Conoco Phillips (COP) — Q1 2022 Earnings Call Transcript

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

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

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

Yes. Thanks, Jeanine. We look at this quarterly review with the Board quarterly. We take an informed view of what we think the macro and the outlook for commodity prices is going to be for the rest of the year. I'd say we moved to $10 billion because we certainly felt like the commodity price outlook is going to be probably above $90 a barrel depending on where things end for the year, and that supported going from $8 billion to $10 billion. Again, that's anchored in our commitment to return at least 30% of our cash flow back to our shareholders. As you noted correctly, over the last 4 to 5 years, we've delivered even more of that and prepared to do that, should the market support that as we go forward. The other thing I can say is you can see that cash is rebuilding on the balance sheet a little bit as a result of the check we wrote at the end of the year. We have a desire, we want to put some more cash on the balance sheet to do that. At the same time, we want to keep funding our stable capital program. As we looked at it, we certainly thought we could afford moving to $10 billion. That's supported by even if prices were to fall below $90 for whatever reason or if they continue to stay strong, investors should expect, calculate our cash flow, and expect to receive a minimum of 30% of that back as we go through the year. That's been our commitment for many, many years now, and we're just living up to that commitment via these strong prices we see in the market.

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

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

The first question is around the capital guidance moving from $7.2 billion to $7.8 billion. I think this was well telegraphed, and certainly, we're in an inflationary environment. But would love your perspective on the components of some of those moving pieces. As we get an early thought into 2023 and normalized spending levels, how much of this does carry forward?

Yes, Neil, I believe what Bill was trying to explain is that we've increased our capital from $7.2 billion to $7.8 billion. About half of that reflects additional activity in our Lower 48 operations by other companies. These represent valuable opportunities that are low-cost and highly competitive in our portfolio, and we want to ensure we don't miss out on them. Therefore, we are actively investing in these opportunities as they arise. The other half of the increase is due to inflation. To provide context, we set our budget last December and shared our outlook during our fourth-quarter call. At that time, we expected some elevated inflation rates, particularly in the Permian region. In other areas of our portfolio, we didn't foresee significant impact. We expected mid-single-digit inflation across our global portfolio. However, following the Ukrainian invasion, we’ve noticed inflationary pressures affecting the entire global portfolio, with persistent issues in the Permian related to spending on labor, rigs, steel, pipes, chemicals, and other critical categories for our industry. Whether this situation will ease as we move into 2023 depends on when global turmoil begins to stabilize. At this moment, it's difficult to predict that normalization will happen soon. I don’t anticipate this will be a temporary situation, and we will have to manage it moving forward. Lastly, we considered the option of reducing scope to stay on budget. Given the current macroeconomic conditions, we decided against that approach, which is why we've raised our capital guidance for the year to $7.8 billion.

Makes a lot of sense, Ryan. And that's the follow-up; it's on Russia and the Ukraine war. How does this structurally change how you think about the company and the oil and gas industry? There are a couple of components to that question. Does it make it more likely that the market will be more accepting of sanctioning long lead time projects, whether in Alaska or elsewhere? Does this change where you ultimately want to invest? Can you also talk about what you're observing in regard to Russia volumes as you closely monitor the oil macro? How do you see that developing in the latter half of the year, understanding that you don't have frontline operations, but you are keeping a close watch on the situation?

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

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

Yes, Phil, this is Tim. I'll take that one. We've been really pleased with how the team has integrated the Shell assets into our overall company and operations. They've done an excellent job, and it has been a safe combination. We have just started bringing wells online with our vendors and completing wells. In terms of activity in the Lower 48, we planned to complete 500 wells throughout the year, and we brought on 90 in the first quarter, so it has always been back-end loaded. We finished the quarter with 22 drilling rigs in the Lower 48 and 8 frac spreads. We have a ten-year plan, and we're still on track to deliver all that activity. As Ryan mentioned, we are not cutting our capital back but instead are trying to maintain steady operations and maximize efficiency. The increase in activity throughout the year applies to our entire asset base, especially in the Permian; we plan to complete 500 wells for the year but only completed 90 in the first quarter. So, it is expected to build up and be back-end loaded.

Okay, that's helpful. My second question is for Bill. There have been significant reductions in net debt in the first quarter. You mentioned the pay down of gross debt and your targets in that area. I'm interested in your thoughts on the appropriate levels of net debt or cash you're maintaining, especially with $2 billion to $3 billion of asset sales still anticipated. It seems that even with the $10 billion return of capital, there is a considerable amount of cash accumulating. Any further insights on this?

Yes. Sure, Phil. So I think that you can see it manifesting itself in the rebuild of our balance sheet with our cash growing to $7.5 billion. I think we're pretty happy right now with our pace in terms of debt reduction and how the program is set up. We've got our glide path established for the next 5 years. You can consider the natural maturities as we move forward. I think we've been fairly opportunistic in the market to set that up and are quite satisfied with where that stands. As you rightly noted, we will continue to build up cash on the balance sheet. We’re looking forward to some asset dispositions later this year, and that’s going to generate cash.

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

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

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

With respect to your last point, Doug, certainly, we're all kind of reviewing in quite a bit of detail the current climate suggestions out of the SEC in the rule-making process. We'll be commenting on that as part of the industry as well. They're a bit problematic. We have always maintained our support for doing everything a company can do about Scope 1 and Scope 2 reductions. We have stated our ambition to be Paris-aligned and net-zero by 2050 with respect to the emissions we generate. All companies ought to have a Paris-aligned climate risk strategy to address and manage the emissions they produce. The problematic piece has always been Scope 3 due to double counting, accountability, and whether it’s reasonable to hold a company like ConocoPhillips responsible for a consumer's decision to buy a pickup truck versus a Toyota Prius. We see those Scope 3 challenges that we think are problematic. Reporting them is complicated, they change, and they can lead to double counting, creating significant difficulties in communicating those in an SEC sort of document that has to be included in your Qs or your Ks. We believe the best approach to impacting the demand side of the equation is a heavy carbon tax. We've been a part of API's decision-making process within our industry association to say this is probably a better way to handle the challenges associated with energy transition.

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

Two questions. I think it's actually really short. First one, I want to go back to the cash tax. Bill, from an accounting standpoint, do you estimate the full-year cash tax rate and then apply that rate throughout the year in each quarter until the full-year estimate has changed over each quarter?

Yes, sure, Paul. We estimate our annual taxes on a yearly basis and then pay quarterly on estimated taxes. As I indicated, we expect to start making those quarterly payments in the second quarter of this year.

Yes, Paul, on the weather question, we had weather impacts in all our major basins in the first quarter. I'm really proud of how the team responded to that; we got everything back online fairly quickly. I would say the weather impact, while it affected almost all of our production, was rather nominal, and we were able to overcome it. As to the second part of your question regarding the Bakken, I think everybody is aware that this was probably the most severe winter in recorded history in North Dakota, and we're still assessing the amount of time it will take to restore full production. I think the assessment is still ongoing.

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

First question, Ryan, when you were talking about everything that's happened in the market, you have to constantly evaluate the sort of 10-year macro and energy transition, demand impact, and your view of mid-cycle pricing. One of the things you mentioned that I would appreciate some expansion on, is that it may change how you think about short cycle versus long cycle production?

Yes, John, I want to emphasize that I believe the transition will not happen abruptly. It will be gradual, and the rate of change is quite uncertain. Our response must focus on ensuring we have the lowest cost barrels available to meet the demand during this transition, while also ensuring we achieve a competitive return. I believe we are in a solid position to accomplish this. In all scenarios, including those monitored by the IEA, which observe several strategies internally, there will be a continued demand for oil and gas well into 2050. Therefore, we need to supply it sustainably, with low greenhouse gas emissions, aiming for net zero by 2050 as well. It's crucial that we provide low-cost barrels, as they will be necessary for an extended period. The industry will require medium- and longer-cycle projects. We simply need to ensure these projects are cost-competitive and environmentally friendly. Projects like Willow and those in Alaska align with this approach. They have production costs well below $40 and emit less than $10 of CO2 per kilogram per barrel. Thus, they fit well within the necessary framework for reliably supplying energy to a world with growing energy needs.

I know on the Shell assets, you all stated in the past that the biggest opportunity there is transitioning from one-mile laterals to two-mile laterals, and to accomplish that, that will require coring up a lot of that acreage with some of the partners. I wanted an update on how that's progressing. If everything goes according to plan, what would be a reasonable amount of that acreage to be converted to two-mile-plus laterals?

Yes, thank you, John. These trades and swaps are a core competency of the team. We're continuing that, and we've seen good opportunities there. It's beginning to manifest itself in some longer laterals, both on the operated and non-operated side regarding the Shell assets, and I expect that to continue.

Just wanted to follow up a little bit on some of your comments regarding LNG here. What I'm trying to understand is, does Conoco believe that the U.S. can really add any incremental LNG export capacity in the next couple of years, say, '23 and '24? Or are those adds more mid-decade and beyond? I want to gauge whether there's going to be more material connectivity between Europe, Asia, and the U.S. in the next few years.

Yes. Sure, Leo, this is Bill. I think that if you look at LNG export capacity today, it's running a little over 12 Bcf a day. The U.S. export terminals are running effectively at capacity or slightly above nameplate. Several operators are evaluating taking FID, but there's a practical reality that once you take FID, it takes several years to build these terminals. If you're looking for impact in the immediate term or mid-decade, I'd say it's closer toward mid-decade before you start seeing new export facilities come online.

Okay. That's helpful for sure. I just wanted to ask a brief question about your Canadian production, specifically in the Montney. As I look at your conventional non-oil sands volumes, it appears they have been declining for the last four quarters based on your data. Do you expect those volumes to start growing at some point, maybe in the back half of the year or in '23? What can you share about the trajectory of the Montney?

Yes, Leo, this is Nick. One of the factors that we have to consider is we took a fairly large capital cost in 2020, and then we were in maintenance mode in 2021. We didn't have any rigs or frac crews. We've restarted that program earlier this year; we started fracking the wells on Pad 4, and we’re also drilling Pad 5 and Pad 6. The drop you’re seeing over the last four quarters was really just due to a lack of activity in Montney. We've resumed drilling on both pads, and we expect to see some of that production come online in Q3 and Q4. Additionally, we are working on our CPF2 facility expansion, which involves enhancing gas handling, condensate recovery, and water handling. We’re about 30% complete on that project, which is on schedule and expected to come online in 2023. The condensate recovery unit will allow us to monetize the Kelt acreage more effectively that we picked up a few years ago.