# CONOCOPHILLIPS (COP) FY 2021 MD&A Verbatim Item 7 Management's Discussion and Analysis from CONOCOPHILLIPS's 10-K for fiscal year 2021. SEC filing source: https://www.sec.gov/Archives/edgar/data/1163165/000156276222000031/cop10k2021.htm Accession: 0001562762-22-000031 Filing date: 2022-02-17 Report date: 2021-12-31 Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Confidence: high Company profile: /company/COP/ All MD&A years: /company/COP/mda/ Next year: /company/COP/mda/fy2022/ (FY 2022) Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations Management’s Discussion and Analysis is the company’s   analysis of its financial performance and of significant trends that may affect future performance.   It should be read in conjunction with the financial statements   and notes, and supplemental oil and gas disclosures included   elsewhere in this report.   It contains forward-looking statements including, without limitation,   statements relating to the company’s   plans, strategies, objectives, expectations and intentions   that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995.   The words “anticipate,”   “believe,” “budget,”   “continue,”   “could,”   “effort,” “estimate,”   “expect,”   “forecast,”   “goal,”   “guidance,”   “intend,” “may,”   “objective,”   “outlook,”   “plan,” “potential,” “predict,” “projection,”   “seek,” “should,”   “target,” “will,”   “would,” and similar expressions   identify forward-looking statements.   The company does not undertake   to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws.   Readers are cautioned that such forward-looking statements should be read in conjunction   with the company’s disclosures under the heading:   “CAUTIONARY STATEMENT   FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS   OF THE PRIVATE   SECURITIES LITIGATION REFORM ACT OF 1995,”   beginning on page 69. The terms “earnings” and “loss” as used in Management’s   Discussion and Analysis refer to net income (loss) attributable to ConocoPhillips. Business Environment and Executive Overview ConocoPhillips is one of the world’s   leading E&P companies based on both production and reserves   with operations and activities in 14 countries.   Our diverse, low cost of supply portfolio   includes resource-rich unconventional plays   in North America; conventional assets in North   America, Europe and Asia; LNG developments; oil sands assets in Canada; and an   inventory of global conventional   and unconventional exploration prospects.   Headquartered in Houston, Texas,   at December 31, 2021, we employed approximately   9,900 people worldwide and had total   assets of $91 billion. Completed Acquisitions On January 15, 2021, we completed our acquisition   of Concho Resources Inc. (Concho), an independent   oil and gas exploration and production   company with operations across   New Mexico and West Texas   in an all-stock transaction for $13.1 billion. See Note 3 . In December 2021, we completed our acquisition   of Shell Enterprises LLC’s (Shell) assets in the   Delaware Basin in an all-cash transaction for $8.7 billion after   customary adjustments.   Assets acquired include approximately 225,000 net acres of producing properties   located entirely in Texas. See Note 3 . See Item 1A “Risk Factors” for further discussion of the risks related to integration of the assets acquired. Overview After an unprecedented 2020, the energy   landscape improved throughout   2021 with prices reaching pre-pandemic levels in the second half of the year;   however,   we expect prices will continue to be cyclical   and volatile.   Our view is that a successful business strategy   in the E&P industry must be resilient in lower price   environments while also retaining upside during periods of higher prices.   As such,   we are unhedged, remain highly disciplined   in our investment decisions and continually   monitor market fundamentals,   including OPEC Plus updates regarding   supply guidance and inventory levels.   Although global oil demand improved through   2021, the global economic recovery remains uncertain and subject to various   risk factors, including actions taken   to stem the proliferation   of COVID- 19. Management’s Discussion and Analysis Table of Contents 35 ConocoPhillips   2021 10-K As the macro energy environment   continues to evolve, we   are embracing what we believe   sector leadership requires through what we call   our triple mandate.   We believe that ConocoPhillips   will play an essential role in meeting energy transition pathway   demand delivering superior and consistent   returns on and of capital through the price cycles,   and achieving our net zero ambition   on operational emissions,   while retaining the flexibility to successfully adapt as the future unfolds. Our triple mandate is supported by financial principles   and capital allocation priorities that   should allow us to deliver superior returns through the cycles.   Our financial principles consist of maintaining   balance sheet strength, providing peer-leading distributions,   making disciplined investments, and delivering   ESG excellence, all of which are in service to delivering competitive financial returns.   Our 2021 acquisitions of Concho and the Shell Permian assets further reinforce our differential   value proposition. In 2021, we successfully delivered on our priorities.   Total   company production was   1,567 MBOED yielding cash provided by operating activities   of $17 billion.   We invested   $5.3 billion into the business in the form of capital expenditures and provided returns   of capital to shareholders of approximately   $6 billion through our ordinary dividend and share repurchases.   For 2021, our ordinary dividend returned $2.4 billion   which included an increase from 43 cents per share to 46 cents   per share,   effective in December.   Share repurchases resumed   in February and amounted to $3.6 billion inclusive of our paced   monetization program related   to the Cenovus Energy (CVE) common shares owned. See Note 5 . We also demonstrated   our commitment to preserving our top-tier balance sheet with an announcement to reduce the company’s   gross debt by $5 billion over five years   through a combination of natural and accelerated   maturities. As part of our ongoing portfolio high-grading   and optimization efforts,   in December 2021, we announced two transactions in our Asia Pacific segment enhancing   our diverse portfolio.   This included notifying Origin Energy of our intent to exercise   our preemption right to purchase   an additional 10 percent shareholding interest   in APLNG for $1.645 billion, before customary   adjustments,   and the sale of our interests in Indonesia for   approximately $1.4 billion before customary adjustments.   In addition to those transactions, in January 2022, we entered   into a divestiture agreement to sell our   interest in noncore assets within   our Lower 48 segment for $440 million.   These transactions are expected to   close in the first half of 2022.   For more information on APLNG, see Note 4 and for more information on pending dispositions, see Note 3 . We announced an increase in our   disposition target to $4 to $5 billion in proceeds   by year-end 2023, with approximately $2 billion sourced   from the Permian Basin.   As of year-end 2021, we have generated   $0.3 billion in disposition proceeds.   The proceeds from these transactions will be used   in accordance with the company’s priorities, including returns of capital to   shareholders and reduction of gross   debt. In December 2021, we announced the initiation of a three-tier   return of capital framework.   This framework is structured to continue delivering   a compelling, growing ordinary dividend and through   -cycle share repurchases.   It includes the addition of a VROC tier.   The VROC tier will provide a flexible tool for   meeting our commitment of returning greater than 30 percent   of cash from operating activities   during periods where commodity prices are meaningfully higher than our planning price range.   We have set our expected   2022 total return of capital   from all three tiers at approximately   $8 billion. For more information on our three-tier return of capital framework, see Capital Resources and Liquidity . Management’s Discussion and Analysis Table of Contents ConocoPhillips   2021 10-K 36 In 2021, we reaffirmed and improved   upon our commitment to ESG leadership   and excellence and the specific targets we set in October 2020   when we became the first U.S.-based   oil and gas company to adopt   a Paris-aligned climate-risk strategy.   Our commitment includes: ● Net-zero ambition for   operational (scope 1 and 2) emissions   by 2050 with active advocacy for a price on carbon to address end-use (scope 3) emissions; ● Targeting   a reduction in gross operated   and net equity operational GHG emissions intensity   by 40 to 50 percent from 2016 levels by 2030; ● Zero routine flaring by 2030, with   an ambition to get there by 2025; ● 10 percent reduction target   for methane emissions intensity   by 2025 from a 2019 baseline, in addition to the 65 percent reduction we have   made since 2015; ● Adding continuous methane detection devices to   our operations, with an initial focus   on the larger Lower 48 facilities; ● Dedicated low carbon technology   organization responsible   for identifying and prioritizing global emissions reduction initiatives and opportunities associated   with the energy transition,   CCUS and hydrogen; and ● ESG performance factoring into   executive and employee compensation   programs. To support   this commitment, in December 2021, we announced that   approximately $0.2 billion of our 2022 company-wide capital expenditures   would be dedicated to energy transition   efforts   across the company’s   global operations aimed at accelerating   the reduction of the company’s   scope 1 and 2 emissions and to pursue business opportunities that address end-use emissions and   early-stage low-carbon   technology opportunities that leverage the company’s adjacencies. Operationally,   we remain focused on safely   executing the business.   Production increased 440 MBOED or 39 percent in 2021, compared to 2020.   Production excluding Libya   for 2021 was 1,527 MBOED.   After adjusting for closed acquisitions and dispositions, impacts from 2020 curtailments,   2021 Winter Storm Uri and the conversion   of Concho two-stream contracted   volumes to a three-stream basis,   production increased   by 28 MBOED or 2 percent. This increase was primarily due to new production   from the Lower 48 and other development   programs across the portfolio,   partially offset by normal field decline.   Production from Libya averaged   40 MBOED in 2021. Management’s Discussion and Analysis Table of Contents 37 ConocoPhillips   2021 10-K Key Operating and Financial   Summary Significant items during 2021 and recent   announcements included the following: ● Announced an increase to expected 2022 return   of capital to shareholders   to a total of $8 billion, with the incremental $1 billion to be distributed   through share repurchases and   VROC tiers; ● Acquired and integrated   Concho, capturing over $1 billion   of synergies and savings ahead of schedule; acquired Shell’s Permian   assets on December 1, 2021; ● Exercised preemption right   to purchase an additional 10 percent   shareholding interest in APLNG, expected to close in the first quarter   of 2022; ● Generated $0.3 billion in disposition proceeds   from noncore sales and entered   into agreements   to sell an additional $1.8 billion in assets, subject to customary   closing adjustments; ● Delivered strong operational   performance across the company’s   asset base, resulting in full-year production of 1,527 MBOED, excluding   Libya; ● Achieved first production from   GMT2, Malikai Phase 2, SNP Phase 2; completed   Tor II project   and started production from a third Montney   multi-well pad; ● Net cash provided by operating   activities was $17 billion, exceeding capital   expenditures and investments of $5.3 billion; ● Distributed $6.0 billion to shareholders   through $2.4 billion in dividends and $3.6 billion of share repurchases, representing   over 30 percent return of cash   provided by operating activities   to shareholders; ● Ended the year with cash and cash equivalents   of $5.0 billion and short-term investments   of $0.4 billion, totaling over $5.4 billion in ending cash   and cash equivalents and short-term investments   ; ● Initiated a paced monetization of the company’s   CVE investment, generating $1.1   billion in proceeds through the sale of 117 million shares, with the funds applied to   share repurchases; 91 million CVE shares remained outstanding at year   -end 2021; and ● Advanced the company’s   net-zero ambition by   announcing an increase in scope 1 and 2 GHG emissions- intensity reduction targets   to 40 to 50 percent from a 2016 baseline on   a net equity and gross operated basis by 2030, from the previous target   of 35 to 45 percent on only a gross operated   basis. Business Environment Brent crude oil prices averaged   $71 per barrel in 2021, compared with $42 per barrel in   2020.   The energy industry has periodically experienced this type of volatility   due to fluctuating supply-and-demand conditions   and such volatility may persist   in the future.   Commodity prices are the most significant factor   impacting our profitability and related reinvestment   of operating cash flows into   our business.   Our strategy is to create   value through price cycles by delivering on the financial principles that   underpin our value proposition; balance sheet strength,   peer leading distributions, disciplined investments   and ESG excellence, all of which support   strong financial returns. ● Balance sheet strength. A strong balance sheet is a strategic   asset that provides flexibility through   price cycles.   We strive to maintain   our ‘A’   -rating, and we have committed   to reducing gross debt by $5 billion over the next five years.   This will reduce interest expense   and provide resilience in periods of volatility. We ended the year with over   $5 billion in cash, maintaining balance sheet strength   even after completing the all-cash acquisition of Shell’s   Permian assets. ● Peer leading distributions. We believe in delivering value   to our shareholders via our three-tiered   return of capital framework,   which consists of a growing, sustainable   dividend, share repurchases, and   beginning in 2022, the addition of VROC.   In 2021, we paid dividends on our common stock of approximately   $2.4 billion and repurchased $3.6 billion of our common stock   partially sourced from our paced monetization program related to the   CVE common shares owned.   Our combined dividends   and repurchases represented over 30 percent   of our net cash provided by operating   activities.   Our first VROC of $0.20 cents per share was paid on January 14, 2022, to   shareholders of record as of January   3, 2022.   Our VROC will be made at the Board of Director’s   discretion, subject to market conditions   and other factors. See Note 5 . See “Item 1A—Risk Factors Our ability to execute our capital return program is subject to certain considerations.” Management’s Discussion and Analysis Table of Contents ConocoPhillips   2021 10-K 38 ● Disciplined investments. Our goal is to achieve strong   free cash flow by exercising capital   discipline, controlling our costs, and safely   and reliably delivering production.   We expect to make capital investments sufficient to   sustain production throughout   the price cycles.   Free cash flow provides funds that are available to return   to shareholders,   strengthen the balance sheet or reinvest   back into the business for future cash flow expansion   . o Exercise capital discipline. We participate in a commodity   price-driven and capital-intensive industry, with varying   lead times from when an investment   decision is made to when an asset is operational and generates   cash flow.   As a result, we must invest   significant capital dollars to develop newly discovered fields,   maintain existing fields, and construct   pipelines and LNG facilities.   We allocate capital   across a geographically diverse,   low cost of supply resource base, which combined with legacy assets results   in low overall production decline.   Cost of supply is the WTI equivalent price that generates   a 10 percent after-tax return   on a point-forward and fully burdened basis.   Fully burdened includes capital infrastructure,   foreign exchange,   cost of carbon, price-related inflation and G&A.   In setting our capital plans, we exercise   a rigorous approach that evaluates projects   using these cost of supply criteria, which we believe will   lead to value maximization and cash flow expansion   using an optimized investment pace,   not production growth for growth’s   sake.   Our cash allocation priorities call for   the investment of sufficient capital to sustain production   and provide returns of capital   to shareholders. o Control our costs. Controlling operating and overhead   costs, without compromising safety   or environmental stewardship,   is a high priority.   Using various methodologies, we monitor these costs monthly,   on an absolute-dollar basis and a per-unit basis   and report to management. Managing operating and overhead costs   is critical to maintaining a competitive position   in our industry, particularly   in a low commodity price environment.   The ability to control our operating and overhead costs positively impacts   our ability to deliver strong cash   from operations. o Optimize our portfolio. In 2021, we completed the acquisition of Concho and   Shell’s Permian assets, significantly increasing our unconventional   portfolio with many additional years   of low cost of supply inventory.   The addition of this highly complementary acreage in the Midland   and Delaware basins created   a sizeable Permian presence to augment   our leading unconventional positions in the Eagle Ford and Bakken   in the Lower 48.   In our Asia Pacific segment, we notified Origin Energy of our intent to exercise   our preemption right to purchase   an additional 10 percent shareholding interest in   APLNG and announced the sale of our interests in   Indonesia. See Note 3 . We continue to evaluate   our assets to determine whether they   compete for capital within   our portfolio and optimize as necessary,   directing capital towards   the most competitive investments and disposing of assets that don’t compete.   As such, in conjunction with our Shell Permian acquisition announcement, we communicated   an increase in our planned disposition target   to $4 to $5 billion in proceeds by year-end   2023 as part of our ongoing portfolio high-grading   and optimization efforts. o Add to our proved reserve base. We primarily add to our proved   reserve base in three ways: ◾ Acquire interest in existing   or new fields. ◾ Apply new technologies and processes to   improve recovery from existing   fields. ◾ Successfully explore, develop and exploit   new and existing fields. As required by current authoritative   guidelines, the estimated future date   when an asset will reach the end of its economic life is based on   historical 12-month first-of-month   average prices and current costs.   This date estimates when production   will end and affects the amount of estimated reserves.   Therefore, as prices and   cost levels change from year to year,   the estimate of proved reserves also changes.   Generally, our   proved reserves decrease as prices   decline and increase as prices rise. Management’s Discussion and Analysis Table of Contents 39 ConocoPhillips   2021 10-K Reserve replacement represents   the net change in proved reserves, net   of production, divided by our current year production, as   shown in our supplemental reserve table disclosures.   Our reserve replacement was 377 percent   in 2021, reflecting a net increase from purchases   and sales as well as higher prices.   Our organic reserve replacement,   which excluded a net increase of 1,115 MMBOE from sales and purchases, was   189 percent in 2021. In the three years ended December 31, 2021, our reserve   replacement was 155 percent.   Our organic reserve replacement   during the three years ended December 31, 2021, which   excluded a net increase of 1,022 MMBOE related   to sales and purchases, was 88 percent. Access to additional resources may become   increasingly difficult as commodity prices can   make projects uneconomic or unattractive.   In addition, prohibition of direct investment   in some nations, national fiscal terms, political   instability,   competition from national oil companies,   and lack of access to high-potential areas due to   environmental or other regulation   may negatively impact our ability to increase our reserve base.   As such, the timing and level at which we add to our reserve base may,   or may not, allow us to fully replace our   production over subsequent years. ● ESG Leadership. Safety and environmental   stewardship, including the operati   onal integrity of our assets, remain our highest priorities.   We are committed to   protecting the health and safety   of everyone who has a role in our operations and the communities   in which we operate.   We strive to conduct   our business with respect and care for the local   and global environment and systematically   manage risk to drive sustainable business operations.   In September 2021, we reaffirmed and improved   upon our commitment to ESG leadership and excellence   and the specific targets that we set in   October 2020 when we became the first U.S. based oil and gas   company to adopt a Paris-aligned   climate-risk strategy.   Our comprehensive energy transition   strategy is designed to sustainably   meet global energy demand while delivering competitive returns on and   of capital through the energy transition.   Our strategy also recognizes the importance of   reducing society’s end-use emissions   to meet global climate goals.   As an E&P company,   active only in the upstream side of the business, we do not   produce end-use products directly for consumers.   We believe that if everyone   addressed their scope 1 and 2 emissions, scope   3 would also be addressed.   This is why we have consistently   taken a prominent role   in advocating that scope 3 emissions be addressed through a well-designed   economywide price on carbon. In addition, we are making early-stage investments   in transition opportunities with the potential   to generate competitive returns that will help address end-use emissions,   including CCUS and Hydrogen.   We are also engaging with our supply chain on their emissions targets. Other significant factors that   can affect our profitability   include: ● Energy commodity prices. Our earnings and operating cash flows generally   correlate with crude oil and natural gas commodity prices.   Commodity price levels are subject to factors   external to the company and over which we have no control,   including but not limited to global economic health, supply   disruptions or fears thereof caused by civil unrest   or military conflicts, actions taken   by OPEC Plus and other producing countries, environmental   laws, tax regulations,   governmental policies, global pandemics and   weather- related disruptions.   The following graph depicts the average   benchmark prices for WTI crude oil, Brent crude oil and U.S. Henry Hub natural gas   over the past three years: Management’s Discussion and Analysis Table of Contents ConocoPhillips   2021 10-K 40 Brent crude oil prices averaged   $70.73 per barrel in 2021, an increase of 70 percent compared   with $41.68 per barrel in 2020.   Similarly, WTI crude oil prices   increased 72 percent from $39.37   per barrel in 2020 to $67.92 per barrel in 2021.   Following COVID-19 economic shutdowns   in early 2020, global oil demand increased steadily through   the year alongside the global economic recovery.   OPEC   Plus supply restraint, capital   discipline by U.S. E&P’s and various   unplanned supply disruptions in producing countries moderated supply growth,   reducing excess global inventories   and putting upward pressure   on global oil prices. Henry Hub natural gas prices increased   85 percent from an average   of $2.08 per MMBTU in 2020 to $3.85 per MMBTU in 2021.   Extreme weather events in many   parts of the world and several global LNG liquefaction outages depleted   global natural gas inventories   in early 2021, generating strong   demand for U.S. LNG exports and supporting robust   domestic demand. Our realized bitumen price increased 368 percent   from an average of $8.02   per barrel in 2020 to $37.52 per barrel in 2021.   The increase was largely driven   by strength in WTI, reflective   of increasing global demand and OPEC discipline.   The WCS differential to WTI at   Hardisty remained fairly flat as   record high production offsets incremental   pipeline capacity.   We continue to optimize   bitumen price realizations through improvements in alternate   blend capability which results in lower diluent   costs and access to the U.S. Gulf Coast market through   rail and pipeline contracts. Our worldwide annual average   realized price increased 70 percent   from $32.15 per BOE in 2020 to $54.63 per BOE in 2021 primarily due to higher realized oil,   natural gas and bitumen prices. North America’s energy   supply landscape has been transformed   from one of resource scarcity   to one of abundance.   In recent years, the use of hydraulic   fracturing and horizontal   drilling in unconventional formations has led to increased   industry actual and forecasted   crude oil and natural gas production   in the U.S.   Although providing significant short   -   and long-term growth opportunities for   our company,   the increased abundance of crude oil and natural   gas due to development of unconventional   plays could also have adverse financial implications   to us, including: an extended period of low commodity   prices; production curtailments; and delay   of plans to develop areas such as unconventional   fields.   Should one or more of these events occur,   our revenues would be reduced, and   additional asset impairments might be possible. Management’s Discussion and Analysis Table of Contents 41 ConocoPhillips   2021 10-K ● Impairments .   We participate in a capital   -intensive industry.   At times, our PP&E and investments   become impaired when, for example,   commodity prices decline significantly for long periods   of time, our reserve estimates are revised downward,   a decision to dispose of an asset leads to a write-down   to its fair value, or the current fair value of an investment   is less than its carrying amount and the loss in value is deemed other than temporary.   As we optimize our assets in the future, it is reasonably   possible we may incur future losses upon sale or impairment charges to   long-lived assets used in operations,   investments in nonconsolidated entities accounted   for under the equity method, and unproved   properties.   For more information on our impairments,   see Note 6 and Note 7 . ● Effective tax rate .   Our operations are in countries   with different tax rates   and fiscal structures. Accordingly,   even in a stable commodity price and fiscal/regulatory   environment, our overall   effective tax rate can vary significantly   between periods based on the “mix” of before-tax   earnings within our global operations. ● Fiscal and regulatory environment .   Our operations can be affected   by changing economic, regulatory and political   environments in the various countries   in which we operate, including civil unrest   or strained relationships with governments   that may impact our operations or   investments.   These changing environments could negatively   impact our results of operations, and further changes   to increase government fiscal take   could have a negative   impact on future operations.   Our management carefully considers the fiscal and regulatory   environment when evaluating   projects or determining the levels and locations of our activity. Outlook Production and Capital 2022 operating plan capital budget   is $7.2 billion.   The plan includes funding for ongoing development   drilling programs, major projects, exploration   and appraisal activities, base maintenance and   $0.2 billion for projects to reduce the company’s   scope 1 and 2 emissions intensity and investme   nts in several early-stage   low-carbon opportunities that address end-use emissions. Production guidance is 1.8 MMBOED in 2022 including Libya   but excluding the impacts from the pending   Indonesia disposition and acquisition of additional APLNG shareholding interest.   First quarter 2022 production   is expected to be 1.75 MMBOED to 1.79 MMBOED. Operating Segments We manage our operations   through six operating segments,   which are primarily defined by geographic   region: Alaska; Lower 48; Canada; Europe, Middle   East and North Africa; Asia Pacific; and   Other International. Corporate and Other represents   income and costs not directly associated   with an operating segment, such as most interest expense, premiums   incurred on the early retirement   of debt, corporate overhead,   certain technology activities, as well as licensing revenues. Our key performance indicators,   shown in the statistical tables provided   at the beginning of the operating segment sections that follow,   reflect results from our operations,   including commodity prices and production. Results of Operations Table of Contents ConocoPhillips   2021 10-K 42 Results of Operations This section of the Form 10-K discusses year-to-year comparisons   between 2021 and 2020.   For discussion of year- to-year comparisons between 2020 and 2019, see "Management's   Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item   7 of our 2020 10-K. Consolidated Results A summary of the company’s net   income (loss) attributable to ConocoPhillips   by business segment follows: Millions of Dollars Years Ended   December 31 2021 2020 2019 Alaska $ 1,386 (719) 1,520 Lower 48 4,932 (1,122) 436 Canada 458 (326) 279 Europe, Middle East and North Africa 1,167 448 3,170 Asia Pacific 453 962 1,483 Other International (107) (64) 263 Corporate and Other (210) (1,880) 38 Net income (loss) attributable to   ConocoPhillips $ 8,079 (2,701) 7,189 Net Income (loss) attributable to   ConocoPhillips increased $10.8 billion in 2021.   2021 earnings were positively impacted by: ● Higher realized commodity prices. ● Higher sales volumes primarily due to our Concho acquisition and   absence of production curtailments. See Note 3 . ● A gain of $1,040 million after-tax on our   Cenovus Energy (CVE) common shares in 2021, as   compared to a $855 million after-tax loss on those shares   in 2020. ● Lower exploration expenses   due to: o Absence of a 2020 impairment for $648 million after   -tax for the entire carrying value   of capitalized undeveloped leasehold   costs related to our Alaska   North Slope Gas asset. o Lower dry hole expenses. o Absence of early cancellation of our 2020 winter exploration   program in Alaska. o Absence of unproved property   impairment and dry hole expenses in 2020 for the Kamunsu   East Field in Malaysia, which is no longer in our development   plans. ● Higher equity in earnings of affiliates, primarily due to   higher LNG sales prices. ● Contingent payments related   to prior dispositions in our Canada and Lower 48 segments. ● An after-tax gain of $194 million recognized   for a FID bonus associated with our Australia   -West divestiture in 2020. See Note 3 . ● Lower impairments, primarily due to the absence   of impairments recognized in 2020 for   noncore assets in our Lower 48 segment partially offset   by an impairment in our APLNG investment   included within our Asia Pacific segment. See Note 7 . These increases in net income (loss) were partly   offset by: ● Higher production and operating expenses   and taxes other than income taxes,   primarily due to higher sales volumes. ● Higher DD&A expenses caused by higher production   volumes, partially offset by lower rates   driven from positive reserve revisions due to higher   commodity prices in 2021. ● Absence of a $597 million after-tax gain   on our Australia-West   divestiture completed in May   2020. ● Restructuring and transaction expenses   of $341 million after-tax associated   with the Concho and Shell acquisitions in addition to mark-to-market   impacts on certain key employee   compensation programs. Results of Operations Table of Contents 43 ConocoPhillips   2021 10-K ● Realized losses on hedges of $233 million after   -tax related to derivative   positions assumed through our Concho acquisition.   These derivative positions were settled   entirely within the first quarter of 2021. See Note 12 . Income Statement Analysis Unless otherwise indicated, all results in Income Statement   Analysis are before-tax. Sales and other operating revenues   increased 144 percent in 2021, mainly due to higher   realized commodity prices and higher sales volumes. Equity in earnings of affiliates increased   $400 million in 2021, primarily due to higher earnings driven   by higher LNG and crude prices, partially offset by a higher   effective tax rate   related to equity method investments   in our Europe, Middle East and North Africa segment   . Gain on dispositions decreased $63 million in 2021, primarily due   to the absence of a $587 million gain related   to our 2020 Australia-West   divestiture and a $179 million loss associated   with the sale of noncore assets in our Other International segment.   The decreases were partially offset   by $200 million related to a FID bonus   associated with our Australia-West   divestiture,   gains recognized for contingent   payments associated with previous   dispositions in our Canada and Lower 48 segments and gains   on sales of certain noncore assets in our Lower 48 segment. Other income (loss) increased $1.7 billion in 2021, primarily due   to a gain of $1,040 million on our CVE common shares in 2021, as compared to a $855 million loss on   those shares in 2020. See Note 5 . Purchased commodities increased 125 percent   in 2021, primarily in line with higher gas and crude prices   and volumes. Production and operating expenses   increased $1,350 million in 2021, primarily in line with higher production volumes. Selling, general and administrative   expenses increased $289 million in 2021, primarily due to   transaction and restructuring expenses associated   with our Concho acquisition and higher compensation and benefits   costs, including mark-to-market impacts of certain   key employee compensation   programs. Exploration expenses decreased   $1,113 million in 2021, primarily due to the absence of 2020 expenses   including an $828 million impairment for the entire   carrying value of capitalized   undeveloped leasehold costs related   to our Alaska North Slope Gas asset, the early cancellation of our   2020 winter exploration   program in Alaska, and   absence of unproved property impairment and   dry hole expenses from 2020 for the Kamunsu   East Field in Malaysia.   2021 also saw lower dry hole expenses in Alaska. Impairments decreased $139 million in 2021, primarily due   to the absence of impairments recognized   in 2020 for noncore assets in our Lower 48 segment partially   offset by an impairment in our APLNG investment   included within our Asia Pacific segment in 2021.   For additional information, see Note 7 and Note 13 . Taxes   other than income taxes increased   $880 million in 2021, caused primarily by higher commodity prices and higher Lower 48 sales volumes. Foreign currency transaction   (gains) losses decreased $50 million in 2021 due to the   absence of derivative gains and other remeasurements. See Note 17—Income Taxes for information regardin   g   our income tax provision   and effective tax rate. Results of Operations Table of Contents ConocoPhillips   2021 10-K 44 Summary Operating Statistics 2021 2020 2019 Average Net Production Crude oil (MBD) Consolidated Operations 816 555 692 Equity affiliates 13 13 13 Total   crude oil 829 568 705 Natural gas liquids (MBD) Consolidated Operations 134 97 107 Equity affiliates 8 8 8 Total   natural gas liquids 142 105 115 Bitumen (MBD) 69 55 60 Natural gas (MMCFD) Consolidated Operations 2,109 1,339 1,753 Equity affiliates 1,053 1,055 1,052 Total   natural gas 3,162 2,394 2,805 Total Production (MBOED) 1,567 1,127 1,348 Dollars Per Unit Average Sales Prices Crude oil (per bbl) Consolidated Operations $ 67.61 39.56 60.98 Equity affiliates 69.45 39.02 61.32 Total   crude oil 67.64 39.54 60.99 Natural gas liquids (per bbl) Consolidated Operations 31.04 12.90 18.73 Equity affiliates 54.16 32.69 36.70 Total   natural gas liquids 32.45 14.61 20.09 Bitumen (per bbl) 37.52 8.02 31.72 Natural gas (per mcf) Consolidated Operations 6.00 3.17 4.25 Equity affiliates 5.31 3.71 6.29 Total   natural gas 5.77 3.41 5.03 Millions of Dollars Worldwide Exploration   Expenses General and administrative;   geological and geophysical, lease rental, and other $ 300 374 322 Leasehold impairment 10 868 221 Dry holes 34 215 200 Total   Exploration Expenses $ 344 1,457 743 Results of Operations Table of Contents 45 ConocoPhillips   2021 10-K We explore for,   produce, transport and market   crude oil, bitumen, natural gas,   LNG and NGLs on a worldwide basis.   At December 31, 2021, our operations   were producing in the U.S., Norway,   Canada, Australia, Indonesia, China, Malaysia, Qatar and Libya. Total production,   including Libya, of 1,567 MBOED increased 440 MBOED or 39 percent   in 2021 compared with 2020, primarily due to: ● Higher volumes in Lower 48 due to our Concho acquisition   . ● New wells online in Lower 48, Canada, Norway,   Malaysia and Alaska. ● Absence of production curtailments,   primarily in our North American assets. ● Higher production in Libya due to the absence of a   forced shutdown of the Es Sider export   terminal and other eastern export terminals. ● Improved well performance in   Norway,   Canada, Alaska and China. The increase in production during 2021 was partly   offset by: ● Normal field decline. ● Absence of production from Australia   -West due to our second quarter   2020 disposition. Production excluding Libya   for 2021 was 1,527 MBOED.   After adjusting for closed acquisitions   and dispositions, impacts from 2020 curtailments, 2021 Winter   Storm Uri and the conversion   of Concho two-stream contracted volumes to a three-stream basis,   production increased by 28 MBOED or 2 percent.   This increase was primarily due to new production from the Lower 48 and other   development programs across   the portfolio,   partially offset by normal field decline. Production from Libya   averaged 40 MBOED in 2021. Results of Operations Table of Contents ConocoPhillips   2021 10-K 46 Alaska 2021 2020 2019 Net Income (Loss) Attributable   to ConocoPhillips ($MM) $ 1,386 (719) 1,520 Average Net Production Crude oil (MBD) 178 181 202 Natural gas liquids (MBD) 16 16 15 Natural gas (MMCFD) 16 10 7 Total Production (MBOED) 197 198 218 Average Sales Prices Crude oil ($ per bbl) $ 69.87 42.12 64.12 Natural gas ($ per mcf) 2.81 2.91 3.19 The Alaska segment primarily explores for,   produces, transports and markets   crude oil, NGLs and natural gas.   In 2021, Alaska contributed 19 percent   of our consolidated liquids production   and less than 1 percent of our consolidated natural   gas production. Net Income (Loss) Attributable to ConocoPhillips Alaska reported earnings of $1,386 million in 2021, compared   with a loss of $719 million in 2020.   Earnings were positively impacted by: ● Higher realized crude oil prices. ● Absence of 2020 exploration expenses   ,   including a $648 million after-tax impairment   associated with the carrying value of our Alaska North Slope Gas assets   and the early cancellation of our winter exploration program. See Note 6 . ● Lower dry hole expenses. Earnings were negatively   impacted by: ● Higher taxes other than income taxes   primarily due to higher realized crude oil prices. Production Average production   decreased 1 MBOED in 2021 compared with 2020, primarily   due to: ● Normal field decline. The production decrease was partly   offset by: ● Absence of curtailments. ● Improved production at   our Western North Slope assets   as a result of net royalty interest   changes associated with periodic redetermination. ● Improved performance in the Greater   Prudhoe Area and Western   North Slope assets. ● New wells online across the segment. Results of Operations Table of Contents 47 ConocoPhillips   2021 10-K Lower 48 2021 2020 2019 Net Income (Loss) Attributable   to ConocoPhillips ($MM) $ 4,932 (1,122) 436 Average Net Production Crude oil (MBD) 447 213 266 Natural gas liquids (MBD)* 110 74 81 Natural gas (MMCFD)* 1,340 585 622 Total Production (MBOED) 780 385 451 Average Sales Prices Crude oil ($ per bbl)** $ 66.12 35.17 55.30 Natural gas liquids ($ per bbl) 30.63 12.13 16.83 Natural gas ($ per mcf)** 4.38 1.65 2.12 *Includes conversion of previously acquired Concho two-stream contracts to three-stream initiated in the fourth quarter of 2021. **Average sales prices, including the impact of hedges settling per initial contract terms in the first quarter of 2021 assumed in our   Concho acquisition were $65.19 per barrel for crude oil and $4.33 per mcf for natural gas for the   year ended December 31, 2021.   As of March 31, 2021, we had settled all oil and gas hedging positions acquired from Concho. See Note 12 . The Lower 48 segment consists of operations   located in the contiguous U.S. and   the Gulf of Mexico.   During 2021, the Lower 48 contributed 55 percent   of our consolidated liquids production   and 64 percent of our consolidated natural gas production. Net Income (Loss) Attributable to ConocoPhillips Lower 48 reported earnings of $4,932 million in 2021, compared   with a loss of $1,122 million in 2020.   Earnings were positively impacted by: ● Higher realized crude oil, NGL and natural   gas prices. ● Higher sales volumes due to our Concho acquisition and the absence   of production curtailments. ● Lower impairments, primarily related   to developed properties in our noncore   assets which were written down to fair value due to lower commodity   prices and development plan changes.   See Note 7 and Note 13 . ● Higher gains on dispositions related to   selling our interests in certain noncore   assets. See Note 3 . Earnings were negatively   impacted by: ● Higher DD&A expenses, production and operating   expenses and taxes other than   income taxes primarily due to higher production volumes.   Partially offsetting the increase   in DD&A expenses were lower rates from price-related reserve revisions. ● Impacts resulting from our Concho acquisition,   including higher selling, general and administrative expenses for transaction and restructuring   charges, as well as realized losses   on derivative settlements. See Note 3 and Note 12 . Production Total   average production   increased 395 MBOED in 2021 compared with 2020, primarily   due to: ● Higher volumes due to our Concho acquisition. ● New wells online from our development programs   in Permian, Eagle Ford   and Bakken. ● Absence of curtailments. These production increases were partly   offset by: ● Normal field decline. Results of Operations Table of Contents ConocoPhillips   2021 10-K 48 Canada 2021* 2020* 2019** Net Income (Loss) Attributable   to ConocoPhillips ($MM) $ 458 (326) 279 Average Net Production Crude oil (MBD) 8 6 1 Natural gas liquids (MBD) 4 2 - Bitumen (MBD) 69 55 60 Natural gas (MMCFD) 80 40 9 Total Production (MBOED) 94 70 63 Average Sales Prices Crude oil ($ per bbl) $ 56.38 23.57 40.87 Natural gas liquids ($ per bbl) 31.18 5.41 19.87 Bitumen ($ per bbl) 37.52 8.02 31.72 Natural gas ($ per mcf) 2.54 1.21 0.49 *Average sales prices include unutilized transportation costs. **Average prices for sales of bitumen produced excludes additional value realized from the purchase and sale of third-party volumes for optimization of our pipeline capacity between Canada and the U.S. Gulf Coast. Our Canadian operations consist of the Surmont   oil sands development in Alberta and the liquids-rich Montney unconventional play in   British Columbia.   In 2021, Canada contributed 8 percent of our   consolidated liquids production and 4 percent of our consolidated   natural gas production. Net Income (Loss) Attributable to ConocoPhillips Canada operations reported   earnings of $458 million in 2021 compared with a loss of $326 million in 2020. Earnings were positively impacted   by: ● Higher realized bitumen prices and crude   oil prices. ● After-tax gains   on disposition related to contingent   payments of $246 million in 2021 associated   with the sale of certain assets to CVE in 2017. ● Higher sales volumes in our Surmont and Montney   assets. Earnings were negatively impacted   by: ● Higher production and operating expenses   primarily due to increased Surmont and Montney   production. Production Total   average production   increased 24 MBOED in 2021 compared with 2020.   The production increase was primarily due to: ● Improved well performance in   Surmont. ● New wells online in Montney. ● Production from our Kelt acquisition   completed in the third quarter of 2020. ● Absence of curtailments. Results of Operations Table of Contents 49 ConocoPhillips   2021 10-K Europe, Middle East and North Africa 2021 2020 2019 Net Income (Loss) Attributable   to ConocoPhillips ($MM) $ 1,167 448 3,170 Consolidated Operations Average Net Production Crude oil (MBD) 118 86 138 Natural gas liquids (MBD) 4 4 7 Natural gas (MMCFD) 313 275 478 Total Production (MBOED) 175 136 224 Average Sales Prices Crude oil ($ per bbl) $ 68.97 43.30 64.94 Natural gas liquids ($ per bbl) 43.97 23.27 29.37 Natural gas ($ per mcf) 13.27 3.23 4.92 The Europe, Middle East and North Africa   segment consists of operations   principally located in the Norwegian sector of the North Sea; the Norwegian Sea; Qatar; Libya;   and terminalling operations in the U.K.   In 2021, our Europe, Middle East and North Africa   operations contributed   12 percent of our consolidated liquids   production and 14 percent of our consolidated   natural gas production. Net Income Attributable to ConocoPhillips The Europe, Middle East and North Africa   segment reported earnings of $1,167 million in 2021 compared   with earnings of $448 million in 2020.   Earnings were positively impacted   by: ● Higher realized natural   gas, crude oil and NGL prices. ● Higher LNG sales prices, reflected in equity in earnings   of affiliates. ● Higher sales volumes of crude oil and LNG. Earnings were negatively   impacted by: ● Higher taxes. ● Higher DD&A expenses and production and   operating expenses.   Partly offsetting the increase   in DD&A expenses were lower rates   from positive reserve revisions. Consolidated Production Average consolidated   production increased 39 MBOED in 2021, compared   with 2020.   The consolidated production increase was primarily due to: ● Higher production in Libya due to the absence   of a forced shutdown of the Es Sider export   terminal and other eastern export terminals. ● Improved well performance in   Norway. ● New production from Norway   drilling activities, including our Tor   II redevelopment project which achieved full production in 2021. These production increases were partly   offset by: ● Normal field decline. Results of Operations Table of Contents ConocoPhillips   2021 10-K 50 Asia Pacific 2021 2020 2019 Net Income (Loss) Attributable   to ConocoPhillips ($MM) $ 453 962 1,483 Consolidated Operations Average Net Production Crude oil (MBD) 65 69 85 Natural gas liquids (MBD) - 1 4 Natural gas (MMCFD) 360 429 637 Total Production (MBOED) 125 141 196 Average Sales Prices Crude oil ($ per bbl) $ 70.36 42.84 65.02 Natural gas liquids ($ per bbl) - 33.21 37.85 Natural gas ($ per mcf) 6.56 5.39 5.91 The Asia Pacific segment has operations   in China, Indonesia, Malaysia and Australia.   During 2021, Asia Pacific contributed 6 percent of our consolidated   liquids production and 17 percent of our consolidated   natural gas production. Net Income Attributable to ConocoPhillips Asia Pacific reported earnings of $453 million   in 2021, compared with $962 million in 2020.   The decrease in earnings was mainly due to: ● An impairment of $688 million after-tax on   our APLNG investment.   See Note 4 and Note 13 . ● Absence of a $597 million after-tax gain   related to our Australia   -West divestiture. See Note 3 . ● Absence of sales volumes associated with Australia   -West. Earnings were positively impacted   by: ● Higher crude oil and natural gas   prices. ● Higher LNG sales prices, reflected in equity in earnings   of affiliates. ● An after-tax gain of $194 million   recognized for a FID bonus associated   with our Australia-West   divestiture. For additional information related   to this FID bonus, see Note 3 and Note 11 . Consolidated Production Average consolidated   production decreased 16 MBOED in 2021, compared   with 2020.   The decrease was primarily due to: ● The divestiture of our Australia   -West assets that contributed   18 MBOED in 2020. ● Normal field decline. These production decreases were partly   offset by: ● Development activity at Bohai Bay   in China. ● First production in Malikai   Phase 2 and SNP Phase 2. ● The absence of curtailments across the segment   and increased demand in Indonesia from coal supply restrictions. Results of Operations Table of Contents 51 ConocoPhillips   2021 10-K Other International 2021 2020 2019 Net Income (Loss) Attributable   to ConocoPhillips ($MM) $ (107) (64) 263 The Other International segment includes exploration   and appraisal activities in Colombia as well as contingencies associated with prior operations   in other countries.   As a result of our Concho acquisition, we refocused   our exploration program   and announced our intent to pursue   managed exits   from certain areas. Other International operations   reported a loss of $107 million in 2021, compared with a   loss of $64 million in 2020. Earnings were negatively   impacted by: ● A $137 million after-tax loss on divestiture   related to our Argentina   exploration interests. See Note 3 . ● Absence of a $29 million after-tax benefit to earnings   from the dismissal of arbitration   related to prior operations in Senegal recognized   in the first quarter of 2020. Changes to earnings were positively impacted   by: ● Absence of exploration expenses   associated with dry hole costs and a full impairment of   capitalized undeveloped leasehold costs in Colombia in the fourth   quarter of 2020. Corporate and Other Millions of Dollars 2021 2020 2019 Net Income (Loss) Attributable   to ConocoPhillips Net interest $ (801) (662) (604) Corporate general and administrative   expenses (317) (200) (252) Technology 25 (26) 123 Other 883 (992) 771 $ (210) (1,880) 38 Net interest consists   of interest and financing expense,   net of interest income and capitalized   interest.   Net interest expense increased $139   million in 2021 compared with 2020, primarily due to higher   debt balances assumed due to our Concho acquisition. See Note 9 . Corporate G&A expenses include   compensation programs and   staff costs.   These expenses increased by $117 million in 2021 compared with 2020, primarily due to restructuring   expenses associated with our Concho acquisition and mark to market adjustments   associated with certain compensation programs   . See Note 16 . Technology includes   our investment in new technologies   or businesses, as well as licensing revenues.   Activities are focused on both conventional   and tight oil reservoirs, shale gas,   heavy oil, oil sands, enhanced oil recovery as well as LNG.   Earnings from Technology   increased by $51 million in 2021 compared with 2020,   primarily due to higher licensing revenues. The category “Other” includes certain foreign currency   transaction gains and losses,   environmental costs associated with sites no longer in operation,   other costs not directly associated with an   operating segment, premiums incurred on the early retirement   of debt,   holding gains or losses on equity securities, and   pension settlement expense.   Earnings in “Other” increased by $1,875 million in 2021 compared   with 2020, primarily due to a gain of $1,040 million on our CVE common shares   in 2021, compared with a $855 million loss in 2020. Capital Resources and Liquidity Table of Contents ConocoPhillips   2021 10-K 52 Capital Resources and Liquidity Financial Indicators Millions of Dollars Except as Indicated 2021 2020 2019 Net cash provided by operating   activities $ 16,996 4,802 11,104 Cash and cash equivalents 5,028 2,991 5,088 Short-term investments 446 3,609 3,028 Short-term debt 1,200 619 105 Total   debt 19,934 15,369 14,895 Total   equity 45,406 29,849 35,050 Percent of total debt to   capital* 31 % 34 30 Percent of floating-rate   debt to total debt 4 % 7 5 *Capital includes total debt and total equity. To meet our   short-   and long-term liquidity requirements,   we look to a variety of funding sources,   including cash generated from operating   activities, proceeds from asset sales,   our commercial paper and credit facility programs and our ability to sell securities using our shelf registration   statement.   In 2021, the primary uses of our available cash were $8.7 billion for the acquisition   of Shell Permian;   $5.3 billion to support our ongoing capital expenditures and investments program;   $3.6 billion to repurchase our common stock;   $2.4 billion to pay dividends;   and $1.2 billion for hedging, transaction and restructuring   costs.   In 2021, cash and cash equivalents increased by   $2.0 billion to $5.0 billion. At December 31, 2021, we had cash and cash   equivalents of $5.0 billion, short-term investments   of $0.4 billion, and available borrowing capacity   under our credit facility of $6.0 billion, totaling   approximately $11.5 billion   of liquidity.   We believe current cash   balances and cash generated by   operations, together with access to   external sources of funds as described below in the “Significant Changes   in Capital” section, will be sufficient to meet our funding requirements in the near- and   long-term, including our capital spending program,   dividend payments and required debt payments. Significant Changes in Capital Operating Activities In 2021, cash provided by operating   activities was $17 billion, compared with $4.8 billion   for 2020.   The increase is primarily due to higher realized commodity   prices and higher sales volumes,   mostly resulting from our acquisition of Concho.   The increase was partly offset by   the $0.8 billion in settlement of oil and gas hedging   positions acquired from Concho, and approximately   $0.4 billion of transaction and restructuring   costs. Our short-   and long-term operating cash flows   are highly dependent upon prices for crude oil, bitumen,   natural gas, LNG and NGLs.   Prices and margins in our industry have historically   been volatile and are driven by market conditions over which we have no   control.   Absent other mitigating factors,   as these prices and margins fluctuate, we would expect a corresponding change   in our operating cash flows. The level of absolute production volumes,   as well as product and location mix, impacts our cash   flows.   Full-year production averaged   1,567 MBOED in 2021.   Full-year production excluding   Libya averaged 1,527   MBOED. Adjusting for closed acquisitions and dispositions,   impacts from 2020 curtailments, 2021 Winter Storm   Uri and the conversion of Concho two-stream   contracted volumes to a   three-stream basis, production   increased 28 MBOED or 2 percent.   First quarter 2022 production   is expected to be 1.75 MMBOED to 1.79 MMBOED.   Future production is subject to numerous uncertainties, including,   among others, the volatile crude oil and natural   gas price environment, which may impact   investment decisions; the effects   of price changes on production sharing and variable-royalty contracts;   acquisition and disposition of fields; field production decline rates;   new technologies; operating efficiencies; timing of startups   and major turnarounds; political instability;   weather-related disruptions; Capital Resources and Liquidity Table of Contents 53 ConocoPhillips   2021 10-K and the addition of proved reserves through   exploratory success and their timely and cost   -effective development.   While we actively manage these factors,   production levels can cause variability   in cash flows, although generally this variability has   not been as significant as that caused by commodity prices. To maintain   or grow our production volumes on   an ongoing basis, we must continue to add   to our proved reserve base.   Our proved reserves generally   increase as prices rise and decrease as prices decline.   Reserve replacement represents the net change in proved   reserves, net of production, divided by our current   year production.   For information on proved   reserves, including both developed and undeveloped   reserves, see the reserve table disclosures contained in “Supplementary Data – Oil and Gas Operations.” See “Item 1A—Risk Factors – Unless we successfully develop our resources, the scope of our business will decline, resulting in an adverse impact to our business.” As discussed in the “Critical Accounting Estimates”   section, engineering estimates of proved   reserves are imprecise; therefore, reserves   may be revised upward or   downward each year due to the impact of changes   in commodity prices or as more technical data   becomes available on reservoirs.   It is not possible to reliably predict how revisions will impact future reserve quantities. Investing Activities In 2021, we invested $5.3 billion   in capital expenditures.   Capital expenditures invested   in 2020 and 2019 were $4.7 billion and $6.6 billion, respectively.   For information about our   capital expenditures and investments,   see the “Capital Expenditures and Investments”   section. In December 2021, we completed our acquisition   of Shell’s assets in   the Delaware Basin for cash consideration   of approximately $8.7 billion after   customary adjustments.   We funded this transaction with cash   on hand.   We completed our acquisition of Concho on January 15, 2021.   The assets acquired in the transaction included   $382 million of cash.   The net impact of these items is recognized   within “Acquisition   of businesses, net of cash acquired” on our consolidated sta   tement of cash flows. See Note 3. In 2021, we announced a disposition target   of $4 to $5 billion in disposition proceeds by year-end   2023.   Only proceeds from transactions announced   or initiated in the third quarter of 2021 or later   will be counted toward this target.   The proceeds from these transactions   will be used in accordance with the company’s   priorities, including returns of capital to shareholders   and reduction of gross debt.   To date,   we have achieved $0.3 billion from   the sale of noncore assets in our Lower 48 segment. Total   proceeds from asset dispositions   in 2021 were $1.7 billion.   Including the $250 million mentioned above, we also received cash proceeds of $1.14 billion from   sales of our investment in CVE   common shares and $244 million of contingent payments related   to dispositions completed before   2021. See Note 3. In May 2021, we announced and began a paced monetization of our   investment in CVE with the plan to   direct proceeds toward   our existing share repurchase program.   We expect to fully dispose   of our CVE common shares by early 2022, however,   the sales pace will be guided by market conditions,   and we retain discretion to   adjust accordingly. See Note 5. Proceeds from asset sales in 2020 were $1.3   billion.   We received cash   proceeds of $765 million for the divestiture of our Australia-West   assets and operations.   We also received proceeds of $359   million and $184 million from the sale of our Niobrara interests   and Waddell Ranch interests   in the Lower 48, respectively. Proceeds from asset sales in 2019 were $3.0   billion, including $2.2 billion for the sale of two ConocoPhillips   U.K. subsidiaries and $350 million for the sale of our 30 percent   interest in the Greater   Sunrise Fields. See Note 3. We invest in short   -term investments as part of our   cash investment strategy,   the primary objective of which is to protect principal, maintain liquidity   and provide yield and total returns;   these investments include time deposits, commercial paper,   as well as debt securities classified as available   for sale.   Funds for short-term needs   to support our operating plan and provide resiliency   to react to short-term price volatility   are invested in highly liquid instruments with maturities within the year.   Funds we consider available to maintain   resiliency in longer term Capital Resources and Liquidity Table of Contents ConocoPhillips   2021 10-K 54 price downturns and to capture opportunities   outside a given operating plan may   be invested in instruments   with maturities greater than one year. See Note 12 . Financing Activities We have a revolving   credit facility totaling $6.0 billion, expiring   in May 2023.   Our revolving credit facility   may be used for direct bank borrowings,   the issuance of letters of credit totaling   up to $500 million, or as support for our commercial paper program.   The revolving credit facility is broadly   syndicated among financial institutions   and does not contain any material   adverse change provisions or any   covenants requiring maintenance of specified financial ratios or credit ratings.   The facility agreement contains   a cross-default provision relating   to the failure to pay principal or interest   on other debt obligations of $200 million or more by   ConocoPhillips, or any of its consolidated subsidiaries.   The amount of the facility is not subject to the redetermination   prior to its expiration date. Credit facility borrowings may   bear interest at a margin above   rates offered   by certain designated banks in the London interbank market or   at a margin above the overnight federal   funds rate or prime rates   offered by certain designated banks in the U.S.   The agreement calls for commitment   fees on available, but unused,   amounts.   The agreement also contains early termination   rights if our current directors   or their approved successors   cease to be a majority of the Board of Directors. The revolving credit facility supports   ConocoPhillips Company’s ability to   issue up to $6.0 billion of commercial paper, which   is primarily a funding source for short-term working   capital needs.   Commercial paper maturities are generally limited to 90 days.   With no commercial paper outstanding   and no direct borrowings or letters   of credit, we had access to $6.0 billion in available borrowing   capacity under the revolving credit facility   at December 31, 2021. On January 15, 2021, we completed the acquisition of Concho   in an all-stock transaction. In the acquisition,   we assumed Concho’s publicly   traded debt and in December 2020, we launched an offer   to exchange Concho’s publicly traded debt for debt issued   by ConocoPhillips.   There were no impacts to ConocoPhillips’   credit ratings as a result of the debt exchange.   In June 2021, we reaffirmed our   commitment to preserving our ‘A’   -rated balance sheet by restating our intent   to reduce gross debt by $5 billion over   the next five years, driving a more resilient   and efficient capital structure.   See Note 9 and Note 3 . On January 25, 2021, S&P revised the industry risk assessment   for the E&P industry to ‘Moderately   High’ from ‘Intermediate’ based on a view of increasing   risks from the energy transition,   price volatility,   and weaker profitability.   On February 11, 2021, S&P downgraded its rating   of our long-term debt from “A”   to “A   -” with a “stable” outlook and affirmed   this rating in November 2021.   In October 2021, Moody’s affirmed its “A3”   rating of our long-term debt and revised its outlook   from “stable” to “positive”.   In December 2021, Fitch affirmed its rating of our long-term debt as “A”   with a “stable” outlook. We do not have any   ratings triggers on any of our corporate   debt that would cause an automatic default,   and thereby impact our access to liquidity,   upon downgrade of our credit ratings.   If our credit ratings are downgraded from their current levels, it could   increase the cost of corporate   debt available to us and restrict   our access to the commercial paper markets.   If our credit rating were to deteriorate   to a level prohibiting us from accessing   the commercial paper market, we   would still be able to access funds under our revolving   credit facility. Certain of our project-related   contracts, commercial contracts   and derivative instruments contain   provisions requiring us to post collateral.   Many of these contracts and instruments   permit us to post either cash or letters   of credit as collateral.   At December 31, 2021 and 2020, we had direct   bank letters of credit of $337 million and   $249 million, respectively,   which secured performance obligations   related to various purchase   commitments incident to the ordinary conduct of business.   In the event of credit ratings downgrades,   we may be required to post   additional letters of credit. We have a universal   shelf registration statement   on file with the SEC under which we have the   ability to issue and sell an indeterminate amount of various   types of debt and equity securities. Capital Resources and Liquidity Table of Contents 55 ConocoPhillips   2021 10-K Capital Requirements For information about our capital   expenditures and investments,   see the “Capital Expenditures and Investments” section. Our debt balance at December 31, 2021, was $19.9 billion,   an increase of $4.6 billion from the balance at December 31, 2020, driven by debt acquired as part   of the Concho acquisition.   Maturities of debt (including payments for finance leases) due in   2022 of $1.1 billion will be paid from current cash   balances and cash generated by operations. See Note 9 . In December 2021, we announced our expected 2022 return   of capital program and the initiation   of a three-tier return of capital framework.   The framework is structured   to deliver a compelling, growing ordinary dividend   and through-cycle share repurchases.   It includes the addition of a discretionary VROC tier.   The VROC will provide a flexible tool for meeting our commitment   of returning greater than   30 percent of cash from operating   activities during periods where commodity prices are meaningfully   higher than our planning price range.   We have set our expected 2022 total capital returns   at approximately $8 billion,   consisting of distributions from each of the three tiers. Consistent with our commitment to   deliver value to shareholders,   in 2021, we paid $2.4 billion, $1.75 per share of common stock, in ordinary dividends. This   was an increase over 2020 and 2019, when we paid $1.69 and   $1.34 per share of common stock, respectively.   On February 3, 2022, we announced a quarterly dividend of $0.46 per share, payable March 1, 2022, to stockholders   of record at the close of business on February   14, 2022.   On January 14, 2022, we paid the first VROC payment   of $0.20 per share to shareholders   of record as of January 3, 2022.   On February 3, 2022, we announced a VROC of $0.30 per share,   payable on April 14, 2022, to stockholders   of record at the close of business on March 31, 2022. The ordinary dividend and VROC are subject to   numerous considerations   and will be determined and approved each quarter by the Board of Directors.   We expect to announce the VROC   when we announce our ordinary dividend, but the quarterly payouts   will be staggered from the ordinary dividend,   resulting in up to eight cash distributions throughout the year. In late 2016, we initiated our current   share repurchase program   with Board of Director’s authorization   of $25 billion of our common stock.   Share repurchases were $3.6   billion, $0.9 billion, and $3.5 billion in 2021, 2020, and 2019, respectively.   As of December 31, 2021, share repurchases   since the inception of our current program totaled 247 million shares and $14 billion.   Repurchases are made at management’s   discretion, at prevailing prices, subject to market conditions and   other factors. For more information on factors   considered when determining the levels of returns   of capital see “Item 1A—Risk Factors – Our ability to execute our capital return program is subject to certain considerations.” In addition to the priorities described above, we have   contractual obligations   to purchase goods and services of approximately $11.8 billion.   We expect to fulfill $6 billion of these   obligations in 2022. These figures exclude purchase commitments for jointly   owned fields and facilities where we are not   the operator.   Purchase obligations of $5.3 billion are related to agreements   to access and utilize the capacity of third   -party equipment and facilities, including pipelines and LNG product terminals, to   transport, process, treat and store   commodities.   Purchase obligations of $5.3 billion are related   to market-based contracts   for commodity product purchases   with third parties.   The remainder is primarily our net share of purchase   commitments for materials   and services for jointly owned fields and facilities where we are the operator. Capital Resources and Liquidity Table of Contents ConocoPhillips   2021 10-K 56 Capital Expenditures and Investments Millions of Dollars 2021 2020 2019 Alaska $ 982 1,038 1,513 Lower 48 3,129 1,881 3,394 Canada 203 651 368 Europe, Middle East and North Africa 534 600 708 Asia Pacific 390 384 584 Other International 33 121 8 Corporate and Other 53 40 61 Capital Program* $ 5,324 4,715 6,636 * Excludes capital related to acquisitions of businesses, net of capital acquired. Our capital expenditures and investments   for the three-year period ended December 31,   2021, totaled $16.7 billion.   The 2021 expenditures supported   key exploration   and developments, primarily: ● Development activities in the Lower 48, primarily Permian,   Eagle Ford, and Bakken. ● Appraisal and development activities in Alaska   related to the Western   North Slope and development activities in the Greater Kuparuk Area. ● Appraisal and development activities in the   Montney and optimization of oil sands   development in Canada. ● Continued development activities across   assets in Norway. ● Continued development activities in China,   Malaysia, and Indonesia. 2022 Capital Budget In December 2021, we announced our 2022 operating plan   capital of $7.2 billion.   The plan includes funding for ongoing development drilling programs,   major projects, exploration and   appraisal activities, base maintenance and $0.2 billion 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. Capital Resources and Liquidity Table of Contents 57 ConocoPhillips   2021 10-K Guarantor Summarized Financial   Information We have various   cross guarantees among ConocoPhillips,   ConocoPhillips Company,   and Burlington Resources LLC with respect to publicly held debt securities.   ConocoPhillips Company is 100 percent   owned by ConocoPhillips. Burlington Resources LLC is   100 percent owned by ConocoPhillips Company.   ConocoPhillips and/or ConocoPhillips Company have fully and unconditionally   guaranteed the payment obligations   of Burlington Resources LLC with respect to its publicly held debt securities.   Similarly, ConocoPhillips   has fully and unconditionally guaranteed the payment obligations of ConocoPhillips   Company with respect to its publicly held   debt securities.   In addition, ConocoPhillips Company has fully and unconditionally   guaranteed the payment obligations   of ConocoPhillips with respect to its publicly held debt securities.   All guarantees are joint and   several. The following tables present summarized   financial information for   the Obligor Group, as defined below: ● The Obligor Group will reflect guarantors   and issuers of guaranteed securities consisting   of ConocoPhillips, ConocoPhillips Company   and Burlington Resources LLC. ● Consolidating adjustments for elimination   of investments in and transactions   between the collective guarantors and issuers   of guaranteed securities are reflected   in the balances of the summarized financial information. ● Non-Obligated Subsidiaries are exclud   ed from this presentation. Upon completing the Concho acquisition on January 15, 2021, we assumed   Concho’s publicly traded   debt of approximately $3.9 billion in aggregate   principal amount, which was recorded   at the fair value of $4.7 billion on the acquisition date.   We completed a debt exchange   offer that settled   on February 8, 2021, of which 98 percent, or approximately $3.8 billion in   aggregate principal amount of Concho’s   notes, were tendered and accepted   for new debt issued by ConocoPhillips.   The new debt issued in the exchange is fully and   unconditionally guaranteed by ConocoPhillips Company.   Both the guarantor and issuer of the exchange   debt is reflected within the Obligor Group presented here. See Note 3 and Note 9 . Transactions   and balances reflecting activity between the Obligors   and Non-Obligated Subsidiaries   are presented separately below: Summarized Income Statement   Data Millions of Dollars 2021 Revenues and Other Income $ 30,457 Income (loss) before income taxes* 8,017 Net income (loss) 8,079 Net Income (Loss) Attributable   to ConocoPhillips 8,079 *Includes approximately $5.4 billion of purchased commodities expense for transactions with Non-Obligated Subsidiaries. Summarized Balance Sheet Data Millions of Dollars December 31, 2021 Current assets $ 7,689 Amounts due from Non-Obligated Subsidiaries, current 1,927 Noncurrent assets 69,841 Amounts due from Non-Obligated Subsidiaries, noncurrent 7,281 Current liabilities 8,005 Amounts due to Non-Obligated Subsidiaries,   current 3,477 Noncurrent liabilities 30,677 Amounts due to Non-Obligated Subsidiaries,   noncurrent 13,007 Capital Resources and Liquidity Table of Contents ConocoPhillips   2021 10-K 58 Contingencies We are subject to legal proceedings,   claims, and liabilities that arise in the ordinary course of business.   We accrue for losses associated with legal   claims when such losses are considered probable   and the amounts can be reasonably estimated.   See “Critical Accounting Estimates”   and Note 11 for information on contingencies. Legal and Tax   Matters We are subject to various   lawsuits and claims, including but not limited to matters   involving oil and gas royalty   and severance tax payments,   gas measurement and valuation   methods, contract disputes,   environmental damages, climate change, personal injury,   and property damage.   Our primary exposures for such matters   relate to alleged royalty and tax underpayments   on certain federal, state   and privately owned properties,   claims of alleged environmental contamination   and damages from historic operations,   and climate change.   We will continue to defend ourselves vigorously   in these matters. Our legal organization   applies its knowledge, experience, and professional   judgment to the specific characteristics of our cases, employing a litigation management   process to manage and monitor the legal   proceedings against us. Our process facilitates the   early evaluation and quantification   of potential exposures in individual cases.   This process also enables us to track those cases   that have been scheduled for trial and/or   mediation.   Based on professional judgment and experience   in using these litigation management   tools and available information   about current developments in all our cases,   our legal organization regularly   assesses the adequacy of current accruals and determines if an adjustment of existing   accruals, or establishment of new accruals, is   required. See Note 17 . Environmental We are subject to the same numerous   international, federal,   state, and local environmental   laws and regulations as other companies in our industry.   The most significant of these environmental   laws and regulations include, among others, the: ● U.S. Federal Clean Air Act, which governs   air emissions. ● U.S. Federal Clean Water   Act, which governs discharges   to water bodies. ● European Union Regulation for   Registration, Evaluation,   Authorization and Restriction of Chemicals (REACH). ● U.S. Federal Comprehensive   Environmental Response,   Compensation and Liability Act (CERCLA or Superfund), which imposes liability on generators,   transporters and arrangers   of hazardous substances at sites where hazardous substance   releases have occurred or are   threatening to occur. ● U.S. Federal Resource   Conservation and Recovery   Act (RCRA), which governs the treatment,   storage, and disposal of solid waste. ● U.S. Federal Oil Pollution Act   of 1990 (OPA90), under which   owners and operators   of onshore facilities and pipelines, lessees or permittees of an area in which an   offshore facility is located,   and owners and operators of vessels   are liable for removal costs   and damages that result from a discharge   of oil into navigable waters   of the U.S. ● U.S. Federal Emergency Planning   and Community Right-to-Know Act (EPCRA),   which requires facilities to report toxic chemical inventories   with local emergency planning committees   and response departments. ● U.S. Federal Safe Drinking   Water Act, which governs   the disposal of wastewater   in underground injection wells. ● U.S. Department of the Interior regulations,   which relate to offshore oil and   gas operations in U.S. waters and impose liability for the cost of pollution   cleanup resulting from operations, as   well as potential liability for pollution damages. ● European Union Trading   Directive resulting in European   Emissions Trading Scheme. Capital Resources and Liquidity Table of Contents 59 ConocoPhillips   2021 10-K These laws and their implementing regulations   set limits on emissions and, in the case of discharges   to water, establish water quality limits, and   establish standards and impose obligations   for the remediation of releases of hazardous substances   and hazardous wastes.   They also, in most cases, require permits   in association with new or modified operations.   These permits can require an applicant   to collect substantial information   in connection with the application process, which can be expensive   and time-consuming.   In addition, there can be delays associated with notice and comment periods and the agency’s   processing of the application.   Many of the delays associated with the permitting process are beyond   the control of the applicant. Many states and foreign   countries where we operate   also have or are developing, similar environmental   laws and regulations governing these same types of activities.   While similar,   in some cases these regulations may impose additional, or more stringent, requirements   that can add to the cost and difficulty   of marketing or transporting products across state   and international borders. The ultimate financial impact arising from environmental   laws and regulations is neither clearly known   nor easily determinable as new standards,   such as air emission standards and water   quality standards, continue to   evolve. However,   environmental laws   and regulations, including those that may   arise to address concerns about global climate change, are expected   to continue to have an   increasing impact on our operations in the U.S. and   in other countries in which we operate.   Notable areas of potential impacts include   air emission compliance and remediation obligations in the U.S.   and Canada. An example is the use of hydraulic   fracturing, an essential completion technique that   facilitates production   of oil and natural gas otherwise trapped   in lower permeability rock formations.   A range of local, state,   federal,   or national laws and regulations currently   govern hydraulic   fracturing operations, with hydraulic   fracturing currently prohibited in some jurisdictions.   Although hydraulic fracturing has   been conducted for many decades,   a number of new laws, regulations and permitting requirements   are under consideration by   various state environmental agencies, and others which could result   in increased costs, operating restrictions,   operational delays and/or   limit the ability to develop oil and natural   gas resources.   Governmental restrictions on hydraulic   fracturing could impact the overall profitability or viability   of certain of our oil and natural gas   investments.   We have adopted   operating principles that incorporate   established industry standards   designed to meet or exceed government   requirements. Our practices continually evolve   as technology improves and regulations   change. We also are subject to certain   laws and regulations relating to   environmental remediation   obligations associated with current and past operations.   Such laws and regulations include CERCLA and RCRA   and their state equivalents. Longer-term expenditures are   subject to considerable uncertainty   and may fluctuate significantly. We occasionally receive requests   for information or notices of potential   liability from the EPA   and state environmental agencies alleging   that we are a potentially responsible   party under CERCLA or an equivalent state statute.   On occasion, we also have been made a party to   cost recovery litigation by   those agencies or by private parties.   These requests, notices and lawsuits   assert potential liability for remediation   costs at various sites that typically are not owned by us, but allegedly contain   wastes attributable to   our past operations.   As of December 31, 2021, there were 15 sites around   the U.S. in which we were identified as a   potentially responsible party under CERCLA and comparable state   laws. Capital Resources and Liquidity Table of Contents ConocoPhillips   2021 10-K 60 For most Superfund sites, our potential   liability will be significantly less than the total   site remediation costs because the percentage of waste   attributable to us, versus   that attributable to all other potentially   responsible parties, is relatively low.   Although liability of those potentially responsible   is generally joint and several   for federal sites and frequently so for state   sites, other potentially responsible parties   at sites where we are a party typically have had the financial strength   to meet their obligations, and where they   have not, or where potentially responsible parties could not be located,   our share of liability has not increased materially.   Many of the sites at which we are potentially responsible   are still under investigation   by the EPA   or the state agencies concerned.   Prior to actual cleanup, those potentially responsible   normally assess site conditions, apportion responsibility   and determine the appropriate remediation.   In some instances, we may have   no liability or attain a settlement   of liability.   Actual cleanup costs generally occur after   the parties obtain EPA   or equivalent state agency approval. There are relatively few   sites where we are a major participant,   and given the timing and amounts of anticipated expenditures, neither the cost of remediation   at those sites nor such costs at   all CERCLA sites, in the aggregate, is expected to have a material   adverse effect on   our competitive or financial condition. Expensed environmental costs   were $632 million in 2021 and are expected   to be about $642 million and $700 million in 2022 and 2023, respectively.   Capitalized environmental   costs were $184 million in 2021 and are expected to be about $218 million and $316 million in   2022 and 2023, respectively. Accrued liabilities for remediation activities   are not reduced for potential recoveries   from insurers or other third parties and are not discounted (except   those assumed in a purchase business combination,   which we do record on a discounted basis). Many of these liabilities result from CERCLA, RCRA   ,   and similar state or international   laws that require us to undertake certain investigative   and remedial activities at sites where we conduct   or once conducted operations   or at sites where ConocoPhillips-generated   waste was disposed.   The accrual also includes a number of sites we identified that may require environmental   remediation but which are not currently   the subject of CERCLA, RCRA, or other agency enforcement activities.   The laws that require or address   environmental remediation   may apply retroactively and regardless   of fault, the legality of the original activities or the current   ownership or control of sites.   If applicable, we accrue receivables for probable   insurance or other third-party recoveries.   In the future, we may incur significant costs under both   CERCLA and RCRA. Remediation activities vary substantially   in duration and cost from site to   site, depending on the mix of unique site characteristics, evolving remediation   technologies, diverse regulatory   agencies and enforcement policies,   and the presence or absence of potentially liable third   parties.   Therefore, it is difficult to develop   reasonable estimates of future site remediation costs. At December 31, 2021, our balance sheet included total   accrued environmental costs   of $187 million, compared with $180 million at December 31, 2020, for remediation   activities in the U.S. and Canada.   We expect to incur a substantial amount of these expenditures   within the next 30 years. Notwithstanding any of the foregoing,   and as with other companies engaged in similar businesses,   environmental costs and liabilities are inherent   concerns in our operations and products,   and there can be no assurance that material costs and liabilities will not be incurred.   However,   we currently do not expect any material   adverse effect upon our results of operations or financial position   as a result of compliance with current environmental   laws and regulations. See Item 1A—Risk Factors – We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations and Note 11 for information on environmental litigatio   n. Capital Resources and Liquidity Table of Contents 61 ConocoPhillips   2021 10-K Climate Change Continuing political and social attention   to the issue of global climate change has resulted   in a broad range of proposed or promulgated   state, national and international   laws focusing on GHG reduction.   These proposed or promulgated laws apply   or could apply in countries where we have   interests or may have   interests in the future. Laws in this field continue to evolve,   and while it is not possible to accurately estimate   either a timetable for implementation or our future compliance costs   relating to implementation, such   laws, if enacted, could have a material impact on our results of operations   and financial condition.   Examples of legislation and precursors   for possible regulation that do or could affect   our operations include: ● European Emissions Trading   Scheme (ETS), the program through   which many of the EU member states are implementing the Kyoto Protocol.   Our cost of compliance with the EU ETS in 2021 was   approximately $19 million (net share before-tax   ). ● U.K. Emissions Trading   Scheme, the program with which the U.K. has   replaced the ETS.   Our cost of compliance with the U.K. ETS in 2021 was approximately   $2.8 million (net share before   -tax). ● The Alberta Technology   Innovation and Emissions Reduction   (TIER) regulation requires any   existing facility with emissions equal to or greater than 100,000 metric   tonnes of carbon dioxide, or equivalent,   per year to meet a facility benchmark intensity.   The total cost of these regulations in 2021 was   approximately $1 million (net share before-tax)   . ● The U.S. Supreme Court decision in Massachusetts   v. EPA,   549 U.S. 497, 127 S.Ct. 1438 (2007), confirmed that the EPA   has the authority to regulate carbon dioxide   as an “air pollutant” under the Federal Clean Air Act. ● The U.S. EPA’s   announcement on March 29, 2010 (published as “Interpretation   of Regulations that Determine Pollutants Covered   by Clean Air Act Permitting Programs,”   75 Fed. Reg. 17004 (April 2, 2010)), and the EPA’s   and U.S. Department of Transportation’s   joint promulgation of a Final Rule on April 1, 2010, that triggers regulation of GHGs under   the Clean Air Act, may trigger more climate-based   claims for damages, and may result in longer agency review   time for development projects. ● The U.S. EPA’s   announcement on January 14, 2015, outlining a series of steps   it plans to take to address methane and smog-forming volatile   organic compound emissions from the   oil and gas industry. ● The U.S. government has announced   on September 17, 2021 the Global Methane Pledge,   a global initiative to reduce global methane emissions   by at least 30 percent from 2020 levels   by 2030. ● Carbon taxes in certain jurisdictions.   Our cost of compliance with Norwegian carbon legislation   in 2021 were fees of approximately   $35 million (net share before   -tax).   We also incur a carbon tax for   emissions from fossil fuel combustion in our   British Columbia and Alberta operations in Canada,   totaling approximately $5.7 million (net   share before-tax). ● The agreement reached in Paris   in December 2015 at the 21 st Conference of the Parties to   the United Nations Framework Convention   on Climate Change, setting out a process   for achieving global emission reductions.   The new administration has recommitted   the United States to the Paris   Agreement, and a significant number of U.S. state   and local governments and major corporations   headquartered in the U.S. have also announced related commitments.   Accordingly,   the U.S. administration set   a new target on April 22, 2021 of a 50 to 52 percent reduction   in GHG emissions from 2005 levels in 2030. In the U.S., some additional form of regulation   may be forthcoming in the future at   the federal and state   levels with respect to GHG emissions.   Such regulation could take   any of several forms that   may result in the creation of additional costs in the form of taxes,   the restriction of output, investments   of capital to maintain compliance with laws and regulations, or required   acquisition or trading of emission allowances.   We are working to continuously improve operational and energy   efficiency through resource and   energy conservation throughout   our operations. Capital Resources and Liquidity Table of Contents ConocoPhillips   2021 10-K 62 Compliance with changes in laws and regulations   that create a GHG tax, emission trading   scheme or GHG reduction policies could significantly increase   our costs, reduce demand for fossil   energy derived products, impact the cost and availability of capital   and increase our exposure to litigation.   Such laws and regulations could also increase demand for less carbon intensive   energy sources, including natural   gas.   The ultimate impact on our financial performance, either positive or negative,   will depend on a number of factors, including but   not limited to: ● Whether and to what extent legislation   or regulation is enacted. ● The timing of the introduction of such legislation or   regulation. ● The nature of the legislation (such as a cap and trade   system or a tax on emissions)   or regulation. ● The price placed on GHG emissions (either by the market   or through a tax). ● The GHG reductions required. ● The price and availability of offsets. ● The amount and allocation of allowances. ● Technological   and scientific developments leading to new products   or services. ● Any potential significant physical   effects of climate change (such   as increased severe weather events, changes in sea levels and changes in temperature). ● Whether,   and the extent to which, increased compliance   costs are ultimately reflected   in the prices of our products and services. See Item 1A—Risk Factors – Existing and future laws, regulations and internal initiatives relating to global climate changes, such as limitations on GHG emissions may impact or limit our business plans, result in significant expenditures, promote alternative uses of energy or reduce demand for our products and Note 11 for information on climate change litigation. Company Response to Climate   -Related Risks The company has responded by putting   in place a Sustainable Development Risk Management   Standard covering the assessment and registration   of significant and high sustainable development   risks based on their consequence and likelihood of occurrence.   We have developed a   company-wide Climate Change Action   Plan with the goal of tracking mitigation activities for   each climate-related risk included in the corporate   Sustainable Development Risk Register. The risks addressed in our Climate Change Action   Plan fall into four broad   categories: ● GHG-related legislation and regulation. ● GHG emissions management. ● Physical climate-related   impacts. ● Climate-related disclosure   and reporting. Emissions are categorized   into three different   scopes.   Gross operated and net   equity Scope 1 and Scope 2 GHG emissions help us understand our climate   transition risk. ● Scope 1 emissions are direct GHG emissions from   sources that we control   or in which we have ownership interest. ● Scope 2 emissions are indirect GHG emissions   from the generation of purchased   electricity or steam that we consume. ● Scope 3 emissions are indirect emissions from   sources that we neither own nor control. Capital Resources and Liquidity Table of Contents 63 ConocoPhillips   2021 10-K We announced in October 2020 the adoption   of a Paris-aligned climate risk framework   with the objective of implementing a coherent set of choices designed   to facilitate the success   of our existing exploration   and production business through the energy transition.   Given the uncertainties remaining about   how the energy transition will evolve, the strategy   aims to be robust across a range   of potential future outcomes. The strategy is comprised of four   pillars: ● Targets   :   Our target framework   consists of a hierarchy   of targets, from a long-term ambition   that sets the direction and aim of the strategy,   to a medium-term performance target   for GHG emissions intensity,   to shorter-term targets for   flaring and methane intensity reductions.   These performance targets are supported by lower-level internal   business unit goals to enable the company to   achieve the company- wide targets.   In September 2021, we increased our interim   operational target and   have set it to reduce our gross operated and net   equity (scope 1 and 2) emissions intensity by   40 to 50 percent from 2016 levels by 2030, an improvement   from the previously announced target   of 35 to 45 percent on only a gross operated basis, with an ambition to   achieve net-zero operated   emissions by 2050.   We have joined the World Bank Flaring Initiative to   work towards zero   routine flaring of associated gas   by 2030, with an ambition to meet that goal by 2025. ● Technology choices:   We expanded our Marginal   Abatement Cost Curve process   to provide a broader range of opportunities for emission   reduction technology. ● Portfolio choices: Our corporate   authorization process requires   all qualifying projects to include a GHG price in their project approval economics.   Different GHG prices are used   depending on the region or jurisdiction.   Projects in jurisdictions with existing GHG pricing regimes   incorporate the existing   GHG price and forecast into   their economics.   Projects where no existing GHG pricing regime   exists utilize a scenario forecast from our internally   consistent World   Energy Model.   In this way,   both existing and emerging regulatory requirements are   considered in our decision-making.   The company does not use an estimated market cost of GHG emissions when assessing   reserves in jurisdictions without existing GHG regulations   . This is in contrast to changes   to the cost of existing GHG emission   regulations which can impact our reserves calculations. ● External engagement: Our external   engagement aims to differentiate   ConocoPhillips within the oil and gas sector with our approach to managing   climate-related risk.   We are a Founding Member of the Climate Leadership Council (CLC), an international   policy institute founded in collaboration   with business and environmental interests   to develop a carbon dividend plan.   Participation in the CLC provides   another opportunity for ongoing dialogue about carbon   pricing and framing the issues in alignment with our   public policy principles.   We also belong to and fund Americans For   Carbon Dividends, the education and advocacy branch of the CLC. Table of Contents ConocoPhillips   2021 10-K 64 Critical Accounting Estimates The preparation of financial statements   in conformity with GAAP requires   management to select appropriate accounting policies and to make   estimates and assumptions that   affect the reported amounts   of assets, liabilities, revenues and expenses. See Note 1 for descriptions of our major accounting policies.   Certain of these accounting policies involve judgments and uncertainties   to such an extent there is a reasonable   likelihood materially different amounts would have been reported   under different conditions,   or if different assumptions had been   used.   These critical accounting estimates are   discussed with the Audit and Finance Committee of the Board   of Directors at least annually.   We believe the following discussions   of critical accounting estimates address   all important accounting areas where the nature of accounting   estimates or assumptions is material   due to the levels of subjectivity and judgment necessary to account for   highly uncertain matters or   the susceptibility of such matters to   change. Oil and Gas Accounting Accounting for oil and gas activity   is subject to special accounting rules unique to the oil   and gas industry.   The acquisition of G&G seismic information, prior to   the discovery of proved reserves,   is expensed as incurred, similar to accounting for research   and development costs.   However,   leasehold acquisition costs and exploratory   well costs are capitalized   on the balance sheet pending determination of whether   proved oil and gas reserves   have been recognized. Property Acquisition Costs At year-end 2021, we held $9.3 billion   of net capitalized unproved   property costs which consisted   primarily of individually significant and pooled leaseholds, mineral   rights held in perpetuity by title ownership,   exploratory wells currently being drilled, and to a lesser   extent, suspended exploratory   wells and capitalized interest.   This amount increased by $6.9 billion at December 31, 2021 as compared   to December 31, 2020, primarily due to the Concho and Shell Permian acquisitions   in the Permian Basin where we have an ongoing   significant and active development program.   Outside of the Permian Basin, the remaining   $2.0 billion is concentrated   in 9 major development areas.   Management periodically assesses our unproved   property for impairment based on the results of exploration and   drilling efforts and the outlook for commercialization. For individually significant leaseholds, management   periodically assesses for impairment based   on exploration and drilling efforts to date.   For insignificant individual leasehold acquisition   costs, management exercises   judgment and determines a percentage probability   that the prospect ultimately will fail to   find proved oil and gas reserves, including estimates of future expirations,   and pools that leasehold information with others   in similar geographic areas.   For prospects in areas with limited, or   no, previous exploratory   drilling, the percentage probability of ultimate failure is normally judged   to be quite high.   This judgmental percentage is multiplied   by the leasehold acquisition cost, and that product is   divided by the contractual period of the leasehold to   determine a periodic leasehold impairment charge that is   reported in exploration expense.   This judgmental probability percentage   is reassessed and adjusted throughout   the contractual period of the leasehold based on favorable   or unfavorable exploratory activity on the leasehold or   on adjacent leaseholds, and leasehold impairment amortization   expense is adjusted prospectively. Exploratory Costs For exploratory wells, drilling   costs are temporarily capitalized,   or “suspended,”   on the balance sheet, pending a determination of whether potentially economic   oil and gas reserves have   been discovered by the drilling effort   to justify development. Table of Contents 65 ConocoPhillips   2021 10-K If exploratory wells encounter   potentially economic quantities of oil and gas,   the well costs remain capitalized   on the balance sheet as long as sufficient progress   assessing the reserves and the economic and operating   viability of the project is being made.   The accounting notion of “sufficient   progress” is a judgmental area,   but the accounting rules do prohibit continued capitalization   of suspended well costs on the expectation   future market conditions will improve or new technologies will be found   that would make the development   economically profitable.   Often, the ability to move into the development   phase and record proved   reserves is dependent on obtaining permits and government or co-venturer   approvals, the timing of which is ultimately   beyond our control.   Exploratory well costs remain suspended as long as we are actively pursuing   such approvals and permits, and believe they will be obtained.   Once all required approvals   and permits have been obtained, the projects   are moved into the development phase, and the oil and gas   reserves are designated as proved   reserves. At year-end 2021, total suspended   well costs were $660 million, compared   with $682 million at year-end 2020. For additional information on suspended   wells, including an aging analysis, see Note 6 . Proved Reserves Engineering estimates of the quantities of proved   reserves are inherently imprecise and   represent only approximate amounts because   of the judgments involved in developing   such information.   Reserve estimates are based on geological and engineering assessments of in-place   hydrocarbon volumes,   the production plan, historical extraction recovery and processing   yield factors, installed plant   operating capacity and approved   operating limits. The reliability of these estimates at   any point in time depends on both the quality and quantity   of the technical and economic data and the efficiency of extracting   and processing the hydrocarbons. Despite the inherent imprecision in   these engineering estimates, accounting   rules require disclosure of “proved” reserve estimates due to the importance   of these estimates to better   understand the perceived value   and future cash flows of a company’s   operations.   There are several authoritative   guidelines regarding the engineering criteria that must be met before estimated   reserves can be designated as “proved.”   Our geosciences and reservoir engineering organization has   policies and procedures in place consistent   with these authoritative guidelines.   We have trained and experienced   internal engineering personnel who estimate   our proved reserves held by consolidated companies, as well as our share   of equity affiliates.   See Oil and Gas supplemental disclosures for additional information. Proved reserve estimates are   adjusted annually in the fourth quarter   and during the year if significant changes occur, and   take into account   recent production and subsurface information   about each field.   Also, as required by current authoritative guidelines,   the estimated future date   when an asset will reach the end of its economic life is based on 12-month average prices   and current costs.   This date estimates when production   will end and affects the amount of estimated reserves.   Therefore, as prices and cost   levels change from year to year,   the estimate of proved reserves also changes.   Generally, our   proved reserves decrease as prices   decline and increase as prices rise. Our proved reserves include estimat   ed quantities related to PSCs, reported   under the “economic interest” method, as well as variable-royalty   regimes, and are subject to fluctuations   in commodity prices; recoverable operating expenses; and capital   costs.   If costs remain stable, reserve quantities   attributable to recovery of costs will change inversely to changes   in commodity prices.   We would expect reserves   from these contracts to   decrease when product prices rise and increase when prices decline. The estimation of proved reserves   is also important to the income statement   because the proved reserve estimate for a field serves as the denominator in the unit-of-production   calculation of the DD&A of the capitalized costs for that asset.   At year-end 2021, the net book value of productive   PP&E subject to a unit-of-production   calculation was approximately $52 billion   and the DD&A recorded on these assets in   2021 was approximately $7.0 billion.   The estimated proved reserves   for our consolidated operations   were 2.5 billion BOE at the end of 2020 and 4.0 billion BOE at the end of 2021.   If the estimates of proved reserves   used in the unit-of-production   calculations had been lower by 10 percent across all calculations,   before-tax DD&A in 2021 would have   increased by an estimated $774 million. Table of Contents ConocoPhillips   2021 10-K 66 Business Combination—Valuation   of Oil and Gas Properties For recent transactions, management   applied the principles of acquisition accounting under FASB   ASC Topic 805   – “Business Combinations” and allocated the purchase   price to assets acquired and liabilities assumed, based   on their estimated fair values as   of the acquisition date.   Estimating the fair values involved   making various assumptions, of which the most significant assumptions   relate to the fair values assigned   to proved and unproved oil and gas properties.   Management utilized a discounted   cash flow approach, based on market participant assumptions, and engaged third party   valuation experts in preparing fair value   estimates. Significant inputs incorporated   within the valuation include future commodity price assumptions   and production profiles of reserve estimates, the   pace of drilling plans, future operating and development   costs, inflation rates, and discount rates using a market   -based weighted average   cost of capital determined at the   time of the acquisition.   When estimating the fair value of unproved   properties, additional risk-weighting   adjustments are applied to probable and possible reserves. The assumptions and inputs incorporated   within the fair value estimates are   subject to considerable management judgement and are based on industry,   market, and economic conditions prevalent   at the time of the acquisition. Although we based these estimates on assumptions   believed to be reasonable, these estimates   are inherently unpredictable and uncertain and actual results   could differ. See Note 3 . Impairments Long-lived assets used in operations   are assessed for impairment whenever changes   in facts and circumstances indicate a possible significant deterioration   in the future cash flows expected   to be generated by an   asset group.   If there is an indication the carrying amount   of an asset may not be recovered,   a recoverability test   is performed using management’s assumptions   for prices, volumes and future development   plans.   If the sum of the undiscounted cash flows before   income-taxes is less than   the carrying value of the asset group, the carrying   value is written down to estimated fair   value and reported as an impairment   in the periods in which the determination is made.   Individual assets are grouped for   impairment purposes at the lowest level for   which there are identifiable cash flows that are largely independent   of the cash flows of other groups of assets—generally   on a field-by-field basis for E&P assets.   Because there usually is a lack of quoted market   prices for long-lived assets, the fair   value of impaired assets is typically determined based   on the present values of expected   future cash flows using discount rates and prices believed to   be consistent with those used by principal   market participants, or based on a multiple of operating cash flow validated   with historical market transactions   of similar assets where possible. The expected future cash flows used   for impairment reviews and   related fair value calculations   are based on estimated future production volumes,   commodity prices, operating costs   and capital decisions, considering all available evidence at the date of review.   Differing assumptions could   affect the timing and the amount of an impairment in any period. See Note 6 and Note 7 . Investments in nonconsolidated   entities accounted for under the equity   method are assessed for impairment whenever changes in the facts and circumstances   indicate a loss in value has occurred.   Such evidence of a loss in value might include our inability to recover   the carrying amount, the lack of sustained earnings   capacity which would justify the current investment   amount, or a current fair value   less than the investment’s   carrying amount. When such a condition is judgmentally determined   to be other than temporary,   an impairment charge is recognized for the difference   between the investment’s   carrying value and its estimated fair   value.   When determining whether a decline in value is other than   temporary,   management considers factors   such as the length of time and extent of the decline, the investee’s   financial condition and near-term prospects,   and our ability and intention to retain our   investment for a period that   will be sufficient to allow for any   anticipated recovery in the market value of the investment.   Since quoted market prices are usually   not available, the fair value is typically based on the present value of expected future   cash flows using discount   rates and prices believed to be consistent with those used by principal market participants,   plus market analysis of comparable   assets owned by the investee, if appropriate.   Differing assumptions could affect   the timing and the amount of an impairment of an investment in any period.   See the “APLNG” section   of Note 4 . Table of Contents 67 ConocoPhillips   2021 10-K Asset Retirement Obligations   and Environmental Costs Under various contracts, permits   and regulations, we have material   legal obligations to remove   tangible equipment and restore the land or   seabed at the end of operations at operational   sites.   Our largest asset removal obligations involve   plugging and abandonment of wells, removal and disposal   of offshore oil and gas platforms around the world, as well as oil and gas   production facilities and pipelines in Alaska.   Fair value is estimated using   a present value approach,   incorporating assumptions about estimated   amounts and timing of settlements and impacts of the use of technologies.   Estimating future asset removal   costs requires significant   judgement.   Most of these removal obligations are   many years, or decades,   in the future and the contracts and regulations   often have vague descriptions of what removal   practices and criteria must be met when the removal   event actually occurs. The carrying value of our asset retirement   obligation estimate is sensitive   to inputs such as asset removal technologies and costs, regulatory   and other compliance considerations,   expenditure timing, and other inputs into valuation of the obligation,   including discount and inflation rates,   which are all subject to change between the time of initial recognition of the liability and future settlement   of our obligation. Normally, changes   in asset removal obligations   are reflected in the income statement   as increases or decreases to DD&A over the remaining life of the assets.   However,   for assets at or nearing the end of their operations,   as well as previously sold assets for which we retained   the asset removal obligation,   an increase in the asset removal obligation can result in an immediate charge   to earnings, because any increase   in PP&E due to the increased obligation would immediately   be subject to impairment, due to the low fair value   of these properties. In addition to asset removal obligations,   under the above or similar contracts, permits   and regulations, we have certain environmental-related   projects.   These are primarily related to remediation   activities required by Canada and various states within the U.S.   at exploration and production   sites.   Future environmental remediation   costs are difficult to estimate because they   are subject to change due to such factors   as the uncertain magnitude of cleanup costs, the unknown time and extent of such   remedial actions that may be required,   and the determination of our liability in proportion to that of other responsible   parties. See Note 8 . Projected Benefit Obligations The actuarial determination of projected benefit   obligations and company   contribution requirements involves judgment about uncertain future events,   including estimated retirement   dates, salary levels at retirement, mortality rates, lump-sum election rates,   rates of return on plan assets,   future health care cost-trend rates,   and rates of utilization of health   care services by retirees.   Due to the specialized nature of these   calculations, we engage outside actuarial firms to assist   in the determination of these projected benefit   obligations and company contribution requirements.   Ultimately,   we will be required to fund all vested   benefits under pension and postretirement benefit plans   not funded by plan assets or investment   returns, but the judgmental assumptions used in the actuarial calculations significantly affect   periodic financial statements and   funding patterns over time. Projected benefit obligations   are particularly sensitive to the discount   rate assumption.   A 100 basis-point decrease in the discount rate assumption   would increase projected benefit obligations   by $1.0 billion.   Benefit expense is sensitive to the discount rate   and return on plan assets assumptions.   A 100 basis-point decrease in the discount rate assumption would increase   annual benefit expense by $70 million, while a 100 basis-point   decrease in the return on plan assets assumption would increase   annual benefit expense by $60 million.   In determining the discount rate, we use yields   on high-quality fixed income investments   matched to the estimated benefit   cash flows of our plans.   We are also exposed to the possibility   that lump sum retirement benefits taken   from pension plans during the year could exceed the   total of service and interest components   of annual pension expense and trigger accelerated recognition   of a portion of unrecognized net actuarial   losses and gains.   These benefit payments are based on decisions by plan   participants and are therefore difficult   to predict.   In the event there is a significant reduction in the expected years   of future service of present employees or the elimination   of the accrual of defined benefits for some or all of their future   services for a significant number of employees,   we could recognize a curtailment gain   or loss. See Note 16 . Table of Contents ConocoPhillips   2021 10-K 68 Contingencies A number of claims and lawsuits are made against   the company arising in the ordinary course   of business. Management exercises   judgment related to accounting   and disclosure of these claims which includes losses, damages, and underpayments associated   with environmental remediation,   tax, contracts, and   other legal disputes. As we learn new facts concerning contingencies,   we reassess our position both with respect to amounts recognized and disclosed considering changes   to the probability of additional losses and potential   exposure. However,   actual losses can and do vary from estimates   for a variety of reasons   including legal, arbitration, or other third-party decisions; settlement discussions;   evaluation of scope of damages; interpretation   of regulatory or contractual terms; expected   timing of future actions; and proportion of liability   shared with other responsible parties.   Estimated future costs related   to contingencies are subject to   change as events evolve and as additional information becomes available   during the administrative and litigation   processes.   For additional information on contingent liabilities, see the “Contingencies”   section within “Capital Resources and   Liquidity” and Note 11 . Income Taxes We are subject to income taxation   in numerous jurisdictions worldwide.   We record deferred   tax assets and liabilities to account for the expected   future tax consequences of events   that have been recognized   in our financial statements and our tax   returns.   We routinely assess our deferred   tax assets and reduce such assets   by a valuation allowance if we deem it is more likely than   not that some portion,   or all, of the deferred tax assets   will not be realized.   In assessing the need for adjustments   to existing valuation allowances,   we consider all available positive and negative evidence.   Positive evidence includes reversals   of temporary differences,   forecasts of future taxable income, assessment of future business assumptions   and applicable tax planning strategies   that are prudent and feasible.   Negative evidence includes losses   in recent years as well as the forecasts   of future net income (loss) in the realizable period.   In making our assessment regarding   valuation allowances, we weight   the evidence based on objectivity.   Numerous judgments and assumptions are   inherent in the determination of future taxable   income, including factors such as future operating   conditions and the assessment of the effects   of foreign taxes   on our U.S. federal income taxes   (particularly as related to prevai   ling oil and gas prices). See Note 17 . We regularly assess and, if required,   establish accruals for uncertain tax   positions that could result from assessments of additional tax by taxing   jurisdictions in countries where we operate.   We recognize a tax   benefit from an uncertain tax position when it   is more likely than not that the   position will be sustained upon examination, based on the technical merits of the position.   These accruals for uncertain tax positions   are subject to a significant amount of judgment and are reviewed   and adjusted on a periodic basis in light of changing facts   and circumstances considering the progress   of ongoing tax audits, court proceedings,   changes in applicable tax laws, including tax case rulings and legislative guidance,   or expiration of the applicable statute   of limitations. See Note 17 regarding discussion of critical accounting   estimates on deferred   tax valuation allowances. Table of Contents 69 ConocoPhillips   2021 10-K Cautionary Statement for the Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act   of 1995 This report includes forward-looking statements   within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.   All statements other than   statements of historical   fact included or incorporated by   reference in this report, including, without   limitation, statements   regarding our future financial position, business strategy,   budgets, projected revenues,   projected costs and plans, objectives   of management for future operatio   ns and the anticipated impact of the Shell Enterprise   LLC (Shell) transaction on the company’s business   and future financial and operating results are   forward-looking statements.   Examples of forward-looking statements   contained in this report include our expected   production growth and outlook   on the business environment generally,   our expected capital budget and   capital expenditures, and discussions   concerning future dividends.   You can often identify   our forward-looking statements   by the words “anticipate,”   “believe,” “budget,”   “continue,”   “could,”   “effort,”   “estimate,”   “expect,”   “forecast,”   “intend,”   “goal,”   “guidance,”   “may,” “objective,”   “outlook,”   “plan,” “potential,”   “predict,” “projection,”   “seek,”   “should,”   “target,”   “will,” “would” and similar expressions. We based the forward-looking   statements on our current   expectations, estimates and   projections about ourselves and the industries in which we operate in   general.   We caution you these   statements are not guarantees   of future performance as they involve   assumptions that, while made in good faith, may   prove to be incorrect, and involve risks and uncertainties we cannot predict.   In addition, we based many of these forward   -looking statements on assumptions about future events   that may prove to be inaccurate.   Accordingly,   our actual outcomes and results may differ materially from   what we have expressed   or forecast in the forward   -looking statements.   Any differences could result from a variety of factors   and uncertainties, including, but not limited to,   the following: ● The impact of public health crises, including pandemics (such as COVID   -19) and epidemics and any related company or government policies   or actions. ● Global and regional changes in the demand, supply,   prices, differentials or other market   conditions affecting oil and gas, including changes   resulting from a public health crisis or from the imposition   or lifting of crude oil production quotas or other actions   that might be imposed by OPEC and other producing countries and the resulting company   or third-party actions in response to such changes. ● Fluctuations in crude oil, bitumen, natural gas,   LNG and NGLs prices, including a prolonged decline in these prices relative to historical   or future expected levels. ● The impact of significant declines in prices for crude   oil, bitumen, natural gas, LNG and   NGLs, which may result in recognition of impairment charges   on our long-lived assets, leaseholds and nonconsolidated equity investments. ● The potential for insufficient liquidity   or other factors, such as those described   herein, that could impact our ability to repurchase shares and   declare and pay dividends, whether fixed   or variable. ● Potential failures or delays   in achieving expected reserve or production   levels from existing and future oil and gas developments, including due to   operating hazards, drilling risks   and the inherent uncertainties in predicting reserves and reservoir performance. ● Reductions in reserves replacement rates,   whether as a result of the significant declines in commodity prices or otherwise. ● Unsuccessful exploratory drilling   activities or the inability to obtain access to exploratory   acreage. ● Unexpected changes in costs or technical   requirements for constructing,   modifying or operating E&P facilities. ● Legislative and regulatory initiatives   addressing environmental concerns,   including initiatives addressing the impact of global climate change or further regulating   hydraulic fracturing, methane   emissions, flaring or water disposal. ● Lack of, or disruptions   in, adequate and reliable transportation   for our crude oil, bitumen, natural gas, LNG and NGLs. ● Inability to timely obtain or maintain   permits, including those necessary for construction, drilling   and/or development, or inability to make   capital expenditures required   to maintain compliance with any necessary permits or applicable laws or regulations. Table of Contents ConocoPhillips   2021 10-K 70 ● Failure to complete definitive   agreements and feasibility studies   for,   and to complete construction of, announced and future E&P and LNG development in a timely   manner (if at all) or on budget. ● Potential disruption or interruption   of our operations due to accidents, extraordinary   weather events, supply chain disruptions, civil unrest, political   events, war,   terrorism, cyber attacks, and   information technology failures, constraints   or disruptions. ● Changes in international monetary   conditions and foreign currency exchange   rate fluctuations. ● Changes in international trade relationships,   including the imposition of trade restrictions or   tariffs relating to crude oil, bitumen, natural   gas, LNG, NGLs and any materials or products   (such as aluminum and steel) used in the operation of our business. ● Substantial investment   in and development use of, competing   or alternative energy sources, including   as a result of existing or future environmental   rules and regulations. ● Liability for remedial actions, including removal   and reclamation obligations,   under existing and future environmental regulations   and litigation. ● Significant operational or investment   changes imposed by existing or future   environmental statutes   and regulations, including international   agreements and national or regional legislation   and regulatory measures to limit or reduce GHG emissions. ● Liability resulting from litigation,   including litigation directly or indirectly   related to the transaction   with Concho Resources Inc., or our failure   to comply with applicable laws and regulations. ● General domestic and international   economic and political developments, including armed   hostilities; expropriation of assets; changes in governmental   policies relating to crude oil, bitumen, natural   gas, LNG and NGLs pricing; regulation or taxation;   and other political, economic or diplomatic developments. ● Volatility in the commodity futures   markets. ● Changes in tax and other laws, regulations   (including alternative energy mandates),   or royalty rules applicable to our business. ● Competition and consolidation in the oil and gas   E&P industry. ● Any limitations on our access to capital   or increase in our cost of capital, including   as a result of illiquidity or uncertainty in domestic or international   financial markets or investment   sentiment. ● Our inability to execute, or delays   in the completion, of any asset dispositions or acquisitions   we elect to pursue. ● Potential failure to obtain,   or delays in obtaining, any necessary   regulatory approvals for   pending or future asset dispositions or acquisitions, or that such   approvals may require modification   to the terms of the transactions or the operation   of our remaining business. ● Potential disruption of our operations   as a result of pending or future asset dispositions or acquisitions, including the diversion of management time and   attention. ● Our inability to deploy the net proceeds from any   asset dispositions that are pending or that we elect   to undertake in the future in the manner   and timeframe we currently   anticipate, if at all. ● The operation and financing of our joint ventures. ● The ability of our customers and other contractual   counterparties to satisfy their obligations   to us, including our ability to collect payments   when due from the government of Venezuela   or PDVSA. ● Our inability to realize anticipated   cost savings and capital expenditure   reductions. ● The inadequacy of storage capacity   for our products, and ensuing curtailments,   whether voluntary or involuntary,   required to mitigate this physical   constraint. ● The risk that we will be unable to retain   and hire key personnel. ● Unanticipated integration   issues relating to the acquisition of assets from   Shell, such as potential disruptions of our ongoing business and higher than anticipated   integration costs. ● Uncertainty as to the long-term value of our   common stock. ● The diversion of management time on integration   -related matters. ● The factors generally described   in Item 1A—Risk Factors in this 2021 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC. 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