# APA Corp (APA) FY 2021 MD&A

Verbatim Item 7 Management's Discussion and Analysis from APA Corp's 10-K for fiscal year 2021.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1841666/000178403122000009/apa-20211231.htm
Accession: 0001784031-22-000009
Filing date: 2022-02-22
Report date: 2021-12-31
Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary.
Confidence: high

Company profile: /company/APA/
All MD&A years: /company/APA/mda/
Next year: /company/APA/mda/fy2022/ (FY 2022)

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together in conjunction with the Company’s Consolidated Financial Statements and accompanying notes included in Part IV, Item 15 of this Annual Report on Form 10-K, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Annual Report on Form 10-K. This section of this Annual Report on Form 10-K generally discusses 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are not included in this Annual Report on Form 10-K are incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020 (filed with the SEC on February 25, 2021).

On January 4, 2021, Apache Corporation announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, Apache Corporation became a direct, wholly owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares were automatically converted into equivalent corresponding shares of APA Corporation. Pursuant to the Holding Company Reorganization, APA Corporation became the successor issuer to Apache Corporation pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache Corporation as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the Company’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have subsidiaries operating around the globe.

Overview

APA is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids (NGLs). The Company’s upstream business currently has exploration and production operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active exploration and appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. The Company’s midstream business (Altus Midstream) is operated by Altus Midstream Company (Nasdaq: ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas.

APA believes energy underpins global progress, and the Company wants to be a part of the conversation and solution as society works to meet growing global demand for reliable and affordable energy. Today, the world faces a dual challenge: To meet growing demand for energy and to do so in a cleaner, more sustainable way. APA believes society can accomplish both and strives to meet those challenges while creating value for all its stakeholders.

The global economy and the energy industry have been deeply impacted by the effects of the coronavirus disease 2019 (COVID-19) pandemic and related governmental actions. Uncertainties in the commodity and financial markets since early 2020 continue to impact oil supply and demand. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of ongoing exploration and appraisal activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its stakeholders. The Company continues to aggressively manage its cost structure regardless of the oil price environment and closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process. For additional detail on the Company’s forward capital investment outlook, refer to “Capital and Operational Outlook” below.

During 2021, the Company reported net income attributable to common stock of $973 million, or $2.59 per diluted share, compared to a net loss of $4.9 billion, or $12.86 per diluted share, in 2020. Net income in 2021 benefited from significantly improved commodity prices that had collapsed in the prior year when the COVID-19 pandemic negatively affected economic activity and the oil markets. In 2020, the Company recorded impairments totaling $4.5 billion in connection with fair value assessments stemming from the global crude oil price collapse.

The Company generated $3.5 billion of cash from operating activities in 2021, which was $2.1 billion or 152 percent higher than the prior year. APA’s higher operating cash flows for 2021 were driven by higher crude oil and natural gas prices and associated revenues. The Company ended the year with a cash balance of $302 million, up $40 million from year-end 2020, after paying back nearly $1.4 billion of debt during 2021 in an effort to reduce near-term debt maturities and strengthening its balance sheet.

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Following this progress and considering the ongoing constructive price environment, the Company initiated a capital return framework for our shareholders, as follows:

•The Company implemented a capital return framework during 2021 for equity holders to participate more directly and materially in cash returns. The Company believes returning 60 percent of cash flow over capital investment creates a good balance for providing near-term cash returns to shareholders while still recognizing the importance of longer-term balance sheet strengthening.

•The Company announced a quarterly dividend increase in the third quarter of 2021 from $0.025 per share to $0.0625 per share and, in the fourth quarter of 2021, announced a further increase to $0.125 per share.

•During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. The Company repurchased approximately 31.2 million of its common shares for $847 million during the fourth quarter of 2021. As of December 31, 2021, the Company had remaining authorization to repurchase up to 48.8 million shares under Company’s share repurchase programs.

Operational Highlights

Key operational highlights for the year include:

United States

•Daily boe production from the Company’s U.S. assets, which decreased 10 percent from the prior year end, accounted for 59 percent of its total worldwide production during 2021. After halting all drilling and completion activity for most of 2020, in response to completion cost reductions, the Company reinstated two operated completion crews in the Permian Basin in late 2020 to begin completing its backlog of drilled but uncompleted well inventory. In early 2021, the Company re-activated one drilling rig in the Permian Basin and one rig in the Austin Chalk. A second rig was added in the Permian Basin in late June 2021. For 2022, the Company will continue to budget its capital program at levels to fund activity necessary to offset inherent declines in production and proved oil and natural gas reserves.

•On October 11, 2021, the Company announced that it has ended routine flaring in its U.S. onshore operations, achieving one of its announced 2021 environmental, social and governance (ESG) goals three months ahead of schedule. The Company also seeks continuous improvement on its safety performance and protocols, having established key safety indicators and metrics that are rigorously managed and that impact annual incentive compensation Company-wide.

•On October 21, 2021, ALTM announced that it will combine with privately owned BCP Raptor Holdco LP (BCP) in an all-stock transaction. As consideration for the transaction, ALTM will issue 50 million shares of Class C Common Stock (and its subsidiary, Altus Midstream LP, will issue a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. Upon closing of the transaction, APA will own approximately 20 percent of the issued and outstanding common stock of the combined entity. The transaction is expected to close during the first quarter of 2022 following completion of customary closing conditions.

International

•In December 2021, the Egyptian President signed and ratified the previously announced agreement with the Egyptian Ministry of Petroleum and the Egyptian General Petroleum Corporation (EGPC) to modernize the terms of the majority of the Company’s production-sharing contracts (PSCs), having an effective date of April 1, 2021. The new PSC consolidates 98 percent of gross acreage and 90 percent of gross production into a single concession and refreshes the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool that provides improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit-sharing rate of 30 percent for all the Company’s production covered under the new concession. The changes also simplify the contractual relationship with EGPC, facilitate recovery of prior investment, and update day-to-day operational governance. The Apache entity that is the sole contractor is owned two-thirds by Apache and one-third by Sinopec International Petroleum Exploration and Production Corporation (Sinopec).

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•Egypt gross equivalent production decreased 14 percent and net production decreased 6 percent from 2020, primarily a result of natural decline given reduced drilling activity in the past year. The modernized production-sharing agreement did not impact 2021 production since it was ratified at the end of the year. The Company continues to build and enhance its robust drilling inventory in Egypt, supplemented with recent seismic acquisitions and new play concept evaluations, on both new and existing acreage. The Company anticipates increased drilling and workover activity in 2022 as a result of the ratification of the new modernized PSC.

•The North Sea maintained two drilling rigs during 2021. During the year, production was significantly impacted by compressor downtime, extended platform turnaround work, and third-party pipeline outages.

•Following three successful exploration discoveries offshore Suriname on Block 58, in late 2020, the Company commenced drilling a fourth exploration well in the block at the Keskesi prospect. In January 2021, the Company and its partner TotalEnergies (formerly Total S.A.) announced a discovery that confirmed oil in the eastern portion of the block. The Company has subsequently transferred operatorship of Block 58 to TotalEnergies, with exploration and appraisal activities continuing to progress. TotalEnergies holds a 50 percent working interest in Block 58.

•In November 2021, the Company announced a successful flow test and pressure buildup at its Sapakara South appraisal well on Block 58, which continues to improve in outlook as additional information is gathered and processed. Further, in February 2022 the Company and TotalEnergies announced an oil discovery at the Krabdagu-1 (KBD-1) exploration well. KBD-1 is located approximately 18 kilometers southeast of the Sapakara South-1 well. The well was designed to test multiple stacked targets in Maastrichtian and Campanian intervals and encountered approximately 90 meters (295 feet) of net oil pay.

For a more detailed discussion related to the Company’s various geographic segments, refer to “Upstream Exploration and Production Properties—Operating Areas” set forth in Part I, Item 1 and 2 of this Annual Report on Form 10-K.

Acquisition and Divestiture Activity

Over the Company’s history, it has repeatedly demonstrated the ability to capitalize quickly and decisively on changes in its industry and economic conditions. A key component of this strategy is to continuously review and optimize APA’s portfolio of assets in response to these changes. Most recently, the Company has completed a series of divestitures designed to monetize nonstrategic assets and enhance the Company’s portfolio in order to allocate resources to more impactful exploration and development opportunities. These divestitures include:

•Permian Basin Divestiture In the second quarter of 2021, the Company completed the sale of certain non-core assets in the Central Basin Platform of the Permian Basin for total cash proceeds of $176 million and the assumption of asset retirement obligations of $44 million.

•U.S. Leasehold Divestitures & Acquisitions During 2021, the Company completed the sale of other non-core assets and leasehold acreage, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $80 million. Also during 2021, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $9 million.

•U.S. Leasehold Divestitures & Other During 2020, the Company completed the sale of certain non-core producing assets and leasehold acreage, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $87 million. The Company also completed certain leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $4 million.

•Suriname Joint Venture Agreement In December 2019, the Company entered into a joint venture agreement with TotalEnergies to explore and develop Block 58 offshore Suriname. Under the terms of the agreement, the Company and TotalEnergies each hold a 50 percent working interest in Block 58. The Company operated the drilling of the first four wells and subsequently transferred operatorship of Block 58 to TotalEnergies. In connection with the agreement, the Company received $100 million upon closing in the fourth quarter of 2019 and $79 million upon satisfying certain closing conditions in the first quarter of 2020 for reimbursement of 50 percent of all costs incurred on Block 58 as of December 31, 2019. Key terms of the agreement provide for TotalEnergies to pay a proportionately larger share of appraisal and development costs, which would be recoverable through hydrocarbon participation.

For detailed information regarding APA’s acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

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Results of Operations

Oil and Gas Production Revenues

The Company’s oil and gas production revenues and respective contribution to total revenues by country are as follows:

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2021","","2020","","2019"],["","","$ Value","","% Contribution","","$ Value","","% Contribution","","$ Value","","% Contribution"],["","","($ in millions)"],["Oil Revenues:"],["United States","","$","1,850","","","40","%","","$","1,209","","","39","%","","$","2,098","","","40","%"],["Egypt(1)","","1,806","","","40","%","","1,102","","","35","%","","1,969","","","38","%"],["North Sea","","929","","","20","%","","795","","","26","%","","1,163","","","22","%"],["Total(1)","","$","4,585","","","100","%","","$","3,106","","","100","%","","$","5,230","","","100","%"],["Natural Gas Revenues:"],["United States","","$","754","","","62","%","","$","251","","","42","%","","$","293","","","43","%"],["Egypt(1)","","270","","","23","%","","280","","","47","%","","295","","","44","%"],["North Sea","","183","","","15","%","","67","","","11","%","","90","","","13","%"],["Total(1)","","$","1,207","","","100","%","","$","598","","","100","%","","$","678","","","100","%"],["NGL Revenues:"],["United States","","$","673","","","95","%","","$","304","","","91","%","","$","372","","","91","%"],["Egypt(1)","","9","","","1","%","","8","","","3","%","","12","","","3","%"],["North Sea","","24","","","4","%","","21","","","6","%","","23","","","6","%"],["Total(1)","","$","706","","","100","%","","$","333","","","100","%","","$","407","","","100","%"],["Oil and Gas Revenues:"],["United States","","$","3,277","","","50","%","","$","1,764","","","44","%","","$","2,763","","","44","%"],["Egypt(1)","","2,085","","","32","%","","1,390","","","34","%","","2,276","","","36","%"],["North Sea","","1,136","","","18","%","","883","","","22","%","","1,276","","","20","%"],["Total(1)","","$","6,498","","","100","%","","$","4,037","","","100","%","","$","6,315","","","100","%"]]
[[/GREPCENT_TABLE]]

(1)Includes revenues attributable to a noncontrolling interest in Egypt.

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Production

The following table presents production volumes by country:

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2021","","Increase (Decrease)","","2020","","Increase (Decrease)","","2019"],["Oil Volumes \u2013 b/d:"],["United States(5)","","75,205","","","(15)%","","88,249","","","(16)%","","105,051"],["Egypt(3)(4)","","70,349","","","(7)%","","75,384","","","(11)%","","84,617"],["North Sea","","36,265","","","(28)%","","50,386","","","1%","","49,746"],["Total","","181,819","","","(15)%","","214,019","","","(11)%","","239,414"],["Natural Gas Volumes \u2013 Mcf/d:"],["United States(5)","","527,461","","","(6)%","","561,731","","","(12)%","","639,580"],["Egypt(3)(4)","","263,653","","","(4)%","","274,175","","","(4)%","","285,972"],["North Sea","","38,565","","","(33)%","","57,464","","","5%","","54,642"],["Total","","829,679","","","(7)%","","893,370","","","(9)%","","980,194"],["NGL Volumes \u2013 b/d:"],["United States(5)","","66,232","","","(11)%","","74,136","","","8%","","68,381"],["Egypt(3)(4)","","531","","","(30)%","","754","","","(19)%","","931"],["North Sea","","1,199","","","(38)%","","1,936","","","11%","","1,739"],["Total","","67,962","","","(12)%","","76,826","","","8%","","71,051"],["BOE per day:(1)"],["United States(5)","","229,348","","","(10)%","","256,007","","","(9)%","","280,029"],["Egypt(3)(4)","","114,821","","","(6)%","","121,834","","","(9)%","","133,209"],["North Sea(2)","","43,892","","","(29)%","","61,899","","","2%","","60,592"],["Total","","388,061","","","(12)%","","439,740","","","(7)%","","473,830"]]
[[/GREPCENT_TABLE]]

(1)The table shows production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the price ratio between the two products.

(2)Average sales volumes from the North Sea were 44,179 boe/d, 62,157 boe/d, and 59,797 boe/d for 2021, 2020, and 2019, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

(3)Gross oil, natural gas, and NGL production in Egypt were as follows:

[[GREPCENT_TABLE]]
[["","","2021","","","","2020","","","","2019"],["Oil (b/d)","","134,711","","","","","164,104","","","","","193,886"],["Natural Gas (Mcf/d)","","586,663","","","","","641,069","","","","","708,682"],["NGL (b/d)","","854","","","","","1,429","","","","","1,722"]]
[[/GREPCENT_TABLE]]

(4)Includes net production volumes per day attributable to a noncontrolling interest in Egypt of:

[[GREPCENT_TABLE]]
[["","","2021","","","","2020","","","","2019"],["Oil (b/d)","","23,504","","","","","25,206","","","","","28,220"],["Natural Gas (Mcf/d)","","88,409","","","","","91,540","","","","","95,539"],["NGL (b/d)","","177","","","","","251","","","","","310"]]
[[/GREPCENT_TABLE]]

(5)Production volumes per day in the Company’s Alpine High field were as follows:

[[GREPCENT_TABLE]]
[["","","2021","","","","2020","","","","2019"],["Oil (b/d)","","1,485","","","","","2,718","","","","","3,475"],["Natural Gas (Mcf/d)","","258,096","","","","","274,279","","","","","316,169"],["NGL (b/d)","","22,950","","","","","24,942","","","","","17,446"]]
[[/GREPCENT_TABLE]]

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Pricing

The following table presents pricing information by country:

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2021","","Increase (Decrease)","","2020","","Increase (Decrease)","","2019"],["Average Oil Price - Per barrel:"],["United States","","$","67.37","","","80%","","$","37.42","","","(32)%","","$","54.71"],["Egypt","","70.33","","","76%","","39.95","","","(37)%","","63.76"],["North Sea","","69.67","","","62%","","42.88","","","(34)%","","65.10"],["Total","","68.97","","","74%","","39.60","","","(34)%","","60.05"],["Average Natural Gas Price - Per Mcf:"],["United States","","$","3.92","","","221%","","$","1.22","","","(3)%","","$","1.26"],["Egypt","","2.81","","","1%","","2.79","","","(1)","","2.83"],["North Sea","","12.96","","","306%","","3.19","","","(29)%","","4.48"],["Total","","3.99","","","118%","","1.83","","","(4)%","","1.90"],["Average NGL Price - Per barrel:"],["United States","","$","27.85","","","148%","","$","11.21","","","(25)%","","$","14.95"],["Egypt","","48.84","","","75%","","27.83","","","(18)%","","33.87"],["North Sea","","54.30","","","83%","","29.73","","","(19)%","","36.83"],["Total","","28.48","","","141%","","11.84","","","(25)%","","15.74"]]
[[/GREPCENT_TABLE]]

Crude Oil Prices A substantial portion of the Company’s crude oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of the Company’s control. Average realized crude oil prices for 2021 were up 74 percent compared to 2020, a direct result of the rising benchmark oil prices over the past year. Crude oil prices realized in 2021 averaged $68.97 per barrel.

Continued volatility in the commodity price environment reinforces the importance of the Company’s asset portfolio. While the market price received for natural gas varies among geographic areas, crude oil tends to trade within a global market. Price movements for all types and grades of crude oil generally move in the same direction.

Natural Gas Prices Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions. The Company’s primary markets include North America, Egypt, and the U.K. An overview of the market conditions in the Company’s primary gas-producing regions follows:

•The Company predominantly sells its natural gas production within the U.S., including to U.S. LNG export facilities, although a portion is sold to markets in Mexico. Most of the Company’s U.S. natural gas is sold on a monthly or daily basis at either monthly or daily index-based prices. The Company’s U.S. realizations averaged $3.92 per Mcf in 2021, up from $1.22 per Mcf in 2020.

•In Egypt, the Company’s natural gas is sold to EGPC, primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. Overall, the Company’s Egypt operations averaged $2.81 per Mcf in 2021, a 1 percent increase from 2020.

•Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The Company’s North Sea operations averaged $12.96 per Mcf in 2021, a 306 percent increase from an average of $3.19 per Mcf in 2020.

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NGL Prices The Company’s U.S. NGL production, which accounted for 97 percent of the Company’s total 2021 NGL production, is sold under contracts with prices at market indices based on Gulf Coast supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.

Crude Oil Revenues  

Crude oil revenues for 2021 totaled $4.6 billion, a $1.5 billion increase from the 2020 total of $3.1 billion. A 74 percent increase in average realized prices increased 2021 revenues by $2.3 billion compared to 2020, while 15 percent lower average daily production decreased revenues by $825 million. Average daily production in 2021 was 182 Mb/d, with prices averaging $68.97 per barrel. Crude oil sales accounted for 71 percent of the Company’s 2021 oil and gas production revenues and 47 percent of its worldwide production.

The Company’s worldwide crude oil production decreased 32 Mb/d compared to 2020, primarily a result of production decline across all countries driven by reduced drilling activity in the prior year, and extended operational downtime and platform turnaround work in the North Sea.

Natural Gas Revenues 

Natural gas revenues for 2021 totaled $1,207 million, a $609 million increase from the 2020 total of $598 million. A 118 percent increase in average realized prices increased 2021 revenues by $705 million compared to 2020, while 7 percent lower average daily production decreased revenues by $96 million. Average daily production in 2021 was 830 MMcf/d, with prices averaging $3.99 per Mcf. Natural gas sales accounted for 18 percent of the Company’s 2021 oil and gas production revenues and 36 percent of its worldwide production.

The Company’s worldwide natural gas production decreased 64 MMcf/d compared to 2020, primarily a result of production decline across all countries, impacts of winter storms in the U.S., and extended operational downtime and platform turnaround work in the North Sea.

NGL Revenues  

NGL revenues for 2021 totaled $706 million, a $373 million increase from the 2020 total of $333 million. A 141 percent increase in average realized prices increased 2021 revenues by $467 million compared to 2020, while 12 percent lower average daily production decreased revenues by $94 million. Average daily production in 2021 was 68 Mb/d, with prices averaging $28.48 per barrel. NGL sales accounted for 11 percent of the Company’s 2021 oil and gas production revenues and 17 percent of its worldwide production.

The Company’s worldwide NGL production decreased 9 Mb/d compared to 2020, primarily a result of production decline across all countries and the impacts of winter storms in the U.S.

Altus Midstream Revenues

The Company beneficially owns approximately 79 percent of ALTM’s outstanding voting common stock. Altus owns and operates a midstream energy asset network in the Permian Basin of West Texas primarily to service the Company’s production from its Alpine High resource play, which commenced production in May 2017. On October 21, 2021, ALTM announced that it will combine with privately owned BCP in an all-stock transaction, and APA’s ownership in ALTM will be reduced from approximately 79 percent to approximately 20 percent. The transaction is expected to close during the first quarter of 2022, following completion of customary closing conditions.

Altus Midstream primarily generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services. For the years ended December 31, 2021 and 2020, Altus Midstream’s service revenues generated through its fee-based contractual arrangements with the Company totaled $127 million and $145 million, respectively. These affiliated revenues are eliminated upon consolidation. The decrease in revenue compared to the prior year was primarily driven by lower natural gas throughput volumes processed by Altus for the Company’s Alpine High production.

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Purchased Oil and Gas Sales

Purchased oil and gas sales represent volumes primarily attributable to transport, fuel, and physical in-basin gas purchases that were sold by the Company to fulfill natural gas takeaway obligations. Sales related to these purchased volumes increased $1.1 billion for the year ended December 31, 2021 from $398 million to $1.5 billion. Purchased oil and gas sales were offset by associated purchase costs of $1.6 billion and $357 million for the years ended December 31, 2021 and 2020, respectively. The increase is the result of sales volume growth associated with additional transport capacity and a more than doubling of the average gas sales price.

Operating Expenses

The table below presents a comparison of the Company’s operating expenses for the years ended December 31, 2021, 2020, and 2019. All operating expenses include costs attributable to a noncontrolling interest in Egypt and Altus.

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2021","","2020","","2019"],["","","(In millions)"],["Lease operating expenses","","$","1,241","","","$","1,127","","","$","1,447"],["Gathering, processing, and transmission","","264","","","274","","","306"],["Purchased oil and gas costs","","1,580","","","357","","","142"],["Taxes other than income","","204","","","123","","","207"],["Exploration","","155","","","274","","","805"],["General and administrative","","376","","","290","","","406"],["Transaction, reorganization, and separation","","22","","","54","","","50"],["Depreciation, depletion, and amortization:"],["Oil and gas property and equipment","","1,255","","","1,643","","","2,512"],["Gathering, processing, and transmission assets","","64","","","76","","","105"],["Other assets","","41","","","53","","","63"],["Asset retirement obligation accretion","","113","","","109","","","107"],["Impairments","","208","","","4,501","","","2,949"],["Financing costs, net","","514","","","267","","","462"]]
[[/GREPCENT_TABLE]]

Lease Operating Expenses (LOE)

LOE includes several key components, such as direct operating costs, repairs and maintenance, and workover costs. Direct operating costs generally trend with commodity prices and are impacted by the type of commodity produced and the location of properties (i.e., offshore, onshore, remote locations, etc.). Fluctuations in commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity price based. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as rig rates, labor, boats, helicopters, materials, and supplies. Crude oil, which accounted for 47 percent of the Company’s total 2021 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.

During 2021, LOE increased $114 million, or 10 percent, compared to 2020. On a per-boe basis, LOE increased $1.75, or 25 percent, compared to 2020, from $7.00 per boe to $8.75 per boe. The increase in costs was driven by maintenance and turnaround costs in the North Sea, higher-priced emissions credits purchased in association with North Sea production, increased workover activity in the U.S., operating costs trending with commodity prices, inflation impacts, and overall higher labor costs that were heavily impacted by mark-to-market adjustments for stock-based compensation.

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Gathering, Processing, and Transmission (GPT)

GPT expenses include amounts paid to third-party carriers and to Altus Midstream for gathering and transmission services for the Company’s upstream natural gas production associated with its Alpine High play. GPT expenses also include midstream operating costs incurred by Altus Midstream. The following table presents a summary of these expenses:

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2021","","2020","","2019"],["","","(In millions)"],["Third-party processing and transmission costs","","$","232","","","$","236","","","$","250"],["Midstream service affiliate costs","","128","","","143","","","134"],["Upstream processing and transmission costs","","360","","","379","","","384"],["Midstream operating expenses","","32","","","38","","","56"],["Intersegment eliminations","","(128)","","","(143)","","","(134)"],["Total Gathering, processing, and transmission","","$","264","","","$","274","","","$","306"]]
[[/GREPCENT_TABLE]]

GPT costs decreased $10 million compared to 2020. Third-party processing and transmission costs decreased $4 million, primarily driven by a decrease in contracted pricing and lower processed volumes. Midstream service affiliate costs decreased $15 million compared to 2020, primarily driven by lower throughput of natural gas volumes at Alpine High. Midstream operating expenses, incurred primarily by Altus, decreased $6 million compared to 2020, driven by continued improvements in operational efficiency as a result of transitioning from mechanical refrigeration units to Altus’ centralized Diamond cryogenic complex. The transition resulted in decreases in contract labor, equipment rentals, and chemical expenses.

Purchased Oil and Gas Costs

Purchased oil and gas costs increased $1.2 billion compared to 2020, and were primarily offset by associated sales totaling $1.5 billion for the year ended 2021, as further discussed above.

Taxes Other Than Income

Taxes other than income primarily consist of severance taxes on onshore properties and in state waters off the coast of the U.S. and ad valorem taxes on U.S. properties. Severance taxes are generally based on a percentage of oil and gas production revenues. The Company is also subject to a variety of other taxes, including U.S. franchise taxes.

Taxes other than income increased $81 million compared to 2020, primarily from higher severance taxes driven by higher commodity prices.

Exploration Expenses

Exploration expenses include unproved leasehold impairments, exploration dry hole expense, geological and geophysical expenses, and the costs of maintaining and retaining unproved leasehold properties. The following table presents a summary of these expenses:

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2021","","2020","","2019"],["","","(In millions)"],["Unproved leasehold impairments","","$","31","","","$","101","","","$","619"],["Dry hole expenses","","66","","","110","","","57"],["Geological and geophysical expenses","","18","","","20","","","59"],["Exploration overhead and other","","40","","","43","","","70"],["Total Exploration","","$","155","","","$","274","","","$","805"]]
[[/GREPCENT_TABLE]]

Exploration expenses decreased $119 million compared to 2020. Unproved leasehold impairments were $70 million lower than the prior year due to improved commodity prices and increased drilling plans in the U.S. Dry hole expense decreased $44 million, geological and geophysical expenses decreased $2 million, and exploration overhead and other expenses decreased $3 million compared to 2020, primarily resulting from decreased exploration activities compared to the prior year.

44

General and Administrative (G&A) Expenses

G&A expenses increased $86 million compared to 2020, primarily driven by higher cash-based stock compensation expense resulting from an increase in the Company’s stock price compared to the prior year, partially offset by lower overhead driven by organizational redesign efforts during 2019 and 2020.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs decreased $32 million compared to 2020, primarily driven by costs associated with the Company’s reorganization efforts incurred primarily in the prior year.

In recent years, the Company has streamlined its portfolio through strategic divestitures and centralized certain operational activities in an effort to capture greater efficiencies and cost savings through shared services. During the second half of 2019, management initiated a comprehensive redesign of the Company’s organizational structure and operations that it believes will better position the Company to be competitive for the long-term and further reduce recurring costs. Reorganization efforts were substantially completed in 2020; however, additional reorganization costs related to ongoing consulting and separation activities in the Company’s international operations were incurred during 2021.

Depreciation, Depletion and Amortization (DD&A)

DD&A expenses on the Company’s oil and gas property for the year ended December 31, 2021 decreased $388 million compared to 2020. The Company’s oil and gas property DD&A rate decreased $1.35 per boe in 2021 compared to 2020, from $10.20 per boe to $8.85 per boe. The decrease was driven by lower production volumes and lower asset property balances associated with proved property impairments recorded during the first quarter of 2020. DD&A expense on the Company’s GPT depreciation decreased $12 million compared to 2020, driven by impairment charges recorded against the carrying value of the Company’s GPT facilities in Egypt during the first quarter of 2020.

Impairments

During 2021, the Company recorded asset impairments totaling $208 million. The charges include $160 million for Altus’ equity method interest in EPIC, as part of Altus’ review of the fair value of its assets in relation to the announced BCP Business Combination, $26 million in connection with inventory valuations in Egypt, and $22 million in connection with inventory valuations and expected equipment dispositions in the North Sea.

During 2020, the Company recorded asset impairments in connection with fair value assessments totaling $4.5 billion, including $4.3 billion for oil and gas proved properties in the U.S, Egypt, and the North Sea, $68 million for GPT facilities in Egypt, $87 million for goodwill in Egypt, and $27 million for inventory and other miscellaneous assets, including lease assets and charges for the early termination of drilling rig leases.

The following table presents a summary of asset impairments recorded for 2021, 2020, and 2019:

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2021","","2020","","2019"],["","","(In millions)"],["Oil and gas proved property","","$","\u2014","","","$","4,319","","","$","1,484"],["GPT facilities","","\u2014","","","68","","","1,295"],["Equity method interests","","160","","","\u2014","","","\u2014"],["Divested unproved properties and leasehold","","\u2014","","","\u2014","","","149"],["Goodwill","","\u2014","","","87","","","\u2014"],["Inventory and other","","48","","","27","","","21"],["Total Impairments","","$","208","","","$","4,501","","","$","2,949"]]
[[/GREPCENT_TABLE]]

45

Financing Costs, Net

Financing costs incurred during the period comprised the following:

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2021","","2020","","2019"],["","","(In millions)"],["Interest expense","","$","419","","","$","438","","","$","430"],["Amortization of debt issuance costs","","8","","","8","","","7"],["Capitalized interest","","(9)","","","(12)","","","(37)"],["Loss (gain) on extinguishment of debt","","104","","","(160)","","","75"],["Interest income","","(8)","","","(7)","","","(13)"],["Total Financing costs, net","","$","514","","","$","267","","","$","462"]]
[[/GREPCENT_TABLE]]

Net financing costs increased $247 million compared to 2020, primarily the result of a $104 million loss on extinguishment of debt during 2021 and a $160 million gain on extinguishment of debt during 2020.

Provision for Income Taxes

Income tax expense increased $514 million from $64 million during 2020 to $578 million during 2021. The Company’s year-to-date 2021 effective income tax rate was primarily impacted by asset impairments and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During 2020, the Company’s effective income tax rate was primarily impacted by oil and gas asset impairments, a goodwill impairment, and an increase in the amount of valuation allowance against its U.S. deferred tax assets.

The Company recorded a full valuation allowance against its U.S. net deferred tax assets and will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance. For additional information regarding income taxes, refer to Note 10—Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is currently under audit by the Internal Revenue Service (IRS) for the 2014-2017 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.

Capital and Operational Outlook

The Company continues to prudently manage its capital program against a volatile price environment and the prolonged effects of the COVID-19 pandemic. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of ongoing exploration and appraisal activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and return of capital to its stakeholders.

The Company’s 2022 capital program will maintain a similar investment approach to the prior year, with upstream capital investment budgeted at approximately $1.6 billion. This budget includes small changes to the timing of rig count increases in Egypt and the U.S. as well as updated views on costs and inflation. This amount also includes approximately $200 million for exploration and appraisal activities, primarily in Suriname. In 2023 and 2024, the total capital budget is anticipated to increase slightly despite a relatively unchanged activity set, given expectations of continued inflationary pressure.

Based on this planned capital activity, the Company anticipates 2022 worldwide production levels will be similar to 2021, after adjusting for divestments. Egypt gross production is expected to increase through the year with higher rig activity, while Egypt net production will be additionally benefited from the effects of the modernized PSC terms. The Company anticipates moderate production declines in the U.S. compared to 2021 given gradual increases in activity levels over the past year and timing of completions.

At current strip pricing, the Company expects to generate significant cash flow over this capital activity budget. The Company’s commitment to return capital to shareholders over the next three years will remain unchanged.

46

The Company’s diversified global portfolio provides the ability to quickly optimize capital allocation as market conditions change. The current uncertainties associated with the COVID-19 pandemic, however, are still evolving and may become more severe and complex. As a result, the COVID-19 pandemic may still materially and adversely affect the Company’s results in a manner that is either not currently known or that the Company does not currently consider to be a significant risk to its business. For additional information about the business risks relating to the COVID-19 pandemic and related governmental actions, refer to Part I, Item 1A—Risk Factors of this Annual Report on Form 10-K.

Separate from the Company’s upstream oil and gas activities, capital spending for Altus’ gathering and processing assets totaled $3 million in 2021, down from $28 million in 2020 when a majority of the midstream infrastructure construction was completed. Altus management believes its existing gathering, processing, and transmission infrastructure capacity is capable of fulfilling its midstream contracts to service the Company’s production from Alpine High and any third-party customers.

Additionally, during the years ended December 31, 2021 and 2020, Altus made cash contributions totaling $28 million and $327 million, respectively, for its Equity Method Interest Pipelines that are all currently in service. Altus estimates it will incur minimal capital contributions during 2022 for its equity interest in these joint venture pipelines. Based on Altus management’s current financial plan and related assumptions prior to closing the BCP Business Combination, Altus believes that cash from operations, a reduced capital program for its midstream infrastructure, and distributions from Equity Method Interests will generate cash flows in excess of capital expenditures and the amount required to fund Altus’ planned quarterly dividend and quarterly payments to the holders of Altus Midstream LP’s Series A Cumulative Redeemable Preferred Units (Preferred Units) during 2022.

For further information on the Equity Method Interest Pipelines, refer to Note 6—Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Capital Resources and Liquidity

Operating cash flows are the Company’s primary source of liquidity. The Company’s short-term and long-term operating cash flows are impacted by highly volatile commodity prices, as well as production costs and sales volumes. Significant changes in commodity prices impact the Company’s revenues, earnings, and cash flows. These changes potentially impact the Company’s liquidity if costs do not trend with related changes in commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.

The Company’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of the Company’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves.

For the year ended December 31, 2021, the Company recognized upward reserve revisions of approximately 10 percent of its year-end 2020 estimated proved reserves as a result of improved commodity prices compared to negative reserve revisions of approximately 7 percent in the prior year as a result of lower commodity prices. The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2021, 2020, and 2019, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 18—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

The Company believes its available liquidity and capital resource alternatives, combined with proactive measures to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including the Company’s capital development program, repayment of debt maturities, payment of dividends, share buy-back activity, and amounts that may ultimately be paid in connection with commitments and contingencies.

The Company may also elect to utilize available cash on hand, committed subsidiary borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for all other liquidity and capital resource needs.

For additional information, refer to Part I, Items 1 and 2—Business and Properties and Part I, Item 1A—Risk Factors of this Annual Report on Form 10-K.

47

Sources and Uses of Cash

The following table presents the sources and uses of the Company’s cash and cash equivalents for the years presented:

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2021","","2020","","2019"],["","","(In millions)"],["Sources of Cash and Cash Equivalents:"],["Net cash provided by operating activities","","$","3,496","","","$","1,388","","","$","2,867"],["Proceeds from Apache credit facility, net","","392","","","150","","","\u2014"],["Proceeds from Altus credit facility, net","","33","","","228","","","396"],["Proceeds from asset divestitures","","256","","","166","","","718"],["Fixed-rate debt borrowings","","\u2014","","","1,238","","","989"],["Redeemable noncontrolling interest - Altus Preferred Unit limited partners","","\u2014","","","\u2014","","","611"],["Other","","23","","","\u2014","","","\u2014"],["","","4,200","","","3,170","","","5,581"],["Uses of Cash and Cash Equivalents:"],["Additions to oil and gas property(1)","","1,101","","","1,270","","","2,594"],["Additions to Altus gathering, processing, and transmission facilities(1)","","3","","","28","","","327"],["Leasehold and property acquisitions","","9","","","4","","","40"],["Contributions to Altus equity method interests","","28","","","327","","","501"],["Acquisition of Altus equity method interests","","\u2014","","","\u2014","","","671"],["Payments on fixed-rate debt","","1,795","","","1,243","","","1,150"],["Dividends paid","","52","","","123","","","376"],["Distributions to noncontrolling interest - Egypt","","279","","","91","","","305"],["Distributions to Altus Preferred Unit limited partners","","46","","","23","","","\u2014"],["Shares repurchased","","847","","","\u2014","","","\u2014"],["Other","","\u2014","","","46","","","84"],["","","4,160","","","3,155","","","6,048"],["Increase (decrease) in cash and cash equivalents","","$","40","","","$","15","","","$","(467)"]]
[[/GREPCENT_TABLE]]

(1)The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this Annual Report on Form 10-K, which include accruals.

Sources of Cash and Cash Equivalents

Net Cash Provided by Operating Activities Operating cash flows are the Company’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile commodity prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense.

Net cash provided by operating activities for the year ended December 31, 2021 totaled $3.5 billion, up $2.1 billion from the year ended December 31, 2020, primarily the result of higher commodity prices compared to the prior year.

For a detailed discussion of commodity prices, production, and operating expenses, refer to “Results of Operations” in this Item 7. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, refer to the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Proceeds from Apache Credit Facility, Net As of December 31, 2021 and 2020, Apache had outstanding borrowings of $542 million and $150 million, respectively, under its credit facility, which is classified as long-term debt.

Proceeds from Altus Credit Facility, Net The construction of Altus’ gathering and processing assets and the associated equity interests in the Equity Method Interest Pipelines has historically required capital expenditures in excess of Altus’ cash on hand and operational cash flows. During the years ended December 31, 2021 and 2020, Altus Midstream LP borrowed $33 million and $228 million, respectively, under its revolving credit facility to meet this shortfall. With the midstream infrastructure complete and all of the Equity Method Interest Pipelines now in service, the Company anticipates that Altus’ existing capital resources will be sufficient to fund its continuing obligations and dividend program.

48

Proceeds from Asset Divestitures The Company received $256 million and $166 million in proceeds from the divestiture of certain non-core assets during the years ended December 31, 2021 and 2020, respectively. For more information regarding the Company’s acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part IV set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Fixed-Rate Debt Borrowings On August 17, 2020, Apache closed offerings of $1.25 billion in aggregate principal amount of senior unsecured notes, comprised of $500 million in aggregate principal amount of 4.625% notes due 2025 and $750 million in aggregate principal amount of 4.875% notes due 2027. The senior unsecured notes are redeemable at any time, in whole or in part, at Apache’s option, at the applicable redemption price. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers, repay a portion of outstanding borrowings under Apache’s senior revolving credit facility, and for general corporate purposes.

Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners On June 12, 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act of 1933, as amended. Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. For more information, refer to Note 13—Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Uses of Cash and Cash Equivalents

Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $1.1 billion and $1.3 billion for the years ended December 31, 2021 and 2020, respectively. The decrease in capital investment is reflective of the Company’s capital program, which was reduced early in 2020 to align with anticipated operating cash flows following the collapse of commodity prices stemming from the COVID-19 pandemic. The Company operated an average of 13 drilling rigs during 2021, compared to an average of 12 drilling rigs during 2020.

Additions to Altus Gathering, Processing, and Transmission (GPT) Facilities The Company’s cash expenditures for GPT facilities totaled $3 million and $28 million during 2021 and 2020, respectively, nearly all comprising midstream infrastructure expenditures incurred by Altus, which were substantially completed as of December 31, 2019. Altus management believes its existing GPT infrastructure capacity is capable of fulfilling its midstream contracts to service the Company’s production from Alpine High and any third-party customers.

Leasehold and Property Acquisitions During 2021 and 2020, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $9 million and $4 million, respectively.

Contributions to Altus Equity Method Interests Altus contributed $28 million and $327 million in cash during 2021 and 2020, respectively, for equity interests in the Equity Method Interest Pipelines. For more information regarding the Company’s equity method interests, refer to Note 6—Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Payments on Fixed-Rate Debt During 2021, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.7 billion aggregate principal amount of notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of $1.8 billion reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $105 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs, in connection with the note purchases.

During 2021, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $22 million for an aggregate purchase price of $20 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $2 million. The Company recognized a $1 million net gain on extinguishment of debt as part of these transactions.

During 2020, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $588 million for an aggregate purchase price of $428 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $168 million. These repurchases resulted in a $158 million net gain on extinguishment of debt. The net gain includes an acceleration of related discount and debt issuance costs. Additionally, on November 3, 2020, Apache redeemed the remaining $183 million of outstanding 3.625% senior notes due February 1, 2021 at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The repurchases were financed by borrowings under Apache’s revolving credit facility.

49

Also during 2020, Apache closed cash tender offers for certain outstanding notes. Apache accepted for purchase $644 million aggregate principal amount certain notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of $644 million, reflecting principal, aggregate discount to par of $38 million, early tender premium of $32 million, and accrued and unpaid interest of $6 million. The Company recorded a net gain of $2 million on extinguishment of debt, including an acceleration of unamortized debt discount and issuance costs, in connection with the note purchases.

The Company expects that Apache will continue to reduce debt outstanding under its indentures from time to time.

Dividends The Company paid $52 million and $123 million during the years ended December 31, 2021 and 2020, respectively, for dividends on its common stock. In the first quarter of 2020, the Company’s Board of Directors approved a reduction in the Company’s quarterly dividend per share from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020. During the third quarter of 2021, the Company’s Board of Directors approved an increase in its quarterly dividend per share from $0.025 to $0.0625, and in the fourth quarter of 2021, approved a further increase to its quarterly dividend to $0.125 per share.

Distributions to Noncontrolling Interest - Egypt Sinopec holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company paid $279 million and $91 million during the years ended December 31, 2021 and 2020, respectively, in cash distributions to Sinopec.

Distributions to Altus Preferred Units limited partners Altus Midstream LP paid $46 million and $23 million in cash distributions to its limited partners holding Preferred Units during the years ended December 31, 2021 and 2020, respectively. For more information regarding the Preferred Units, refer to Note 13—Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Liquidity

The following table presents a summary of the Company’s key financial indicators as of December 31:

[[GREPCENT_TABLE]]
[["","","2021","","2020"],["","","(In millions)"],["Cash and cash equivalents","","$","302","","","$","262"],["Total debt - Apache","","6,853","","","8,148"],["Total debt - Altus","","657","","","624"],["Total equity (deficit)","","(717)","","","(645)"],["Available committed borrowing capacity - Apache","","2,426","","","2,944"],["Available committed borrowing capacity - Altus","","141","","","176"]]
[[/GREPCENT_TABLE]]

Cash and Cash Equivalents As of December 31, 2021, the Company had $302 million in cash and cash equivalents, of which approximately $132 million was held by Altus. The majority of the Company’s cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.

Debt As of December 31, 2021, the Company had $7.5 billion in total debt outstanding, which consisted of notes, debentures, credit facility borrowings, and finance lease obligations. Future interest payments on the fixed-rate notes and debentures are approximately $4.7 billion. As of December 31, 2021, current debt included $213 million carrying value of 3.25% senior notes due April 15, 2022 and $2 million of finance lease obligations. On January 18, 2022, Apache redeemed the remaining $213.5 million of outstanding 3.25% senior notes due April 15, 2022 at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s revolving credit facility.

Committed Credit Facilities In March 2018, Apache entered into a revolving credit facility with commitments totaling $4.0 billion. In March 2019, the term of this facility was extended by one year to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise of an extension option. Apache can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of December 31, 2021. The facility is for general corporate purposes. Letters of credit are available for security needs, including in respect of North Sea decommissioning obligations. The facility has no collateral requirements, is not subject to borrowing base redetermination, and has no drawdown restrictions or prepayment obligations in the event of a decline in credit ratings.

50

As of December 31, 2021, there were $542 million of borrowings and an aggregate £748 million and $20 million in letters of credit outstanding under this facility. As of December 31, 2020, there were $150 million of borrowings and an aggregate £633 million and $40 million in letters of credit outstanding under this facility. The outstanding letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020.

At Apache’s option, the interest rate per annum for borrowings under the 2018 facility is either a base rate, as defined, plus a margin, or the London Inter-bank Offered Rate (LIBOR), plus a margin. Apache also pays quarterly a facility fee at a per annum rate on total commitments. The margins and the facility fee vary based upon Apache’s senior long-term debt rating. At December 31, 2021, the base rate margin was 0.5 percent, the LIBOR margin was 1.50 percent, and the facility fee was 0.25 percent. A commission is payable quarterly to lenders on the face amount of each outstanding letter of credit at a per annum rate equal to the LIBOR margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks.

The financial covenants of the credit facility require Apache to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. For purposes of this calculation, capital excludes the effects of non-cash write-downs, impairments, and related charges occurring after June 30, 2015. At December 31, 2021, Apache’s debt-to-capital ratio as calculated under the credit facility was 28 percent. The 2018 facility’s negative covenants restrict the ability of Apache and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with exceptions for liens typically arising in the oil and gas industry; liens securing debt incurred to finance the acquisition, construction, improvement, or capital lease of assets, provided that such debt, when incurred, does not exceed the subject purchase price and costs, as applicable, and related expenses; liens on subsidiary assets located outside of the United States and Canada; and liens arising as a matter of law, such as tax and mechanics’ liens. Apache also may incur liens on assets if debt secured thereby does not exceed 15 percent of Apache’s consolidated net tangible assets, or approximately $1.9 billion as of December 31, 2021. Negative covenants also restrict Apache’s ability to merge with another entity unless it is the surviving entity, dispose of substantially all of its assets, and guarantee debt of non-consolidated entities in excess of the stated threshold.

In November 2018, Altus Midstream LP entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream LP’s two, one-year extension options). The agreement for this facility, as amended, provides aggregate commitments from a syndicate of banks of $800 million. All aggregate commitments include a letter of credit subfacility of up to $100 million and a swingline loan subfacility of up to $100 million. Altus Midstream LP may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of December 31, 2021, there were $657 million of borrowings and a $2 million letter of credit outstanding under this facility. As of December 31, 2020, there were $624 million of borrowings and no letters of credit outstanding under this facility. The Altus Midstream LP credit facility is unsecured and is not guaranteed by APA or any of its subsidiaries, including Apache.

The agreement for Altus Midstream LP’s credit facility, as amended, restricts distributions in respect of capital to Apache and other unit holders in certain circumstances. Unless the Leverage Ratio is less than or equal to 4.00:1.00, the agreement limits such distributions to $30 million per calendar year until either (i) the consolidated net income of Altus Midstream LP and its restricted subsidiaries, as adjusted pursuant to the agreement, for three consecutive calendar months equals or exceeds $350 million on an annualized basis or (ii) Altus Midstream LP has a specified senior long-term debt rating; in addition, before the occurrence of one of those two events, the Leverage Ratio must be less than or equal to 5.00:1.00. In no event can any distribution be made that would, after giving effect to it on a pro forma basis, result in a Leverage Ratio greater than (i) 5.00:1.00 or (ii) for a specified period after a qualifying acquisition, 5.50:1.00. The Leverage Ratio is the ratio of (1) the consolidated indebtedness of Altus Midstream LP and its restricted subsidiaries to (2) EBITDA (as defined in the agreement) of Altus Midstream LP and its restricted subsidiaries for the 12-month period ending immediately before the determination date. The Leverage Ratio as of December 31, 2021 was less than 4.00:1.00. 

The terms of Altus Midstream LP’s Preferred Units also contain certain restrictions on distributions in respect of capital, including the common units held by Altus Midstream Company and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation. Refer to Note 13—Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K for further information. In addition, the amount of any cash distributions to Altus Midstream LP by any entity in which it has an interest accounted for by the equity method is subject to such entity’s compliance with the terms of any debt or other agreements by which it may be bound, which in turn may impact the amount of funds available for distribution by Altus Midstream LP to its partners. 

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There are no clauses in either the agreement for Apache’s 2018 credit facility or for Altus Midstream LP’s 2018 credit facility that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. These agreements do not have drawdown restrictions or prepayment    obligations in the event of a decline in credit ratings. However, each agreement allows the lenders to accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches, and if a borrower or any of its subsidiaries defaults on other indebtedness in excess of the stated threshold, is insolvent, or has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold. Lenders may also accelerate payment maturity and terminate lending and issuance commitments under the applicable agreement if Apache or Altus Midstream LP, as applicable, undergoes a specified change in control or any borrower has specified pension plan liabilities in excess of the stated threshold. Each of Apache and Altus Midstream LP was in compliance with the terms of its 2018 credit facility as of December 31, 2021.

There is no assurance of the terms upon which potential lenders under future credit facilities will make loans or other extensions of credit available to Apache or its subsidiaries or the composition of such lenders.

There is no assurance that the financial condition of banks with lending commitments to Apache or Altus Midstream LP will not deteriorate. We closely monitor the ratings of the banks in our bank groups. Having large bank groups allows the Company to mitigate the potential impact of any bank’s failure to honor its lending commitment.

Commercial Paper Program As of December 31, 2020, no commercial paper was outstanding. Apache did not use its commercial paper program during 2021 and terminated the program during the third quarter of 2021.

Contractual Obligations

Purchase Obligations From time to time, the Company enters into agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments and agreements to secure capacity rights on third-party pipelines. As of December 31, 2021, the Company had contractual obligations totaling $4.9 billion, of which $1.2 billion is related to U.S. firm transportation contracts and $3.5 billion is related to the new PSC with the EGPC. Under terms agreed to in the modernized PSC, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. The Company believes it will be able to satisfy this obligation within its current exploration and development program.

Leases In the normal course of business, the Company enters into various lease agreements for real estate, drilling rigs, vessels, aircrafts, and equipment related to its exploration and development activities, which are typically classified as operating leases under the provisions of Financial Accounting Standards Board ASC Topic 842 (Leases). As of December 31, 2021, the Company had net minimum commitments of $272 million and $42 million for operating and finance leases, respectively.

For additional information regarding these obligations, refer to Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

For information regarding the Company’s liability for dismantlement, abandonment, and restoration costs of oil and gas properties or pension or postretirement benefit obligations, refer to Notes 8—Asset Retirement Obligation and Note 12—Retirement and Deferred Compensation Plans in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

The Company is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess settlements resulting from litigation. The Company’s management believes that it has adequately reserved for its contingent obligations, including approximately $2 million for environmental remediation and approximately $84 million for various contingent legal liabilities. For a detailed discussion of the Company’s lease obligations, purchase obligations, environmental and legal contingencies, and other commitments, please see Note 11—Commitments and Contingencies and Note 12—Retirement and Deferred Compensation Plans in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

As further described above under “Capital and Operational Outlook,” Altus Midstream LP and/or its subsidiaries have equity ownership in four Equity Method Interest Pipelines. Altus Midstream LP and/or its subsidiaries may be required to fund future capital expenditures for its equity interest share in the development of the applicable pipeline. Altus estimates that it will incur minimal capital contributions for its equity interests in these joint venture pipelines during 2022.

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With respect to oil and gas operations in the Gulf of Mexico, the Bureau of Ocean Energy Management (BOEM) issued a Notice to Lessees (NTL No. 2016-N01) significantly revising the obligations of companies operating in the Gulf of Mexico to provide supplemental assurances of performance with respect to plugging, abandonment, and decommissioning obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies’ oil and gas leases. While the NTL was paused in mid-2017 and is currently listed on BOEM’s website as “rescinded,” if reinstated, the NTL will likely require that the Company provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to the Company’s current ownership interests in various Gulf of Mexico leases. The Company is working closely with BOEM to make arrangements for the provision of such additional required security, if such security becomes necessary under the NTL. Additionally, the Company is not able to predict the effect that these changes might have on counterparties to which the Company has sold Gulf of Mexico assets or with whom the Company has joint ownership. Such changes could cause the bonding obligations of such parties to increase substantially, thereby causing a significant impact on the counterparties’ solvency and ability to continue as a going concern.

Potential Decommissioning Obligations on Sold Properties

The Company’s subsidiaries have potential exposure to future obligations related to divested properties. The Company has divested various leases, wells, and facilities located in the Gulf of Mexico (GOM) where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser of such GOM assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, APA’s subsidiaries could be required to perform such actions under applicable federal laws and regulations. In such event, such subsidiaries may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.

In 2013, Apache sold its GOM Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Currently, Apache holds two bonds (Bonds) and five Letters of Credit backed by investment-grade counterparties to secure Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets.

On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets will be used to fund decommissioning of Legacy GOM Assets.

In September 2021, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently required to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notification to BSEE. Apache expects to receive such orders on the other Legacy GOM Assets included in GOM Shelf’s notification letter. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.

If Apache incurs costs to decommission any Legacy GOM Asset and GOM Shelf does not reimburse Apache for such costs, then Apache will obtain reimbursement from Trust A, the Bonds, and the Letters of Credit until such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets.

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If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be ordered by BSEE to perform, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to effectively use its available cash to fund the deficit.

As of December 31, 2021, Apache estimates that its potential liability to fund decommissioning of Legacy GOM Assets it may be ordered to perform ranges from $1.2 billion to $1.4 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, during 2021, the Company recorded a contingent liability of $1.2 billion, representing the estimated costs of decommissioning it may be required to perform on Legacy GOM Assets. Of the total liability recorded, $1.1 billion is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $100 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. The Company also recorded a $740 million asset, which represents the amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $640 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $100 million is reflected under “Other current assets.” A “Loss on previously sold Gulf of Mexico properties” in the amount of $446 million was recognized in the third quarter of 2021 to reflect the net impact to the Company’s statement of consolidated operations. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. In addition, significant changes in the market price of oil, gas, and NGLs could further impact Apache’s estimate of its contingent liability to decommission Legacy GOM Assets.

Insurance Program

The Company maintains insurance policies that include coverage for physical damage to its assets, general liabilities, workers’ compensation, employers’ liability, sudden and accidental pollution, and other risks. The Company’s insurance coverage is subject to deductibles or retentions that it must satisfy prior to recovering on insurance. Additionally, the Company’s insurance is subject to policy exclusions and limitations. There is no assurance that insurance will adequately protect the Company against liability from all potential consequences and damages. Further, the Company does not have coverage in place for a variety of other risks including Gulf of Mexico named windstorm and business interruption. Service agreements, including drilling contracts, generally indemnify the Company for injuries and death of the service provider’s employees as well as subcontractors hired by the service provider.

The Company purchases multi-year political risk insurance from The Islamic Corporation for the Insurance of Investment and Export Credit Trade (ICIEC, an agency of the Islamic Development Bank) and highly-rated insurers covering a portion of its investments in Egypt for losses arising from confiscation, nationalization, and expropriation risks. In the aggregate, these insurance policies provide up to $750 million of coverage, subject to policy terms and conditions and a retention of approximately $500 million.

The Company also has an insurance policy with U.S. International Development Finance Corporation (DFC), which, subject to policy terms and conditions, provides up to $150 million of coverage through 2024 for losses arising from (1) non-payment by EGPC of arbitral awards covering amounts owed the Company on past due invoices and (2) expropriation of exportable petroleum in the event that actions taken by the government of Egypt prevent the Company from exporting its share of production. The Multilateral Investment Guarantee Agency (MIGA), a member of the World Bank Group, provides $60 million in reinsurance to DFC.

Future insurance coverage for the Company’s industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable or unavailable on terms economically acceptable.

Critical Accounting Estimates

The Company prepares its financial statements and accompanying notes in conformity with accounting principles generally accepted in the U.S., which require management to make estimates and assumptions about future events that affect reported amounts in the financial statements and the accompanying notes. The Company identifies certain accounting policies involving estimation as critical accounting estimates based on, among other things, their impact on the portrayal of the Company’s financial condition, results of operations, or liquidity, as well as the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting estimates address accounting matters that are inherently uncertain due to unknown future resolution of such matters. Management routinely discusses the development, selection, and disclosure of each critical accounting estimate. The following is a discussion of the Company’s most critical accounting estimates.

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Reserves Estimates

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations.

Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.

Despite the inherent imprecision in these engineering estimates, the Company’s reserves are used throughout its financial statements. For example, since the Company uses the units-of-production method to amortize its oil and gas properties, the quantity of reserves could significantly impact DD&A expense. A material adverse change in the estimated volumes of reserves could result in property impairments. Finally, these reserves are the basis for the Company’s supplemental oil and gas disclosures. For more information regarding the Company’s supplemental oil and gas disclosures, refer to Note 18—Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.

Reserves are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous twelve months, held flat for the life of the production, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

The Company has elected not to disclose probable and possible reserves or reserve estimates in this filing.

Oil and Gas Exploration Costs

The Company accounts for its exploration and production activities using the successful efforts method of accounting. Costs of acquiring unproved and proved oil and gas leasehold acreage are capitalized. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are also capitalized. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have been found. On a quarterly basis, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities and determines whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the statement of consolidated operations. Otherwise, the costs of exploratory wells remain capitalized.

Offshore Decommissioning Contingency

The Company has potential exposure to future obligations related to divested properties. For information regarding a potential obligation to decommission sold properties estimated and recorded in the third quarter of 2021, please refer to “Potential Obligation to Decommission Sold Properties” above and in Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part IV, Item 5 of this Annual Report on Form 10-K. Changes in significant assumptions impacting the Company’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. In addition, significant changes in the market price of oil, gas, and NGLs could further impact the Company’s estimate of its contingent liability to decommission Legacy GOM Assets.

Impairment of Equity Method Interests

Equity method interests are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.

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Altus recorded an impairment charge on its equity method interest in EPIC in the fourth quarter of 2021. The fair value of the impaired interest was determined using the income approach. The income approach considered estimates of future throughput volumes, tariff rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using a discount rate believed to be consistent with that which would be applied by market participants. The Company has classified this nonrecurring fair value measurement as Level 3 in the fair value hierarchy. Refer to Note 6—Equity Method Interests, within Part IV, Item 15 of this Annual Report on Form 10-K for further details of Altus’ equity method interests. Negative revisions in future estimates of throughput volumes, revenue assumptions or costs related to the Altus’ equity method interests could lead to further impairments of such interests in future periods.

Long-Lived Asset Impairments

Long-lived assets used in operations, including proved oil and gas properties and GPT assets, are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication that the carrying amount of an asset group may not be recovered, the asset is assessed by management through an established process in which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is assessed by management using the income approach.

Under the income approach, the fair value of each asset group is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, the success of future exploration for and development of unproved reserves, expected throughput volumes for GPT assets, discount rates, and other variables. Key assumptions used in developing a discounted cash flow model described above include estimated quantities of crude oil and natural gas reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative, and capital costs adjusted for inflation. The Company discounts the resulting future cash flows using a discount rate believed to be consistent with those applied by market participants.

To assess the reasonableness of our fair value estimate, when available, management uses a market approach to compare the fair value to similar assets. This requires management to make certain judgments about the selection of comparable assets, recent comparable asset transactions, and transaction premiums.

Although the fair value estimate of each asset group is based on assumptions believed to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimate. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the asset group, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an additional impairment of long-lived assets in future periods.

Over the past several years, the Company has experienced substantial volatility in commodity prices, which impacted its future development plans and operating cash flows. As such, material impairments of certain proved oil and gas properties and gathering, processing, and transmission facilities were recorded in 2020 and 2019. For discussion of these impairments, see “Fair Value Measurements” of Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements.

Asset Retirement Obligation (ARO)

The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms in the North Sea and Gulf of Mexico. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.

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ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

Income Taxes

The Company’s oil and gas exploration and production operations are subject to taxation on income in numerous jurisdictions worldwide. The Company records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in its financial statements and tax returns. Management routinely assesses the ability to realize the Company’s deferred tax assets. If management concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices).

The Company regularly assesses and, if required, establishes accruals for uncertain tax positions that could result from assessments of additional tax by taxing jurisdictions in countries where the Company operates. The Company recognizes 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, case law, and any new legislation. The Company believes that its accruals for uncertain tax positions are adequate in relation to the potential for any additional tax assessments.