 20 companies that we compete with. And the range of operating cost reductions, it looks like it's been from a low of 3% from one company up to around 15%, maybe a little bit higher by one company.

We announced very early in the year that we were reducing by 10%. So I think I would expect that we've retained our competitiveness on operating efficiency.

Our next question comes from Jeanine Wai from Barclays.

I'll just follow-up on Neil's earlier question on Alaska and election risk. In Alaska, I believe you mentioned that you already leased up all the acreage that you're interested in. But I'm not sure I caught what you said on the status of the permits. And specifically, do you already have state and federal permits for Willow? And once you receive those federal permits, how insulated do you think the project would be if there was some kind of potential change in the oil and gas regulatory environment on federal land?

Well, I -- so for Willow, specific to your question, we're in the process right now, and we expect to get all the federal permits later this year. So everything is on track, all the comments. We're in the process on the record of decision. So we don't expect -- at these 10 seconds, we don't expect any issues associated with the permitting process for Willow and some of the other things that we're doing on the North Slope.

I'm not sure, Jeanine, I'm not sure I caught your last part. Could you rephrase that for me? You said something about what would the citizens say to different permitting?

No, I think you answered it in terms of how many permits you had and if you think that might be insulated was the second part of the question.

I guess the follow-up would be, if there is some kind of issue that would affect your development plans, either in Alaska, federal for Willow or elsewhere, can you talk about what's the most likely alternatives would be to backfill those growth projects? I know you mentioned the Qatar project you're still very interested in. And maybe if you can just run through a couple more that you think might be high on your list? And whether this potential risk in the U.S. kind of factored into your Kelt acreage acquisition?

Yes, Jeanine, this is Matt. I'll maybe take that. So Willow, in particular, if there was a permitting issue, we don't anticipate one. But if there were one, we'd just delay the project until that was resolved. I mean, we've had to do that in the past in Alaska. We wouldn't necessarily reallocate that capital at the time because we -- if we head back towards the capital pace that we had before the COVID crisis, there's no advantage in accelerating. So we'd probably just wait.

We're still -- as Ryan talked a little bit earlier in the call, we're still interested in the North Field expansion opportunity, but that's a process that will run its course through the rest of this year.

And the -- in terms of federal land in the U.S. other than in Alaska, the -- most of the federal land we have in the U.S. is in New Mexico. The -- but we -- this was a topical question several months ago, and it's becoming topical again. And at the time, I think we've provided an answer that as we looked at our 10-year plan at the time, if we were unable to drill on federal lands completely in New Mexico, we could just substitute that with nonfederal lands for the next 10 years.

So we would just move the drilling to a different location that's not affected by that. So the short version of that is that any constraints on our ability to develop on federal lands in the U.S. will not be a significant issue for the company.

Our next question comes from Paul Cheng from Scotiabank.

Don, let me add my congratulations. Really appreciate the help over the years. We had fun. But I will also say that while I'm happy for you, but don't get too comfortable in the beach or in the Gulf Coast. You're too young for that.

Thanks, Paul.

Anyway, a couple of questions. First, Ryan, can you maybe help me understand a little bit in terms of your thought process in designing for next year's CapEx, do you plan to run the position is going to be free cash flow positive? Or that neutral free cash flow or that you will be willing to have a cash flow deficit that after CapEx and dividend for next year?

And also in addition to the price signal, is that the most important driver in your decision? Or that this is actually a secondary, and more important, you will look at the actual demand-supply balance in the inventory? So we're trying to understand that how you're going through the process?

Well, I think in terms of trying to answer your question, Paul, that's to be determined. I don't think we've -- we want to watch, as I said in my opening comments, not only the direction of the recovery but the magnitude of the recovery as it goes back to what we believe will be midcycle price over the long haul. So we're trying to balance all those things. We're trying to consider what will be our free cash flow, and that's going to be a function of, obviously, the price and the supply-demand fundamentals that drive that, and then what our CapEx program is going to be to get the productive capacity of the company re-ramped up to where we were pre-COVID level.

But we're also considering what the balance sheet needs to look like, what the cash on the balance sheet needs to be and think about potential scenarios around slower recovery and slower kind of price movement and either worse demand fundamentals or excess supply fundamentals, depending which side of the equation that you're on.

So I know it's not a very satisfying answer, but we're putting all that into the pot, mixing it around and trying to understand. And we'll have more to say about that as the year follows through and as we get closer to 2021, but that's what we're trying to -- those are the -- that's why I wanted to establish those kind of questions we're asking ourselves, which I think all of industry is asking itself. But it is rooted in the fundamentals of supply and demand, and understanding what the price trajectory is going to look like as we go into next year and beyond.

Our next question comes from Ryan Todd from Simmons Energy.

And I'll add my congratulations, Don. It's been a pleasure over the years.

Maybe one follow-up on the curtailed Lower 48 volumes. You talked about the restoration into September. Is that -- is the timing of that just based on production nominations? Is it based on the current oil price? Or does it assume some further recovery between now and then in price?

And is there any -- as we think about the timeline of that resumption, is there anything that could cause that to push further to the right?

Yes. I mean, I'm happy to -- Don, do you want to take that? Go ahead.

No, Ryan, I think we got to netback pricing a little while ago to where we were comfortable starting to restore production. Saw that happen in our plans for August and are increasing a little bit more in September as well. We just got to the point where the netback pricing was high enough to where curtailment economics just weren't going to look like it was going to deliver the 20%-plus type of returns that we were expecting. So we decided to come up with a ramp-up plan.

But rather than just go from 20% of capacity in July to 100% in August, we decided to spread that out over a few months and watch the market. And frankly, we were kind of expecting, and we're still expecting that there could be a pullback somewhere along the way. And so if there is, then what we showed you this morning and what's in the materials that we posted is our current plan based on our current outlook. If things change significantly, then we may change as well.

So we will be responsive to the market, and if the market returns back to very poor netbacks like they were in April and May, then we'll adjust our plan accordingly.

All right. And then maybe one follow-up. Ryan, in your prepared remarks at the start, your comments seem to suggest some debate on the proper mechanism of returning cash to shareholders above the current dividend. Has your view on this changed at all in recent months? And what other mechanisms are you looking at beyond share buybacks?

Well, I think we've I think we've had this conversation probably with most people on the phone over the course of the last two or three years as we look at kind of the optimum way to return money back to the shareholders.

So obviously, today, in the current environment that we're dealing in the ordinary dividend that we're providing is well in excess of 30% of our cash flow. So it satisfies some of our -- the markers that we set down with respect to our value proposition.

So as we think about price recovery and incremental cash flows coming, we are thinking about what is the optimum or the best way to return money back to the shareholder? And obviously, share buyback is one of those options that we're looking at as well as some sort of variable dividend type of structure. It's a conversation we've had with, I think, the buy- and the sell-side for a number of years now. We continue to analyze and continue to think about it, trying to figure out the best way. But a large part of that is informed about what the trajectory is, what the recovery looks like, and ultimately what the midcycle price, we think, is going to be in the marketplace.

So a lot of that we have to put together, but are thinking about all those kinds of alternatives.

We have no further questions at this time. I would like to turn the call back over to Ms. Ellen DeSanctis.

Thank you, Zanera. That wraps things up. We're at the top of the hour. I appreciate everybody's time and interest this morning. And by all means, reach out if you have any follow-up questions.

Thank you, everybody, and stay safe.

Thank you. And thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.