# APA Corp (APA) FY 2022 MD&A

Verbatim Item 7 Management's Discussion and Analysis from APA Corp's 10-K for fiscal year 2022.

SEC filing source: https://www.sec.gov/Archives/edgar/data/1841666/000178403123000007/apa-20221231.htm
Accession: 0001784031-23-000007
Filing date: 2023-02-23
Report date: 2022-12-31
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/
Previous year: /company/APA/mda/fy2021/ (FY 2021)
Next year: /company/APA/mda/fy2023/ (FY 2023)

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 2022 and 2021 items and year-to-year comparisons between 2022 and 2021. Discussions of 2020 items and year-to-year comparisons between 2021 and 2020 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, 2021 (filed with the SEC on February 22, 2022).

On March 1, 2021, Apache Corporation consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which Apache Corporation became a direct, wholly owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares 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. As a holding company, APA Corporation’s primary assets are its ownership interests in its subsidiaries.

Overview

APA is an independent energy company that owns consolidated subsidiaries that explore for, develop, and produce 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 the Dominican Republic and other international locations that may, over time, result in reportable discoveries and development opportunities. Prior to the BCP Business Combination defined below, the Company’s midstream business was operated by Altus. Altus owned, developed, and operated 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. APA strives to meet those challenges while creating value for all its stakeholders.

Early in 2020, impacts of the coronavirus disease 2019 (COVID-19) pandemic and related governmental actions began to exert significant downward pressure on crude oil and natural gas prices. Since that time, commodity prices worldwide have largely rebounded; however, uncertainties in the global supply chain, commodity prices, and financial markets, including the impact of inflation, rising interest rates, and the conflict in Ukraine 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 shareholders. 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 2022, the Company reported net income attributable to common stock of $3.7 billion, or $11.02 per diluted share, compared to net income of $973 million, or $2.59 per diluted share, in 2021. Net income in 2022 benefited from higher commodity prices and increased revenues attributable to a new merged concession agreement in Egypt. The increase in realized prices was primarily driven by the effects of global inflation, the conflict in Ukraine on global commodity prices, and uncertainties around spare capacity and energy security globally.

35

The Company generated $4.9 billion of cash from operating activities in 2022, which was $1.4 billion or 41 percent higher than the prior year. APA’s higher operating cash flows for 2022 were driven by higher crude oil and natural gas prices and associated revenues. Since year-end 2021, the Company has reduced its total outstanding debt and redeemable preferred interests by $2 billion and $712 million, respectively, through the deconsolidation of ALTM and the retirement of outstanding notes and debentures. The Company also repurchased 36.2 million shares of its common stock for $1.4 billion during 2022. The Company had $245 million of cash on hand at December 31, 2022.

The Company remains committed to its capital return framework established in 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’s quarterly dividend was increased in the fourth quarter of 2021 from $0.0625 per share to $0.125 per share. The dividend was further increased in the third quarter of 2022 to $0.25 per share, representing a return to pre-COVID-19 dividend levels.

•Beginning in the fourth quarter of 2021 and through the end of 2022, the Company has repurchased 67.4 million shares of the Company’s common stock. As of December 31, 2022, the Company had remaining authorization to repurchase up to 52.6 million shares under the Company’s share repurchase programs.

The Company does not anticipate any significant changes to activity levels in its three-year capital investment program or capital return framework in the context of higher strip oil and gas prices, remaining committed to safe, steady, and efficient operations across all assets and returning free cash flow to shareholders through dividends and share repurchases.

Operational Highlights

Key operational highlights for the year include:

United States

•Daily boe production from the Company’s U.S. assets, which decreased 8 percent from the prior year end, accounted for 53 percent of its total worldwide production during 2022. During 2022, the Company averaged 4 drilling rigs in the U.S., averaging 2 rigs each in the Southern Midland Basin and Delaware Basin assets. The Company’s core Midland Basin development program and newly acquired properties in the Texas Delaware Basin are expected to represent key growth areas for the U.S. assets.

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, having an effective date of April 1, 2021. The new merged concession agreement (MCA) consolidated 98 percent of gross acreage and 90 percent of gross production under one concession agreement 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).

•Egypt gross equivalent production decreased 1 percent and net production increased 26 percent from 2021, primarily a function of improved cost recovery under the new merged concession agreement ratified at the end of 2021. The Company continues to build and enhance its drilling inventory in Egypt, supplemented with recent seismic acquisitions and new play concept evaluations on both new and existing acreage. The Company continues to increase drilling and workover activity as a result of the merged concession agreement. Egypt production growth is building on improvements in new well connections and recompletion activity.

•During 2022, the Company focused on several environmental initiatives in Egypt and has delivered on its 2022 upstream flaring reduction goal by flaring at least 40 percent less gas than would otherwise be flared without these initiatives, with the Company now compressing this gas into sales lines.

36

•The North Sea maintained two drilling rigs during 2022. Production was negatively impacted by considerable planned and unplanned downtime at Beryl and Forties during the third quarter of 2022, improving in the fourth quarter of 2022 following completion of these maintenance activities.

•During the second quarter of 2022, the Company announced flow test results from the Krabdagu exploration well on Block 58 offshore Suriname, which encountered approximately 32 meters of net pay in each of the Upper Campanian and Lower Campanian zones. Since 2019, the Company and TotalEnergies have drilled or participated in five discovery wells in the block, the Maka Central-1, Sapakara West-1, Kwaskwasi-1, Keskesi East-1, and Krabdagu-1, all of which successfully tested for the presence of hydrocarbons. Ongoing exploration and appraisal drilling is continuing to confirm additional resource and optimal development well locations. APA holds a 50 percent working interest in Block 58, with TotalEnergies, the operator, holding the other 50 percent working interest.

•During the third quarter of 2022, the Company announced an oil discovery offshore Suriname at Baja-1 in Block 53. Baja-1 was drilled to a depth of 5,290 meters and encountered 34 meters of net oil pay in a single interval within the Campanian. Fluid and log analysis indicates light oil with a gas-oil ratio of 1,600 to 2,200 standard cubic feet per barrel. Evaluation of open-hole well logs, cores, and reservoir fluids is ongoing. The Company also received regulatory approval regarding an amendment to the Block 53 production-sharing contract which provides options to extend the exploration period of the contract. The first option was executed and extended the license to year-end 2023, with the option to extend further, subject to certain other investment commitments. APA is the operator and holds a 45 percent interest in Block 53.

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 acquisitions and divestitures designed to enhance the Company’s portfolio and monetize nonstrategic assets in order to allocate resources to more impactful exploration and development opportunities. These acquisitions and divestitures during 2022 include:

•BCP Business Combination On February 22, 2022, ALTM closed a transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik). As consideration for the contribution of the Contributed Interests, ALTM issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP’s unitholders.

ALTM’s stockholders continued to hold their existing shares of ALTM common stock. Apache Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM common stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock after the transaction closed. The Company deconsolidated ALTM upon closing the transaction and recognized a gain of approximately $609 million that reflects the difference of the Company’s share of ALTM’s deconsolidated balance sheet and the fair value of its 20 percent retained ownership in the combined entity.

Subsequent to the close of the transaction, in March 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for $224 million, reducing the Company’s retained ownership percentage in Kinetik to approximately 13 percent.

37

•Delaware Basin Divestitures & Acquisitions In the third quarter of 2022, the Company closed on the acquisition of oil and gas assets surrounding core acreage in the Delaware Basin for approximately $615 million after post-closing adjustments. The Company paid $591 million in connection with this acquisition during 2022, with final cash settlement anticipated to be completed during the first quarter of 2023. Also during 2022, the Company completed a previously announced transaction to sell certain non-core mineral rights in the Delaware Basin, for total cash proceeds of $726 million.

•U.S. Leasehold Acquisitions During 2022, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $37 million.

•U.S. Leasehold Divestitures & Other During 2022, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $52 million.

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.

38

Results of Operations

Oil, Natural Gas, and Natural Gas Liquids Production Revenues

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

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2022","","2021","","2020"],["","","$ Value","","% Contribution","","$ Value","","% Contribution","","$ Value","","% Contribution"],["","","($ in millions)"],["Oil Revenues:"],["United States","","$","2,458","","","36","%","","$","1,850","","","40","%","","$","1,209","","","39","%"],["Egypt(1)","","3,145","","","46","%","","1,806","","","40","%","","1,102","","","35","%"],["North Sea","","1,232","","","18","%","","929","","","20","%","","795","","","26","%"],["Total(1)","","$","6,835","","","100","%","","$","4,585","","","100","%","","$","3,106","","","100","%"],["Natural Gas Revenues:"],["United States","","$","918","","","59","%","","$","754","","","62","%","","$","251","","","42","%"],["Egypt(1)","","370","","","23","%","","270","","","23","%","","280","","","47","%"],["North Sea","","281","","","18","%","","183","","","15","%","","67","","","11","%"],["Total(1)","","$","1,569","","","100","%","","$","1,207","","","100","%","","$","598","","","100","%"],["NGL Revenues:"],["United States","","$","765","","","94","%","","$","673","","","95","%","","$","304","","","91","%"],["Egypt(1)","","6","","","1","%","","9","","","1","%","","8","","","3","%"],["North Sea","","45","","","5","%","","24","","","4","%","","21","","","6","%"],["Total(1)","","$","816","","","100","%","","$","706","","","100","%","","$","333","","","100","%"],["Oil and Gas Revenues:"],["United States","","$","4,141","","","45","%","","$","3,277","","","50","%","","$","1,764","","","44","%"],["Egypt(1)","","3,521","","","38","%","","2,085","","","32","%","","1,390","","","34","%"],["North Sea","","1,558","","","17","%","","1,136","","","18","%","","883","","","22","%"],["Total(1)","","$","9,220","","","100","%","","$","6,498","","","100","%","","$","4,037","","","100","%"]]
[[/GREPCENT_TABLE]]

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

39

Production

The following table presents production volumes by country:

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2022","","Increase (Decrease)","","2021","","Increase (Decrease)","","2020"],["Oil Volumes \u2013 b/d:"],["United States(5)","","70,398","","","(6)%","","75,205","","","(15)%","","88,249"],["Egypt(3)(4)","","85,081","","","21%","","70,349","","","(7)%","","75,384"],["North Sea","","32,578","","","(10)%","","36,265","","","(28)%","","50,386"],["Total","","188,057","","","3%","","181,819","","","(15)%","","214,019"],["Natural Gas Volumes \u2013 Mcf/d:"],["United States(5)","","473,292","","","(10)%","","527,461","","","(6)%","","561,731"],["Egypt(3)(4)","","356,327","","","35%","","263,653","","","(4)%","","274,175"],["North Sea","","35,327","","","(8)%","","38,565","","","(33)%","","57,464"],["Total","","864,946","","","4%","","829,679","","","(7)%","","893,370"],["NGL Volumes \u2013 b/d:"],["United States(5)","","62,727","","","(5)%","","66,232","","","(11)%","","74,136"],["Egypt(3)(4)","","196","","","(63)%","","531","","","(30)%","","754"],["North Sea","","1,111","","","(7)%","","1,199","","","(38)%","","1,936"],["Total","","64,034","","","(6)%","","67,962","","","(12)%","","76,826"],["BOE per day:(1)"],["United States(5)","","212,007","","","(8)%","","229,348","","","(10)%","","256,007"],["Egypt(3)(4)","","144,665","","","26%","","114,821","","","(6)%","","121,834"],["North Sea(2)","","39,577","","","(10)%","","43,892","","","(29)%","","61,899"],["Total","","396,249","","","2%","","388,061","","","(12)%","","439,740"]]
[[/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 40,812 boe/d, 44,179 boe/d, and 62,157 boe/d for 2022, 2021, and 2020, 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]]
[["","","2022","","","","2021","","","","2020"],["Oil (b/d)","","137,260","","","","","134,711","","","","","164,104"],["Natural Gas (Mcf/d)","","555,562","","","","","586,663","","","","","641,069"],["NGL (b/d)","","297","","","","","854","","","","","1,429"]]
[[/GREPCENT_TABLE]]

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

[[GREPCENT_TABLE]]
[["","","2022","","","","2021","","","","2020"],["Oil (b/d)","","28,200","","","","","23,504","","","","","25,206"],["Natural Gas (Mcf/d)","","118,074","","","","","88,409","","","","","91,540"],["NGL (b/d)","","65","","","","","177","","","","","251"]]
[[/GREPCENT_TABLE]]

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

[[GREPCENT_TABLE]]
[["","","2022","","","","2021","","","","2020"],["Oil (b/d)","","777","","","","","1,485","","","","","2,718"],["Natural Gas (Mcf/d)","","192,253","","","","","258,096","","","","","274,279"],["NGL (b/d)","","18,362","","","","","22,950","","","","","24,942"]]
[[/GREPCENT_TABLE]]

40

Pricing

The following table presents pricing information by country:

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2022","","Increase (Decrease)","","2021","","Increase (Decrease)","","2020"],["Average Oil Price - Per barrel:"],["United States","","$","95.68","","","42%","","$","67.37","","","80%","","$","37.42"],["Egypt","","101.25","","","44%","","70.33","","","76%","","39.95"],["North Sea","","100.87","","","45%","","69.67","","","62%","","42.88"],["Total","","99.11","","","44%","","68.97","","","74%","","39.60"],["Average Natural Gas Price - Per Mcf:"],["United States","","$","5.31","","","35%","","$","3.92","","","221%","","$","1.22"],["Egypt","","2.85","","","1%","","2.81","","","1%","","2.79"],["North Sea","","23.36","","","80%","","12.96","","","306%","","3.19"],["Total","","4.98","","","25%","","3.99","","","118%","","1.83"],["Average NGL Price - Per barrel:"],["United States","","$","33.41","","","20%","","$","27.85","","","148%","","$","11.21"],["Egypt","","76.80","","","57%","","48.84","","","75%","","27.83"],["North Sea","","67.07","","","24%","","54.30","","","83%","","29.73"],["Total","","34.51","","","21%","","28.48","","","141%","","11.84"]]
[[/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 2022 were up 44 percent compared to 2021, a direct result of the rising benchmark oil prices over the past year. Crude oil prices realized in 2022 averaged $99.11 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 sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. The Company’s U.S. realizations averaged $5.31 per Mcf in 2022, a 35 percent increase from an average of $3.92 per Mcf in 2021.

•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 $2.85 per Mcf in 2022, a 1 percent increase from an average of $2.81 per Mcf in 2021.

•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 $23.36 per Mcf in 2022, an 80 percent increase from an average of $12.96 per Mcf in 2021.

41

NGL Prices The Company’s U.S. NGL production, which accounted for 98 percent of the Company’s total 2022 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 2022 totaled $6.8 billion, a $2.2 billion increase from the 2021 total of $4.6 billion. A 44 percent increase in average realized prices increased 2022 revenues by $2.0 billion compared to 2021, while 3 percent higher average daily production increased revenues by $251 million. Average daily production in 2022 was 188 Mb/d, with prices averaging $99.11 per barrel. Crude oil sales accounted for 74 percent of the Company’s 2022 oil and gas production revenues and 48 percent of its worldwide production.

The Company’s worldwide crude oil production increased 6 Mb/d compared to 2021, primarily a function of improved cost recovery under the merged concession agreement in Egypt ratified at the end of 2021, offset by extended operational downtime in the North Sea and natural production decline across all assets.

Natural Gas Revenues 

Natural gas revenues for 2022 totaled $1.6 billion, a $362 million increase from the 2021 total of $1.2 billion. A 25 percent increase in average realized prices increased 2022 revenues by $301 million compared to 2021, while 4 percent higher average daily production increased revenues by $61 million. Average daily production in 2022 was 865 MMcf/d, with prices averaging $4.98 per Mcf. Natural gas sales accounted for 17 percent of the Company’s 2022 oil and gas production revenues and 36 percent of its worldwide production.

The Company’s worldwide natural gas production increased 35 MMcf/d compared to 2021, primarily a result of increased net production in Egypt resulting from improved cost recovery under the merged concession agreement ratified at the end of 2021, offset by extended operational downtime in the North Sea and natural production decline across all assets.

NGL Revenues  

NGL revenues for 2022 totaled $816 million, a $110 million increase from the 2021 total of $706 million. A 21 percent increase in average realized prices increased 2022 revenues by $149 million compared to 2021, while 6 percent lower average daily production decreased revenues by $39 million. Average daily production in 2022 was 64 Mb/d, with prices averaging $34.51 per barrel. NGL sales accounted for 9 percent of the Company’s 2022 oil and gas production revenues and 16 percent of its worldwide production.

The Company’s worldwide NGL production decreased 4 Mb/d compared to 2021, primarily a result of natural production decline in the U.S.

Altus Midstream Revenues

Prior to the deconsolidation of Altus on February 22, 2022, the Company beneficially owned approximately 79 percent of ALTM’s outstanding voting common stock. Altus owned and operated 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.

Altus Midstream primarily generated revenue by providing fee-based natural gas gathering, compression, processing, and transmission services. For the years ended December 31, 2022 and 2021, Altus Midstream’s service revenues generated through its fee-based contractual arrangements with the Company totaled $16 million and $127 million, respectively. These affiliated revenues were eliminated upon consolidation.

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 $368 million for the year ended December 31, 2022 to $1.9 billion from $1.5 billion in the prior year. Purchased oil and gas sales were offset by associated purchase costs of $1.8 billion and $1.6 billion for the years ended December 31, 2022 and 2021, respectively. The increase is a result of higher average natural gas prices during 2022 compared to the prior year.

42

Operating Expenses

The table below presents a comparison of the Company’s operating expenses for the years ended December 31, 2022, 2021, and 2020. All operating expenses include costs attributable to a noncontrolling interest in Egypt and Altus.

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2022","","2021","","2020"],["","","(In millions)"],["Lease operating expenses","","$","1,444","","","$","1,241","","","$","1,127"],["Gathering, processing, and transmission","","367","","","264","","","274"],["Purchased oil and gas costs","","1,776","","","1,580","","","357"],["Taxes other than income","","268","","","204","","","123"],["Exploration","","305","","","155","","","274"],["General and administrative","","483","","","376","","","290"],["Transaction, reorganization, and separation","","26","","","22","","","54"],["Depreciation, depletion, and amortization:"],["Oil and gas property and equipment","","1,186","","","1,255","","","1,643"],["Gathering, processing, and transmission assets","","15","","","64","","","76"],["Other assets","","32","","","41","","","53"],["Asset retirement obligation accretion","","117","","","113","","","109"],["Impairments","","\u2014","","","208","","","4,501"],["Financing costs, net","","379","","","514","","","267"]]
[[/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 48 percent of the Company’s total 2022 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.

During 2022, LOE increased $203 million, or 16 percent, compared to 2021. On a per-boe basis, LOE increased $1.20, or 14 percent, compared to 2021, from $8.75 per boe to $9.95 per boe. The increase in costs was driven by higher labor costs and operating costs trending with higher oil and gas prices and global inflation, coupled with higher workover activity in the U.S. during 2022.

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,"],["","","2022","","2021","","2020"],["","","(In millions)"],["Third-party processing and transmission costs","","$","269","","","$","232","","","$","236"],["Midstream service costs - ALTM","","18","","","128","","","143"],["Midstream service costs - Kinetik","","93","","","\u2014","","","\u2014"],["Upstream processing and transmission costs","","380","","","360","","","379"],["Midstream operating expenses","","5","","","32","","","38"],["Intersegment eliminations","","(18)","","","(128)","","","(143)"],["Total Gathering, processing, and transmission","","$","367","","","$","264","","","$","274"]]
[[/GREPCENT_TABLE]]

43

GPT costs increased $103 million compared to 2021. Third-party processing and transmission costs increased $37 million, primarily driven by an increase in average transportation rates during the year. Costs for services provided by ALTM in the first quarter of 2022 and prior to the BCP Business Combination totaling $18 million were eliminated in the Company’s consolidated financial statements and reflected as “Intersegment eliminations” in the table above. Subsequent to the BCP Business Combination and the Company’s deconsolidation of Altus on February 22, 2022, these midstream services continue to be provided by Kinetik but are no longer eliminated. Midstream services provided by Kinetik totaled $93 million for the year ended 2022.

Purchased Oil and Gas Costs

Purchased oil and gas costs increased $196 million compared to 2021, and were primarily offset by associated sales totaling $1.9 billion for the year ended 2022, as 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 $64 million compared to 2021, 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,"],["","","2022","","2021","","2020"],["","","(In millions)"],["Unproved leasehold impairments","","$","24","","","$","31","","","$","101"],["Dry hole expenses","","183","","","66","","","110"],["Geological and geophysical expenses","","23","","","18","","","20"],["Exploration overhead and other","","75","","","40","","","43"],["Total Exploration","","$","305","","","$","155","","","$","274"]]
[[/GREPCENT_TABLE]]

Exploration expenses increased $150 million compared to 2021, primarily the result of higher dry hole expenses in Suriname and Egypt and higher exploration overhead, a function of increased exploration activities.

General and Administrative (G&A) Expenses

G&A expenses increased $107 million compared to 2021, primarily driven by higher cash-based stock compensation expense resulting from an increase in the Company’s stock price and achievement of performance and financial objectives as defined in the stock award plans. Higher overall wages across the Company and global inflationary pressures also impacted G&A expenses compared to the prior-year period.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs increased $4 million compared to 2021, primarily a result of transaction costs from the BCP Business Combination, partially offset by a decrease in costs associated with the Company’s prior year reorganization efforts that are substantially completed.

44

Depreciation, Depletion and Amortization (DD&A)

DD&A expenses on the Company’s oil and gas property for the year ended December 31, 2022 decreased $69 million compared to 2021. The Company’s oil and gas property DD&A rate decreased $0.67 per boe in 2022 compared to 2021, from $8.85 per boe to $8.18 per boe. The decrease on an absolute basis was driven by lower depletion rates in Egypt under the new merged concession agreement, partially offset by higher production volumes. DD&A expense on the Company’s GPT depreciation decreased $49 million compared to 2021, primarily driven by certain Egyptian assets being fully depreciated coupled with the deconsolidation of Altus during the first quarter of 2022.

Impairments

No asset impairments were recorded in 2022. During 2021, the Company recorded asset impairments totaling $208 million. The charges include $160 million for Altus’ equity method interests, $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.

The following table presents a summary of asset impairments recorded for 2022, 2021, and 2020:

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2022","","2021","","2020"],["","","(In millions)"],["Oil and gas proved property","","$","\u2014","","","$","\u2014","","","$","4,319"],["GPT facilities","","\u2014","","","\u2014","","","68"],["Equity method interests","","\u2014","","","160","","","\u2014"],["Goodwill","","\u2014","","","\u2014","","","87"],["Inventory and other","","\u2014","","","48","","","27"],["Total Impairments","","$","\u2014","","","$","208","","","$","4,501"]]
[[/GREPCENT_TABLE]]

Financing Costs, Net

Financing costs incurred during 2022, 2021, and 2020 comprised the following:

[[GREPCENT_TABLE]]
[["","","For the Year Ended December 31,"],["","","2022","","2021","","2020"],["","","(In millions)"],["Interest expense","","$","332","","","$","419","","","$","438"],["Amortization of debt issuance costs","","8","","","8","","","8"],["Capitalized interest","","(18)","","","(9)","","","(12)"],["Loss (gain) on extinguishment of debt","","67","","","104","","","(160)"],["Interest income","","(10)","","","(8)","","","(7)"],["Total Financing costs, net","","$","379","","","$","514","","","$","267"]]
[[/GREPCENT_TABLE]]

Net financing costs during 2022 decreased $135 million compared to 2021, primarily the result of the reduction of fixed-rate debt during 2021 and the first half of 2022. Additionally, losses incurred on the extinguishment of debt were lower during 2022 compared to the prior year period.

45

Provision for Income Taxes

Income tax expense increased $1.1 billion from $578 million during 2021 to $1.7 billion during 2022. The Company’s year-to-date 2022 effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of the Energy (Oil and Gas) Profits Levy Act 2022 (the Energy Profits Levy) on July 14, 2022, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During 2021, the Company’s 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.

On May 26, 2022, the U.K. Chancellor of the Exchequer announced a new tax (the Energy Profits Levy) on the profits of oil and gas companies operating in the U.K. and the U.K. Continental Shelf. Under the new law, an additional levy is assessed at a 25 percent rate and is effective for the period of May 26, 2022, through December 31, 2025. The Company recorded a deferred tax expense of $208 million associated with the remeasurement of the U.K. deferred tax liability. On November 17, 2022, the U.K. Chancellor of the Exchequer announced in the Autumn Statement 2022 further changes to the Energy Profits Levy, increasing the levy assessed from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023, through March 31, 2028. On November 22, 2022, the U.K. Government published draft legislation to implement this change, among other provisions, and on January 10, 2023, the Finance Act 2023 was enacted, receiving Royal Assent. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, in the first quarter of 2023, the Company expects to record a deferred tax expense of approximately $170 million to $190 million related to the remeasurement of the December 31, 2022 U.K. deferred tax liability.

On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (Corporate AMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1 billion for any three consecutive years preceding the tax year at issue. The Corporate AMT is effective for tax years beginning after December 31, 2022. The Company is continuing to evaluate the provisions of the IRA and awaits further guidance from the U.S. Treasury Department to properly assess the impact of these provisions on the Company.

The Company recorded a full valuation allowance against its U.S. net deferred tax assets. The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the existing deferred tax assets. A significant piece of negative evidence evaluated was the U.S. pre-tax book cumulative loss incurred over the three-year period ended December 31, 2022. This cumulative loss was primarily the result of low commodity prices and oil and gas impairments during this period. Such objective evidence limits the ability to consider other subjective evidence, such as the Company’s projections for future growth.

However, given the Company’s current and anticipated future domestic earnings, the Company believes that there is a reasonable possibility that within the next 12 months the U.S. will exit its cumulative loss, allowing the Company to reach a conclusion that a material portion of the U.S. valuation allowance may no longer be needed. A release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense, which could be material for the period the release is recorded. 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.

46

Capital and Operational Outlook

The Company continues to prudently manage its capital program against a volatile price environment and the effects of global inflation and rising interest rates. 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 shareholders.

The Company’s 2023 capital program will maintain a similar investment approach to the prior year while reflecting potential inflationary impacts, with upstream capital investment budgeted at $2.0 billion to $2.1 billion. Based on the planned levels of capital activity, the Company anticipates 2023 worldwide production levels will increase approximately four to five percent compared with 2022 volumes. Higher oil volumes in Egypt and the U.S. will be the primary contributors of this growth and are anticipated to more than offset natural gas production declines in both regions. In the North Sea, the Company anticipates a modest production rebound in 2023, with three new wells planned to commence production in the first half of the year and less scheduled maintenance turnaround. The Company plans to release the Ocean Patriot semi-submersible drilling rig around mid-year 2023 once it completes its scheduled drilling campaign in the North Sea. Reallocation of this capital to other areas is being evaluated, as recent tax changes in the U.K. have made returns in the North Sea less attractive than other investment opportunities within the Company’s portfolio. In Suriname, activity in the first half of 2023 is focused on the two appraisal wells being drilled at Krabdagu and subsequent flow testing. Following that, another exploration test on Block 58 is also planned.

At current strip pricing, the Company expects to generate significant cash flow over this capital activity budget. The Company’s current commitment to return capital to shareholders through a mix of dividends and share buybacks remains unchanged.

47

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 sustained decreases 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, 2022, the Company recognized a slight upward reserve revision related to increases in commodity prices during the year. The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2022, 2021, and 2020, 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 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.

48

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,"],["","","2022","","2021","","2020"],["","","(In millions)"],["Sources of Cash and Cash Equivalents:"],["Net cash provided by operating activities","","$","4,943","","","$","3,496","","","$","1,388"],["Proceeds from APA and Apache credit facilities, net","","24","","","392","","","150"],["Proceeds from Altus credit facility, net","","\u2014","","","33","","","228"],["Proceeds from asset divestitures","","778","","","256","","","166"],["Fixed-rate debt borrowings","","\u2014","","","\u2014","","","1,238"],["Proceeds from sale of Kinetik shares","","224","","","\u2014","","","\u2014"],["Other, net","","11","","","20","","","\u2014"],["","","5,980","","","4,197","","","3,170"],["Uses of Cash and Cash Equivalents:"],["Additions to upstream oil and gas property(1)","","1,770","","","1,101","","","1,270"],["Acquisition of Delaware Basin properties","","591","","","\u2014","","","\u2014"],["Leasehold and property acquisitions","","37","","","9","","","4"],["Contributions to Altus equity method interests","","\u2014","","","28","","","327"],["Payments on fixed-rate debt","","1,493","","","1,795","","","1,243"],["Dividends paid to APA common stockholders","","207","","","52","","","123"],["Distributions to noncontrolling interest - Egypt","","362","","","279","","","91"],["Distributions to Altus Preferred Unit limited partners","","11","","","46","","","23"],["Treasury stock activity, net","","1,423","","","847","","","\u2014"],["Deconsolidation of Altus cash and cash equivalents","","143","","","\u2014","","","\u2014"],["Other, net","","\u2014","","","\u2014","","","74"],["","","6,037","","","4,157","","","3,155"],["Increase (decrease) in cash and cash equivalents","","$","(57)","","","$","40","","","$","15"]]
[[/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, 2022 totaled $4.9 billion, up $1.4 billion from the year ended December 31, 2021, 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 APA and Apache Credit Facilities, Net As of December 31, 2022, there were outstanding borrowings of $566 million under APA’s syndicated credit facilities. As of December 31, 2021, there were outstanding borrowings of $542 million under Apache’s former syndicated credit facility. These borrowings are classified as long-term debt.

Proceeds from Altus Credit Facility, Net During the year ended December 31, 2021, Altus Midstream LP borrowed $33 million under its revolving credit facility to fund capital contributions to its equity method interests. Prior to the deconsolidation of Altus on February 22, 2022, there were no additional borrowings under this facility in 2022.

49

Proceeds from Asset Divestitures The Company received $778 million and $256 million in proceeds from the divestiture of certain non-core assets during the years ended December 31, 2022 and 2021, respectively. The Company also received $224 million of cash proceeds from the sale of four million of its shares in Kinetik during 2022. 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.

Uses of Cash and Cash Equivalents

Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $1.8 billion and $1.1 billion for the years ended December 31, 2022 and 2021, respectively. The increase in capital investment is reflective of the increase in the Company’s capital program in 2022 associated with higher cash flow from operations. The Company operated an average of 22 drilling rigs during 2022, compared to an average of 13 drilling rigs during 2021.

Acquisition of Delaware Basin Properties During 2022, the Company completed the acquisition of oil and gas assets in the Delaware Basin for approximately $615 million, after post-closing adjustments. Cash consideration paid totaled $591 million, with final cash settlement anticipated to be completed during the first quarter of 2023.

Leasehold and Property Acquisitions During 2022 and 2021, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $37 million and $9 million, respectively.

Payments on Fixed-Rate Debt On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 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 former revolving credit facility.

During the quarter ended March 31, 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.

During the quarter ended March 31, 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of an aggregate $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.

On October 17, 2022, Apache redeemed the outstanding $123 million outstanding principal amount of 2.625% notes due January 15, 2023, 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 in part by Apache’s borrowing under the Company’s U.S. dollar-denominated revolving credit facility.

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.

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

50

Dividends Paid to APA Common Stockholders The Company paid $207 million and $52 million during the years ended December 31, 2022 and 2021, respectively, for dividends on its common stock. 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, a further increase to $0.125 per share. During the third quarter of 2022, the Company’s Board of Directors approved a further increase to its quarterly dividend to $0.25 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 $362 million and $279 million during the years ended December 31, 2022 and 2021, respectively, in cash distributions to Sinopec.

Distributions to Altus Preferred Unit Limited Partners Prior to the deconsolidation of Altus on February 22, 2022, Altus Midstream LP paid $11 million and $46 million in cash distributions to its limited partners holding Preferred Units during the years ended December 31, 2022 and 2021, 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.

Treasury Stock Activity, Net During 2022, the Company repurchased 36.2 million shares at an average price of $39.34 per share totaling $1.4 billion, and as of December 31, 2022, the Company had remaining authorization to repurchase 52.6 million shares. During 2021, the Company repurchased 31.2 million shares at an average price of $27.14 per share totaling $847 million.

Liquidity

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

[[GREPCENT_TABLE]]
[["","","2022","","2021"],["","","(In millions)"],["Cash and cash equivalents","","$","245","","","$","302"],["Total debt - APA and Apache","","5,453","","","6,853"],["Total debt - Altus","","\u2014","","","657"],["Total equity (deficit)","","1,345","","","(717)"],["Available committed borrowing capacity under syndicated credit facilities","","2,238","","","2,426"],["Available committed borrowing capacity - Altus","","\u2014","","","141"]]
[[/GREPCENT_TABLE]]

Cash and Cash Equivalents As of December 31, 2022, the Company had $245 million in cash and cash equivalents. 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, 2022, the Company had $5.5 billion in total debt outstanding, which consisted of notes and debentures of Apache, credit facility borrowings, and finance lease obligations. Future interest payments on the fixed-rate notes and debentures are approximately $4.2 billion. As of December 31, 2022, current debt included $2 million of finance lease obligations.

Committed Credit Facilities On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility).

•One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

•The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

51

In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a New Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under the USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a New Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.

As of December 31, 2022, there were $566 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £652 million in letters of credit outstanding under the GBP Agreement. 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 the Former Facility. The 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.

All borrowings under the USD Agreement bear interest at one of two per annum rate options selected by the borrower, being either an alternate base rate (as defined), plus a margin ranging from 0.10% to 0.675% (Base Rate Margin), or an adjusted term SOFR rate (as defined), plus a margin varying from 1.10% to 1.675% (Applicable Margin). All borrowings under the GBP Agreement bear interest at an adjusted rate per annum determined by reference to the Sterling Overnight Index Average published by the Bank of England, plus the Applicable Margin. Each New Agreement also requires the borrower to pay quarterly a facility fee on total commitments. Margins and facility fees are at varying rates per annum determined by reference to the senior, unsecured, non-credit enhanced, long-term indebtedness for borrowed money of APA, or if such indebtedness is not rated and the Apache guaranty is in effect, of Apache (Long-Term Debt Rating). As of December 31, 2022, Apache’s Long-Term Debt Rating applied, and the Base Rate Margin was 0.60%, the Applicable Margin was 1.60%, and the facility fee was 0.275%.

A commission is payable quarterly to lenders under each New Agreement on the face amount of each outstanding letter of credit at a per annum rate equal to the Applicable Margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks.

Borrowers under each New Agreement, which may include certain subsidiaries of APA, may borrow, prepay, and reborrow loans and obtain letters of credit, and APA may obtain letters of credit for the account of its subsidiaries, in each case subject to representations and warranties, covenants, and events of default substantially similar to those in the Former Facility, such as:

•A financial covenant requires APA 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 continues to exclude the effects of non-cash write-downs, impairments, and related charges occurring after June 30, 2015. At December 31, 2022, APA’s debt-to-capital ratio as calculated under each New Agreement was 21 percent.

• A negative covenant restricts the ability of APA 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 U. S. and Canada; and liens arising as a matter of law, such as tax and mechanics’ liens. Liens on assets also are permitted if debt secured thereby does not exceed 15 percent of APA’s consolidated net tangible assets or approximately $1.5 billion as of December 31, 2022.

• Negative covenants restrict APA’s ability to merge with another entity unless it is the surviving entity, a borrower’s disposition of substantially all of its assets, prohibitions on the ability of certain subsidiaries to make payments to borrowers, and guarantees by APA or certain subsidiaries of debt of non-consolidated entities in excess of the stated threshold.

• Lenders may accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches; if a borrower or certain subsidiaries defaults on other indebtedness in excess of the stated threshold, has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold, or has specified pension plan liabilities in excess of the stated threshold; or APA undergoes a specified change in control. Such acceleration and termination are automatic upon specified insolvency events of a borrower or certain subsidiaries.

52

Consistent with the Former Facility, the New Agreements do not require collateral, do not have a borrowing base, do not permit lenders to accelerate maturity or refuse to lend based on unspecified material adverse changes, and do not have borrowing restrictions or prepayment obligations in the event of a decline in credit ratings.

The Company was in compliance with the terms of each New Agreement as of December 31, 2022.

In November 2018, Altus and its subsidiary, Altus Midstream LP (Altus LP), were subsidiaries of Apache, and Altus LP entered into an unsecured revolving credit facility for general corporate purposes. The agreement for the facility, as amended, provided aggregate commitments from a syndicate of banks of $800 million, including a letter of credit subfacility. The credit facility was not guaranteed by APA, Apache, or any of APA’s other subsidiaries. On February 22, 2022, Altus was deconsolidated from APA and Apache. As of December 31, 2021, there were $657 million of borrowings and $2 million letters of credit outstanding under the facility.

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 APA or its subsidiaries or the composition of such lenders.

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

Uncommitted Credit Facilities The Company from time to time has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of December 31, 2022 and 2021, there were no outstanding borrowings under these facilities. As of December 31, 2022, there were £199 million and $17 million in letters of credit outstanding under these facilities. As of December 31, 2021, there were £117 million and $17 million in letters of credit outstanding under these facilities.

Former Apache 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, 2022, the Company had contractual obligations totaling $3.0 billion, of which $1.0 billion is related to U.S. firm transportation contracts, $1.8 billion is related to the new merged concession agreement with the EGPC, and $0.2 billion of other items. Under terms agreed to in the Egypt modernized PSC, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. As of December 31, 2022, the Company has spent $1.7 billion and believes it will be able to satisfy the remaining 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 (FASB) Accounting Standards Codification (ASC) Topic 842 (Leases). As of December 31, 2022, the Company had net minimum commitments of $315 million and $45 million for operating and finance leases, respectively.

53

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 $1 million for environmental remediation and approximately $64 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.

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. 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.

54

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.

By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently obligated 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 expects to 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.

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, 2022, 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, the Company has recorded a contingent liability of $1.2 billion as of December 31, 2022, representing the estimated costs of decommissioning it may be required to perform on Legacy GOM Assets. Of the total liability recorded, $738 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $450 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. 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.

As of December 31, 2022, the Company has also recorded a $667 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, $217 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $450 million is reflected under “Other current assets.” The Company recognized $157 million and $446 million during 2022 and 2021, respectively, of “Losses on previously sold Gulf of Mexico properties” to reflect the net impact of changes to the estimated decommissioning liability and decommissioning asset to the Company’s statement of consolidated operations.

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.

55

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.

Apache 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 Apache on past due invoices and (2) expropriation of exportable petroleum in the event that actions taken by the government of Egypt prevent Apache 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.

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 significant judgment involved 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.

56

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 potential decommissioning obligations on sold properties estimated and recorded in the third quarter of 2021, please refer to “Potential Decommissioning Obligations on 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.

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.

Altus recorded an impairment charge on its equity method interest in the EPIC crude oil pipeline (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.

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.

57

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. 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.

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.