Good morning and welcome to the Q2 '20 earnings call. My name is Zanera and I'll be the operator for today's call. 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 plans. 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 mask 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, 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 curtailments decisions was that we could create value by foregoing short-term cash flow 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 cash flows. 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%. Market 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. As Don's already cleared a high-level view of the second quarter production curtailments, as shown in more detail on slide 5, 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 collect downhole pressure measurements and sustained injection in the relevant fields to maximize flush production. It was a massive effort conducted extremely well by our operational 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 COVID mitigation, and that's going to extend the duration of the turnaround. And also some minor non-operating curtailments are 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, we have 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 flowback in February of this year. All 14 of the new wells have now been tied in to the permanent facilities, and production from pad one is ramping up. We used completion designs developed in our Lower 48 Big Three 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 end-of-well results. And we could see from our early proprietary well data that the liquids-rich part of this play holds significant low-cost 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 a 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 than 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 one billion barrels of resource, with 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. Please go ahead. Your line is open.

Yes, hello, and congratulations to Don as well. You will certainly be missed, and I appreciate all the time we worked together. My first question is regarding the commentary you provided on the third quarter. I understand that you're not offering specific guidance, but I wanted to clarify the various factors at play. We have the curtailment impact with a positive 110,000. There is also maintenance that I believe accounts for a 20 KBB headwind, but I am unsure of what the second quarter maintenance was. Is the number you provided an absolute figure, or is it a quarter-over-quarter change? Additionally, are there any other aspects we should consider, such as base decline rates or anything similar? Thank you.

Yes, for the quarter, it is 20,000, which is the absolute number. In the second quarter, it was about 5,000 barrels a day, resulting in a 15,000 difference from the second quarter. In Alaska, it's about 5,000 barrels a day, about 7,000 in Canada, about 7,000 in APME and Malaysia, and there's a little in Norway. In the third quarter of 2019, it was higher at about 30,000 barrels a day, so it's slightly less than the third quarter of 2019. There are no other significant factors aside from the return of curtailed production, which will mostly be completed in the third quarter. Does that answer your question?

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 you suggest oil prices remain in the low 40s 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. Phil, regarding the exit rate, we expect the 2020 production to be roughly similar to 2019 when making direct comparisons. Production in the first and second quarters of this year was slightly higher than the same period last year, so we anticipate it will be somewhat lower in the second half to balance things out. Currently, we predict that the fourth quarter production rates will be approximately 6% to 8% lower in 2020 compared to 2019. This gives a general idea of the expected profile. As for sustaining capital, it remains unchanged at around $3.8 billion annually. The flat production from 2019 to 2020 should not be seen as an indicator of required sustaining capital with our current 2020 capital program, since we are not aiming to sustain production in the current price environment. We have been monitoring activities and reducing production, but if we were to design a capital program aimed at sustaining production, it would still be around $3.8 billion per year.

Thank you. Our next question comes from Neil Mehta from Goldman Sachs. Please go ahead. Your line is open.

Good morning, guys. 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 onetime in nature? Or was there anything in there that you would think of carrying forward?

Well Neil, this is Don. Yes, we hope that this is a one-time issue. Of course, that will depend on future developments. We have seen some improvements as we progressed through the second quarter. April and May were quite challenging, and I believe we mentioned this back in late April. What we observed in the field regarding differentials was significantly different from what was being displayed on the screens. However, that situation improved materially as we entered June and has been stable in July concerning the real differentials in netbacks at the lease. Now that we have completed the trade month of August, it seems to be holding up reasonably well for most of the next quarter, the third quarter. Alaska realizations were rather weak, and everyone is aware of the low refinery utilization rates on the West Coast in pad 5. To give some context, in the first quarter, we captured 97% of the Brent market price, and in the second quarter, that dropped to 86%, reflecting a notable quarter-on-quarter difference. In the third quarter, we are seeing a return to normal levels, which we hope will continue. However, we did experience significantly lower realizations compared to the market in Alaska, as well as in the Lower 48, particularly in the Bakken and the Permian.

Thank you. 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.

Thank you, Neil. Regarding M&A, I think we've previously explained in detail how we view the business, particularly in terms of supply costs and acquisition requirements needed to remain competitive. We have a 15 billion barrel resource base with an average supply cost in the 30s, which must be aligned with our financial goals and beneficial for the business. We are being patient and diligent, monitoring the market closely for both asset and corporate deals. The Chevron Noble acquisition, with the premium paid, is a positive sign because the high premiums seen in recent years aren't sustainable. We're encouraged by these developments as they could prompt necessary changes in the market to reduce G&A costs. We are considering all types of deals as long as they fit our outlined criteria. Regarding federal acreage in Alaska, there's a ballot initiative coming up in November that we are closely focused on. I believe Alaskans understand that increasing taxes on the industry at this time isn't beneficial and will lead to reduced investments and a slowdown in activity across the North Slope. This represents poor policy for the state and problematic legislation through initiatives. The federal acreage we operate on is mainly in NPRA, where our activities include the Alpine and Willow discoveries. Despite political rhetoric, we feel confident about the safety of our operations there. We have already leased the most promising land available. If an explorer transitions to development, the concern will be whether the permitting process will delay progress. However, we have navigated various administrations for 50 years and have successfully managed to complete our projects responsibly and sustainably. A one-year delay is manageable within our global portfolio.

Thank you. Our next question comes from Doug Terreson from Evercore ISI. Please go ahead. Your line is open.

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

Good morning, 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 in second quarter looks like a pretty astute economic decision. And on this point, my question is regarding 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 a 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. Let me start. Matt may want to add a few comments as well. We have discussed this, and I think Matt mentioned in his prepared comments that we do not expect any issues with returning to shut-in production. We have begun that process, curtailing 225,000 barrels in the second quarter. As Matt explained, we are in the process of resuming some of that production in Alaska and in the Lower 48. Production in Alaska has returned, and we are seeing flush production. I don’t think we’ve encountered some of the challenges we might have anticipated regarding bringing that production back online. We are confident not only that we will return, but that we will also see flush production and the favorable economic analysis that Don outlined. Looking at the forward curve, we expect to achieve a return of over 20%, indicating that the decisions made during our curtailment discussions were economically sound. Regarding shale exposure, we believe we are competitively positioned with a lower decline rate. While we are not entirely dependent on shale, the shale sector is likely to see a higher decline rate due to reduced CapEx and some curtailments affecting not just us, but the entire industry. Given our financial flexibility and strength of our balance sheet, we feel we are in a very competitive position and have the financial strength to respond effectively.

Okay. Thanks a lot guys.

Thank you. Our next question comes from Roger Read from Wells Fargo. Please go ahead. Your line is open.

Yes. Thank you. Good morning. 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 or 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 kinds 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 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 2021 and 2022 plans?

Yes, this is Matt. I wouldn't say there's a specific trigger. It was very clear in the discussion about curtailments that the economic criteria indicated that prices in the 30s made more sense, and below that, it made sense to defer production and bring it on later. The same economic calculation applies to adding new production. One reason we've been curtailing production is that we haven't been completing and bringing on any new wells, as that wouldn't make economic sense. The criteria for adding new production depend on the cost to supply being low enough. Our efforts are focused on developing a portfolio with a cost of supply below $40. As long as the cost of supply remains low enough, we would apply similar criteria for new production as we did for curtailments. Looking at the current market strip, it suggests that for our portfolio, it's acceptable to bring on new production if needed.

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.

Thank you. Our next question comes from Doug Leggate from Bank of America. Please go ahead. Your line is open.

Thank you. Good afternoon, everyone, and good morning. 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, Ryan, I would like to start by addressing a potentially controversial point. You have shown some confidence in a recovery in commodities, although I’m not sure if that term is too strong. You mentioned smaller peers like Noble, who appear less confident to the extent of exiting the market at what some might consider a low point. In light of the changes in the M&A landscape and ConocoPhillips' strategic goals, I am curious if you considered Noble's process. If not, could you explain why? Additionally, what kinds of opportunities does ConocoPhillips believe could address any gaps in your portfolio?

We did consider it, Doug, and it's a valid question. When we evaluate it, we think about how it matches our portfolio. We have some concerns, particularly regarding the Middle Eastern gas position, which does present some political complications for us due to other activities in the region. The second significant aspect of the Noble portfolio is based in Colorado, and we have just gone through a difficult exit from that state, so we prefer not to return. Furthermore, their position in Weld County might offer a different viewpoint on Colorado. However, we believe they are reasonably valued even with a potential recovery in commodity prices, but they do not fit well in our portfolio.

I appreciate the answer. However, I would like to ask a follow-up question. Considering that long-life, low-decline growth potential assets appear to align well with Conoco, are you focusing on that in your M&A considerations? Specifically, are you more concerned about inventory depth in your unconventional portfolio? What strategic gaps do you perceive?

I’m not too concerned about the inventory gap in our unconventional portfolio. The recent Kelt acquisition enhances our long-term position in that area. It’s about quality over quantity, and we are focused on the cost of supply in the unconventional space, just as we are in other areas. Low-cost, low-decline long-life assets would indeed align with another growth opportunity for us.

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 non-cash moving parts? I'm thinking specifically about how you manage DD&A rates and some of the other maybe corporate 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.

Thank you, Doug. There was a significant variation in earnings estimates, as anticipated, due to the volatile quarter. Additionally, we did not provide any guidance, so we weren't entirely surprised by this. I can highlight a few factors that would likely be challenging for others outside the company to assess. One key factor was the lower realizations I mentioned earlier, which had a cash impact, not just a non-cash one. I noted our market capture percentages compared to past quarters, estimating around a 15% per share impact, which we hope is temporary. Another unexpected factor was DD&A. Our DD&A fill significantly decreased this quarter due to lower production, but our DD&A rate rose a couple of dollars per BOE because of an adjustment we made anticipating declining reserves from lower prices. Some companies choose to revise their DD&A rates and reserves at year-end, but we assess them periodically throughout the year and make interim updates, as we did in 2016 when reserves decreased. In the second quarter, we made an interim adjustment that increased the DD&A rate. This wasn't the only reason for the increase; we also faced impacts from our curtailment decisions and an unusual product mix during the quarter with low volumes in the Lower 48 and Alaska, which also affected the rate. A third important element that might not have been expected was the mark-to-market movements. The stock market rebounded significantly from the end of the first quarter to the end of the second quarter, impacting ConocoPhillips stock as well. We experienced a pre-tax adverse cost impact of around $50 million due to mark-to-market compensation and benefits issues. In contrast, from the end of the fourth quarter to the end of the first quarter, we saw a positive impact as SG&A went negative, resulting in about a $90 million pre-tax mark-to-market benefit when the stock market and ConocoPhillips stock declined. These are the three main items I believe would be difficult to estimate from outside the company.

Thank you. Our next question comes from Scott Hanold from RBC. Please go ahead. Your line is open.

Thanks, and congratulations to Don as well. Ryan, you mentioned in your prepared remarks about reviewing guidance for the upcoming year and beyond. Overall, it seems that your core strategic principles remain consistent with what you've communicated over the past several years, including during the recent November Analyst Day. Should we expect Conoco to revise or clarify some of what we heard regarding your high-level operations and growth strategy in light of recent developments? Additionally, are you becoming a bit more cautious due to the circumstances we've seen recently?

Yes, Scott. I believe that once we move past the current disruptions related to curtailments, our guidance will be communicated more clearly as we look ahead. There has been considerable uncertainty as we entered the second quarter. As we develop our plans and assess our scenarios regarding the timing and extent of the recovery, we will update the market on our strategies for 2021 and beyond. We have a strong portfolio and a substantial resource base that allows for low-cost supply and investment opportunities. You can expect us to return to a modest growth path, similar to what we outlined in November. We possess the necessary assets and portfolio to make this happen. The key questions now revolve around the market's recovery, with some analysts predicting a flat situation indefinitely, which we do not share. We anticipate a recovery and expect mid-cycle prices driven by demand recovery. Additionally, we are considering how the exploration and production sector will behave going forward—whether companies will invest rationally, repair their balance sheets, and provide substantial returns to shareholders, which we believe is essential for the industry's value proposition. While there are many factors at play, we remain confident in our plans and in our capability to grow the company if it aligns with our objectives for both shareholder and capital returns.

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 take that question. I believe you're referring to the fact that our unit cost rates didn't decrease as much as you might have expected or didn't fall like our competitors. I can only speculate on this since I haven't analyzed the competitors' numbers in detail. However, I think much of it relates to our production strategy in the second quarter and our decisions regarding curtailment. For instance, we made significant cuts in the Eagle Ford, where our lifting costs are only a couple of dollars a barrel. Our unconventionals typically generate high cash flow and have very low operating costs per barrel of oil equivalent. So with that production offline, we haven't been able to realize those cost benefits. Looking back beyond the second quarter, ConocoPhillips has consistently maintained competitive operational efficiency. This year, we benchmark ourselves against the top 20 competitors and have observed a range of operating cost reductions from one company with as little as 3% to another exceeding 15%. Earlier this year, we announced a planned reduction of 10%. Therefore, I believe we have maintained our competitiveness in operating efficiency.

Thank you. Our next question comes from Jeanine Wai from Barclays. Please go ahead. Your line is open.

Hi, good afternoon, everyone.

Good afternoon, Jeanine.

Hi, good afternoon. Thanks for having me on. 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?

For Willow, in response to your question, we are currently in the process of obtaining all the federal permits, which we expect to receive later this year. Everything is progressing as planned, including the record of decision. At this point, we do not anticipate any issues with the permitting process for Willow or our other projects on the North Slope. I'm not sure I caught the last part of your question. Could you please rephrase it? You mentioned something about what citizens might say regarding 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.

Yes, Jeanine, this is Matt. I can address that. Regarding Willow, we do not anticipate any permitting issues, but if one were to arise, we would delay the project until it was resolved. We have had similar situations in Alaska before. At that point, we wouldn't necessarily reallocate capital because if we return to our pre-COVID capital pace, there’s no benefit in accelerating. So, we would likely just wait. As Ryan mentioned earlier in the call, we are still interested in the North Slope expansion opportunity, which will take time to develop over the course of this year. As for federal land in the U.S., excluding Alaska, most of it is located in New Mexico. This has become a relevant topic again after we discussed it a few months ago. At that time, we indicated that if we were unable to drill on federal lands in New Mexico, we could shift our drilling to non-federal lands over the next ten years. In summary, any limitations on our ability to develop federal lands in the U.S. will not pose a major issue for the company.

Thank you. Our next question comes from Paul Cheng from Scotiabank.

Thank you. Good morning. 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, don't get too comfortable on 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 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?

In response to your question, Paul, the situation is still uncertain. As I mentioned earlier, we need to observe both the recovery's direction and magnitude, as we aim for mid-cycle pricing over the long term. We're balancing many factors, including our expected free cash flow, which will depend on price and the supply-demand dynamics. Additionally, we'll consider our capital expenditure program to restore the company's productive capacity to pre-COVID levels. We're also evaluating our balance sheet needs and the necessary cash reserves, while contemplating various scenarios such as a slower recovery, price fluctuations, or changes in demand and supply fundamentals. I understand this may not be the most satisfying answer, but we're incorporating all these factors into our analysis, and we'll provide more clarity as the year progresses and as we approach 2021. We're asking ourselves these critical questions, which reflect what the entire industry is considering. Ultimately, our focus is on the fundamentals of supply and demand and predicting the pricing trend for the upcoming year and beyond.

Thank you. Our next question comes from Ryan Todd from Simmons Energy. Please go ahead. Your line is open.

Thanks, and congratulations, Don. It's been a pleasure over the years. I have a follow-up regarding the reduced Lower 48 volumes you mentioned, particularly about the restoration expected in September. Is the timing of that determined by production nominations, the current oil price, or does it anticipate some further recovery in price by then? Additionally, as we consider the timeline for that resumption, is there anything that might delay it further?

Yes. I'm happy to let Don answer 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.

Thanks. 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 buyback?

We have discussed with many people over the past couple of years the best way to return money to shareholders. Currently, the ordinary dividend we are providing exceeds 30% of our cash flow, which aligns with the goals we've set regarding our value proposition. As we consider price recovery and additional cash flows, we're evaluating the most effective methods for returning money to shareholders. Share buybacks are being considered, along with a potential variable dividend structure. This is a topic we’ve engaged in with both buy-side and sell-side analysts for several years. We are continually analyzing and seeking the best approach, factoring in the market trajectory, recovery potential, and our expectations for mid-cycle prices. All of these considerations will guide our decisions as we explore various alternatives.

Thank you. 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.