Conoco Phillips (COP) — Q4 2021 Earnings Call Transcript

Thank you, Zanera. Welcome to all of our listeners today. First, let me introduce the members of our team who are on today's call. We have Ryan Lance, our Chairman and CEO; and Bill Bullock, Executive Vice President and Chief Financial Officer; Dominic Macklon, Executive Vice President of Strategy, Sustainability, and Technology; Tim Leach, Executive Vice President of Lower 48; and Nick Olds, Executive Vice President for Global Operations. Ryan and Bill will lead off today's call with some prepared comments, after which the team will be available to take your questions. Before I turn the call over to Ryan, a few quick reminders. In conjunction with this morning's release, we posted supplemental materials that include fourth quarter and full year 2021 highlights, earnings and cash flow summaries, preliminary reserve replacement information, price realization analysis, and updated 2022 guidance and sensitivities. During our call, we may make forward-looking statements based on current expectations. Actual results could differ due to the factors described in today's press release and in our periodic filings with the SEC. Finally, we will also make reference to some non-GAAP financial measures today. Reconciliations to the nearest corresponding GAAP measure can be found in this morning's release and on our website. With that, I'll turn the call over to Ryan.

Thank you, Mark. So 2021 was a truly remarkable year for ConocoPhillips. Our operating performance around the globe was outstanding. We generated strong returns on capital for our shareholders and closed on two significant, highly accretive acquisitions in the heart of the Permian Basin. Our exceptional results last year are directly attributable to the talent and dedication of our global workforce. We produced 1.6 million barrels per day and brought first production online at GMT2 in Alaska, the third Montney well pad, and the Malikai Phase 2 and SNP Phase 2 projects in Malaysia. We also completed the Tor II project in Norway and achieved all of this with excellent cost, schedule, safety, and environmental performance. Financially, we achieved a 14% full year return on capital employed, or 16% on a cash adjusted basis, and generated $15.7 billion in cash from operations, with over $10 billion in free cash flow. We returned $6 billion to our shareholders, representing 38% of our cash from operations. Additionally, we continued our rigorous portfolio optimization work, completing the truly transformative Concho and Shell Permian acquisitions and further high-grading our asset base around the world. In the Asia Pacific region, we exercised our preemption right to acquire an additional 10% in APLNG and announced the sale of assets in Indonesia for $1.4 billion. In the Lower 48, we generated $0.3 billion in proceeds from the sale of non-core assets last year. Last week, we signed an agreement to sell an additional property set outside of our core areas for an additional $440 million. Collectively, these transactions reduced both the average cost of supply and the GHG intensity of our resource base, and we're well down the road towards achieving our $4 billion to $5 billion in dispositions by 2023. In early December, consistent with our 10-year plan and capital allocation priorities, we announced a returns-driven capital budget for 2022 that is expected to deliver modest growth this year. We also introduced a new variable return of cash or VROC, tiered to our distribution framework, and provided a full year target of $7 billion in total returns of capital to our shareholders. Based on current prices on the forward curve, we've increased the target to $8 billion, with the incremental $1 billion coming in the form of increased share repurchases and a higher variable return of cash. The $0.30-per-share VROC announced for the second quarter represents a 50% increase over our inaugural variable return paid to shareholders that we paid this quarter. Now to put the $8 billion in perspective, it equates to an increase of more than 30% from the $6 billion returned last year and a greater than 50% increase in projected cash return to shareholders. Our three-tier distribution framework provides a flexible and durable means to meet our returns commitment through the price cycle and truly is differential to others in this sector, as our returns commitment is based on a percentage of cash from operations and not free cash flow. We are guided in everything we do by our triple mandate: we must reliably and responsibly deliver oil and gas production to meet energy transition pathway demand; we need to generate competitive returns on capital for our shareholders; and we aim to achieve our Paris-aligned net zero ambition by 2050. I am very proud of the excellent operational and returns-focused performance we delivered in 2021, and I am equally pleased about the progress we have made in support of the third pillar of our mandate. We increased our medium-term emissions intensity reduction target to 40% to 50% by 2030 and expanded it to include both gross operated and net equity production. As a reminder, we're also committed to further reducing our methane emissions and achieving our zero-routine flaring ambition by 2025. As highlighted in our December release, we've allocated $0.2 billion of this year's capital program for projects to reduce the company's Scope 1 and 2 emissions intensity and investments in several early-stage low-carbon opportunities that address end-use emissions. We strongly believe that this level of focus on and performance toward fully realizing our triple mandate has ConocoPhillips very well positioned to thrive through the energy transition. While we're on the topic of energy transition, I'd like to touch on the macroenvironment. Commodity prices today reflect global energy demand returning to pre-pandemic levels, along with supply being impacted by decreased investment in oil and gas over the past couple of years, concerns about inventory levels, and the amount of available spare production capacity in the system. All these factors demonstrate the ongoing importance of our sector to the global economy and the importance of a managed and orderly transition. However, supply and demand balances are fragile at the moment, which may drive continued volatility. The simple reality is that most alternative energy sources still have a long way to go towards becoming as scalable, reliable, affordable, and accessible as the world needs them to be. This returns me to our triple mandate and the importance of performing well across all three pillars for our shareholders and for the people relying on our products. Now with that, let me turn the call over to Bill, and he will cover the fourth quarter and our 2022 outlook.

Thanks, Ryan. Looking at fourth quarter earnings, we generated $2.27 per share in adjusted earnings. This performance reflects production above the midpoint of guidance and strong price realizations, as well as some commercial and inventory timing benefits, partially offset by slightly higher costs in depreciation, depletion, and amortization. Lower 48 production averaged 818,000 barrels of oil equivalent per day for the quarter, including 483,000 from the Permian, 213,000 from the Eagle Ford, and 100,000 from the Bakken. As previously communicated, our Permian and overall Lower 48 production were both increased roughly 40,000 barrels of oil equivalent per day in the quarter due to the conversion from two to three stream accounting for the acquired Concho assets. At the end of the year, we had 20 operated drilling rigs and 9 frac crews working in the Lower 48, including those developing the acreage we recently acquired from Shell. As Ryan touched on earlier, operations across the rest of the portfolio also ran extremely well last year, with our GMT2 project in Alaska producing first oil in the fourth quarter as planned. Turning to cash from operations, we generated $5.5 billion in cash from operations, excluding working capital, resulting in free cash flow of $3.9 billion in the quarter. For the full year 2021, we generated $15.7 billion in cash from operations, $10.4 billion of free cash flow and returned $6 billion to shareholders. In addition to the asset dispositions Ryan covered, we also sold 117 million shares we held in Cenovus in the year, generating $1.1 billion in proceeds that we used to fund the repurchase of our own shares. This left us with a little over 90 million Cenovus shares at the end of the year, which we intend to fully monetize by the end of this quarter. We ended the year with over $5 billion in cash, maintaining our exemplary balance sheet strength even after completing the all-cash acquisition of Shell's Delaware Basin assets. To recap, it was not only a strong quarter, but one that also bodes very well for 2022 and future years. We continue to optimize the portfolio; our businesses are running well across the globe, and we have had an overall reserve replacement ratio of nearly 380%, establishing an incredibly powerful platform for the company as we head into this year and beyond. Our cash flow performance and leverage to prices have substantially improved over the past couple of years, as demonstrated by our fourth-quarter results, and we expect it will continue to improve as we begin including the newly-acquired Delaware assets in our consolidated results this quarter. To illustrate this point, at a WTI price of $75 a barrel, with a $3 differential to Brent and a Henry Hub price of $3.75, we estimate our 2022 full-year cash from operations would be approximately $21 billion, reflecting our reentry into a tax-paying position in the U.S. at those price levels. Our free cash flow for the year would be roughly $14 billion. We are currently unhedged across our globally diverse production base, so we expect to fully capture the upside of the current price environment. We provided updated sensitivities in today's supplemental materials to help estimate how much earnings and cash from operations are projected to change this year with market price movements. In summary, all that we've shared today underscores our readiness to reliably generate very competitive returns for our shareholders as we strategically move forward as a responsible, valuable exploration and production player in the energy transition.

Our first question, maybe for you, Ryan. It's still pretty early in the year, but you have the confidence to increase the expected cash return by $1 billion through the $8 billion. You provided an update on your macro view earlier in the call. Is this really the primary driver for increasing the cash return level? And can you provide an update on how inflation is trending for Conoco, given continued strong oil prices as well as recent general industry commentary from service companies?

Yes, thanks, Jeanine. It is the primary reason we're increasing our returns of capital to our shareholders from the $7 billion that we announced just a few weeks ago to $8 billion now. It represents a significant increase year-on-year, reflecting our view as we consistently evaluate the forward curve, the market conditions, our capital position, and our balance sheet. Overall, we see a strengthening commodity market, which is a reflection of the strengthening since we announced our capital budget for the year in December. Additionally, we are experiencing some inflationary pressures as a result of stronger commodity prices, particularly in the Permian Basin, but also spreading a bit to the Lower 48. Previously, we were expecting mid-single-digit type of inflation across the entire company, which has now shifted to mid-level single-digit inflation rates. We're observing the impact broadly across commodities we spend on, like tubulars, trucking, labor, chemicals, and other categories, primarily in the more active parts of the Lower 48 like the Permian. However, overall, we see much lower inflation globally, and this diversification in our portfolio offsets some of those pressures. We are mindful and responsive to these trends.

Okay, great. Our second question is about the Shell acquisition. We know it hasn't been long since it closed, but can you provide any updates on integration opportunities or any efficiency gains? For example, Concho was very successful in capturing lower-hanging cost savings related to supply chain and marketing optimizations; however, given the higher percentage of non-operator interest in the Shell deal, that could dampen the impact of similar optimizations. Are there unique opportunities with the Shell assets?

Jeanine, this is Tim. Yes, let me address those questions. As a reminder, we closed the Shell acquisition on December 1, just 70 days after we announced the transaction. We've had a smooth transition of operatorship and personnel over this time, which has been a major success. We plan to maintain the four rigs on that property at the same activity rate that Shell was running throughout the remainder of this year while integrating our personnel and rigs into the operations. Since assuming operatorship, we've quickly transitioned to our methods of well drilling design and casing design, which have yielded lower costs. We've also switched to our fracking design, enhancing economics by utilizing our proppant specifications and cluster spacing. All of these factors contribute to improved efficiency. The largest near-term opportunity involves increasing the well lateral lengths from one mile to two miles. We've engaged with our field partners who we have established relationships with in the past to drill longer laterals. This low-hanging fruit enhances return rates on well economics significantly. We are also actively managing the integration of assets, as we've exemplified by the recent sale of non-core assets, allowing us valuable efficiency within the broader organization.

Ryan, you were quoted recently discussing the U.S. production profile, suggesting an entry-to-exit growth rate of around 800,000 barrels a day. I would love your perspective on how you're seeing the production profile for the U.S. and how that contrasts with peers. It's challenging for us to derive a same-store sales growth rate for Conoco in the Permian, given your recent acquisitions. As you think about growth rates in '22 versus '21 for your asset base, how are you evaluating that in the Permian?

Yes, I can let Tim talk about the specifics regarding the Lower 48 and our assets. However, at a macro level, I was quoted that we project an entry-to-exit growth of about 800,000 barrels a day this year. Given the strength of recent data, I would actually increase that estimate. Importantly, this figure only reflects crude and condensate production and excludes NGLs. This would likely shift to 800,000 to 900,000 barrels a day growth in the U.S. for this year with a similar pattern for the following year. Growth this year is primarily driven by private players, with some influence from public players. In the following year, we expect public companies to contribute significantly as they exit maintenance capital modes and add activity back into their operations, including Basins such as the Bakken, Eagle Ford, and Permian.

Yes, my perspective aligns with Ryan’s, though I would emphasize that the Permian's underlying decline rate is substantial. Increased activity from the privates will lead to higher production. Larger companies such as ourselves tend to emphasize sustainable growth rates that optimize efficiency and lower costs, rather than maximizing production in a less disciplined manner. We've articulated a high single-digit growth rate for our Permian region per our 10-year plan. Moreover, substantial consolidation likely lies ahead, meaning our operated production increased over 35% in the Permian since the Shell deal.

As a follow up, you have developed a core competence around M&A, with the Foster Creek transaction, Concho, and the Shell assets. How do you view ConocoPhillips' potential role in further consolidation, particularly in the Lower 48?

I believe there's a strong rationale for further industry consolidation, especially for responsible handling of assets, which aligns with our strategic goals. We emphasize our triple mandate, focusing on taking responsible assets into the stewardship of ConocoPhillips. With the acquisitions of Concho and Shell, we have significant responsibilities on our plate. We actively monitor the market and ensure any potential new assets align with our value proposition and strategic goals. Our ongoing assessment includes rigorous evaluations of how additional acquisitions could contribute to our 10-year plan and reduce costs. We continuously seek opportunities to enhance our portfolio, including identifying non-core assets that may be divested for better positioning.

I want to revisit your comments about the switch from one-mile to two-mile laterals. Have you explored three-mile laterals yet? If so, what were the results, and are there reductions in cost of supply with these deeper laterals?

Yes, Roger. We recently completed a drilling project in the Southern Midland Basin that included several three-mile laterals, including one at 3.5 miles, drilled in record time. We are pleased with the results and production. This clearly represents a substantial opportunity for the future, but we also need to account for constraints on lease configurations, which favor having larger acreage blocks.

Ryan, I want to revisit your comments about the Permian. Are you concerned about U.S. growth returning to historical levels? Given the recent growth trends and their implications on global markets, how does this impact your strategy?

Yes, Doug, I am concerned, and this consideration is top of mind. The significant factor differs from late 2014 and 2015 when we experienced similar growth levels is how spare capacity is currently allocated in the OPEC+ group. The previous spare capacity figures differ substantially from today’s landscape. Yet, global inventories are significantly lower, particularly within the U.S. While I believe we have some time, higher growth levels invoke concerns that warrant careful monitoring.

My follow-up question, although you may not be able to respond formally, relates to breakeven analysis and sustaining capital. Given the evolving portfolio, can you provide an update in a post-tax context, especially considering your return to paying full cash taxes?

Yes, Doug, it's Dominic here. Looking back at our 10-year plan, it includes tax modeling based on mid-cycle pricing, which indicated a $30 WTI breakeven. Higher prices mean we would incur higher tax liabilities. However, this reflects the competitive edge of our portfolio.

That’s well articulated, Dominic.

With proxy season approaching, could you discuss the shareholder proposition concerning your Scope 3 emissions? Where do you currently stand on that?

Yes. Thanks, Scott. We have engaged extensively with our shareholders on this resolution. We've met with approximately half of our stockholder base, representing around 80% of our institutional investors. A summary of this dialogue will be detailed in our proxy statement. In summary, we received strong support for being the first U.S.-based oil and gas company to set a Paris-aligned net zero ambition regarding our Scope 1 and 2 emissions, and for our progress in this area, including the $200 million capital allocation for this year focused on Scope 1 and 2 emission reductions and supporting low carbon business opportunities. Our shareholders, with very few exceptions, did not express an expectation for ConocoPhillips as an upstream E&P company to set a Scope 3 target. This stems from a general acknowledgment that this would likely shift responsible Paris-aligned production to less accountable sources. Effective reduction of end-use emissions requires comprehensive advocacy from all industrial, commercial, and retail consumers. However, we are not ignoring Scope 3. We actively advocate for an economy-wide carbon price which is essential for addressing both supply and demand aspects. We are also collaborating with our supply chain on their reductions plans and making investments in low carbon opportunities such as carbon capture storage and hydrogen. We firmly believe that a Paris-aligned E&P company, focusing on reliable, low GHG intensity production and low cost supply has a pivotal role in the energy transition.

Thank you for that comprehensive update. As a follow-up, can you share insights on your operations in Norway? That is, regarding the Tor project, we saw robust gas volumes this quarter; is this reflective of ramping to full capacity, or are there other operational strategies in play?

Yes, Scott, this is Nick. We brought all the wells at Tor II online in May of last year as planned. This asset is producing as anticipated, and we've actively worked with our non-operated partners to maximize gas production through the end of 2021. What we're seeing now is a culmination of those efforts, so yes, our assets are performing well, with Tor II operating as expected and additional gas production contributing positively in 2021.

Could you elaborate on the planned 2022 activity levels? Specifically, what cadence do you envision for the upcoming year, including insights on rig count and frac crews per basin?

Phil, this is Tim again. The cadence of activity is expected to be back-end weighted for the year to optimize efficiency. Currently, we have 20 drilling rigs operating and nine frac spreads, with plans to add approximately four more drilling rigs throughout the year. One will be deployed to the Bakken, while the remainder will be split between the Eagle Ford and the Permian. This strategy emphasizes a disciplined approach toward growth and our commitment to efficiency in operations. As stated in previous quarters, our operations in the Permian will maintain a constrained growth pace with significant flexibility.

What we strive to accomplish is setting clear expectations at the start of the year for our teams and providing them a framework to efficiently execute our plans.

Thanks for that clarity. As a follow-up for Bill, I appreciate the updates on cash flow for 2022. Can you confirm if there are any first-quarter tax or royalty payments pending for Libya? Another peer operating there mentioned related comments on their earnings call. And I assume your guidance excludes any working capital adjustments?

Certainly, Phil. Regarding Libya, we are now current with our income tax obligations through the end of January. We expect this to maintain and continue throughout the year. In January, we made a substantial payment of about $900 million, catching up on taxes owed from last year, which is reflected in our financials under working capital. Therefore, I confirm our guidance of $21 billion in cash from operations is excluding this amount.

I have a couple of follow-up questions on your operating expense guidance of $7.3 billion for 2022. Could you provide a breakdown of how much of that increase stems from portfolio changes, the switch from two to three streams, and how much is attributable to inflation?

Ryan, thanks for that question. Just to provide context, in Q3 of last year, we achieved a $6 billion run-rate target following the acquisition of Concho; this was a $1 billion improvement compared to the 2019 pro forma adjusted operating costs. As we move to this year and see the increased guidance of $7.3 billion, this includes integration of the Shell acquisition costs, adjustments related to converting historical Concho production from two to three streams, and anticipated inflation. I would estimate that roughly half of the increase could be attributed to the Shell Permian integration and the Concho conversion, while the remainder stems from anticipated inflation and should be distributed equally.

To provide further context, we were at about the $7 billion level pre-Concho acquisition with 1.5 million barrels a day of production. We are now at the similar level with a production capacity of around 1.8 million barrels a day for 2022.

That is very helpful. For a follow-up regarding realizations, I noticed they continue to trend toward highs across your mix. Could you discuss any efforts from your organization that are driving these realizations and expectations for the future?

Certainly, Ryan. Our overall realizations as a percentage of Brent increased to 82% in Q4 from 77% in Q3. This is largely attributed to a 45% increase in Henry Hub and about a 120% increase in our gas prices in Europe, while Brent only saw a 9% increase. This relative outperformance is driving the increased percentage of total realizations. Our crude realizations remain strong and within historical ranges. I anticipate we will sustain these realizations as we optimize deliveries moving forward. It's the gas realizations showcasing the most change, as our Lower 48 rates shifted from approximately 90% back to around 115%, primarily due to the conversion of Concho volumes from two to three streams, aligning with earlier indications.

Can you discuss the asset divestitures within the $4 billion to $5 billion range? Will the proceeds primarily go towards debt reduction, or could they potentially accelerate your capital return profile via buybacks or dividends? Given you have about $1.2 billion in short-term debt, but not significant maturities ahead, how do you view this?

Cash is cash, Josh. We assess overall cash flow and proceeds, considering those alongside our long-term commitment to shareholders. Our history reflects consistent return of significant percentages of both cash and sale proceeds to shareholders annually. Thus, we’re attentive to cash management for debt repayment, as well as shareholder returns. We have a $5 billion gross debt reduction target, and we’re tracking well on that front. Bill might provide additional insights on specifics related to our balance sheet.

Absolutely, Ryan. We remain firmly on target toward our $15 billion gross debt reduction goal by 2026. We have about $800 million of debt maturing this year, which we plan to repay at maturity. We are also exploring potential debt refinancing, contingent upon the current cost to retire, issue new debt, and how best to optimize our portfolio in the market environment. You can expect us to act on beneficial market conditions fairly soon.

Can you elaborate on your position within the global gas market with regard to your recent increase in APLNG? Given the dynamics in Europe and prices in Asia, do you see a growth opportunity in this segment?

Long-term, we hold a bullish perspective on LNG prices, particularly in Europe and Asia, due to trends in the energy transition. This belief influences our decision to increase our stake in APLNG and our interest in the North Field expansion in Qatar. Our focus on LNG is driven by its significance in servicing energy demands in both regions. The versatility of our cost model enables it to be indifferent regarding oil and gas, allowing for strategic allocation towards sectors showing structural advantages over the next few years.

Can you provide clarity on the production profile moving from Q4 to Q1? It seems with Shell and Alaska production ramping, guidance for Q1 suggests lower production of 1.75 to 1.79 million barrels per day. Can you discuss this apparent discrepancy?

Paul, I'm not concerned about production. Our team will manage it effectively. There are some planned turnarounds in Qatar in Q1 that were not present in Q4, affecting overall production levels. Additionally, it is a bit of a back-end ramp in our Lower 48 regions, frequently influenced by completion schedules and timelines.

Regarding the deal related to the Shell interest in Libya, how do you view the rationale behind participating, given the high tax regime and political volatility?

The opportunity was presented to us, Paul, as Total had expressed interest in acquiring Hess's stake in Libya, aiming for more control within the partnership structure. This deal still represents an attractive arrangement for us, with considerations for both production efficiency and partnership dynamics. We are quantitatively aware of the risks involved, but the deal itself presents favorable cost-to-supply metrics, allowing for extensive collaboration opportunities within the fields.

With your U.S. growth projection of 0.8 to 0.9 million barrels a day primarily in the Permian, how are you considering gas takeaway capacity as you meet production growth targets? How do you foresee the basin's overall dynamics playing out?

Our commercial team actively monitors gas takeaway capacities, ensuring we are strategically positioned. We have the capacity to evacuate gas to various hubs. However, we are cautious to avert a return to flaring across the industry by ensuring gas infrastructure aligns with production demands.

As production ramps up, we acknowledge the importance of managing capacity and closely observe the overall market trends toward proposed initiatives that may enhance takeaway expansion in the Permian Basin.

Can you outline your perspective and approach regarding the potential need to revisit the capital program mid-year?

We continuously assess our operational environment. Monitoring inflationary pressures and peer activities allows us to adapt our strategy. We are committed to maintaining the stability in our operated scope while still having flexibility to accommodate evolving circumstances and efficiency opportunities.

In relation to inflation concerns, can you clarify what's incorporated into your cost guidance? Is the couple hundred million dollars for inflation effectively locking in service cost inflation? Furthermore, are there particular aspects that will still encounter spot market fluctuations?

We are not fully locked in on service costs, so we remain exposed to spot market conditions. Various categories notably influenced by inflation are monitored closely. Recent trends in steel, chemicals, labor, and trucking illustrate some upward movements, and we're evaluating these as the year progresses.

Do you have insight into what portion of service items reside in a locked-in state?

I would need to gather more details on that aspect to get back with you.

Thank you, Zanera, and thanks to everyone who dialed into today's call.