EDGAR 10-K Filing

Company CIK: 1841666
Filing Year: 2022
Filename: 1841666_10-K_2022_0001784031-22-000009.json

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ITEM 1. BUSINESS
ITEMS 1 and 2. BUSINESS AND PROPERTIES
GENERAL
APA Corporation (APA or the Company), is an independent energy company that explores for, develops, and produces natural gas, crude oil, and NGLs. The Company’s upstream business currently has exploration and production operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active exploration and appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. The Company’s midstream business (Altus Midstream) is operated by Altus Midstream Company (Nasdaq: ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas.
On March 1, 2021, Apache Corporation completed 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 were automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA 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 (Nasdaq) 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.
The Company’s common stock, par value $0.625 per share, is listed on the Nasdaq. Through the Company’s website, www.apacorp.com, you can access, free of charge, electronic copies of the charters of the committees of its board of directors (Board of Directors), other documents related to corporate governance (including the Code of Business Conduct and Ethics and APA’s Corporate Governance Principles), and documents the Company files with the SEC, including the Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, as well as any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act. Included in the Company’s annual and quarterly reports are the certifications of its principal executive officer and its principal financial officer that are required by applicable laws and regulations. Access to these electronic filings is available as soon as reasonably practicable after the Company files such material with, or furnishes it to, the SEC. You may also request printed copies of the Company’s corporate charter, bylaws, committee charters, or other governance documents free of charge by writing to the Company’s corporate secretary at the address on the cover of this Annual Report on Form 10-K. The Company’s reports filed with the SEC are made available on its website at www.sec.gov. From time to time, the Company also posts announcements, updates, and investor information on its website in addition to copies of all recent press releases. Information on the Company’s website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
Certain properties referred to herein may be held by subsidiaries of APA Corporation.
BUSINESS STRATEGY
OUR PURPOSE
APA believes energy underpins global progress, and the Company wants to be a part of the conversation and solution as society works to meet growing global demand for reliable and affordable energy. Today, the world faces a dual challenge: To meet growing demand for energy and to do so in a cleaner, more sustainable way. APA believes society can accomplish both, and strives to meet those challenges while creating value for all its stakeholders.
OUR VISION
To be the premier exploration and production company, contributing to global progress by helping meet the world’s energy needs.
OUR CORE VALUES
•Safety is not negotiable and will not be compromised.
•Conduct business with honesty and integrity.
•We derive benefit from the Earth and take our environmental responsibility seriously.
•Treat stakeholders with respect and dignity.
•Invest in our greatest asset: our people.
•Expect top performance and innovation.
•Seek relentless improvement in all facets.
•Drive to succeed with a sense of urgency.
•Foster a contrarian spirit.
APA maintains a diversified asset portfolio, including conventional and unconventional, onshore and offshore, exploration and production interests. In the U.S., APA operations are primarily focused in the Permian Basin of West Texas and Eastern New Mexico, with additional operations located in the Eagle Ford shale and Austin Chalk areas of Southeast Texas, offshore in the Gulf of Mexico, and along the Gulf Coast. Internationally, the Company has conventional onshore assets in Egypt’s Western Desert, offshore assets on the U.K.’s Continental Shelf, an offshore appraisal and exploration program in Suriname, and an offshore exploration block in the Dominican Republic.
Rigorous management of the Company’s asset portfolio plays a key role in optimizing shareholder value over the long term. Over the past several years, APA has entered into a series of transactions that have upgraded its portfolio of assets, enhanced its capital allocation process to further optimize investment returns, and increased focus on internally generated exploration with full-cycle, returns-focused growth. Management actively reviews certain non-strategic assets for opportunities, which include potential monetization of legacy properties and other non-core leasehold positions.
During 2021, the Company made significant progress on key aspects of its portfolio. Specifically, the Company refreshed the economic foundation for its business in Egypt with the announcement of the ratification of a modernized production-sharing contract (PSC) with the Egyptian Ministry of Petroleum and the Egyptian General Petroleum Corporation (EGPC). The new PSC consolidates the majority of the Company’s gross acreage and production in Egypt into a single concession and refreshes existing development and exploration lease terms. The modernized PSC incentivizes increased investment and production growth and places Egypt at the top of many attractive investment opportunities in APA’s global portfolio.
In October 2021, Altus Midstream Company (ALTM) announced that it will combine with privately owned BCP Raptor Holdco LP (BCP) in an all-stock transaction, and APA’s ownership in ALTM will be reduced from approximately 79 percent to approximately 20 percent. Reducing APA’s interest in Altus to a minority position will have a number of benefits to APA shareholders, including simplification of its financial reporting and enhanced comparability with its upstream-only peers, while maintaining a noncontrolling interest in future growth opportunities.
The global economy and the energy industry have been deeply impacted by the effects of the coronavirus disease 2019 (COVID-19) pandemic and related governmental actions. Uncertainty in the commodity and financial markets since early 2020 continue to impact oil supply and demand. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of ongoing exploration and appraisal activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and return of capital to its stakeholders. The Company continues to aggressively manage its cost structure regardless of the oil price environment and closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process.
For a more in-depth discussion of the Company’s 2021 results, divestitures, strategy, and its capital resources and liquidity, please see Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K.
BUSINESS OVERVIEW
The following business overview further describes the operations and activities for the Company’s upstream exploration and production properties, by geographic region, and Altus Midstream.
UPSTREAM EXPLORATION AND PRODUCTION
Operating Areas
APA has exploration and production operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea. APA also has active exploration and appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities.
The following table sets out a brief comparative summary of certain key 2021 data for each of the Company’s operating areas. Additional data and discussion are provided in Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K.
Production Percentage
of Total
Production Production
Revenue Year-End
Estimated
Proved
Reserves Percentage
of Total
Estimated
Proved
Reserves Gross
Wells
Drilled Gross
Productive
Wells
Drilled
(In MMboe) (In millions) (In MMboe)
United States 83.7 59 % $ 3,277 617 68 % 102 102
Egypt(1)
41.9 30 % 2,085 197 21 % 54 39
North Sea(2)
16.0 11 % 1,136 99 11 % 6 4
Other International - - - - - 4 -
Total 141.6 100 % $ 6,498 913 100 % 166 145
(1)The Company’s operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 22 percent of 2021 production and accounted for 16 percent of year-end estimated proved reserves.
(2)Sales volumes from the Company’s North Sea assets for 2021 were 16.1 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.
United States
In 2021, the Company’s U.S. upstream oil and gas operations contributed approximately 59 percent of production and 68 percent of estimated year-end proved reserves, consistent with prior years. APA has access to significant liquid hydrocarbons across its 3.8 million gross acres (1.8 million net acres) in the U.S., 75 percent of which are undeveloped.
The Company’s U.S. assets are primarily located in the Permian Basin in West Texas and New Mexico, including the Permian sub-basins: Midland Basin, Central Basin Platform/Northwest Shelf, and Delaware Basin. Examples of shale plays being developed within these sub-basins include the Woodford, Barnett, Pennsylvanian, Cline, Wolfcamp, Bone Spring, and Spraberry. APA is one of the largest operators in the Permian Basin, operating approximately 6,000 gross oil and gas wells across its acreage, with additional interests in more than 3,000 non-operated wells. Of note, approximately six percent of the Company’s net acreage position in the Permian Basin is on federal onshore lands. APA also has operations located in the Eagle Ford shale and Austin Chalk areas of Southeast Texas, offshore in the Gulf of Mexico, and along the Gulf Coast in South Texas and Louisiana.
Highlights of the Company’s operations in the U.S. include:
•Southern Midland Basin APA holds approximately 332,000 gross acres (238,000 net acres) in the Southern Midland Basin. During 2021, the Company averaged one rig targeting oil plays in the Wolfcamp and Spraberry formations, drilling 49 gross development wells in this basin with a 100 percent success rate.
•Delaware Basin APA holds approximately 267,000 gross acres (134,000 net acres) in the Delaware Basin, including opportunities in the Bone Spring and other formations of Eastern New Mexico and bordering West Texas, and the Alpine High play in the Southern portion of the Permian Basin, primarily in Reeves County, Texas. During 2021, the Company focused on completing wells drilled from previous years and completed 27 gross development wells.
•Legacy Assets APA holds approximately 3.2 million gross acres (1.5 million net acres) in legacy properties, of which 1.1 million gross acres are in the offshore waters of the Gulf of Mexico. Legacy onshore properties are located primarily in the Eagle Ford shale and Austin Chalk areas of Southeast Texas. The Company participated in drilling 14 gross non-operated development wells in these areas during 2021. The Company also initiated a targeted drilling program on its Austin Chalk acreage where it will continue to evaluate and high-grade inventory opportunities. Consistent with the Company’s broader portfolio management efforts, certain non-strategic leasehold positions on its legacy acreage holdings during the year were divested, primarily in the Central Basin Platform subbasin of the Permian Basin, and additional monetization opportunities are continuing to be evaluated.
•New Venture Assets APA separately has undeveloped acreage positions across several states where it intends to pursue exploration interests and potential development opportunities over time.
•During the fourth quarter of 2021, the Company announced that it has ended routine flaring in its U.S. onshore operations, achieving one of its announced 2021 environmental, social and governance (ESG) goals, three months ahead of schedule.
With the improvement in commodity prices, the Company is returning to a modest level of activity in the U.S. After halting all drilling and completion activity for most of 2020, in early 2021 the Company re-activated one rig in the Permian Basin and one rig in the Austin Chalk. A second rig was added in the Permian Basin in late June 2021. For 2022, the Company will continue to budget its capital program at levels to fund activity necessary to offset inherent declines in production and proved oil and natural gas reserves. Future rig activity levels and drilling targets will be dependent on the success of the Company’s drilling program and its ability to add reserves economically.
U.S. Marketing In general, most of the Company’s U.S. natural gas production is sold at either monthly or daily index-based prices. The tenor of the Company’s sales contracts span from daily to multi-year transactions. Natural gas is sold to a variety of customers that include local distribution, utility, and midstream companies as well as end-users, marketers, and integrated major oil companies. APA strives to maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk. The Company predominantly sells its natural gas production within the U.S., including to U.S. LNG export facilities, although a portion may be sold to markets in Mexico.
APA primarily markets its U.S. crude oil production to integrated major oil companies, marketing and transportation companies, and refiners based on West Texas Intermediate (WTI) pricing indices (e.g. WTI Houston, West Texas Sour (WTS), or WTI Midland) and some predominately Brent related international pricing indices, adjusted for quality, transportation, and a market-reflective differential. The Company’s objective is to maximize the value of crude oil sold by identifying the best markets and most economical transportation routes available to move the product. Sales contracts are generally 30-day evergreen contracts that renew automatically until canceled by either party. These contracts provide for sales that are priced daily at prevailing market prices. Also, from time to time, the Company will enter into physical term sales contracts. These term contracts typically have a firm transportation commitment and often provide an opportunity for higher than prevailing market prices.
APA’s U.S. NGL production is sold under contracts with prices 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.
U.S. Delivery Commitments The Company has long-term delivery commitments for natural gas and crude oil that require APA to deliver an average of 251 Bcf of natural gas per year for the period from 2022 through 2029 at variable, market-based pricing and deliver an average of 6.4 MMbbls of crude oil per year from 2022 through 2025 at variable, market-based pricing.
APA currently expects to fulfill its delivery commitments with production from its proved reserves, production from continued development and/or spot market purchases as necessary. APA may also enter into contractual arrangements to reduce its delivery commitments. The Company has not experienced any significant constraints in satisfying the committed quantities required by its delivery commitments.
For more information regarding the Company’s commitments, please see Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations-Capital Resources and Liquidity-Contractual Obligations of this Annual Report on Form 10-K.
International
In 2021, international assets contributed 41 percent of APA’s production and 50 percent of oil and gas revenues. Approximately 32 percent of estimated proved reserves at year-end were located outside the U.S.
APA has two international locations with ongoing development and production operations:
•Egypt, which includes onshore conventional assets located in Egypt’s Western Desert; and
•the North Sea, which includes offshore assets based in the U.K.
The Company also has an active offshore exploration program and appraisal operations ongoing in Suriname and an offshore exploration block in the Dominican Republic.
Egypt APA has 26 years of exploration, development and operations experience in Egypt and is one of the largest acreage holders in Egypt’s Western Desert. At year-end 2021, the Company held 5.3 million gross acres in Egypt in six separate concessions, but primarily held in a new, single concession that resulted from the ratification of a modernized production sharing contract (PSC) with the Egyptian government, as more fully described below. Development leases within concessions currently have expiration dates ranging from 1 to 20 years, with extensions possible for additional commercial discoveries or on a negotiated basis. Approximately 68 percent of the Company’s gross acreage in Egypt is undeveloped, providing APA with considerable exploration and development opportunities for the future.
APA’s Egypt operations are conducted pursuant to PSCs. Under the terms of the Company’s PSCs, the Company is the contractor partner (Contractor) with Egyptian General Petroleum Corporation (EGPC) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and are reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on the Company’s Egypt operations despite impacting the Company’s production and reserves.
On December 27, 2021, the Company announced the ratification of a modernized PSC with EGPC having an effective date of April 1, 2021. The new PSC consolidates 98 percent of gross acreage and 90 percent of gross production into a single concession and refreshes the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool to provide 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 APA subsidiary that became the sole Contractor under the PSC is owned by an APA-operated joint venture owned two-thirds by the Company and one-third by Sinopec International Petroleum Exploration and Production Corporation (Sinopec).
The Company’s estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country’s share of reserves. Through the joint venture, Sinopec holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company’s Egypt assets, including the one-third noncontrolling interest, contributed 30 percent of 2021 production and 21 percent of year-end estimated proved reserves. Excluding the impacts of the noncontrolling interest, Egypt contributed 22 percent of 2021 production and 16 percent of year-end estimated proved reserves.
In 2021, the Company drilled 30 gross development and 24 gross exploration wells in Egypt. A key component of the Company’s success has been the ability to acquire and evaluate 3-D seismic surveys that enable the Company’s technical teams to consistently high-grade existing prospects and identify new targets across multiple pay horizons in the Cretaceous, Jurassic, and deeper Paleozoic formations. The Company has completed seismic surveys covering over 3 million acres to date and 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.
For 2022, the Company plans to increase activity to a 15 rig drilling program for the year and increase well completions by approximately three times compared to 2021 with a goal of growing gross oil production 13 to 15 percent.
North Sea The Company has interests in approximately 494,000 gross acres in the U.K. North Sea. These assets contributed 11 percent of the Company’s 2021 production and approximately 11 percent of year-end estimated proved reserves.
The Company entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). Since acquiring Forties, the Company has actively invested in these assets and has established a large inventory of drilling prospects through successful exploration programs and the interpretation of 4-D seismic. Building upon its success in Forties, in 2011 the Company acquired Mobil North Sea Limited, providing the Company with additional exploration and development opportunities in the North Sea across numerous fields, including operated interests in the Beryl, Ness, Nevis, Nevis South, Skene, and Buckland fields and a non-operated interest in the Maclure field. The Company also has a non-operated interest in the Nelson field acquired in 2011. The Beryl field, which is a geologically complex area with multiple fields and stacked pay potential, provides for significant exploration opportunity. The North Sea assets play a strategic role in APA’s portfolio by providing competitive investment opportunities and potential reserve upside with high-impact exploration potential, near existing infrastructure.
During 2021, the Company averaged two rigs in the North Sea and drilled 4 gross development and two gross exploration wells. Production was significantly impacted by compressor downtime, extended platform turnaround work, and third-party outage during 2021.
In 2022, the expected capital program for the North Sea remains relatively unchanged from the prior year with one floating rig and one platform crew.
International Marketing The Company’s natural gas production in Egypt 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. Crude oil production is sold to third parties in the export market or to EGPC when called upon to supply domestic demand. Oil production sold to third parties is sold and exported from one of two terminals on the Northern coast of Egypt. Oil production sold to EGPC is sold at prices related to the export market.
The Company’s North Sea crude oil production is sold under term, entitlement volume contracts and spot variable volume contracts with a market-based index price plus a differential to capture the higher market value under each type of arrangement. Natural gas from the Beryl field is processed through the Scottish Area Gas Evacuation (SAGE) gas plant, operated by Ancala Midstream Acquisitions Limited. Natural 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 condensate mix from the SAGE plant is processed further downstream. The split streams of propane, butane, and condensate are sold separately on a monthly entitlement basis at the Braefoot Bay terminal using index pricing less transportation.
Other Exploration
New Ventures APA’s international New Ventures team provides exposure to new growth opportunities by looking outside of the Company’s traditional core areas and targeting higher-risk, higher-reward exploration opportunities located in frontier basins as well as new plays in more mature basins.
In December 2019, the Company entered into a joint venture agreement with TotalEnergies (formerly Total S.A.) to explore and develop Block 58 offshore Suriname. The Company holds a 50 percent working interest in Block 58, which comprises approximately 1.4 million gross acres in water depths ranging from less than 100 meters to more than 2,100 meters. Starting in late 2019 and throughout 2020, the Company drilled the first three wells in the block, the Maka Central-1, Sapakara West-1, and Kwaskwasi-1, all of which successfully tested for the presence of hydrocarbons in multiple stacked targets in the upper Cretaceous-aged Campanian and Santonian intervals, encountering both oil and gas condensate.
In January 2021, APA and TotalEnergies announced the fourth consecutive discovery in Block 58 at Keskesi East-1, which confirmed oil in the eastern portion of the block. In accordance with the joint venture agreement, the Company transferred operatorship of Block 58 to TotalEnergies on January 1, 2021. TotalEnergies holds a 50 percent working interest in Block 58 as the operator, with an active appraisal and exploration program budgeted for 2022.
The Company is also a 45 percent working interest holder in Suriname on Block 53, where technical work completed in 2021 has led to the resumption of exploration activities. An exploration well is planned for early 2022 with partners CEPSA and Petronas who have a 25 percent and 30 percent working interest, respectively.
APA also holds an offshore exploration block in the Dominican Republic.
Drilling Statistics
Worldwide in 2021, APA drilled or participated in drilling 166 gross wells, with 145 wells (87 percent) completed as producers. Historically, APA’s drilling activities in the U.S. have generally concentrated on exploitation and extension of existing producing fields rather than exploration. As a general matter, the Company’s operations outside of the U.S. focus on a mix of exploration and development wells. In addition to wells completed, at year-end a number of wells had not yet reached completion: 53 gross (41.7 net) in the U.S., 22 gross (22.0 net) in Egypt, 1 gross (1 net) in the North Sea, and 1 gross (0.5 net) in Suriname.
The following table shows the results of the oil and gas wells drilled and completed for each of the last three fiscal years:
Net Exploratory Net Development Total Net Wells
Productive Dry Total Productive Dry Total Productive Dry Total
United States - - - 67.9 - 67.9 67.9 - 67.9
Egypt 10.0 14.0 24.0 28.5 1.0 29.5 38.5 15.0 53.5
North Sea 0.6 0.5 1.1 1.8 0.5 2.3 2.4 1.0 3.4
Other International - 1.3 1.3 - - - - 1.3 1.3
Total 10.6 15.8 26.4 98.2 1.5 99.7 108.8 17.3 126.1
United States - - - 46.3 0.8 47.1 46.3 0.8 47.1
Egypt 17.7 7.0 24.7 35.7 - 35.7 53.4 7.0 60.4
North Sea 0.6 1.0 1.6 4.2 0.6 4.8 4.8 1.6 6.4
Other International - 1.5 1.5 - - - - 1.5 1.5
Total 18.3 9.5 27.8 86.2 1.4 87.6 104.5 10.9 115.4
United States 6.3 - 6.3 181.0 - 181.0 187.3 - 187.3
Egypt 8.5 13.5 22.0 37.2 1.5 38.7 45.7 15.0 60.7
North Sea - - - 8.4 - 8.4 8.4 - 8.4
Total 14.8 13.5 28.3 226.6 1.5 228.1 241.4 15.0 256.4
Productive Oil and Gas Wells
The number of productive oil and gas wells, operated and non-operated, in which the Company had an interest as of December 31, 2021, is set forth below:
Oil Gas Total
Gross Net Gross Net Gross Net
United States 8,862 5,309 957 663 9,819 5,972
Egypt 1,026 991 114 111 1,140 1,102
North Sea 164 121 13 8 177 129
Total 10,052 6,421 1,084 782 11,136 7,203
Domestic 8,862 5,309 957 663 9,819 5,972
Foreign 1,190 1,112 127 119 1,317 1,231
Total 10,052 6,421 1,084 782 11,136 7,203
Gross natural gas and crude oil wells include 494 wells with multiple completions.
Production, Pricing, and Lease Operating Cost Data
The following table describes, for each of the last three fiscal years, oil, NGL, and gas production volumes, average lease operating costs per boe (including transportation costs but excluding severance and other taxes), and average sales prices for each of the countries where the Company has operations:
Production Average Lease
Operating
Cost per Boe Average Sales Price
Oil NGL Gas Oil NGL Gas
Year Ended December 31, (MMbbls) (MMbbls) (Bcf) (Per bbl) (Per bbl) (Per Mcf)
United States 27.4 24.2 192.5 $ 8.37 $ 67.37 $ 27.85 $ 3.92
Egypt(1)
25.7 0.2 96.2 11.48 70.33 48.84 2.81
North Sea(2)
13.2 0.4 14.1 26.12 69.67 54.30 12.96
Total 66.3 24.8 302.8 11.31 68.97 28.48 3.99
United States 32.3 27.1 205.6 $ 7.39 $ 37.42 $ 11.21 $ 1.22
Egypt(1)
27.6 0.3 100.4 10.35 39.95 27.83 2.79
North Sea(2)
18.4 0.7 21.0 15.60 42.88 29.73 3.19
Total 78.3 28.1 327.0 9.37 39.60 11.84 1.83
United States 38.3 25.0 233.5 $ 9.24 $ 54.71 $ 14.95 $ 1.26
Egypt(1)
30.9 0.3 104.4 10.77 63.76 33.87 2.83
North Sea(2)
18.2 0.6 19.9 16.75 65.10 36.83 4.48
Total 87.4 25.9 357.8 10.62 60.05 15.74 1.90
(1)Includes production volumes attributable to a one-third noncontrolling interest in Egypt.
(2)Sales volumes from the Company’s North Sea assets for 2021, 2020, and 2019 were 16.1 MMboe, 22.7 MMboe, and 21.8 MMboe, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.
Gross and Net Undeveloped and Developed Acreage
The following table summarizes the Company’s gross and net acreage position as of December 31, 2021:
Undeveloped Acreage Developed Acreage
Gross Acres Net Acres Gross Acres Net Acres
(In thousands)
United States 2,862 1,278 947 568
Egypt 3,610 3,610 1,690 1,634
North Sea 309 290 185 139
Other International 2,934 1,737 - -
Total 9,715 6,915 2,822 2,341
As of December 31, 2021, the Company held 636,000 net undeveloped acres that are scheduled to expire by year-end 2022 if production is not established or the Company takes no action to extend the terms. The Company also held 10,000 and 97,000 net undeveloped acres set to expire by year-end 2023 and 2024, respectively. The Company strives to extend the terms of many of these licenses and concession areas through operational or administrative actions but cannot assure that such extensions can be achieved on an economic basis or otherwise on terms agreeable to both the Company and third parties, including governments. No oil and gas reserves were recorded on this undeveloped acreage set to expire.
Exploration concessions in the Company’s Egypt asset were extended upon ratification of the modernized PSC with the EGPC, and no acreage is scheduled to expire over the next three years. The Company will continue to pursue acreage extensions and access to new concessions in areas in which it believes exploration opportunities exist.
Additionally, the Company has exploration interests in Block 53 and Block 58 offshore Suriname and offshore the Dominican Republic. Approximately 390,000 net undeveloped acres in Block 53 are set to expire in 2022 contingent on planned drilling activity. The Company also continues to assess, contract, and potentially explore undeveloped acreage positions in other international locations.
As of December 31, 2021, approximately 93 percent of U.S. net undeveloped acreage was held by production or owned as undeveloped mineral rights.
Estimated Proved Reserves and Future Net Cash Flows
Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves.
Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating its proved reserves, APA uses several different traditional methods that can be classified in three general categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy with similar properties. The Company will, at times, utilize additional technical analysis, such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods, to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of the Company’s reserve estimates.
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 period.
The following table shows proved oil, NGL, and gas reserves as of December 31, 2021, based on average commodity prices in effect on the first day of each month in 2021, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms. The total column of this table shows reserves on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a ratio of 6 Mcf to 1 bbl. This ratio is not reflective of the current price ratio between the two products.
Oil NGL Gas Total
(MMbbls) (MMbbls) (Bcf) (MMboe)
Proved Developed:
United States 181 164 1,238 551
Egypt(1)
107 1 465 185
North Sea 77 2 76 92
Total 365 167 1,779 828
Proved Undeveloped:
United States 18 16 184 65
Egypt(1)
11 - 10 13
North Sea 6 - 7 7
Total 35 16 201 85
Total Proved 400 183 1,980 913
(1)Includes total proved developed and total proved undeveloped reserves of 62 MMboe and 4 MMboe, respectively, attributable to a one-third noncontrolling interest in Egypt.
As of December 31, 2021, the Company had total estimated proved reserves of 400 MMbbls of crude oil, 183 MMbbls of NGLs, and 2.0 Tcf of natural gas. Combined, these total estimated proved reserves are the volume equivalent of 913 million boe, of which liquids represents 64 percent. As of December 31, 2021, the Company’s proved developed reserves totaled 828 MMboe and estimated PUD reserves totaled 85 MMboe, or approximately 9 percent of worldwide total proved reserves. APA has elected not to disclose probable or possible reserves in this filing. The Company has one field that contains 15 percent or more of its total proved reserves for the years ended December 31, 2021 and 2020, and none in 2019.
During 2021, the Company added 102 MMboe of proved reserves through exploration and development activity. There were also upward revisions of previously estimated reserves of 107 MMboe. Upward revisions related to changes in product prices accounted for 85 MMboe. Engineering and performance upward revisions accounted for 22 MMboe, with the modernized PSC in Egypt resulting in an increase of 57 MMboe, partially offset by other downward revisions of 35 MMboe across all of the Company’s geographic areas of operations. The Company also sold 28 MMboe of proved reserves associated with U.S. divestitures, primarily related to the Permian Basin.
As previously discussed, in December 2021, the Egyptian government signed into law an agreement to modernize and consolidate a majority of the Company’s Egypt PSCs. The impact of the consolidated PSC to proved reserves based on the modernized terms is an estimated increase of 53 MMboe and 4 MMboe in developed and undeveloped reserves, respectively, and approximately $750 million in discounted future net cash flows. Approximately 96 percent of the Company’s Egypt reserves are now consolidated within the modernized PSC. These estimates include Sinopec’s noncontrolling interest in Egypt.
The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2021, 2020, and 2019, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 18-Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Estimated future net cash flows were calculated using a discount rate of 10 percent per annum, end of period costs, and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.
Proved Undeveloped Reserves
The Company’s total estimated PUD reserves of 85 MMboe as of December 31, 2021, increased by 9 MMboe from 76 MMboe of PUD reserves reported at year end 2020. During the year, the Company converted 33 MMboe of PUD reserves to proved developed reserves through development drilling activity. In the U.S., the Company converted 28 MMboe, with the remaining 5 MMboe in its international areas. The Company sold 2 MMboe of PUD reserves in the U.S. and did not acquire any PUD reserves during the year. The Company added 63 MMboe of new PUD reserves through extensions and discoveries. Downward revisions totaled 19 MMboe, comprising 7 MMboe associated with engineering and interest revisions, 11 MMboe associated with revised development plans, and 1 MMboe associated with product prices.
During 2021, a total of approximately $213 million was spent on projects associated with proved undeveloped reserves. A portion of APA’s costs incurred each year relate to development projects that will convert undeveloped reserves to proved developed reserves in future years. During 2021, the Company spent approximately $174 million on PUD reserve development activity in the U.S. and $39 million in the international areas. As of December 31, 2021, the Company had no material amounts of proved undeveloped reserves scheduled to be developed beyond five years from initial disclosure.
Preparation of Oil and Gas Reserve Information
The Company’s reported reserves are reasonably certain estimates which, by their very nature, are subject to revision. These estimates are reviewed throughout the year and revised either upward or downward, as warranted.
APA’s proved reserves are estimated at the property level and compiled for reporting purposes by a centralized group of experienced reservoir engineers that is independent of the operating groups. These engineers interact with engineering and geoscience personnel in each of the Company’s operating areas and with accounting and marketing employees to obtain the necessary data for projecting future production, costs, net revenues, and ultimate recoverable reserves. All relevant data is compiled in a computer database application, to which only authorized personnel are given security access rights consistent with their assigned job function. Reserves are reviewed internally with senior management and presented to APA’s Board of Directors in summary form on a quarterly basis. Annually, each property is reviewed in detail by our corporate and operating asset engineers to ensure forecasts of operating expenses, netback prices, production trends, and development timing are reasonable.
APA’s Executive Vice President of Development is the person primarily responsible for overseeing the preparation of the Company’s internal reserve estimates and for coordinating any reserves audits conducted by a third-party engineering firm. He has Bachelor of Science and Master of Science degrees in Petroleum Engineering and over 30 years of experience in the energy industry and energy sector of the banking industry. The Executive Vice President of Development reports directly to the Company’s Chief Executive Officer.
The estimate of reserves disclosed in this Annual Report on Form 10-K is prepared by the Company’s internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. The Company engages Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to conduct a reserves audit, which includes a review of the Company’s processes and the reasonableness of the Company’s estimates of proved hydrocarbon liquid and gas reserves. The Company selects the properties for review by Ryder Scott based primarily on relative reserve value. The Company also considers other factors such as geographic location, new wells drilled during the year and reserves volume. During 2021, the properties selected for each country ranged from 82 to 84 percent of the total future net cash flows discounted at 10 percent. These properties also accounted for 83 percent of the value of the Company’s international proved reserves and 94 percent of the value of the Company’s new wells drilled worldwide. In addition, all fields containing five percent or more of the Company’s total proved reserves volume were included in Ryder Scott’s review. The review covered 80 percent of total proved reserves on a boe basis.
Ryder Scott’s review for the years 2021, 2020, and 2019 covered 83, 85, and 87 percent, respectively, of the value and 80, 81, and 85 percent, respectively, of the volume of the Company’s worldwide estimated proved reserves. Ryder Scott’s 2021 review covered 80, 80, and 81 percent of the estimated proved reserve volume in the U.S., Egypt, and U.K., respectively.
Ryder Scott’s review of 2020 covered 80 percent of U.S., 82 percent of Egypt, and 83 percent of the U.K.’s total proved reserves.
Ryder Scott’s review of 2019 covered 85 percent of U.S., 86 percent of Egypt, and 80 percent of the U.K.’s total proved reserves.
The Company has filed Ryder Scott’s independent report as an exhibit to this Annual Report on Form 10-K.
According to Ryder Scott’s opinion, based on their review, including the data, technical processes, and interpretations presented by the Company, the overall procedures and methodologies utilized by the Company in determining the proved reserves comply with the current SEC regulations, and the overall proved reserves for the reviewed properties as estimated by the Company are, in aggregate, reasonable within the established audit tolerance guidelines as set forth in the Society of Petroleum Engineers auditing standards.
ALTUS MIDSTREAM
In November 2018, Apache Midstream LLC, one of the Company’s wholly owned subsidiaries completed a transaction with ALTM and its then wholly owned subsidiary Altus Midstream LP to create a pure-play, Permian Basin midstream C-corporation anchored by gathering, processing, and transmission assets at Alpine High. Pursuant to the agreement, the Company’s subsidiary contributed certain Alpine High midstream assets and options (the Pipeline Options) to acquire equity interests in five separate third-party pipeline projects (the Equity Method Interest Pipelines) to Altus Midstream LP and/or its subsidiaries. In exchange for the assets, the Company’s subsidiary received economic voting and non-economic voting shares in ALTM and limited partner interests in Altus Midstream LP, representing an approximate 79 percent ownership interest in the combined entities.
Because a wholly owned subsidiary of APA has a controlling financial interest in Altus, APA fully consolidates the assets and liabilities of Altus in its consolidated financial statements, with a corresponding noncontrolling interest reflected separately.
Business Combination with BCP
On October 21, 2021, ALTM announced that it will 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 dated as of that same date and entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). The combination creates an integrated midstream company in the Texas Delaware Basin offering services for residue gas, NGLs, crude oil and water. There are numerous expected commercial and financial synergies generated from the complementary midstream systems and enhanced scale of the business. The combined business will have a more diversified asset profile and customer base, with a lower risk profile than either entity on a stand-alone basis. BCP is the parent company of EagleClaw Midstream, which includes EagleClaw Midstream Ventures, the Caprock Midstream and Pinnacle Midstream businesses, and a 26.7 percent interest in the Permian Highway Pipeline. Pursuant to the BCP Contribution Agreement, Contributor will contribute all of the equity interests of the Contributed Entities (the Contributed Interests) to Altus Midstream LP, with each Contributed Entity becoming a wholly owned subsidiary of Altus Midstream LP (the BCP Business Combination).
As consideration for the contribution of the Contributed Interests, ALTM will issue 50 million shares of Class C Common Stock (and Altus Midstream LP will issue a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. The transaction is expected to close during the first quarter of 2022 following completion of customary closing conditions.
As a result of the transaction, ALTM’s current stockholders will continue to hold their shares of Class A Common Stock and Class C Common Stock (collectively, ALTM Common Stock), Contributor or its designees will collectively own approximately 75 percent of the issued and outstanding shares of ALTM Common Stock, Apache Midstream LLC, a wholly owned subsidiary of APA, which currently owns approximately 79 percent of the issued and outstanding shares of ALTM Common Stock, will own approximately 20 percent of the issued and outstanding shares of ALTM Common Stock, and the remaining current stockholders will own approximately 5 percent of the issued and outstanding shares of ALTM Common Stock.
Gathering, Processing, and Transmission Assets
Altus owns, develops, and operates gas gathering, processing, and transmission assets in the Permian Basin of West Texas. Altus generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services for the Company’s production from its Alpine High resource play. As of December 31, 2021, Altus’ assets included approximately 182 miles of in-service natural gas gathering pipelines, approximately 46 miles of residue-gas pipelines with four market connections, and approximately 38 miles of NGL pipelines. Three cryogenic processing trains, each with nameplate capacity of 200 MMcf/d, were placed into service during 2019. Other assets include an NGL truck loading terminal with six Lease Automatic Custody Transfer units and eight NGL bullet tanks with 90,000 gallon capacity per tank. Altus’ existing gathering, processing, and transmission infrastructure is expected to provide capacity levels capable of fulfilling its midstream contracts to service the Company’s production from Alpine High and third-party customers as market activity in the area continues to develop.
Pipeline Options and Equity Method Interest Pipelines
Gulf Coast Express Pipeline In December 2018, Altus Midstream LP closed on the exercise of its Pipeline Option with Kinder Morgan Texas Pipeline LLC (Kinder Morgan), thereby acquiring a 15 percent equity interest in the Gulf Coast Express Pipeline Project (GCX). Altus Midstream LP acquired an additional 1 percent equity interest in May 2019, for a total 16 percent equity interest in GCX. GCX is a long-haul natural gas pipeline with capacity of approximately 2.0 Bcf/d and transports natural gas from the Waha area in Northern Pecos County, Texas to the Agua Dulce Hub near the Texas Gulf Coast. GCX is operated by Kinder Morgan and was placed into service in September 2019.
EPIC Crude Oil Pipeline In March 2019, Altus Midstream LP’s subsidiary closed on the exercise of its Pipeline Option with EPIC Pipeline LP, thereby acquiring a 15 percent equity interest in the EPIC crude oil pipeline (EPIC). The long-haul crude oil pipeline extends from the Orla area in Northern Reeves County, Texas to the Port of Corpus Christi, Texas, and has Permian Basin initial throughput capacity of approximately 600 MBbl/d. The project includes terminals in Orla, Pecos, Crane, Wink, Robstown, Hubson, and Gardendale, Texas with Port of Corpus Christi connectivity and export access. It services Delaware Basin, Midland Basin, and Eagle Ford Shale production. EPIC is operated by EPIC Consolidated Operations, LLC and was placed into service in early 2020.
Permian Highway Pipeline In May 2019, Altus Midstream LP’s subsidiary closed on the exercise of its Pipeline Option with Kinder Morgan, thereby acquiring an approximate 26.7 percent equity interest in the Permian Highway Pipeline (PHP). The long-haul natural gas pipeline has capacity of approximately 2.1 Bcf/d and transports natural gas from the Waha area in Northern Pecos County, Texas to the Katy, Texas area with connections to U.S. Gulf Coast and Mexico markets. PHP, which is operated by Kinder Morgan, was placed into service in January 2021.
Shin Oak NGL Pipeline In July 2019, Altus Midstream LP’s subsidiary closed on the exercise of its Pipeline Option with Enterprise Products Operating LLC (Enterprise Products), thereby acquiring a 33 percent equity interest in Breviloba LLC, which owns the Shin Oak NGL Pipeline (Shin Oak). The long-haul NGL pipeline has capacity of up to 550 MBbl/d and transports NGL production from the Orla area in Northern Reeves County, Texas through the Waha area in Northern Pecos County, Texas, and on to Mont Belvieu, Texas. Shin Oak is operated by Enterprise Products and was placed into service during 2019.
MAJOR CUSTOMERS
The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. During 2021, sales to EGPC and CFE International accounted for approximately 14 percent and 10 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2020, sales to EGPC and Vitol accounted for approximately 17 percent and 14 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2019, sales to BP and Sinopec, and their respective affiliates, each accounted for approximately 10 percent and 11 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues.
Management does not believe that the loss of any one of these customers would have a material adverse effect on the results of operations.
HUMAN CAPITAL MANAGEMENT
Human Capital and Employees
APA believes that its people are one of the Company’s most important investments and greatest asset. Successful execution of the Company’s business strategies depends on its ability to attract, develop, incentivize, and retain diverse, talented, qualified, and highly skilled employees at all levels of the organization. As such, the Company continues to focus on health and safety, diversity and inclusion, total rewards, and community partnerships to ensure that being a part of the APA family is a positive experience for all.
As of December 31, 2021, the Company employed approximately 2,253 full-time equivalent employees in locations across the organization.
Employees
North America 1,381
United Kingdom 638
Egypt 230
Suriname 2
France 2
Total employees 2,253
Women in Global Workforce Women in Global Leadership Roles Women on the Board of Directors
Gender % of Employees Gender % of Employees Gender % of Employees
F 23% F 18% F 30%
M 77% M 82% M 70%
Amongst the Company’s U.S. workforce, 34 percent self-report as non-white.
U.S. Employees
Race % of Employees
American Indian or Alaskan Native 1 %
Asian 7 %
Black or African American 6 %
Hispanic/Latino 19 %
Native Hawaiian or Other Pacific Islander - %
Two or More Races 1 %
White 66 %
The Company does not request racial diversity data from its non-U.S. colleagues, where tracking these metrics is largely prohibited by law.
COVID-19 Response
Since the onset of the COVID-19 pandemic, the Company has put employee health and well-being front and center, and it has adjusted its approach to how work gets done accordingly. APA’s guiding principles for decisions and actions throughout the pandemic have been safety, flexibility, and empathy.
APA implemented and/or supported a tracking and case management system across the Company’s operational locations to further protect and support people, while minimizing the impact to the business. In the U.S., for example, the Company managed nearly 800 cases of potential or confirmed exposure and illness (through mid-2021), providing individual support. The Company also coordinated efforts with a third-party medical provider to offer vaccinations and boosters to employees and their dependents on a voluntary basis. Each operating area, in the U.S., U.K., Egypt, and Suriname, used specific tracking systems, which were ultimately managed by the U.S. case management team. This oversight process provided for comprehensive reporting and analysis to key leadership to enable effective decision-making.
Oversight and Management
The Company’s Board of Directors has three standing committees, each devoted to a separate aspect of risk oversight. The Management Development and Compensation (MD&C) Committee, the Audit Committee, the Corporate Responsibility, Governance, and Nominating (CRG&N) Committee, and/or the full Board of Directors receive regular reports on certain human capital matters, including the Company’s diversity and inclusion programs and initiatives.
•The MD&C Committee oversees the Company’s compensation programs, leadership development and succession planning strategies, and seeks continuous improvement in the diversity and inclusion practices used in developing and deploying these processes.
•The Audit Committee oversees the integrity of the Company's financial statements and monitors human capital management risk against compliance with legal and regulatory requirements.
•The CRG&N Committee oversees the nomination of Company directors, the annual Board of Directors evaluation process, corporate governance and ESG issues, as well as the Company’s annual sustainability report.
Reports and recommendations made to the Board of Directors and its committees are part of the framework that ensures APA’s daily actions and decisions are guided by its core values, including upholding the health and safety of the Company’s team, stakeholders, and communities; investing in its workforce; ensuring environmental responsibility; and acting ethically and with integrity.
Diversity and Inclusion
APA recognizes diversity and inclusion (D&I) as vital to its long-term success. In 2020, the Company established a dedicated D&I function to build on its commitment to D&I across the organization. Since that time, APA’s focus has been on providing unconscious bias training for its global workforce, expanding employee resource groups (ERGs) in terms of quantity and geography, and increasing awareness about the importance of D&I and each employee’s role in ensuring that APA has a culture where all employees are valued and can thrive with a sense of belonging, not just as employees, but as people.
In 2021, APA strengthened its commitment through the following key accomplishments:
•Launching annual mandatory D&I training for all of the Company’s people leaders, and assigning it as recommended training for all employees across our global locations;
•Refreshing the Global D&I Council to obtain employee perspectives and feedback on the Company’s D&I initiatives;
•Increasing employee engagement by promoting the establishment of Employee Resource Groups;
•Launching global employee engagement campaigns to celebrate the diversity of the Company’s employees;
•Introducing a global mentorship program to promote access to leadership and career development;
•Conducting annual pay equity analysis; and
•Expanding community outreach efforts to continue APA’s support of underserved populations
Talent
Throughout the Company, APA seeks to attract, develop, and retain the best talent. During 2021, the Company expanded its talent management organization with dedicated talent acquisition and development functions that have both established and implemented hiring and development processes, including standardizing candidate selection. APA honed its global succession planning program by including a robust assessment of competency proficiency levels for identified successors. The Company continues to advance its global employee development strategy through formal development plans, on-the-job learning, and challenging work assignments that strengthen business critical skillsets to meet future workforce needs. APA also deployed a leadership development program that embeds a leadership framework detailing clear behaviors that the Company expects from its people leaders to ensure they align with its culture.
Training and Development
During 2021, the Company launched an updated approach to global performance management focusing on development, which included a detailed framework for core, leadership, and technical competencies. This approach emphasizes ongoing performance conversations between managers and employees with a focus on mitigating bias in performance conversations.
In addition, employees create a personal development plan, and APA provides additional resources to support employees in their personal and professional development, including:
•Utilization of multiple, third-party online training offerings;
•Leadership and personal development coaching opportunities through a collaboration with a leading human resources consulting company;
•Ongoing education for people leaders around the Company’s leadership competencies and behaviors;
•Annual compliance, antitrust, bribery, corruption, and code of business conduct and ethics training required for all employees and leaders; and
•Cybersecurity training focusing on keeping the Company and employees’ personal information secure.
Total Rewards
Year after year, APA has steadily upgraded its total rewards compensation programs with the objective of retaining, rewarding, and attracting the best talent by providing total rewards that are competitive. To foster a stronger sense of ownership and align the interests of employees and shareholders, restricted stock units are provided to eligible employees under APA’s broad-based compensation program. Furthermore, the Company offers comprehensive, locally relevant and innovative benefits. In the U.S. these include, among other benefits:
•Comprehensive health insurance coverage offered to employees working an average of 20 hours or more each week;
•401(k) plan with up to 8 percent Company match;
•6 percent Company contributions to a money purchase retirement plan;
•Company-paid short-term disability that pays a percentage of base pay according to years of service;
•Parental leave for all new parents for birth and adoption;
•Elder care leave to temporarily care for or find permanent care for elder family members; and
•Mental health and well-being benefits, including free coaching and therapy as well as access to self-care resources and a well-being platform that offers ongoing training and challenges to help employees with sustaining healthy habits.
Health and Safety
APA’s priority is the health and safety of its workforce. The Company’s environmental, health, and safety and operations functions partner to consistently reinforce its core values, standards, and operating practices, as well as foster a safety culture that empowers the Company’s workforce to stop work if conditions or behaviors are deemed unsafe. APA strives to be incident-free across its global operations every day, with the help of visible and engaged leadership, by setting clear expectations and making safety personal for all employees and contractors.
2021 Global Primary Workforce Safety Goals
Total Recordable Incident Rate (TRIR) 0.26 44% below target of 0.46
Days Away, Restricted and Transferred Rate (DART) 0.13 40% below target of 0.22
Severe Injury and Fatality Rate (SIF) 0.016 59% below target of 0.039
Vehicle Incident Rate (VIR) 0.53 39% below target of 0.87
Community Partnerships
APA is committed to being socially and environmentally responsible in the communities where it operates. The Community Partnerships group oversees the Company’s global strategic social investing and community engagement, including the stewardship of key stakeholder relationships.
APA’s global giving strategy and philosophy is focused into three pillars: Sustainable Communities, Environmental Stewardship, and Access to Energy, through which the Company creates sustainable and positive impacts. Based on these pillars, APA is committed to addressing acute social needs within the local communities where it operates; ensuring that it remains focused on its long-standing legacy and commitment to environmental stewardship and conservation; and supporting underserved communities that lack access to reliable, affordable energy.
•Sustainable Communities: APA continues to partner with organizations within the communities in which it operates to improve quality of life through access to education and essential medical supplies; development of innovative healthcare technologies and procedures; support for vulnerable populations, including women and children in need; response to natural disasters; and support for first responders.
•Environmental Stewardship: In 2021, the Company’s environmental stewardship initiatives included grants of 55,000 trees to 66 community partners through the APA Corporation Tree Grant Program; continued partnership with the Texas Parks and Wildlife Foundation to provide sustainable funding for the restoration of Balmorhea State Park; and multi-year support of the Pecos Watershed Conservation Initiative, an alliance of seven energy companies, in partnership with the National Fish and Wildlife Foundation, to restore and protect natural grasslands and habitats within the greater Trans-Pecos Region.
•Access to Energy: The Company continues to partner with Switch Energy Alliance, which provides collaborative global energy education and solutions for more than 15 million students and environmental organizations.
APA also provides employees with volunteer service opportunities in collaboration with our Community Partnerships program. The Company seeks meaningful volunteer opportunities that instill a sense of pride, ownership, and accomplishment for employees in their communities. As community needs change and stakeholder engagement continues, APA continues to adjust its charitable giving program.
OFFICES
The Company’s principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. As of year-end 2021, the Company maintained offices in Midland, Texas; Houston, Texas; Cairo, Egypt; and Aberdeen, Scotland. The Company leases its primary office space. The current lease on the Company’s principal executive offices runs through December 31, 2024. The Company has an option to extend the lease through 2029. For information regarding the Company’s obligations under its office leases, please see Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations-Capital Resources and Liquidity-Contractual Obligations and 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.
TITLE TO INTERESTS
As is customary in the oil and gas industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time the Company acquires properties. The Company believes that its title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in the Company’s operations. The interests owned by the Company may be subject to one or more royalty, overriding royalty, or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as production payments, net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in the Company’s operations.
ADDITIONAL INFORMATION ABOUT THE COMPANY
Response Plans and Available Resources
The Company’s subsidiaries developed Oil Spill Response Plans (the Plans) for their respective offshore operations in the Gulf of Mexico, the North Sea, and Suriname, which ensure rapid and effective responses to spill events that may occur on such entities’ operated properties. Annually, drills are conducted to measure and maintain the effectiveness of the Plans.
The Company’s subsidiary, Apache, is a member of Oil Spill Response Limited (OSRL), a large international oil spill response cooperative, which entitles any affiliated entity worldwide to access OSRL’s services. Apache also has a contract for response resources and services with National Response Corporation (NRC). NRC is the world’s largest commercial Oil Spill Response Organization and is the global leader in providing end-to-end environmental, industrial, and emergency response solutions with operating bases in 13 countries.
In the event of a spill in the Gulf of Mexico, Clean Gulf Associates (CGA) is the primary oil spill response association available to Apache. Apache is a member of CGA, a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies’ operations in the Gulf of Mexico.
Additionally, the Company is an active member of Wild Well Control’s WellCONTAINED Subsea Containment System for Suriname operations. This membership includes contingency planning, and response, to an uncontrolled subsea well event. The Company utilizes a detailed Source Control Emergency Response Plan (SCERP) for offshore Suriname planning. The SCERP has been designed to ensure that the goals of the Company’s source control emergency preparedness efforts will be met in the unlikely event of an actual response to an uncontrolled well event. This includes the use of subsea dispersant systems and field deployment of one of Wild Well Control’s containment system capping stacks.
Competitive Conditions
The oil and gas industry is highly competitive in the exploration for and acquisitions of reserves, the acquisition of oil and gas leases, equipment and personnel required to find and produce reserves, and the gathering and marketing of oil, gas, and NGLs. The Company’s competitors include national oil companies, major integrated oil and gas companies, other independent oil and gas companies, and participants in other industries supplying energy and fuel to industrial, commercial, and individual consumers.
Certain of the Company’s competitors may possess financial or other resources substantially larger than the Company possesses or have established strategic long-term positions and maintain strong governmental relationships in countries in which the Company may seek new entry. As a consequence, the Company may be at a competitive disadvantage in bidding for leases or drilling rights.
However, the Company believes its diversified portfolio of core assets, which comprises large acreage positions and well-established production bases across three geographic areas, its balanced production mix between oil and gas, its management and incentive systems, and its experienced personnel give it a strong competitive position relative to many of the Company’s competitors who do not possess similar geographic and production diversity. The Company’s global position provides a large inventory of geologic and geographic opportunities in the geographic areas in which it has producing operations to which it can reallocate capital investments in response to changes in commodity prices, local business environments, and markets. This also reduces the risk that the Company will be materially impacted by an event in a specific area or country.
Environmental Compliance
As an owner or lessee and operator of oil and gas properties and facilities, the Company is subject to numerous federal, state, local, and foreign laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Although environmental requirements have a substantial impact upon the energy industry as a whole, the Company does not believe that these requirements affect it differently, to any material degree, than other companies in the oil and gas industry.
The Company has made and will continue to make expenditures in its efforts to comply with these requirements, which the Company believes are necessary business costs in the oil and gas industry. The Company has established policies for continuing compliance with environmental laws and regulations, including regulations applicable to its operations in all countries in which it does business. The Company has established operating procedures and training programs designed to limit the environmental impact of its field facilities and identify and comply with changes in existing laws and regulations. The costs incurred under these policies and procedures are inextricably connected to normal operating expenses such that the Company is unable to separate expenses related to environmental matters; however, the Company does not believe expenses related to training and compliance with regulations and laws that have been adopted or enacted to regulate the discharge of materials into the environment will have a material impact on its capital expenditures, earnings, or competitive position.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
The Company’s business activities and the value of its securities are subject to significant hazards and risks, including those described below. If any of such events should occur, the Company’s business, financial condition, liquidity, and/or results of operations could be materially harmed, and holders and purchasers of APA’s securities could lose part or all of their investments. Additional risks relating to the Company’s securities may be included in the prospectus supplements related to offerings of such securities from time to time in the future.
RISKS RELATED TO PRICING, DEMAND, AND PRODUCTION FOR CRUDE OIL, NATURAL GAS, AND NGLs
The COVID-19 pandemic has and may continue to adversely impact the Company’s business, financial condition, and results of operations, the global economy, and the demand for and prices of oil, natural gas, and NGLs. The unprecedented nature of the current situation makes it impossible for the Company to identify all potential risks related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on its business.
The COVID-19 pandemic and the actions taken by third parties, including, but not limited to, governmental authorities, businesses, and consumers, in response to the pandemic have adversely impacted the global economy and created significant volatility in the global financial markets. Business closures, restrictions on travel, “stay-at-home” or “shelter-in-place” orders, and other restrictions on movement within and among communities have significantly reduced demand for and the prices of oil, natural gas, and NGLs. As of the date of this Annual Report on Form 10-K, efforts to contain COVID-19 have not been successful in many regions, vaccination distribution programs have encountered delays, new variants have emerged, and the global pandemic remains ongoing. While some geographic regions have lifted, relaxed, or otherwise modified their pandemic response measures to lessen the impact of such measures on business operations and commerce, these regions may reinstitute restrictions as circumstances change. A continued, prolonged period or a renewed period of reduced demand, the failure to timely distribute or the ineffectiveness of or reluctance or refusal of individuals to take any vaccines, the failure to develop adequate treatments, and other adverse impacts from the pandemic may materially adversely affect the Company’s business, financial condition, cash flows, and results of operations.
The Company’s operations rely on its workforce being able to access its wells, platforms, structures, and facilities located upon or used in connection with its oil and gas leases. Additionally, because the Company has previously implemented, and may elect to or be required in the future to reimplement, remote working procedures for a significant portion of its workforce for health and safety reasons and/or to comply with applicable national, state, and/or local government requirements, the Company relies on such persons having sufficient access to its information technology systems, including through telecommunication hardware, software, and networks. If a significant portion of the Company’s workforce cannot effectively perform their responsibilities, whether resulting from a lack of physical or virtual access, quarantines, illnesses, governmental actions or restrictions, including vaccine mandates and the reactions thereto, information technology or telecommunication failures, or other restrictions or adverse impacts resulting from the pandemic, the Company’s business, financial condition, cash flows, and results of operations may be materially adversely affected.
The unprecedented nature of the current situation resulting from the COVID-19 pandemic makes it impossible for the Company to identify all potential risks related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on its business, financial condition, cash flows, or results of operations. Such results will depend on future events, which the Company cannot predict, including the scope, duration, and potential reoccurrence of the COVID-19 pandemic, the emergence and impact of COVID-19 variants, or any other localized epidemic or global pandemic, the distribution and effectiveness of vaccines, therapeutics, and treatments, the demand for and the prices of oil, natural gas, and NGLs, and the actions taken by third parties, including, but not limited to, governmental authorities, customers, contractors, and suppliers, in response to the COVID-19 pandemic or any other epidemics or pandemics. The COVID-19 pandemic and its unprecedented consequences have amplified, and may continue to amplify, the other risks identified in this Annual Report on Form 10-K.
Crude oil, natural gas, and NGL price volatility could adversely affect the Company’s operating results and the price of APA’s common stock.
The Company’s revenues, operating results, and future rate of growth depend highly upon the prices it receives for its crude oil, natural gas, and NGL production. Historically, the markets for these commodities have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2021 ranged from a high of $85.64 per barrel to a low of $47.47 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2021 ranged from a high of $23.86 per MMBtu to a low of $2.43 per MMBtu. The market prices for
crude oil, natural gas, and NGLs depend on factors beyond the Company’s control. These factors include demand, which fluctuates with changes in market and economic conditions, and other factors, including:
•worldwide and domestic supplies of crude oil, natural gas, and NGLs;
•actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC);
•political conditions and events (including instability, changes in governments, or armed conflict) in oil and gas producing regions;
•the occurrence of global events such as epidemics or pandemics (including, specifically, the COVID-19 pandemic) and the actions taken by third parties, including, but not limited to, governmental authorities, customers, contractors, and suppliers, in response to such epidemics or pandemics;
•the level of global crude oil and natural gas inventories;
•the price and level of imported foreign crude oil, natural gas, and NGLs;
•the price and availability of alternative fuels, including coal and biofuels;
•the availability of pipeline capacity and infrastructure;
•the availability of crude oil transportation and refining capacity;
•weather conditions;
•the impact of political pressure and the influence of environmental groups and other stakeholders on decisions and policies related to the industries in which the Company and its affiliates operate;
•domestic and foreign governmental regulations and taxes, including legislative, regulatory, policy changes, or initiatives and addressing the impact of global climate change, hydraulic fracturing, methane emissions, flaring, or water disposal; and
•the overall economic environment.
The Company’s results of operations, as well as the carrying value of its oil and gas properties, are substantially dependent upon the prices of oil, natural gas, and NGLs. Low prices have previously adversely affected and could again adversely affect the Company’s revenues, operating income, cash flow, and proved reserves, and continued low prices could have a material adverse impact on the Company’s operations and limit its ability to fund capital expenditures. Without the ability to fund capital expenditures, the Company would be unable to replace reserves and production. Sustained low prices of crude oil, natural gas, and NGLs may further adversely impact the Company’s business as follows:
•weakening the Company’s financial condition and reducing its liquidity;
•limiting the Company’s ability to fund planned capital expenditures and operations;
•reducing the amount of crude oil, natural gas, and NGLs that the Company can produce economically;
•causing the Company to delay or postpone some of its capital projects;
•reducing the Company’s revenues, operating income, and cash flows;
•limiting the Company’s access to sources of capital, such as equity and long-term debt;
•reducing the carrying value of the Company’s oil and gas properties, resulting in additional non-cash impairments; or
•reducing the carrying value of the Company’s gathering, processing, and transmission facilities, resulting in additional impairments.
The Company’s ability to sell crude oil, natural gas, or NGLs and/or receive market prices for these commodities and/or meet volume commitments under transportation services agreements may be adversely affected by pipeline and gathering system capacity constraints, the inability to procure and resell volumes economically, and various transportation interruptions.
A portion of the Company’s crude oil, natural gas, and NGL production in any region may be interrupted, limited, or shut in from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or capital constraints that limit the ability of third parties to construct gathering
systems, processing facilities, or interstate pipelines to transport the Company’s production, or the Company might voluntarily curtail production in response to market conditions. If a substantial amount of the Company’s production is interrupted at the same time, it could temporarily adversely affect the Company’s cash flows. Additionally, if the Company is unable to procure and resell third-party volumes at or above a net price that covers the cost of transportation, the Company’s cash flows could be adversely affected.
The Company may not realize an adequate return on wells that it drills.
Drilling for oil and gas involves numerous risks, including the risk that the Company will not encounter commercially productive oil or gas reservoirs. The wells the Company drills or participates in may not be productive, and the Company may not recover all or any portion of its investment in those wells. The seismic data and other technologies the Company uses do not allow it to know conclusively prior to drilling a well that crude or natural gas is present or may be produced economically. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors including, but not limited to:
•unexpected drilling conditions;
•pressure or irregularities in formations;
•equipment failures or accidents;
•fires, explosions, blowouts, and surface cratering;
•marine risks, such as capsizing, collisions, and hurricanes;
•other adverse weather conditions; and
•increases in the cost of or shortages or delays in the availability of drilling rigs and equipment.
Future drilling activities may not be successful, and, if unsuccessful, such failure could have an adverse effect on the Company’s future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.
The Company’s commodity price risk management and trading activities may prevent it from benefiting fully from price increases and may expose it to other risks.
To the extent that the Company engages in price risk management activities to protect itself from commodity price declines, the Company may be prevented from realizing the benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, the Company’s hedging arrangements may expose it to the risk of financial loss in certain circumstances, including instances in which:
•the Company’s production falls short of the hedged volumes;
•there is a widening of price-basis differentials between delivery points for the Company’s production and the delivery point assumed in the hedge arrangement;
•the counterparties to the Company’s hedging or other price risk management contracts fail to perform under those arrangements; or
•an unexpected event materially impacts commodity prices.
RISKS RELATED TO OPERATIONS AND DEVELOPMENT PROJECTS
The Company’s operations involve a high degree of operational risk, particularly risk of personal injury, damage to or loss of equipment, and environmental accidents.
The Company’s operations are subject to hazards and risks inherent in the drilling, production, and transportation of crude oil, natural gas, and NGLs, including:
•well blowouts, explosions, fires, and cratering;
•pipeline or other facility ruptures and spills;
•formations with abnormal pressures;
•equipment malfunctions;
•hurricanes, major storms, and cyclones, which could affect the Company’s operations in areas such as on and offshore the Gulf Coast, North Sea, and Suriname, and other natural and anthropogenic disasters and weather conditions; and
•surface spillage and surface or ground water contamination from petroleum constituents, saltwater, or hydraulic fracturing chemical additives.
Failure or loss of equipment, as the result of equipment malfunctions, cyberattacks, or natural disasters, such as hurricanes, could result in property damages, personal injury, environmental pollution, and other damages for which the Company could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion, fire at a location where the Company’s equipment and services are used, or ground water contamination from chemical additives used in hydraulic fracturing may result in substantial claims for damages. Ineffective containment of a drilling well blowout or pipeline rupture or surface spillage and surface or ground water contamination from petroleum constituents or hydraulic fracturing could result in extensive environmental pollution and substantial remediation expenses. If a significant amount of the Company’s production is interrupted, containment efforts prove to be ineffective, or litigation arises as the result of a catastrophic occurrence, the Company’s cash flows and, in turn, its results of operations could be materially and adversely affected.
Weather and climate may have a significant adverse impact on the Company’s revenues and production.
Demand for oil and natural gas are, to a significant degree, dependent on weather and climate, which impact the price the Company receives for the commodities it produces. In addition, the Company’s exploration, development, and production activities and equipment have been and can be adversely affected by severe weather, such as freezing temperatures, hurricanes in the Gulf of Mexico, or major storms in the North Sea, which have previously caused and may cause a loss of production from temporary cessation of activity or lost or damaged equipment. The Company’s planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather conditions, and not all such effects can be predicted, eliminated, or insured against.
The Company’s insurance policies do not cover all of the risks the Company faces, which could result in significant financial exposure.
Exploration for and production of crude oil, natural gas, and NGLs can be hazardous, involving natural disasters and other events such as blowouts, cratering, fires, explosions, and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. The Company’s international operations are also subject to political risk. The insurance coverage that the Company maintains against certain losses or liabilities arising from its operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to the Company against all operational risks.
A terrorist or cyberattack targeting systems and infrastructure used by the Company or others in the oil and gas industry may adversely impact the Company’s operations.
The Company’s business has become increasingly dependent on digital technologies to conduct certain exploration, development, and production activities. The Company depends on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, communicate with personnel and third-party partners, and conduct many of the Company’s activities. Unauthorized access to the Company’s digital technology could lead to operational disruption, data corruption, communication interruption, loss of intellectual property, loss of confidential and fiduciary data, and loss or corruption of reserves or other proprietary information. Also, external digital technologies control nearly all of the oil and gas distribution and refining systems in the U.S. and abroad, which are necessary to transport and market the Company’s production. A cyberattack directed at oil and gas distribution systems have previously and could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets, and make it difficult or impossible to accurately account for production and settle transactions. Any such terrorist attack, environmental activist group activity, or cyberattack that affects the Company or its customers, suppliers, or others with whom it does business could have a material adverse effect on the Company’s business, cause it to incur a material financial loss, subject it to possible legal claims and liability, and/or damage its reputation.
While certain of the Company’s insurance policies may allow for coverage of associated damages resulting from such events, if the Company were to incur a significant liability for which it was not fully insured, that could have a material adverse effect on the Company’s financial position, results of operations, and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
While the Company has experienced cyberattacks in the past, it has not suffered any material losses as a result of such attacks; however, there is no assurance that the Company will not suffer such losses in the future. Further, as cyberattacks continue to evolve, the Company may be required to expend significant additional resources to continue to modify or enhance its protective measures or to investigate and remediate any vulnerabilities to cyberattacks. In addition, cyberattacks against the Company or others in its industry could result in additional regulations, which could lead to increased regulatory compliance costs, insurance coverage cost, or capital expenditures. The Company cannot predict the potential impact that such additional regulations could have on its business and operations or the energy industry at large.
Material differences between the estimated and actual timing of critical events or costs may affect the completion and commencement of production from development projects.
The Company is involved in several large development projects, and the completion of these projects may be delayed beyond the Company’s anticipated completion dates. These projects may be delayed by project approvals from joint venture partners, timely issuances of permits and licenses by governmental agencies, weather conditions, manufacturing and delivery schedules of critical equipment, and other unforeseen events. Delays and differences between estimated and actual timing of critical events may adversely affect the Company’s large development projects and its ability to participate in large-scale development projects in the future. In addition, the Company’s estimates of future development costs are based on its current expectations of prices and other costs of equipment and personnel the Company will need to implement such projects. The actual future development costs may be significantly higher than the Company currently estimates. If costs become too high, the development projects may become uneconomic to the Company, and it may be forced to abandon such development projects.
RISKS RELATED TO RESERVES AND LEASEHOLD ACREAGE
Discoveries or acquisitions of additional reserves are needed to avoid a material decline in reserves and production.
The production rate from oil and natural gas properties generally declines as reserves are depleted, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. Therefore, unless the Company adds reserves through exploration and development activities, identifies additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves through engineering studies, or acquires additional properties containing proved reserves, the Company’s estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon the Company’s level of success in acquiring or finding additional reserves on an economic basis. Furthermore, as oil or natural gas prices increase, the Company’s cost for additional reserves could also increase.
The Company may fail to fully identify potential problems related to acquired reserves or to properly estimate those reserves.
Although the Company performs a review of properties that it acquires, which the Company believes is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in-depth every individual property involved in each acquisition. Ordinarily, the Company will focus its review efforts on the higher-value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit the Company as a buyer to become sufficiently familiar with the properties to assess fully and accurately their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the Company often assumes certain environmental and other risks and liabilities in connection with acquired properties. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future production rates and costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. In addition, there can be no assurance that acquisitions will not have an adverse effect upon the Company’s operating results, particularly during the periods in which the operations of acquired businesses are being integrated into the Company’s ongoing operations.
Crude oil, natural gas, and NGL reserves are estimates, and actual recoveries may vary significantly.
There are numerous uncertainties inherent in estimating crude oil, natural gas, and NGL reserves and their value. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas, and NGLs that cannot be measured in an exact manner. Because of the high degree of judgment involved, the accuracy of any reserve estimate is inherently imprecise and a function of the quality of available data and the engineering and geological interpretation. The Company’s reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore,
reserves quantities will change when actual prices increase or decrease. In addition, results of drilling, testing, and production may substantially change the reserve estimates for a given reservoir over time. The estimates of the Company’s proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including:
•historical production from the area compared with production from other areas;
•the effects of regulations by governmental agencies, including changes to severance and excise taxes;
•future operating costs and capital expenditures; and
•workover and remediation costs.
For these reasons, estimates of the economically recoverable quantities of crude oil, natural gas, and NGLs attributable to any particular group of properties, classifications of those reserves, and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to upward or downward adjustment, and actual production, revenue, and expenditures with respect to the Company’s reserves likely will vary, possibly materially, from estimates.
Additionally, because some of the Company’s reserves estimates are calculated using volumetric analysis, those estimates are less reliable than the estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. In addition, realization or recognition of proved undeveloped reserves will depend on the Company’s development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.
Certain of the Company’s undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
A sizeable portion of the Company’s acreage is currently undeveloped. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If the leases expire, the Company will lose its right to develop the related properties. The Company’s drilling plans for these areas are subject to change based upon various factors, including drilling results, commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.
RISKS RELATED TO COUNTERPARTIES
The credit risk of financial institutions could adversely affect the Company.
The Company is party to numerous transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, other investment funds, and other institutions. These transactions expose the Company to credit risk in the event of default of the counterparty. Deterioration in the credit or financial markets may impact the credit ratings of the Company’s current and potential counterparties and affect their ability to fulfill their existing obligations to the Company and their willingness to enter into future transactions with the Company. The Company may also have exposure to financial institutions in the form of derivative transactions in connection with any hedges. The Company also has exposure to insurance companies in the form of claims under the Company’s policies. In addition, if any lender under the Company’s credit facilities is unable to fund its commitment, the Company’s liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under the credit facilities.
The Company is exposed to a risk of financial loss if a counterparty fails to perform under a derivative contract. This risk of counterparty non-performance is of particular concern given the recent volatility of the financial markets and significant changes in commodity prices, which could lead to sudden changes in a counterparty’s liquidity and impair its ability to perform under the terms of the derivative contract. The Company is unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if the Company does accurately predict sudden changes, its ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of the Company’s hedge providers or some other similar proceeding or liquidity constraint might make it unlikely that the Company would be able to collect all or a significant portion of amounts owed to it by the distressed entity or entities. During periods of falling commodity prices, the Company’s hedge receivable positions increase, which increases the Company’s exposure. If the creditworthiness of the counterparties deteriorates and results in their nonperformance, the Company could incur a significant loss.
The distressed financial conditions of the Company’s purchasers and partners have had and could have an adverse impact on the Company in the event they are unable to pay the Company for the products or services it provides or to reimburse it for their share of costs.
Concerns about global economic conditions and the volatility of oil, natural gas, and NGL prices have had a significant adverse impact on the oil and gas industry. The Company is exposed to risk of financial loss from trade, joint venture, joint interest billing, and other receivables. The Company sells its crude oil, natural gas, and NGLs to a variety of purchasers. As operator, the Company pays expenses and bills its non-operating partners for their respective shares of costs. As a result of recent economic conditions and the previously severe decline in commodity prices, some of the Company’s customers and non-operating partners experienced severe financial problems that had a significant impact on their creditworthiness. The Company cannot provide assurance that one or more of its financially distressed customers or non-operating partners will not default on their obligations to the Company or that such a default or defaults will not have a material adverse effect on the Company’s business, financial position, future results of operations, or future cash flows. Furthermore, the bankruptcy of one or more of the Company’s customers or non-operating partners or some other similar proceeding or liquidity constraint have made it and might make it unlikely that the Company will or would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. Nonperformance by a trade creditor or non-operating partner could result in significant financial losses.
The Company’s liabilities could be adversely affected in the event one or more of its transaction counterparties become the subject of a bankruptcy case.
From time to time the Company has divested noncore or nonstrategic domestic and international assets. The agreements relating to these transactions contain provisions pursuant to which liabilities related to past and future operations have been allocated between the parties by means of liability assumptions, indemnities, escrows, trusts, bonds, letters of credit, and similar arrangements. One of the most significant of these liabilities involves the decommissioning of wells and facilities previously owned by the Company. One or more of the counterparties in these transactions could fail to perform its obligations under these agreements as a result of financial distress. In the event that any such counterparty becomes the subject of a case or proceeding under Title 11 of the United States Code or any other relevant insolvency law or similar law (which are collectively referred to as Insolvency Laws), the counterparty may not perform its obligations under the agreements related to these transactions. In that case, the Company’s remedy in the proceeding would be a claim for damages for the breach of the contractual arrangements, which may be either a secured claim or an unsecured claim depending on whether or not the Company has collateral from the counterparty for the performance of the obligations. Resolution of the Company’s claim for damages in such a proceeding may be delayed, and the Company may be forced to use available cash to cover the costs of the obligations assumed by the counterparties under such agreements should they arise, pending final resolution of the proceeding.
Despite the provisions in the Company’s agreements requiring purchasers of its state or federal leasehold interests to assume certain liabilities and obligations related to such interests, if a purchaser of such interests becomes the subject of a case or proceeding under relevant Insolvency Laws or becomes unable financially to perform such liabilities or obligations, the Company would expect the relevant governmental authorities to require it to perform and hold it responsible for such liabilities and obligations. In such event, the Company may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.
If a court or a governmental authority were to make any of the foregoing determinations or take any of the foregoing actions, or any similar determination or action, it could adversely impact the Company’s cash flows, operations, or financial condition.
For additional information regarding Apache’s prior Gulf of Mexico properties and the bankruptcy of the purchaser of those properties, see the information set forth under “Potential Obligation to Decommission Sold Properties” in Note 11-Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Item 15 of this Annual Report on Form 10-K.
The Company does not always control decisions made under joint operating agreements, and the parties under such agreements may fail to meet their obligations.
The Company conducts many of its exploration and production (E&P) operations through joint operating agreements with other parties under which the Company may not control decisions, either because it does not have a controlling interest or is not an operator under the agreement. There is risk that these parties may at any time have economic, business, or legal interests or goals that are inconsistent with the Company’s, and therefore, decisions may be made that the Company does not believe are in its best interest. Moreover, parties to these agreements may be unable to meet their economic or other obligations,
and the Company may be required to fulfill those obligations alone. In either case, the value of the investment may be adversely affected.
The Company own an approximate 79 percent interest in Altus, which holds substantially all of Apache’s former gathering, processing, and transmission assets in Alpine High. Altus may be subject to different risks than those described in this Annual Report on Form 10-K.
The Company owns an approximate 79 percent interest in Altus, which holds substantially all of Apache’s former gathering, processing, and transmission assets in Alpine High. Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas, anchored by midstream service contracts to service the Company’s production from Apache’s Alpine High resource play. Altus generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services and through its Equity Method Interest Pipelines. Given the nature of its business, Altus may be subject to different and additional risks than those described in this Annual Report on Form 10-K. For a description of these risks, refer to Altus’ most recently filed Annual Report on Form 10-K and any subsequently filed Quarterly Reports on Form 10-Q.
On October 21, 2021, ALTM announced that it will combine with privately owned BCP in an all-stock transaction. The transaction is expected to close during the first quarter of 2022, following completion of customary closing conditions. Upon closing of the transaction, the Company will no longer control Altus.
RISKS RELATED TO CAPITAL MARKETS
A downgrade in the Company’s credit rating could negatively impact its cost of and ability to access capital.
The Company receives debt ratings from the major credit rating agencies in the U.S. Factors that may impact the Company’s credit ratings include its debt levels, planned asset purchases or sales, and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, product mix, commodity pricing levels, and other factors are also considered by the rating agencies. A ratings downgrade could adversely impact the Company’s ability to access debt markets in the future and increase the cost of future debt. During 2021, the Company’s credit rating was affirmed by Moody’s to Ba1/Stable and by Standard and Poor’s to BB+/Stable. Past ratings downgrades have required, and any future downgrades may require, the Company to post letters of credit or other forms of collateral for certain obligations.
Market conditions may restrict the Company’s ability to obtain funds for future development and working capital needs, which may limit its financial flexibility.
The financial markets are subject to fluctuation and are vulnerable to unpredictable shocks. The Company has a significant development project inventory and an extensive exploration portfolio, which will require substantial future investment. The Company and/or its partners may need to seek financing to fund these or other future activities. The Company’s future access to capital, as well as that of its partners and contractors, could be limited if the debt or equity markets are constrained. This could significantly delay development of the Company’s property interests.
The Company’s syndicated credit facility currently matures in March 2024. There is no assurance of the terms upon which potential lenders under future agreements will make loans or other extensions of credit available to the Company or its subsidiaries or the composition of such lenders.
The discontinuation and uncertain cessation date of LIBOR, and the adoption of an alternative reference rate, may have a material adverse impact on the Company’s floating rate indebtedness and financing costs.
Pursuant to the terms of the Company’s revolving credit facility (1) the Company may elect to use the London Interbank Offering Rate (LIBOR) as a benchmark for establishing the interest rate on floating interest rate borrowings and (2) the commission payable to the lenders on the face amount of each outstanding letter of credit uses LIBOR as a benchmark. On November 30, 2020, the ICE Benchmark Administration (IBA) announced that it intends to continue publishing LIBOR until the end of June 2023, beyond the previously announced 2021 cessation date. The IBA announcement was supported by announcements from the U.K.’s Financial Conduct Authority (FCA), which regulates LIBOR, and the Board of Governors of the Federal Reserve System, Federal Deposit Insurance Corporation and Office of the Comptroller of the Currency (U.S. Regulators). However, both the FCA and U.S. Regulators in their announcements also advised banks to cease entering into new contracts referencing LIBOR after December 2021. These announcements indicate that the continuation of LIBOR in existing contracts may not be assured after 2021 and will not be assured beyond 2023. In light of these recent announcements, the future
of LIBOR at this time is uncertain, and any changes in the methods by which LIBOR is determined or regulatory activity related to LIBOR’s phaseout could cause LIBOR to perform differently than in the past or cease to exist.
In the U.S., the Alternative Reference Rates Committee (the working group formed to recommend an alternative rate to LIBOR) has identified the Secured Overnight Financing Rate (SOFR) as its preferred alternative rate for LIBOR. There can be no guarantee that SOFR will become a widely-accepted benchmark in place of LIBOR. Although the full impact of the transition away from LIBOR, including the discontinuance of LIBOR publication and the adoption of SOFR as the replacement rate for LIBOR, remains unclear, these changes may have an adverse impact on the Company’s floating rate indebtedness and financing costs under its revolving credit facility.
The Company’s ability to declare and pay dividends is subject to limitations.
The payment of future dividends on the Company’s capital stock is subject to the discretion of the Company’s board of directors, which considers, among other factors, the Company’s operating results, overall financial condition, credit-risk considerations, and capital requirements, as well as general business and market conditions. The board of directors is not required to declare dividends on APA’s common stock and may decide not to declare dividends.
Any indentures and other financing agreements that the Company enters into in the future may limit its ability to pay cash dividends on its capital stock, including APA common stock. In addition, under Delaware law, dividends on capital stock may only be paid from “surplus,” which is the amount by which the fair value of the Company’s total assets exceeds the sum of its total liabilities, including contingent liabilities, and the amount of its capital; if there is no surplus, cash dividends on capital stock may only be paid from the Company’s net profits for the then-current and/or the preceding fiscal year. Further, even if the Company is permitted under its contractual obligations and Delaware law to pay cash dividends on common stock, the Company may not have sufficient cash to pay dividends in cash on its common stock.
Unfavorable ESG ratings and funding limitation initiatives may lead to negative investor and public sentiment toward the Company and to the diversion of capital from the Company’s industry.
Organizations that provide information to investors on corporate governance and related matters have developed ratings for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform and advise their investment and voting decisions. In addition, certain organizations and stakeholders may encourage lenders to limit funding to E&P companies. Unfavorable ESG ratings and funding limitation initiatives may lead to negative investor and public sentiment toward the Company and to the diversion of capital from the Company’s industry, which could have a negative impact on the Company’s access to and costs of capital.
RISKS RELATED TO FINANCIAL RESULTS
Future economic conditions in the U.S. and certain international markets may materially adversely impact the Company’s operating results.
Current global market conditions and uncertainty, including economic instability in emerging markets, are likely to have significant long-term effects on the Company’s operating results. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate could result in decreased demand growth for the Company’s oil and natural gas production as well as lower commodity prices, which would reduce the Company’s cash flows from operations and its profitability.
The Company faces strong industry competition that may have a significant negative impact on the Company’s results of operations.
Strong competition exists in all sectors of the oil and gas E&P industry. The Company competes with major integrated and other independent oil and gas companies for acquisitions of oil and gas leases, properties, and reserves, equipment and labor required to explore, develop, and operate those properties, and marketing of crude oil, natural gas, and NGL production. Crude oil, natural gas, and NGL prices impact the costs of properties available for acquisition and the number of companies with the financial resources to pursue acquisition opportunities. Many of the Company’s competitors have financial and other resources substantially larger than the Company possesses and have established strategic, long-term positions and maintain strong governmental relationships in countries in which the Company may seek new entry. As a consequence, the Company may be at a competitive disadvantage in bidding for drilling rights. In addition, many of the Company’s larger competitors may have a competitive advantage when responding to factors that affect demand for oil and gas production, such as fluctuating worldwide commodity prices and levels of production, the cost and availability of alternative fuels, and the application of
government regulations. The Company also competes in attracting and retaining personnel, including geologists, geophysicists, engineers, and other specialists. These competitive pressures may have a significant negative impact on the Company’s results of operations.
The Company’s ability to utilize net operating losses and other tax attributes to reduce future taxable income may be limited if the Company experiences an ownership change.
As described in Note 10-Income Taxes of the Notes to Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K, the Company has substantial net operating loss carryforwards (NOLs) and other tax attributes available to potentially offset future taxable income. If the Company were to experience an “ownership change” under Section 382 of the Internal Revenue Code of 1986, as amended, which is generally defined as a greater than 50 percentage point change, by value, in the Company’s equity ownership by five-percent shareholders over a three-year period, the Company’s ability to utilize its pre-change NOLs and other pre-change tax attributes to potentially offset its post-change income or taxes may be limited. Such a limitation could materially adversely affect the Company’s operating results or cash flows by effectively increasing its future tax obligations.
RISKS RELATED TO GOVERNMENTAL REGULATION AND POLITICAL RISKS
The Company may incur significant costs related to environmental matters.
As an owner or lessee and operator of oil and gas properties, the Company is subject to various federal, state, local, and foreign laws and regulations relating to the discharge of materials into and protection of the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup and other remediation activities resulting from operations, subject the lessee to liability for pollution and other damages, limit or constrain operations in affected areas, and require suspension or cessation of operations in affected areas. The Company’s efforts to limit its exposure to such liability and cost may prove inadequate and result in significant adverse effects to the Company’s results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require the Company to make significant capital expenditures. Such capital expenditures could adversely impact the Company’s cash flows and its financial condition.
The Company’s U.S. operations are subject to governmental risks.
The Company’s U.S. operations have been, and at times in the future may be, affected by political developments and by federal, state, and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls, and environmental protection laws and regulations.
In response to the Deepwater Horizon incident in the U.S. Gulf of Mexico in April 2010 and as directed by the Secretary of the U.S. Department of the Interior, the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE) issued guidelines and regulations regarding safety, environmental matters, drilling equipment, and decommissioning applicable to drilling in the Gulf of Mexico. These regulations imposed additional requirements and caused delays with respect to development and production activities in the Gulf of Mexico.
With respect to oil and gas operations in the Gulf of Mexico, the 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 Apache provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to Apache’s current ownership interests in various Gulf of Mexico leases. The Company is working closely with BOEM to make arrangements for the provision of such additional required security, if such security becomes necessary under the NTL. Additionally, the Company is not able to predict the effect that these changes might have on counterparties to which Apache has sold Gulf of Mexico assets or with whom Apache 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.
New political developments, the enactment of new or stricter laws or regulations or other governmental actions impacting the Company’s U.S. operations, and increased liability for companies operating in this sector may adversely impact the Company’s results of operations.
Proposed federal, state, or local regulation regarding hydraulic fracturing could increase the Company’s operating and capital costs.
Several proposals are before the U.S. Congress that, if implemented, would either prohibit or restrict the practice of hydraulic fracturing or subject the process to regulation under the Safe Drinking Water Act. Several states and political subdivisions are considering legislation, ballot initiatives, executive orders, or other actions to regulate hydraulic fracturing practices that could impose more stringent permitting, transparency, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. Hydraulic fracturing of wells and subsurface water disposal are also under public and governmental scrutiny due to potential environmental and physical impacts, including possible contamination of groundwater and drinking water and possible links to induced seismicity. In addition, some municipalities have significantly limited or prohibited drilling activities and/or hydraulic fracturing or are considering doing so. The Company routinely uses fracturing techniques in the U.S. and other regions to expand the available space for natural gas and oil to migrate toward the wellbore. It is typically done at substantial depths in formations with low permeability.
Although it is not possible at this time to predict the final outcome of the governmental actions regarding hydraulic fracturing, any new federal, state, or local restrictions on hydraulic fracturing that may be imposed in areas in which the Company conducts business could result in increased compliance costs or additional operating restrictions in the U.S.
Changes in tax rules and regulations, or interpretations thereof, may adversely affect the Company’s business, financial condition, and results of operations.
The U.S. federal and state income tax laws affecting oil and gas exploration, development, and extraction may be modified by administrative, legislative, or judicial interpretation at any time. Previous legislative proposals, if enacted into law, could make significant changes to such laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas E&P companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. The passage or adoption of these changes, or similar changes, could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development. The Company is unable to predict whether any of these changes or other proposals will be enacted. Any such changes could adversely affect the Company’s business, financial condition, and results of operations.
RISKS RELATED TO CLIMATE CHANGE
Changes to existing regulations related to emissions and the impact of any changes in climate could adversely impact the Company’s business.
Certain countries where the Company operates, including the U.K., either tax or assess some form of greenhouse gas (GHG) related fees on the Company’s operations. Exposure has not been material to date, although a change in existing regulations could adversely affect the Company’s cash flows and results of operations. Additionally, there has been discussion in other countries where the Company operates, including the U.S., regarding legislation or regulation of GHG. Numerous proposals have been made and could continue to be made at the national, regional, and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. Moreover, on January 27, 2021, the President issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across governmental agencies and economic sectors.
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, restriction of emissions, electric vehicle mandates, and combustion engine phaseouts. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil, natural gas, and NGLs. Additionally, political, litigation, and financial risks related to climate change may result in curtailed refinery activity, increased regulation, or other adverse direct and indirect effects on the Company’s business, financial condition, and results of operations. For example, there is a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector.
Any such legislation, regulations, or other regulatory initiatives, if enacted, or additional or increased taxes, assessments, or GHG-related fees on the Company’s operations could lead to increased operating expenses or cause the Company to make significant capital investments for infrastructure modifications.
Enhanced scrutiny on ESG matters could have an adverse effect on the Company’s operations.
Enhanced scrutiny on ESG matters related to, among other things, concerns raised by advocacy groups about climate change, hydraulic fracturing, waste disposal, oil spills, and explosions of natural gas transmission pipelines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines, and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens, increased risk of litigation, and adverse impacts on the Company’s access to capital. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance, and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits the Company requires to conduct its operations to be withheld, delayed, or burdened by requirements that restrict the Company’s ability to profitably conduct its business.
The Company’s estimates used in various scenario planning analyses could differ materially from actual results and could expose us to new or additional risks.
In 2021, the Company undertook a scenario planning analysis in alignment with recommendations of the Financial Stability Board’s Taskforce on Climate-related Financial Disclosures (“TCFD”). This expanded climate-focused scenario planning framework included forecasts of future demand and pricing in energy markets, as well as changes in government regulations and policy. Given the dynamic nature of the Company’s business, the Company generally performs annual scenario analyses with five-year time horizons. When analyzing longer-term TCFD scenarios, the Company relies on external analysis for demand scenarios, carbon pricing, and comparison-pricing scenarios, which are then compared to the Company’s internally prepared base-case pricing analysis averaged out to 2040. Given the numerous estimates that are required to run these scenarios, the Company’s estimates could differ materially from actual results. Additionally, by electing to set and share publicly these metrics in the Company’s sustainability report and the Company’s commitment to expand upon its disclosures, the Company’s business may also face increased scrutiny related to ESG initiatives. As a result, the Company could damage its reputation if it fails to act responsibly in the areas in which it reports. Any harm to the Company’s reputation resulting from setting these metrics, expanding its disclosures, or its failure or perceived failure to meet such metrics or disclosures could adversely affect the Company’s business, financial performance, and growth.
The Company operates in Gulf Coast wetlands, which face threats from climate change and human activities.
A changing climate creates uncertainty and could result in broad changes, both physical and financial, to the areas in which the Company operates, including Gulf Coast wetlands. For several decades, the State of Louisiana has lost an estimated 20 square miles of wetlands per year, due to natural processes of subsidence, saltwater intrusion, and shoreline erosion, as well as human activities, such as levee construction along the Mississippi River and the dredging of navigation canals. A possible result of climate change is more frequent and more severe weather events, such as hurricanes and major flooding events. The risk of increased or more severe hurricanes or flooding events along or near the Gulf Coast could increase the Company’s costs to repair damaged facilities and restore production. Additionally, federal, state, and local laws and regulations may impose numerous obligations applicable to the Company’s operations including: (i) the limitation or prohibition of certain activities on wetlands; (ii) the imposition of substantial liabilities for pollution resulting from operations; (iii) the reporting of the types and quantities of various substances that are generated, stored, processed, or released in connection with protected properties; and (iv) the installation of costly emission monitoring and/or pollution control equipment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of the Company’s operations. In addition, the Company may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt the Company’s operations or specific projects and limit its growth and revenue.
The guidance upon which the Company’s consumptive water use reporting was modified and could be revised in the future, resulting in the over or underreporting of the Company’s consumptive water use, and could expose the Company to financial risk.
Based on Ipieca’s Sustainability Reporting Guidance of the Oil and Gas Industry (2020), the Company modified the way it reports its water data compared to previous years and also restated data from past years. Previously, the Company included produced water usage in its consumptive use calculations, which led to an over-reporting of consumptive water use. Based on re-evaluation of water reporting definitions and guidance, the Company determined that produced water - non-potable water
released from deep underground formations and brought to the surface during oil and gas exploration and production - should not be classified as consumed in the same sense as fresh water. Produced water is generally not of the quality that most users would be able to utilize and is therefore not available for third-party usage outside of the oilfield. The Company’s revised reporting now reflects only fresh water and non-potable water from surface water or shallow groundwater that are consumed in oil and gas operations.
The treatment and disposal of produced water is becoming more highly regulated and restricted and could expose the Company to additional costs or limit certain operations.
The treatment and disposal of produced water is becoming more highly regulated and restricted. The Company’s ability to accurately report and track its water use is necessary for its continued ability to reuse and recycle water, when possible. While the Company remains focused on reusing or recycling water over disposal of water, the Company’s costs for obtaining and disposing of water could increase significantly if reusing and recycling water becomes impractical. Further, compliance with reporting and environmental regulations governing the withdrawal, storage, use, and discharge of water may increase the Company’s operating costs, which could materially and adversely affect its business, results of operations, and financial conditions. For example, the Railroad Commission of Texas (RRC) has been developing data associated with seismic activity, particularly such activity related to injection wells used for produced water disposal. In September 2021, the RRC began to limit saltwater disposal in the Midland Basin under what is known as a Seismic Response Action (or SAR) due to increased seismic activity. These developments could result in restriction of disposal wells that could have a material effect on the Company’s capital expenses and operating costs or limit production in certain areas.
RISKS RELATED TO INTERNATIONAL OPERATIONS
International operations have uncertain political, economic, and other risks.
The Company’s operations outside the U.S. are based primarily in Egypt and the U.K., with significant exploration and appraisal activities offshore Suriname. On a barrel equivalent basis, approximately 41 percent of the Company’s 2021 production was outside the U.S., and approximately 32 percent of the Company’s estimated proved oil and gas reserves as of December 31, 2021, were located outside the U.S. As a result, a significant portion of the Company’s production and resources are subject to the increased political and economic risks and other factors associated with international operations including, but not limited to:
•general strikes and civil unrest;
•the risk of war, acts of terrorism, expropriation and resource nationalization, and forced renegotiation or modification of existing contracts, including through prospective or retroactive changes in the laws and regulations applicable to such contracts;
•import and export regulations;
•taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions;
•price control;
•transportation regulations and tariffs;
•constrained oil or natural gas markets dependent on demand in a single or limited geographical area;
•exchange controls, currency fluctuations, devaluations, or other activities that limit or disrupt markets and restrict payments or the movement of funds;
•laws and policies of the U.S. affecting foreign trade, including trade sanctions;
•the long-term effects of the U.K.’s withdrawal from the European Union, including any resulting instability in global financial markets or the value of foreign currencies such as the British pound;
•the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where the Company currently operates;
•the possible inability to subject foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of courts in the U.S.; and
•difficulties in enforcing the Company’s rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.
Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to the Company by another country, the Company’s interests could decrease in value or be lost. Even the Company’s smaller international assets may affect its overall business and results of operations by distracting management’s attention from its more significant assets. Certain regions of the world in which the Company operates have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investments such as the Company’s. In an extreme case, such a change could result in termination of contract rights and expropriation of the Company’s assets. This could adversely affect the Company’s interests and its future profitability.
The impact that future terrorist attacks or regional hostilities, as have occurred in countries and regions in which the Company operates, may have on the oil and gas industry in general and on the Company’s operations in particular is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants, and refineries, could be direct targets or indirect casualties of an act of terror or war. The Company may be required to incur significant costs in the future to safeguard its assets against terrorist activities.
A deterioration of conditions in Egypt or changes in the economic and political environment in Egypt could have an adverse impact on the Company’s business.
Deterioration in the political, economic, and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of the Company’s assets or resource nationalization, and/or forced renegotiation or modification of the Company’s existing contracts with Egyptian General Petroleum Corporation (EGPC), or threats or acts of terrorism could materially and adversely affect the Company’s business, financial condition, and results of operations. The Company’s operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 22 percent of the Company’s 2021 production and accounted for 16 percent of the Company’s year-end estimated proved reserves and 20 percent of the Company’s estimated discounted future net cash flows.
The Company’s operations are sensitive to currency rate fluctuations.
The Company’s operations are sensitive to fluctuations in foreign currency exchange rates, particularly between the U.S. dollar and the British pound. The Company’s financial statements, presented in U.S. dollars, may be affected by foreign currency fluctuations through both translation risk and transaction risk. Volatility in exchange rates may adversely affect the Company’s results of operations, particularly through the weakening of the U.S. dollar relative to other currencies.
RISKS RELATED TO THE HOLDING COMPANY REORGANIZATION
APA, as the parent holding company of Apache, is dependent on the operations and funds of its subsidiaries, including Apache.
As a result of the Holding Company Reorganization APA became the successor issuer to, and parent holding company of, Apache. APA has no business operations of its own, and its only significant assets are the outstanding equity interests of its subsidiaries, including Apache. As a result, APA relies on cash flows from its subsidiaries, including Apache, to pay dividends with respect to APA’s common stock and to meet its financial obligations, including to service any debt obligations that the Company may incur from time to time. Legal and contractual restrictions in agreements governing future indebtedness of Apache, as well as Apache’s financial condition and future operating requirements, may limit Apache’s ability to distribute cash to the Company. If Apache is limited in its ability to distribute cash to the Company, or if Apache’s earnings or other available assets of are not sufficient to pay distributions or make loans to the Company in the amounts or at the times necessary for it to pay dividends with respect to its common stock and/or to meet its financial obligations, then the Company’s business, financial condition, cash flows, results of operations, and reputation may be materially adversely affected.
The Company may not obtain the anticipated benefits of the reorganization into a holding company structure.
The Company believes that its new operating structure will allow it to focus on running its diverse businesses independently, with the goal of maximizing each of the business’ potential. However, the anticipated benefits of the Holding Company Reorganization may not be obtained if circumstances prevent the Company from taking advantage of the strategic and business opportunities that it expects the structure may afford the Company. As a result, the Company may incur the costs of a holding company structure without realizing the anticipated benefits, which could adversely affect the Company’s business, financial condition, cash flows, and results of operations.
Management is dedicating significant effort to the new operating structure. These efforts may divert management’s focus and resources from the Company’s operations, strategic initiatives, or development opportunities, which could adversely affect the Company’s prospects, business, financial condition, cash flows, and results of operations.
GENERAL RISK FACTORS
Certain anti-takeover provisions in the Company’s charter and Delaware law could delay or prevent a hostile takeover.
The Company’s charter authorizes the board of directors to issue preferred stock in one or more series and to determine the voting rights and dividend rights, dividend rates, liquidation preferences, conversion rights, redemption rights, including sinking fund provisions and redemption prices, and other terms and rights of each series of preferred stock. In addition, Delaware law imposes restrictions on mergers and other business combinations between the Company and any holder of 15 percent or more of APA’s outstanding common stock. These provisions may deter hostile takeover attempts that could result in an acquisition of the Company that would have been financially beneficial to APA’s shareholders.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
The information set forth under “Legal Matters” and “Environmental Matters” in 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 is incorporated herein by reference.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
None.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
APA’s common stock, par value $0.625 per share, is traded on the Nasdaq Global Select Market (Nasdaq) under the symbol “APA.” The closing price of APA’s common stock, as reported by the Nasdaq for January 31, 2022, was $33.21 per share. As of January 31, 2022, there were 346,776,379 shares of APA’s common stock outstanding held by approximately 3,300 stockholders of record and 152,000 beneficial owners.
The Company has paid cash dividends on its common stock for 57 consecutive years through December 31, 2021. In the third quarter of 2021, APA’s Board of Directors approved an increase in the Company’s quarterly dividend per share from $0.025 per share to $0.0625 per share, effective for all dividends payable after September 14, 2021, and further increased the quarterly dividend in the fourth quarter of 2021 to $0.125 per share to be paid on February 22, 2022. When, and if, declared by the Company’s Board of Directors, future dividend payments will depend upon the Company’s level of earnings, financial requirements, and other relevant factors.
Information concerning securities authorized for issuance under equity compensation plans is set forth under the caption “Equity Compensation Plan Information” in the proxy statement relating to the Company’s 2022 annual meeting of stockholders, which is incorporated herein by reference.
Issuer Purchases of Equity Securities
The table below sets forth information with respect to shares of common stock repurchased by APA during 2021.
Period Purchased Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs(1)
Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
January 1 to January 31, 2021 - $ - - 40,000,019
February 1 to February 28, 2021 - - - 40,000,019
March 1 to March 31, 2021 - - - 40,000,019
April 1 to April 30, 2021 - - - 40,000,019
May 1 to May 31, 2021 - - - 40,000,019
June 1 to June 30, 2021 - - - 40,000,019
July 1 to July 31, 2021 - - - 40,000,019
August 1 to August 31, 2021 - - - 40,000,019
September 1 to September 30, 2021 - - - 40,000,019
October 1 to October 31, 2021 12,849,856 26.48 12,849,856 67,150,163
November 1 to November 30, 2021 11,153,840 28.28 11,153,840 55,996,323
December 1 to December 31, 2021 7,200,533 26.58 7,200,533 48,795,790
Total 31,204,229 $ 27.14
(1)During the fourth quarter of 2018, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of an additional 40 million shares of the Company’s common stock. In both cases, shares may be purchased either in the open market or through privately held negotiated transactions.
The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s 500 Index (S&P 500 Index) and of the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) from December 31, 2016, through December 31, 2021. The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that the Company specifically incorporates it by reference into such filing.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among APA Corporation, the S&P 500 Index,
and the Dow Jones U.S. Exploration & Production Index
* $100 invested on 12/31/16 in stock or index, including reinvestment of dividends.
Fiscal year ending December 31.
2016 2017 2018 2019 2020 2021
APA Corporation $ 100.00 $ 67.87 $ 43.18 $ 43.63 $ 24.56 $ 46.86
S&P 500 Index 100.00 121.83 116.49 153.17 181.35 233.41
Dow Jones U.S. Exploration & Production Index 100.00 101.30 83.30 92.79 61.57 105.24

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. SELECTED FINANCIAL DATA
Omitted.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together in conjunction with the Company’s Consolidated Financial Statements and accompanying notes included in Part IV, Item 15 of this Annual Report on Form 10-K, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Annual Report on Form 10-K. This section of this Annual Report on Form 10-K generally discusses 2021 and 2020 items and year-to-year comparisons between 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are not included in this Annual Report on Form 10-K are incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020 (filed with the SEC on February 25, 2021).
On January 4, 2021, Apache Corporation announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, Apache Corporation became a direct, wholly owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares were automatically converted into equivalent corresponding shares of APA Corporation. Pursuant to the Holding Company Reorganization, APA Corporation became the successor issuer to Apache Corporation pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache Corporation as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the Company’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have subsidiaries operating around the globe.
Overview
APA is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids (NGLs). The Company’s upstream business currently has exploration and production operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active exploration and appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. The Company’s midstream business (Altus Midstream) is operated by Altus Midstream Company (Nasdaq: ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas.
APA believes energy underpins global progress, and the Company wants to be a part of the conversation and solution as society works to meet growing global demand for reliable and affordable energy. Today, the world faces a dual challenge: To meet growing demand for energy and to do so in a cleaner, more sustainable way. APA believes society can accomplish both and strives to meet those challenges while creating value for all its stakeholders.
The global economy and the energy industry have been deeply impacted by the effects of the coronavirus disease 2019 (COVID-19) pandemic and related governmental actions. Uncertainties in the commodity and financial markets since early 2020 continue to impact oil supply and demand. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of ongoing exploration and appraisal activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its stakeholders. The Company continues to aggressively manage its cost structure regardless of the oil price environment and closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process. For additional detail on the Company’s forward capital investment outlook, refer to “Capital and Operational Outlook” below.
During 2021, the Company reported net income attributable to common stock of $973 million, or $2.59 per diluted share, compared to a net loss of $4.9 billion, or $12.86 per diluted share, in 2020. Net income in 2021 benefited from significantly improved commodity prices that had collapsed in the prior year when the COVID-19 pandemic negatively affected economic activity and the oil markets. In 2020, the Company recorded impairments totaling $4.5 billion in connection with fair value assessments stemming from the global crude oil price collapse.
The Company generated $3.5 billion of cash from operating activities in 2021, which was $2.1 billion or 152 percent higher than the prior year. APA’s higher operating cash flows for 2021 were driven by higher crude oil and natural gas prices and associated revenues. The Company ended the year with a cash balance of $302 million, up $40 million from year-end 2020, after paying back nearly $1.4 billion of debt during 2021 in an effort to reduce near-term debt maturities and strengthening its balance sheet.
Following this progress and considering the ongoing constructive price environment, the Company initiated a capital return framework for our shareholders, as follows:
•The Company implemented a capital return framework during 2021 for equity holders to participate more directly and materially in cash returns. The Company believes returning 60 percent of cash flow over capital investment creates a good balance for providing near-term cash returns to shareholders while still recognizing the importance of longer-term balance sheet strengthening.
•The Company announced a quarterly dividend increase in the third quarter of 2021 from $0.025 per share to $0.0625 per share and, in the fourth quarter of 2021, announced a further increase to $0.125 per share.
•During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. The Company repurchased approximately 31.2 million of its common shares for $847 million during the fourth quarter of 2021. As of December 31, 2021, the Company had remaining authorization to repurchase up to 48.8 million shares under Company’s share repurchase programs.
Operational Highlights
Key operational highlights for the year include:
United States
•Daily boe production from the Company’s U.S. assets, which decreased 10 percent from the prior year end, accounted for 59 percent of its total worldwide production during 2021. After halting all drilling and completion activity for most of 2020, in response to completion cost reductions, the Company reinstated two operated completion crews in the Permian Basin in late 2020 to begin completing its backlog of drilled but uncompleted well inventory. In early 2021, the Company re-activated one drilling rig in the Permian Basin and one rig in the Austin Chalk. A second rig was added in the Permian Basin in late June 2021. For 2022, the Company will continue to budget its capital program at levels to fund activity necessary to offset inherent declines in production and proved oil and natural gas reserves.
•On October 11, 2021, the Company announced that it has ended routine flaring in its U.S. onshore operations, achieving one of its announced 2021 environmental, social and governance (ESG) goals three months ahead of schedule. The Company also seeks continuous improvement on its safety performance and protocols, having established key safety indicators and metrics that are rigorously managed and that impact annual incentive compensation Company-wide.
•On October 21, 2021, ALTM announced that it will combine with privately owned BCP Raptor Holdco LP (BCP) in an all-stock transaction. As consideration for the transaction, ALTM will issue 50 million shares of Class C Common Stock (and its subsidiary, Altus Midstream LP, will issue a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. Upon closing of the transaction, APA will own approximately 20 percent of the issued and outstanding common stock of the combined entity. The transaction is expected to close during the first quarter of 2022 following completion of customary closing conditions.
International
•In December 2021, the Egyptian President signed and ratified the previously announced agreement with the Egyptian Ministry of Petroleum and the Egyptian General Petroleum Corporation (EGPC) to modernize the terms of the majority of the Company’s production-sharing contracts (PSCs), having an effective date of April 1, 2021. The new PSC consolidates 98 percent of gross acreage and 90 percent of gross production into a single concession and refreshes the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool that provides improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit-sharing rate of 30 percent for all the Company’s production covered under the new concession. The changes also simplify the contractual relationship with EGPC, facilitate recovery of prior investment, and update day-to-day operational governance. The Apache entity that is the sole contractor is owned two-thirds by Apache and one-third by Sinopec International Petroleum Exploration and Production Corporation (Sinopec).
•Egypt gross equivalent production decreased 14 percent and net production decreased 6 percent from 2020, primarily a result of natural decline given reduced drilling activity in the past year. The modernized production-sharing agreement did not impact 2021 production since it was ratified at the end of the year. The Company continues to build and enhance its robust drilling inventory in Egypt, supplemented with recent seismic acquisitions and new play concept evaluations, on both new and existing acreage. The Company anticipates increased drilling and workover activity in 2022 as a result of the ratification of the new modernized PSC.
•The North Sea maintained two drilling rigs during 2021. During the year, production was significantly impacted by compressor downtime, extended platform turnaround work, and third-party pipeline outages.
•Following three successful exploration discoveries offshore Suriname on Block 58, in late 2020, the Company commenced drilling a fourth exploration well in the block at the Keskesi prospect. In January 2021, the Company and its partner TotalEnergies (formerly Total S.A.) announced a discovery that confirmed oil in the eastern portion of the block. The Company has subsequently transferred operatorship of Block 58 to TotalEnergies, with exploration and appraisal activities continuing to progress. TotalEnergies holds a 50 percent working interest in Block 58.
•In November 2021, the Company announced a successful flow test and pressure buildup at its Sapakara South appraisal well on Block 58, which continues to improve in outlook as additional information is gathered and processed. Further, in February 2022 the Company and TotalEnergies announced an oil discovery at the Krabdagu-1 (KBD-1) exploration well. KBD-1 is located approximately 18 kilometers southeast of the Sapakara South-1 well. The well was designed to test multiple stacked targets in Maastrichtian and Campanian intervals and encountered approximately 90 meters (295 feet) of net oil pay.
For a more detailed discussion related to the Company’s various geographic segments, refer to “Upstream Exploration and Production Properties-Operating Areas” set forth in Part I, Item 1 and 2 of this Annual Report on Form 10-K.
Acquisition and Divestiture Activity
Over the Company’s history, it has repeatedly demonstrated the ability to capitalize quickly and decisively on changes in its industry and economic conditions. A key component of this strategy is to continuously review and optimize APA’s portfolio of assets in response to these changes. Most recently, the Company has completed a series of divestitures designed to monetize nonstrategic assets and enhance the Company’s portfolio in order to allocate resources to more impactful exploration and development opportunities. These divestitures include:
•Permian Basin Divestiture In the second quarter of 2021, the Company completed the sale of certain non-core assets in the Central Basin Platform of the Permian Basin for total cash proceeds of $176 million and the assumption of asset retirement obligations of $44 million.
•U.S. Leasehold Divestitures & Acquisitions During 2021, the Company completed the sale of other non-core assets and leasehold acreage, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $80 million. Also during 2021, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $9 million.
•U.S. Leasehold Divestitures & Other During 2020, the Company completed the sale of certain non-core producing assets and leasehold acreage, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $87 million. The Company also completed certain leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $4 million.
•Suriname Joint Venture Agreement In December 2019, the Company entered into a joint venture agreement with TotalEnergies to explore and develop Block 58 offshore Suriname. Under the terms of the agreement, the Company and TotalEnergies each hold a 50 percent working interest in Block 58. The Company operated the drilling of the first four wells and subsequently transferred operatorship of Block 58 to TotalEnergies. In connection with the agreement, the Company received $100 million upon closing in the fourth quarter of 2019 and $79 million upon satisfying certain closing conditions in the first quarter of 2020 for reimbursement of 50 percent of all costs incurred on Block 58 as of December 31, 2019. Key terms of the agreement provide for TotalEnergies to pay a proportionately larger share of appraisal and development costs, which would be recoverable through hydrocarbon participation.
For detailed information regarding APA’s acquisitions and divestitures, refer to Note 2-Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Results of Operations
Oil and Gas Production Revenues
The Company’s oil and gas production revenues and respective contribution to total revenues by country are as follows:
For the Year Ended December 31,
2021 2020 2019
$ Value % Contribution $ Value % Contribution $ Value % Contribution
($ in millions)
Oil Revenues:
United States $ 1,850 40 % $ 1,209 39 % $ 2,098 40 %
Egypt(1)
1,806 40 % 1,102 35 % 1,969 38 %
North Sea 929 20 % 795 26 % 1,163 22 %
Total(1)
$ 4,585 100 % $ 3,106 100 % $ 5,230 100 %
Natural Gas Revenues:
United States $ 754 62 % $ 251 42 % $ 293 43 %
Egypt(1)
270 23 % 280 47 % 295 44 %
North Sea 183 15 % 67 11 % 90 13 %
Total(1)
$ 1,207 100 % $ 598 100 % $ 678 100 %
NGL Revenues:
United States $ 673 95 % $ 304 91 % $ 372 91 %
Egypt(1)
9 1 % 8 3 % 12 3 %
North Sea 24 4 % 21 6 % 23 6 %
Total(1)
$ 706 100 % $ 333 100 % $ 407 100 %
Oil and Gas Revenues:
United States $ 3,277 50 % $ 1,764 44 % $ 2,763 44 %
Egypt(1)
2,085 32 % 1,390 34 % 2,276 36 %
North Sea 1,136 18 % 883 22 % 1,276 20 %
Total(1)
$ 6,498 100 % $ 4,037 100 % $ 6,315 100 %
(1)Includes revenues attributable to a noncontrolling interest in Egypt.
Production
The following table presents production volumes by country:
For the Year Ended December 31,
2021 Increase
(Decrease) 2020 Increase
(Decrease) 2019
Oil Volumes - b/d:
United States(5)
75,205 (15)% 88,249 (16)% 105,051
Egypt(3)(4)
70,349 (7)% 75,384 (11)% 84,617
North Sea 36,265 (28)% 50,386 1% 49,746
Total 181,819 (15)% 214,019 (11)% 239,414
Natural Gas Volumes - Mcf/d:
United States(5)
527,461 (6)% 561,731 (12)% 639,580
Egypt(3)(4)
263,653 (4)% 274,175 (4)% 285,972
North Sea 38,565 (33)% 57,464 5% 54,642
Total 829,679 (7)% 893,370 (9)% 980,194
NGL Volumes - b/d:
United States(5)
66,232 (11)% 74,136 8% 68,381
Egypt(3)(4)
531 (30)% 754 (19)% 931
North Sea 1,199 (38)% 1,936 11% 1,739
Total 67,962 (12)% 76,826 8% 71,051
BOE per day:(1)
United States(5)
229,348 (10)% 256,007 (9)% 280,029
Egypt(3)(4)
114,821 (6)% 121,834 (9)% 133,209
North Sea(2)
43,892 (29)% 61,899 2% 60,592
Total 388,061 (12)% 439,740 (7)% 473,830
(1)The table shows production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the price ratio between the two products.
(2)Average sales volumes from the North Sea were 44,179 boe/d, 62,157 boe/d, and 59,797 boe/d for 2021, 2020, and 2019, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.
(3)Gross oil, natural gas, and NGL production in Egypt were as follows:
2021 2020 2019
Oil (b/d) 134,711 164,104 193,886
Natural Gas (Mcf/d) 586,663 641,069 708,682
NGL (b/d) 854 1,429 1,722
(4)Includes net production volumes per day attributable to a noncontrolling interest in Egypt of:
2021 2020 2019
Oil (b/d) 23,504 25,206 28,220
Natural Gas (Mcf/d) 88,409 91,540 95,539
NGL (b/d) 177 251 310
(5)Production volumes per day in the Company’s Alpine High field were as follows:
2021 2020 2019
Oil (b/d) 1,485 2,718 3,475
Natural Gas (Mcf/d) 258,096 274,279 316,169
NGL (b/d) 22,950 24,942 17,446
Pricing
The following table presents pricing information by country:
For the Year Ended December 31,
2021 Increase
(Decrease) 2020 Increase
(Decrease) 2019
Average Oil Price - Per barrel:
United States $ 67.37 80% $ 37.42 (32)% $ 54.71
Egypt 70.33 76% 39.95 (37)% 63.76
North Sea 69.67 62% 42.88 (34)% 65.10
Total 68.97 74% 39.60 (34)% 60.05
Average Natural Gas Price - Per Mcf:
United States $ 3.92 221% $ 1.22 (3)% $ 1.26
Egypt 2.81 1% 2.79 (1) 2.83
North Sea 12.96 306% 3.19 (29)% 4.48
Total 3.99 118% 1.83 (4)% 1.90
Average NGL Price - Per barrel:
United States $ 27.85 148% $ 11.21 (25)% $ 14.95
Egypt 48.84 75% 27.83 (18)% 33.87
North Sea 54.30 83% 29.73 (19)% 36.83
Total 28.48 141% 11.84 (25)% 15.74
Crude Oil Prices A substantial portion of the Company’s crude oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of the Company’s control. Average realized crude oil prices for 2021 were up 74 percent compared to 2020, a direct result of the rising benchmark oil prices over the past year. Crude oil prices realized in 2021 averaged $68.97 per barrel.
Continued volatility in the commodity price environment reinforces the importance of the Company’s asset portfolio. While the market price received for natural gas varies among geographic areas, crude oil tends to trade within a global market. Price movements for all types and grades of crude oil generally move in the same direction.
Natural Gas Prices Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions. The Company’s primary markets include North America, Egypt, and the U.K. An overview of the market conditions in the Company’s primary gas-producing regions follows:
•The Company predominantly sells its natural gas production within the U.S., including to U.S. LNG export facilities, although a portion is sold to markets in Mexico. Most of the Company’s U.S. natural gas is sold on a monthly or daily basis at either monthly or daily index-based prices. The Company’s U.S. realizations averaged $3.92 per Mcf in 2021, up from $1.22 per Mcf in 2020.
•In Egypt, the Company’s natural gas is sold to EGPC, primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. Overall, the Company’s Egypt operations averaged $2.81 per Mcf in 2021, a 1 percent increase from 2020.
•Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The Company’s North Sea operations averaged $12.96 per Mcf in 2021, a 306 percent increase from an average of $3.19 per Mcf in 2020.
NGL Prices The Company’s U.S. NGL production, which accounted for 97 percent of the Company’s total 2021 NGL production, is sold under contracts with prices at market indices based on Gulf Coast supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.
Crude Oil Revenues
Crude oil revenues for 2021 totaled $4.6 billion, a $1.5 billion increase from the 2020 total of $3.1 billion. A 74 percent increase in average realized prices increased 2021 revenues by $2.3 billion compared to 2020, while 15 percent lower average daily production decreased revenues by $825 million. Average daily production in 2021 was 182 Mb/d, with prices averaging $68.97 per barrel. Crude oil sales accounted for 71 percent of the Company’s 2021 oil and gas production revenues and 47 percent of its worldwide production.
The Company’s worldwide crude oil production decreased 32 Mb/d compared to 2020, primarily a result of production decline across all countries driven by reduced drilling activity in the prior year, and extended operational downtime and platform turnaround work in the North Sea.
Natural Gas Revenues
Natural gas revenues for 2021 totaled $1,207 million, a $609 million increase from the 2020 total of $598 million. A 118 percent increase in average realized prices increased 2021 revenues by $705 million compared to 2020, while 7 percent lower average daily production decreased revenues by $96 million. Average daily production in 2021 was 830 MMcf/d, with prices averaging $3.99 per Mcf. Natural gas sales accounted for 18 percent of the Company’s 2021 oil and gas production revenues and 36 percent of its worldwide production.
The Company’s worldwide natural gas production decreased 64 MMcf/d compared to 2020, primarily a result of production decline across all countries, impacts of winter storms in the U.S., and extended operational downtime and platform turnaround work in the North Sea.
NGL Revenues
NGL revenues for 2021 totaled $706 million, a $373 million increase from the 2020 total of $333 million. A 141 percent increase in average realized prices increased 2021 revenues by $467 million compared to 2020, while 12 percent lower average daily production decreased revenues by $94 million. Average daily production in 2021 was 68 Mb/d, with prices averaging $28.48 per barrel. NGL sales accounted for 11 percent of the Company’s 2021 oil and gas production revenues and 17 percent of its worldwide production.
The Company’s worldwide NGL production decreased 9 Mb/d compared to 2020, primarily a result of production decline across all countries and the impacts of winter storms in the U.S.
Altus Midstream Revenues
The Company beneficially owns approximately 79 percent of ALTM’s outstanding voting common stock. Altus owns and operates a midstream energy asset network in the Permian Basin of West Texas primarily to service the Company’s production from its Alpine High resource play, which commenced production in May 2017. On October 21, 2021, ALTM announced that it will combine with privately owned BCP in an all-stock transaction, and APA’s ownership in ALTM will be reduced from approximately 79 percent to approximately 20 percent. The transaction is expected to close during the first quarter of 2022, following completion of customary closing conditions.
Altus Midstream primarily generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services. For the years ended December 31, 2021 and 2020, Altus Midstream’s service revenues generated through its fee-based contractual arrangements with the Company totaled $127 million and $145 million, respectively. These affiliated revenues are eliminated upon consolidation. The decrease in revenue compared to the prior year was primarily driven by lower natural gas throughput volumes processed by Altus for the Company’s Alpine High production.
Purchased Oil and Gas Sales
Purchased oil and gas sales represent volumes primarily attributable to transport, fuel, and physical in-basin gas purchases that were sold by the Company to fulfill natural gas takeaway obligations. Sales related to these purchased volumes increased $1.1 billion for the year ended December 31, 2021 from $398 million to $1.5 billion. Purchased oil and gas sales were offset by associated purchase costs of $1.6 billion and $357 million for the years ended December 31, 2021 and 2020, respectively. The increase is the result of sales volume growth associated with additional transport capacity and a more than doubling of the average gas sales price.
Operating Expenses
The table below presents a comparison of the Company’s operating expenses for the years ended December 31, 2021, 2020, and 2019. All operating expenses include costs attributable to a noncontrolling interest in Egypt and Altus.
For the Year Ended December 31,
2021 2020 2019
(In millions)
Lease operating expenses $ 1,241 $ 1,127 $ 1,447
Gathering, processing, and transmission 264 274 306
Purchased oil and gas costs 1,580 357 142
Taxes other than income 204 123 207
Exploration 155 274 805
General and administrative 376 290 406
Transaction, reorganization, and separation 22 54 50
Depreciation, depletion, and amortization:
Oil and gas property and equipment 1,255 1,643 2,512
Gathering, processing, and transmission assets 64 76 105
Other assets 41 53 63
Asset retirement obligation accretion 113 109 107
Impairments 208 4,501 2,949
Financing costs, net 514 267 462
Lease Operating Expenses (LOE)
LOE includes several key components, such as direct operating costs, repairs and maintenance, and workover costs. Direct operating costs generally trend with commodity prices and are impacted by the type of commodity produced and the location of properties (i.e., offshore, onshore, remote locations, etc.). Fluctuations in commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity price based. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as rig rates, labor, boats, helicopters, materials, and supplies. Crude oil, which accounted for 47 percent of the Company’s total 2021 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.
During 2021, LOE increased $114 million, or 10 percent, compared to 2020. On a per-boe basis, LOE increased $1.75, or 25 percent, compared to 2020, from $7.00 per boe to $8.75 per boe. The increase in costs was driven by maintenance and turnaround costs in the North Sea, higher-priced emissions credits purchased in association with North Sea production, increased workover activity in the U.S., operating costs trending with commodity prices, inflation impacts, and overall higher labor costs that were heavily impacted by mark-to-market adjustments for stock-based compensation.
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:
For the Year Ended December 31,
2021 2020 2019
(In millions)
Third-party processing and transmission costs $ 232 $ 236 $ 250
Midstream service affiliate costs 128 143 134
Upstream processing and transmission costs 360 379 384
Midstream operating expenses 32 38 56
Intersegment eliminations (128) (143) (134)
Total Gathering, processing, and transmission $ 264 $ 274 $ 306
GPT costs decreased $10 million compared to 2020. Third-party processing and transmission costs decreased $4 million, primarily driven by a decrease in contracted pricing and lower processed volumes. Midstream service affiliate costs decreased $15 million compared to 2020, primarily driven by lower throughput of natural gas volumes at Alpine High. Midstream operating expenses, incurred primarily by Altus, decreased $6 million compared to 2020, driven by continued improvements in operational efficiency as a result of transitioning from mechanical refrigeration units to Altus’ centralized Diamond cryogenic complex. The transition resulted in decreases in contract labor, equipment rentals, and chemical expenses.
Purchased Oil and Gas Costs
Purchased oil and gas costs increased $1.2 billion compared to 2020, and were primarily offset by associated sales totaling $1.5 billion for the year ended 2021, as further discussed above.
Taxes Other Than Income
Taxes other than income primarily consist of severance taxes on onshore properties and in state waters off the coast of the U.S. and ad valorem taxes on U.S. properties. Severance taxes are generally based on a percentage of oil and gas production revenues. The Company is also subject to a variety of other taxes, including U.S. franchise taxes.
Taxes other than income increased $81 million compared to 2020, primarily from higher severance taxes driven by higher commodity prices.
Exploration Expenses
Exploration expenses include unproved leasehold impairments, exploration dry hole expense, geological and geophysical expenses, and the costs of maintaining and retaining unproved leasehold properties. The following table presents a summary of these expenses:
For the Year Ended December 31,
2021 2020 2019
(In millions)
Unproved leasehold impairments $ 31 $ 101 $ 619
Dry hole expenses 66 110 57
Geological and geophysical expenses 18 20 59
Exploration overhead and other 40 43 70
Total Exploration $ 155 $ 274 $ 805
Exploration expenses decreased $119 million compared to 2020. Unproved leasehold impairments were $70 million lower than the prior year due to improved commodity prices and increased drilling plans in the U.S. Dry hole expense decreased $44 million, geological and geophysical expenses decreased $2 million, and exploration overhead and other expenses decreased $3 million compared to 2020, primarily resulting from decreased exploration activities compared to the prior year.
General and Administrative (G&A) Expenses
G&A expenses increased $86 million compared to 2020, primarily driven by higher cash-based stock compensation expense resulting from an increase in the Company’s stock price compared to the prior year, partially offset by lower overhead driven by organizational redesign efforts during 2019 and 2020.
Transaction, Reorganization, and Separation (TRS) Costs
TRS costs decreased $32 million compared to 2020, primarily driven by costs associated with the Company’s reorganization efforts incurred primarily in the prior year.
In recent years, the Company has streamlined its portfolio through strategic divestitures and centralized certain operational activities in an effort to capture greater efficiencies and cost savings through shared services. During the second half of 2019, management initiated a comprehensive redesign of the Company’s organizational structure and operations that it believes will better position the Company to be competitive for the long-term and further reduce recurring costs. Reorganization efforts were substantially completed in 2020; however, additional reorganization costs related to ongoing consulting and separation activities in the Company’s international operations were incurred during 2021.
Depreciation, Depletion and Amortization (DD&A)
DD&A expenses on the Company’s oil and gas property for the year ended December 31, 2021 decreased $388 million compared to 2020. The Company’s oil and gas property DD&A rate decreased $1.35 per boe in 2021 compared to 2020, from $10.20 per boe to $8.85 per boe. The decrease was driven by lower production volumes and lower asset property balances associated with proved property impairments recorded during the first quarter of 2020. DD&A expense on the Company’s GPT depreciation decreased $12 million compared to 2020, driven by impairment charges recorded against the carrying value of the Company’s GPT facilities in Egypt during the first quarter of 2020.
Impairments
During 2021, the Company recorded asset impairments totaling $208 million. The charges include $160 million for Altus’ equity method interest in EPIC, as part of Altus’ review of the fair value of its assets in relation to the announced BCP Business Combination, $26 million in connection with inventory valuations in Egypt, and $22 million in connection with inventory valuations and expected equipment dispositions in the North Sea.
During 2020, the Company recorded asset impairments in connection with fair value assessments totaling $4.5 billion, including $4.3 billion for oil and gas proved properties in the U.S, Egypt, and the North Sea, $68 million for GPT facilities in Egypt, $87 million for goodwill in Egypt, and $27 million for inventory and other miscellaneous assets, including lease assets and charges for the early termination of drilling rig leases.
The following table presents a summary of asset impairments recorded for 2021, 2020, and 2019:
For the Year Ended December 31,
2021 2020 2019
(In millions)
Oil and gas proved property $ - $ 4,319 $ 1,484
GPT facilities - 68 1,295
Equity method interests 160 - -
Divested unproved properties and leasehold - - 149
Goodwill - 87 -
Inventory and other 48 27 21
Total Impairments $ 208 $ 4,501 $ 2,949
Financing Costs, Net
Financing costs incurred during the period comprised the following:
For the Year Ended December 31,
2021 2020 2019
(In millions)
Interest expense $ 419 $ 438 $ 430
Amortization of debt issuance costs 8 8 7
Capitalized interest (9) (12) (37)
Loss (gain) on extinguishment of debt 104 (160) 75
Interest income (8) (7) (13)
Total Financing costs, net $ 514 $ 267 $ 462
Net financing costs increased $247 million compared to 2020, primarily the result of a $104 million loss on extinguishment of debt during 2021 and a $160 million gain on extinguishment of debt during 2020.
Provision for Income Taxes
Income tax expense increased $514 million from $64 million during 2020 to $578 million during 2021. The Company’s year-to-date 2021 effective income tax rate was primarily impacted by asset impairments and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During 2020, the Company’s effective income tax rate was primarily impacted by oil and gas asset impairments, a goodwill impairment, and an increase in the amount of valuation allowance against its U.S. deferred tax assets.
The Company recorded a full valuation allowance against its U.S. net deferred tax assets and will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance. For additional information regarding income taxes, refer to Note 10-Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is currently under audit by the Internal Revenue Service (IRS) for the 2014-2017 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.
Capital and Operational Outlook
The Company continues to prudently manage its capital program against a volatile price environment and the prolonged effects of the COVID-19 pandemic. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of ongoing exploration and appraisal activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and return of capital to its stakeholders.
The Company’s 2022 capital program will maintain a similar investment approach to the prior year, with upstream capital investment budgeted at approximately $1.6 billion. This budget includes small changes to the timing of rig count increases in Egypt and the U.S. as well as updated views on costs and inflation. This amount also includes approximately $200 million for exploration and appraisal activities, primarily in Suriname. In 2023 and 2024, the total capital budget is anticipated to increase slightly despite a relatively unchanged activity set, given expectations of continued inflationary pressure.
Based on this planned capital activity, the Company anticipates 2022 worldwide production levels will be similar to 2021, after adjusting for divestments. Egypt gross production is expected to increase through the year with higher rig activity, while Egypt net production will be additionally benefited from the effects of the modernized PSC terms. The Company anticipates moderate production declines in the U.S. compared to 2021 given gradual increases in activity levels over the past year and timing of completions.
At current strip pricing, the Company expects to generate significant cash flow over this capital activity budget. The Company’s commitment to return capital to shareholders over the next three years will remain unchanged.
The Company’s diversified global portfolio provides the ability to quickly optimize capital allocation as market conditions change. The current uncertainties associated with the COVID-19 pandemic, however, are still evolving and may become more severe and complex. As a result, the COVID-19 pandemic may still materially and adversely affect the Company’s results in a manner that is either not currently known or that the Company does not currently consider to be a significant risk to its business. For additional information about the business risks relating to the COVID-19 pandemic and related governmental actions, refer to Part I, Item 1A - Risk Factors of this Annual Report on Form 10-K.
Separate from the Company’s upstream oil and gas activities, capital spending for Altus’ gathering and processing assets totaled $3 million in 2021, down from $28 million in 2020 when a majority of the midstream infrastructure construction was completed. Altus management believes its existing gathering, processing, and transmission infrastructure capacity is capable of fulfilling its midstream contracts to service the Company’s production from Alpine High and any third-party customers.
Additionally, during the years ended December 31, 2021 and 2020, Altus made cash contributions totaling $28 million and $327 million, respectively, for its Equity Method Interest Pipelines that are all currently in service. Altus estimates it will incur minimal capital contributions during 2022 for its equity interest in these joint venture pipelines. Based on Altus management’s current financial plan and related assumptions prior to closing the BCP Business Combination, Altus believes that cash from operations, a reduced capital program for its midstream infrastructure, and distributions from Equity Method Interests will generate cash flows in excess of capital expenditures and the amount required to fund Altus’ planned quarterly dividend and quarterly payments to the holders of Altus Midstream LP’s Series A Cumulative Redeemable Preferred Units (Preferred Units) during 2022.
For further information on the Equity Method Interest Pipelines, refer to Note 6-Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Capital Resources and Liquidity
Operating cash flows are the Company’s primary source of liquidity. The Company’s short-term and long-term operating cash flows are impacted by highly volatile commodity prices, as well as production costs and sales volumes. Significant changes in commodity prices impact the Company’s revenues, earnings, and cash flows. These changes potentially impact the Company’s liquidity if costs do not trend with related changes in commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.
The Company’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of the Company’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves.
For the year ended December 31, 2021, the Company recognized upward reserve revisions of approximately 10 percent of its year-end 2020 estimated proved reserves as a result of improved commodity prices compared to negative reserve revisions of approximately 7 percent in the prior year as a result of lower commodity prices. The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2021, 2020, and 2019, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 18-Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
The Company believes its available liquidity and capital resource alternatives, combined with proactive measures to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including the Company’s capital development program, repayment of debt maturities, payment of dividends, share buy-back activity, and amounts that may ultimately be paid in connection with commitments and contingencies.
The Company may also elect to utilize available cash on hand, committed subsidiary borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for all other liquidity and capital resource needs.
For additional information, refer to Part I, Items 1 and 2-Business and Properties and Part I, Item 1A - Risk Factors of this Annual Report on Form 10-K.
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:
For the Year Ended December 31,
2021 2020 2019
(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities $ 3,496 $ 1,388 $ 2,867
Proceeds from Apache credit facility, net 392 150 -
Proceeds from Altus credit facility, net 33 228 396
Proceeds from asset divestitures 256 166 718
Fixed-rate debt borrowings - 1,238 989
Redeemable noncontrolling interest - Altus Preferred Unit limited partners - - 611
Other 23 - -
4,200 3,170 5,581
Uses of Cash and Cash Equivalents:
Additions to oil and gas property(1)
1,101 1,270 2,594
Additions to Altus gathering, processing, and transmission facilities(1)
3 28 327
Leasehold and property acquisitions 9 4 40
Contributions to Altus equity method interests 28 327 501
Acquisition of Altus equity method interests - - 671
Payments on fixed-rate debt 1,795 1,243 1,150
Dividends paid 52 123 376
Distributions to noncontrolling interest - Egypt 279 91 305
Distributions to Altus Preferred Unit limited partners 46 23 -
Shares repurchased 847 - -
Other - 46 84
4,160 3,155 6,048
Increase (decrease) in cash and cash equivalents $ 40 $ 15 $ (467)
(1)The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this Annual Report on Form 10-K, which include accruals.
Sources of Cash and Cash Equivalents
Net Cash Provided by Operating Activities Operating cash flows are the Company’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile commodity prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense.
Net cash provided by operating activities for the year ended December 31, 2021 totaled $3.5 billion, up $2.1 billion from the year ended December 31, 2020, primarily the result of higher commodity prices compared to the prior year.
For a detailed discussion of commodity prices, production, and operating expenses, refer to “Results of Operations” in this Item 7. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, refer to the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Proceeds from Apache Credit Facility, Net As of December 31, 2021 and 2020, Apache had outstanding borrowings of $542 million and $150 million, respectively, under its credit facility, which is classified as long-term debt.
Proceeds from Altus Credit Facility, Net The construction of Altus’ gathering and processing assets and the associated equity interests in the Equity Method Interest Pipelines has historically required capital expenditures in excess of Altus’ cash on hand and operational cash flows. During the years ended December 31, 2021 and 2020, Altus Midstream LP borrowed $33 million and $228 million, respectively, under its revolving credit facility to meet this shortfall. With the midstream infrastructure complete and all of the Equity Method Interest Pipelines now in service, the Company anticipates that Altus’ existing capital resources will be sufficient to fund its continuing obligations and dividend program.
Proceeds from Asset Divestitures The Company received $256 million and $166 million in proceeds from the divestiture of certain non-core assets during the years ended December 31, 2021 and 2020, respectively. For more information regarding the Company’s acquisitions and divestitures, refer to Note 2-Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part IV set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Fixed-Rate Debt Borrowings On August 17, 2020, Apache closed offerings of $1.25 billion in aggregate principal amount of senior unsecured notes, comprised of $500 million in aggregate principal amount of 4.625% notes due 2025 and $750 million in aggregate principal amount of 4.875% notes due 2027. The senior unsecured notes are redeemable at any time, in whole or in part, at Apache’s option, at the applicable redemption price. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers, repay a portion of outstanding borrowings under Apache’s senior revolving credit facility, and for general corporate purposes.
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners On June 12, 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act of 1933, as amended. Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. For more information, refer to Note 13-Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Uses of Cash and Cash Equivalents
Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $1.1 billion and $1.3 billion for the years ended December 31, 2021 and 2020, respectively. The decrease in capital investment is reflective of the Company’s capital program, which was reduced early in 2020 to align with anticipated operating cash flows following the collapse of commodity prices stemming from the COVID-19 pandemic. The Company operated an average of 13 drilling rigs during 2021, compared to an average of 12 drilling rigs during 2020.
Additions to Altus Gathering, Processing, and Transmission (GPT) Facilities The Company’s cash expenditures for GPT facilities totaled $3 million and $28 million during 2021 and 2020, respectively, nearly all comprising midstream infrastructure expenditures incurred by Altus, which were substantially completed as of December 31, 2019. Altus management believes its existing GPT infrastructure capacity is capable of fulfilling its midstream contracts to service the Company’s production from Alpine High and any third-party customers.
Leasehold and Property Acquisitions During 2021 and 2020, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $9 million and $4 million, respectively.
Contributions to Altus Equity Method Interests Altus contributed $28 million and $327 million in cash during 2021 and 2020, respectively, for equity interests in the Equity Method Interest Pipelines. For more information regarding the Company’s equity method interests, refer to Note 6-Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Payments on Fixed-Rate Debt During 2021, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.7 billion aggregate principal amount of notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of $1.8 billion reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $105 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs, in connection with the note purchases.
During 2021, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $22 million for an aggregate purchase price of $20 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $2 million. The Company recognized a $1 million net gain on extinguishment of debt as part of these transactions.
During 2020, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $588 million for an aggregate purchase price of $428 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $168 million. These repurchases resulted in a $158 million net gain on extinguishment of debt. The net gain includes an acceleration of related discount and debt issuance costs. Additionally, on November 3, 2020, Apache redeemed the remaining $183 million of outstanding 3.625% senior notes due February 1, 2021 at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The repurchases were financed by borrowings under Apache’s revolving credit facility.
Also during 2020, Apache closed cash tender offers for certain outstanding notes. Apache accepted for purchase $644 million aggregate principal amount certain notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of $644 million, reflecting principal, aggregate discount to par of $38 million, early tender premium of $32 million, and accrued and unpaid interest of $6 million. The Company recorded a net gain of $2 million on extinguishment of debt, including an acceleration of unamortized debt discount and issuance costs, in connection with the note purchases.
The Company expects that Apache will continue to reduce debt outstanding under its indentures from time to time.
Dividends The Company paid $52 million and $123 million during the years ended December 31, 2021 and 2020, respectively, for dividends on its common stock. In the first quarter of 2020, the Company’s Board of Directors approved a reduction in the Company’s quarterly dividend per share from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020. During the third quarter of 2021, the Company’s Board of Directors approved an increase in its quarterly dividend per share from $0.025 to $0.0625, and in the fourth quarter of 2021, approved a further increase to its quarterly dividend to $0.125 per share.
Distributions to Noncontrolling Interest - Egypt Sinopec holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company paid $279 million and $91 million during the years ended December 31, 2021 and 2020, respectively, in cash distributions to Sinopec.
Distributions to Altus Preferred Units limited partners Altus Midstream LP paid $46 million and $23 million in cash distributions to its limited partners holding Preferred Units during the years ended December 31, 2021 and 2020, respectively. For more information regarding the Preferred Units, refer to Note 13-Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Liquidity
The following table presents a summary of the Company’s key financial indicators as of December 31:
2021 2020
(In millions)
Cash and cash equivalents $ 302 $ 262
Total debt - Apache 6,853 8,148
Total debt - Altus 657 624
Total equity (deficit) (717) (645)
Available committed borrowing capacity - Apache 2,426 2,944
Available committed borrowing capacity - Altus 141 176
Cash and Cash Equivalents As of December 31, 2021, the Company had $302 million in cash and cash equivalents, of which approximately $132 million was held by Altus. The majority of the Company’s cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.
Debt As of December 31, 2021, the Company had $7.5 billion in total debt outstanding, which consisted of notes, debentures, credit facility borrowings, and finance lease obligations. Future interest payments on the fixed-rate notes and debentures are approximately $4.7 billion. As of December 31, 2021, current debt included $213 million carrying value of 3.25% senior notes due April 15, 2022 and $2 million of finance lease obligations. On January 18, 2022, Apache redeemed the remaining $213.5 million of outstanding 3.25% senior notes due April 15, 2022 at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s revolving credit facility.
Committed Credit Facilities In March 2018, Apache entered into a revolving credit facility with commitments totaling $4.0 billion. In March 2019, the term of this facility was extended by one year to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise of an extension option. Apache can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of December 31, 2021. The facility is for general corporate purposes. Letters of credit are available for security needs, including in respect of North Sea decommissioning obligations. The facility has no collateral requirements, is not subject to borrowing base redetermination, and has no drawdown restrictions or prepayment obligations in the event of a decline in credit ratings.
As of December 31, 2021, there were $542 million of borrowings and an aggregate £748 million and $20 million in letters of credit outstanding under this facility. As of December 31, 2020, there were $150 million of borrowings and an aggregate £633 million and $40 million in letters of credit outstanding under this facility. The outstanding letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020.
At Apache’s option, the interest rate per annum for borrowings under the 2018 facility is either a base rate, as defined, plus a margin, or the London Inter-bank Offered Rate (LIBOR), plus a margin. Apache also pays quarterly a facility fee at a per annum rate on total commitments. The margins and the facility fee vary based upon Apache’s senior long-term debt rating. At December 31, 2021, the base rate margin was 0.5 percent, the LIBOR margin was 1.50 percent, and the facility fee was 0.25 percent. A commission is payable quarterly to lenders on the face amount of each outstanding letter of credit at a per annum rate equal to the LIBOR margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks.
The financial covenants of the credit facility require Apache to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. For purposes of this calculation, capital excludes the effects of non-cash write-downs, impairments, and related charges occurring after June 30, 2015. At December 31, 2021, Apache’s debt-to-capital ratio as calculated under the credit facility was 28 percent. The 2018 facility’s negative covenants restrict the ability of Apache and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with exceptions for liens typically arising in the oil and gas industry; liens securing debt incurred to finance the acquisition, construction, improvement, or capital lease of assets, provided that such debt, when incurred, does not exceed the subject purchase price and costs, as applicable, and related expenses; liens on subsidiary assets located outside of the United States and Canada; and liens arising as a matter of law, such as tax and mechanics’ liens. Apache also may incur liens on assets if debt secured thereby does not exceed 15 percent of Apache’s consolidated net tangible assets, or approximately $1.9 billion as of December 31, 2021. Negative covenants also restrict Apache’s ability to merge with another entity unless it is the surviving entity, dispose of substantially all of its assets, and guarantee debt of non-consolidated entities in excess of the stated threshold.
In November 2018, Altus Midstream LP entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream LP’s two, one-year extension options). The agreement for this facility, as amended, provides aggregate commitments from a syndicate of banks of $800 million. All aggregate commitments include a letter of credit subfacility of up to $100 million and a swingline loan subfacility of up to $100 million. Altus Midstream LP may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of December 31, 2021, there were $657 million of borrowings and a $2 million letter of credit outstanding under this facility. As of December 31, 2020, there were $624 million of borrowings and no letters of credit outstanding under this facility. The Altus Midstream LP credit facility is unsecured and is not guaranteed by APA or any of its subsidiaries, including Apache.
The agreement for Altus Midstream LP’s credit facility, as amended, restricts distributions in respect of capital to Apache and other unit holders in certain circumstances. Unless the Leverage Ratio is less than or equal to 4.00:1.00, the agreement limits such distributions to $30 million per calendar year until either (i) the consolidated net income of Altus Midstream LP and its restricted subsidiaries, as adjusted pursuant to the agreement, for three consecutive calendar months equals or exceeds $350 million on an annualized basis or (ii) Altus Midstream LP has a specified senior long-term debt rating; in addition, before the occurrence of one of those two events, the Leverage Ratio must be less than or equal to 5.00:1.00. In no event can any distribution be made that would, after giving effect to it on a pro forma basis, result in a Leverage Ratio greater than (i) 5.00:1.00 or (ii) for a specified period after a qualifying acquisition, 5.50:1.00. The Leverage Ratio is the ratio of (1) the consolidated indebtedness of Altus Midstream LP and its restricted subsidiaries to (2) EBITDA (as defined in the agreement) of Altus Midstream LP and its restricted subsidiaries for the 12-month period ending immediately before the determination date. The Leverage Ratio as of December 31, 2021 was less than 4.00:1.00.
The terms of Altus Midstream LP’s Preferred Units also contain certain restrictions on distributions in respect of capital, including the common units held by Altus Midstream Company and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation. Refer to Note 13-Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K for further information. In addition, the amount of any cash distributions to Altus Midstream LP by any entity in which it has an interest accounted for by the equity method is subject to such entity’s compliance with the terms of any debt or other agreements by which it may be bound, which in turn may impact the amount of funds available for distribution by Altus Midstream LP to its partners.
There are no clauses in either the agreement for Apache’s 2018 credit facility or for Altus Midstream LP’s 2018 credit facility that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. These agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, each agreement allows the lenders to accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches, and if a borrower or any of its subsidiaries defaults on other indebtedness in excess of the stated threshold, is insolvent, or has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold. Lenders may also accelerate payment maturity and terminate lending and issuance commitments under the applicable agreement if Apache or Altus Midstream LP, as applicable, undergoes a specified change in control or any borrower has specified pension plan liabilities in excess of the stated threshold. Each of Apache and Altus Midstream LP was in compliance with the terms of its 2018 credit facility as of December 31, 2021.
There is no assurance of the terms upon which potential lenders under future credit facilities will make loans or other extensions of credit available to Apache or its subsidiaries or the composition of such lenders.
There is no assurance that the financial condition of banks with lending commitments to Apache or Altus Midstream LP will not deteriorate. We closely monitor the ratings of the banks in our bank groups. Having large bank groups allows the Company to mitigate the potential impact of any bank’s failure to honor its lending commitment.
Commercial Paper Program As of December 31, 2020, no commercial paper was outstanding. Apache did not use its commercial paper program during 2021 and terminated the program during the third quarter of 2021.
Contractual Obligations
Purchase Obligations From time to time, the Company enters into agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments and agreements to secure capacity rights on third-party pipelines. As of December 31, 2021, the Company had contractual obligations totaling $4.9 billion, of which $1.2 billion is related to U.S. firm transportation contracts and $3.5 billion is related to the new PSC with the EGPC. Under terms agreed to in the modernized PSC, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. The Company believes it will be able to satisfy this obligation within its current exploration and development program.
Leases In the normal course of business, the Company enters into various lease agreements for real estate, drilling rigs, vessels, aircrafts, and equipment related to its exploration and development activities, which are typically classified as operating leases under the provisions of Financial Accounting Standards Board ASC Topic 842 (Leases). As of December 31, 2021, the Company had net minimum commitments of $272 million and $42 million for operating and finance leases, respectively.
For additional information regarding these obligations, refer to Note 11-Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
For information regarding the Company’s liability for dismantlement, abandonment, and restoration costs of oil and gas properties or pension or postretirement benefit obligations, refer to Notes 8-Asset Retirement Obligation and Note 12-Retirement and Deferred Compensation Plans in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
The Company is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess settlements resulting from litigation. The Company’s management believes that it has adequately reserved for its contingent obligations, including approximately $2 million for environmental remediation and approximately $84 million for various contingent legal liabilities. For a detailed discussion of the Company’s lease obligations, purchase obligations, environmental and legal contingencies, and other commitments, please see Note 11-Commitments and Contingencies and Note 12-Retirement and Deferred Compensation Plans in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
As further described above under “Capital and Operational Outlook,” Altus Midstream LP and/or its subsidiaries have equity ownership in four Equity Method Interest Pipelines. Altus Midstream LP and/or its subsidiaries may be required to fund future capital expenditures for its equity interest share in the development of the applicable pipeline. Altus estimates that it will incur minimal capital contributions for its equity interests in these joint venture pipelines during 2022.
With respect to oil and gas operations in the Gulf of Mexico, the Bureau of Ocean Energy Management (BOEM) issued a Notice to Lessees (NTL No. 2016-N01) significantly revising the obligations of companies operating in the Gulf of Mexico to provide supplemental assurances of performance with respect to plugging, abandonment, and decommissioning obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies’ oil and gas leases. While the NTL was paused in mid-2017 and is currently listed on BOEM’s website as “rescinded,” if reinstated, the NTL will likely require that the Company provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to the Company’s current ownership interests in various Gulf of Mexico leases. The Company is working closely with BOEM to make arrangements for the provision of such additional required security, if such security becomes necessary under the NTL. Additionally, the Company is not able to predict the effect that these changes might have on counterparties to which the Company has sold Gulf of Mexico assets or with whom the Company has joint ownership. Such changes could cause the bonding obligations of such parties to increase substantially, thereby causing a significant impact on the counterparties’ solvency and ability to continue as a going concern.
Potential Decommissioning Obligations on Sold Properties
The Company’s subsidiaries have potential exposure to future obligations related to divested properties. The Company has divested various leases, wells, and facilities located in the Gulf of Mexico (GOM) where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser of such GOM assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, APA’s subsidiaries could be required to perform such actions under applicable federal laws and regulations. In such event, such subsidiaries may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.
In 2013, Apache sold its GOM Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Currently, Apache holds two bonds (Bonds) and five Letters of Credit backed by investment-grade counterparties to secure Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets.
On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets will be used to fund decommissioning of Legacy GOM Assets.
In September 2021, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently required to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notification to BSEE. Apache expects to receive such orders on the other Legacy GOM Assets included in GOM Shelf’s notification letter. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.
If Apache incurs costs to decommission any Legacy GOM Asset and GOM Shelf does not reimburse Apache for such costs, then Apache will obtain reimbursement from Trust A, the Bonds, and the Letters of Credit until such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets.
If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be ordered by BSEE to perform, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to effectively use its available cash to fund the deficit.
As of December 31, 2021, Apache estimates that its potential liability to fund decommissioning of Legacy GOM Assets it may be ordered to perform ranges from $1.2 billion to $1.4 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, during 2021, the Company recorded a contingent liability of $1.2 billion, representing the estimated costs of decommissioning it may be required to perform on Legacy GOM Assets. Of the total liability recorded, $1.1 billion is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $100 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. The Company also recorded a $740 million asset, which represents the amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $640 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $100 million is reflected under “Other current assets.” A “Loss on previously sold Gulf of Mexico properties” in the amount of $446 million was recognized in the third quarter of 2021 to reflect the net impact to the Company’s statement of consolidated operations. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. In addition, significant changes in the market price of oil, gas, and NGLs could further impact Apache’s estimate of its contingent liability to decommission Legacy GOM Assets.
Insurance Program
The Company maintains insurance policies that include coverage for physical damage to its assets, general liabilities, workers’ compensation, employers’ liability, sudden and accidental pollution, and other risks. The Company’s insurance coverage is subject to deductibles or retentions that it must satisfy prior to recovering on insurance. Additionally, the Company’s insurance is subject to policy exclusions and limitations. There is no assurance that insurance will adequately protect the Company against liability from all potential consequences and damages. Further, the Company does not have coverage in place for a variety of other risks including Gulf of Mexico named windstorm and business interruption. Service agreements, including drilling contracts, generally indemnify the Company for injuries and death of the service provider’s employees as well as subcontractors hired by the service provider.
The Company purchases multi-year political risk insurance from The Islamic Corporation for the Insurance of Investment and Export Credit Trade (ICIEC, an agency of the Islamic Development Bank) and highly-rated insurers covering a portion of its investments in Egypt for losses arising from confiscation, nationalization, and expropriation risks. In the aggregate, these insurance policies provide up to $750 million of coverage, subject to policy terms and conditions and a retention of approximately $500 million.
The Company also has an insurance policy with U.S. International Development Finance Corporation (DFC), which, subject to policy terms and conditions, provides up to $150 million of coverage through 2024 for losses arising from (1) non-payment by EGPC of arbitral awards covering amounts owed the Company on past due invoices and (2) expropriation of exportable petroleum in the event that actions taken by the government of Egypt prevent the Company from exporting its share of production. The Multilateral Investment Guarantee Agency (MIGA), a member of the World Bank Group, provides $60 million in reinsurance to DFC.
Future insurance coverage for the Company’s industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable or unavailable on terms economically acceptable.
Critical Accounting Estimates
The Company prepares its financial statements and accompanying notes in conformity with accounting principles generally accepted in the U.S., which require management to make estimates and assumptions about future events that affect reported amounts in the financial statements and the accompanying notes. The Company identifies certain accounting policies involving estimation as critical accounting estimates based on, among other things, their impact on the portrayal of the Company’s financial condition, results of operations, or liquidity, as well as the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting estimates address accounting matters that are inherently uncertain due to unknown future resolution of such matters. Management routinely discusses the development, selection, and disclosure of each critical accounting estimate. The following is a discussion of the Company’s most critical accounting estimates.
Reserves Estimates
Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations.
Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.
Despite the inherent imprecision in these engineering estimates, the Company’s reserves are used throughout its financial statements. For example, since the Company uses the units-of-production method to amortize its oil and gas properties, the quantity of reserves could significantly impact DD&A expense. A material adverse change in the estimated volumes of reserves could result in property impairments. Finally, these reserves are the basis for the Company’s supplemental oil and gas disclosures. For more information regarding the Company’s supplemental oil and gas disclosures, refer to Note 18-Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Reserves are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous twelve months, held flat for the life of the production, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.
The Company has elected not to disclose probable and possible reserves or reserve estimates in this filing.
Oil and Gas Exploration Costs
The Company accounts for its exploration and production activities using the successful efforts method of accounting. Costs of acquiring unproved and proved oil and gas leasehold acreage are capitalized. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are also capitalized. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as to whether proved reserves have been found. On a quarterly basis, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities and determines whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the statement of consolidated operations. Otherwise, the costs of exploratory wells remain capitalized.
Offshore Decommissioning Contingency
The Company has potential exposure to future obligations related to divested properties. For information regarding a potential obligation to decommission sold properties estimated and recorded in the third quarter of 2021, please refer to “Potential Obligation to Decommission Sold Properties” above and in Note 11-Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part IV, Item 5 of this Annual Report on Form 10-K. Changes in significant assumptions impacting the Company’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. In addition, significant changes in the market price of oil, gas, and NGLs could further impact the Company’s estimate of its contingent liability to decommission Legacy GOM Assets.
Impairment of Equity Method Interests
Equity method interests are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.
Altus recorded an impairment charge on its equity method interest in EPIC in the fourth quarter of 2021. The fair value of the impaired interest was determined using the income approach. The income approach considered estimates of future throughput volumes, tariff rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using a discount rate believed to be consistent with that which would be applied by market participants. The Company has classified this nonrecurring fair value measurement as Level 3 in the fair value hierarchy. Refer to Note 6-Equity Method Interests, within Part IV, Item 15 of this Annual Report on Form 10-K for further details of Altus’ equity method interests. Negative revisions in future estimates of throughput volumes, revenue assumptions or costs related to the Altus’ equity method interests could lead to further impairments of such interests in future periods.
Long-Lived Asset Impairments
Long-lived assets used in operations, including proved oil and gas properties and GPT assets, are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication that the carrying amount of an asset group may not be recovered, the asset is assessed by management through an established process in which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is assessed by management using the income approach.
Under the income approach, the fair value of each asset group is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, the success of future exploration for and development of unproved reserves, expected throughput volumes for GPT assets, discount rates, and other variables. Key assumptions used in developing a discounted cash flow model described above include estimated quantities of crude oil and natural gas reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative, and capital costs adjusted for inflation. The Company discounts the resulting future cash flows using a discount rate believed to be consistent with those applied by market participants.
To assess the reasonableness of our fair value estimate, when available, management uses a market approach to compare the fair value to similar assets. This requires management to make certain judgments about the selection of comparable assets, recent comparable asset transactions, and transaction premiums.
Although the fair value estimate of each asset group is based on assumptions believed to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimate. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the asset group, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an additional impairment of long-lived assets in future periods.
Over the past several years, the Company has experienced substantial volatility in commodity prices, which impacted its future development plans and operating cash flows. As such, material impairments of certain proved oil and gas properties and gathering, processing, and transmission facilities were recorded in 2020 and 2019. For discussion of these impairments, see “Fair Value Measurements” of Note 1-Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements.
Asset Retirement Obligation (ARO)
The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms in the North Sea and Gulf of Mexico. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.
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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company’s exposure to market risk. The term market risk relates to the risk of loss arising from adverse changes in oil, gas, and NGL prices, interest rates, or foreign currency and adverse governmental actions. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how the Company views and manages its ongoing market risk exposures.
Commodity Price Risk
The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. These factors have only been heightened as the implications of the COVID-19 pandemic became more apparent. The Company continually monitors its market risk exposure, including the impact and developments related to the COVID-19 pandemic, which introduced significant volatility in the financial markets beginning in early 2020.
The Company’s average crude oil realizations increased 74 percent to $68.97 per barrel in 2021 from $39.60 per barrel in 2020. The Company’s average natural gas price realizations increased 118 percent to $3.99 per Mcf in 2021 from $1.83 per Mcf in 2020. The Company’s average NGL realizations increased 141 percent to $28.48 per barrel in 2021 from $11.84 per barrel in 2020. Based on average daily production for 2021, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $66 million, a $0.10 per Mcf change in the weighted average realized price of natural gas would have increased or decreased revenues for the year by approximately $30 million, and a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the year by approximately $25 million.
The Company periodically enters into derivative positions on a portion of its projected crude oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Such derivative positions may include the use of futures contracts, swaps, and/or options. The Company does not hold or issue derivative instruments for trading purposes. As of December 31, 2021, the Company had open natural gas derivatives, not designated as cash flow hedges, in a liability position with a fair value of approximately $10 million. A 10 percent increase in basis differential of the hedges would increase the liability by approximately $30 million, while a 10 percent decrease in basis differential of the hedges would move the derivatives to an asset position of approximately $21 million. These fair value changes assume volatility based on prevailing market parameters as of December 31, 2021. Refer to Note 4-Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report Form 10-K for notional volumes and terms with the Company’s derivative contracts.
Interest Rate Risk
At December 31, 2021, Apache had $6.3 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 5.07 percent. Although near-term changes in interest rates may affect the fair value of fixed-rate debt, such changes do not expose the Company to the risk of earnings or cash flow loss associated with that debt. The Company is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under the Apache and Altus Midstream LP credit facilities. As of December 31, 2021, the Company had approximately $302 million in cash and cash equivalents, approximately 57 percent of which was invested in money market funds and short-term investments with major financial institutions. As of December 31, 2021, there were $542 million and $657 million of borrowings outstanding under the Apache Corporation and Altus Midstream LP revolving credit facilities, respectively. A change in the interest rate applicable to short-term investments and credit facility borrowings would have an immaterial impact on earnings and cash flows but could impact interest costs associated with future debt issuances or any future borrowings.
Foreign Currency Exchange Rate Risk
The Company’s cash activities relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The Company’s North Sea production is sold under U.S. dollar contracts, while the majority of costs incurred are paid in British pounds. The Company’s Egypt production is primarily sold under U.S. dollar contracts, and the majority of costs incurred are denominated in U.S. dollars. Transactions denominated in British pounds are converted to U.S. dollar equivalents based on the average exchange rates during the period.
Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Foreign currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when the Company re-measures its foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. A foreign currency net gain or loss of $3 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of December 31, 2021.
The Company is subject to increased foreign currency risk associated with the effects of the U.K.’s withdrawal from the European Union. The Company has periodically entered into foreign exchange contracts in order to minimize the impact of fluctuating exchange rates for the British pound on the Company’s operating expenses. As of December 31, 2021, the Company had outstanding foreign exchange contracts with a total notional amount of £180 million that are used to reduce its exposure to fluctuating foreign exchange rates for the British pound. A 10 percent strengthening of the British pound against the U.S. dollar would result in a foreign currency net gain of $20 million, while a 10 percent weakening of the British pound against the U.S. dollar would result in a loss of $14 million as of December 31, 2021.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements and supplementary financial information required to be filed under this Item 8 are presented on pages through in Part IV, Item 15 of this Annual Report on Form 10-K and are incorporated herein by reference.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
The financial statements for the fiscal years ended December 31, 2021, 2020, and 2019, included in this Annual Report on Form 10-K, have been audited by Ernst & Young LLP, independent registered public accounting firm, as stated in their audit report appearing herein. There have been no changes in or disagreements with the accountants during the periods presented.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
John J. Christmann IV, the Company’s Chief Executive Officer and President, in his capacity as principal executive officer, and Stephen J. Riney, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of December 31, 2021, the end of the period covered by this Annual Report on Form 10-K. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information the Company is required to disclose under applicable laws and regulations is recorded, processed, summarized, and reported within the time periods specified in the Commission’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
The Company periodically reviews the design and effectiveness of its disclosure controls, including compliance with various laws and regulations that apply to its operations, both inside and outside the United States. The Company makes modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if the Company’s reviews identify deficiencies or weaknesses in its controls.
Management’s Annual Report on Internal Control Over Financial Reporting; Attestation Report of the Registered Public Accounting Firm
The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to the “Report of Management on Internal Control Over Financial Reporting,” included on Page in Part IV, Item 15 of this Annual Report on Form 10-K.
The independent auditors attestation report called for by Item 308(b) of Regulation S-K is incorporated herein by reference to the “Report of Independent Registered Public Accounting Firm,” included on Page through in Part IV, Item 15 of this Annual Report on Form 10-K.
Changes in Internal Control over Financial Reporting
There was no change in our internal controls over financial reporting during the quarter ending December 31, 2021, that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information set forth under the captions “Nominees for Election as Directors,” “Information About Our Executive Officers,” and “Securities Ownership and Principal Holders” in the proxy statement relating to the Company’s 2022 annual meeting of shareholders (the Proxy Statement) is incorporated herein by reference.
Code of Business Conduct
Pursuant to Rule 5610 of the Nasdaq, the Company is required to adopt a code of business conduct and ethics for its directors, officers, and employees. In February 2004, the board of directors of Apache, the Company’s predecessor registrant, adopted the Code of Business Conduct and Ethics (Code of Conduct) and the Company’s board of directors, as part of the Holding Company Reorganization, adopted and revised it in March 2021. The revised Code of Conduct also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access the Company’s Code of Conduct on the Governance page of the Company’s website at www.apacorp.com. Any shareholder who so requests may obtain a printed copy of the Code of Conduct by submitting a request to the Company’s corporate secretary at the address on the cover of this Annual Report on Form 10-K. Changes in and waivers to the Code of Conduct for the Company’s directors, chief executive officer and certain senior financial officers will be posted on the Company’s website within four business days and maintained for at least 12 months. Information on the Company’s website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
The information set forth under the captions “Compensation Discussion and Analysis,” “Summary Compensation Table,” “Grants of Plan Based Awards Table,” “Outstanding Equity Awards at Fiscal Year-End Table,” “Option Exercises and Stock Vested Table,” “Non-Qualified Deferred Compensation Table,” “Potential Payments Upon Termination or Change in Control” and “Director Compensation Table” in the Proxy Statement is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information set forth under the captions “Securities Ownership and Principal Holders” and “Equity Compensation Plan Information” in the Proxy Statement is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information set forth under the captions “Certain Business Relationships and Transactions” and “Director Independence” in the Proxy Statement is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
The information set forth under the caption “Ratification of Appointment of Independent Auditors” in the Proxy Statement is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)Documents included in this report:
1. Financial Statements
Report of management on internal control over financial reporting
Report of independent registered public accounting firm (PCAOB ID: 42)
Report of independent registered public accounting firm (PCAOB ID: 42)
Statement of consolidated operations for each of the three years in the period ended December 31, 2021
Statement of consolidated comprehensive income (loss) for each of the three years in the period ended December 31, 2021
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2021
Consolidated balance sheet as of December 31, 2021 and 2020
Statement of consolidated changes in equity (deficit) and noncontrolling interest for each of the three years in the period ended December 31, 2021
Notes to consolidated financial statements
2. Financial Statement Schedules
Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s financial statements and related notes.
3. Exhibits
EXHIBIT
NO. DESCRIPTION
2.1 - Agreement and Plan of Merger, dated as of March 1, 2021, by and among Apache Corporation, Registrant, and APA Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
3.1 - Amended and Restated Certificate of Incorporation of Registrant, dated March 1, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
3.2 - Amended and Restated Bylaws of Registrant, dated September 14, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed September 20, 2021, SEC File No. 001-40144).
4.1 - Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
4.2 - Description of Equity Securities of the Registrant (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
10.1 - Assignment and Assumption Agreement, dated as of March 1, 2021, by and between Registrant and Apache Corporation (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.2 - APA Corporation Income Continuance Plan, as amended and restated effective as of March 1, 2021 (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.3 - APA Corporation Executive Termination Policy, as amended and restated effective as of March 1, 2021 (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.4 - APA Corporation 2016 Omnibus Compensation Plan, dated February 3, 2016, effective May 12, 2016 (incorporated by reference to Exhibit 10.1 to Apache Corporation’s Current Report on Form 8-K filed May 16, 2016, SEC File No. 001-4300).
†10.5 - First Amendment to the Registrant’s 2016 Omnibus Compensation Plan, dated July 29, 2019 (incorporated by reference to Exhibit 10.13 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.6 - Second Amendment to the Registrant’s 2016 Omnibus Compensation Plan, dated March 1, 2021 (incorporated by reference to Exhibit 10.6 to the Registrant’s Current Report on Form 8-K12B filed on March 1, 2021, SEC File No. 001-40144).
†10.7 - APA Corporation 2011 Omnibus Equity Compensation Plan, as amended and restated May 12, 2016 (incorporated by reference to Exhibit 10.1 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.8 - First Amendment to the Registrant’s 2011 Omnibus Equity Compensation Plan, dated July 29, 2019 (incorporated by reference to Exhibit 10.15 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.9 - Second Amendment to the Registrant’s 2011 Omnibus Equity Compensation Plan, dated March 1, 2021 (incorporated by reference to Exhibit 10.5 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.10 - APA Corporation 2007 Omnibus Equity Compensation Plan, as amended and restated May 4, 2011 (incorporated by reference to Exhibit 10.1 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).
†10.11 - First Amendment to the Registrant’s 2007 Omnibus Equity Compensation Plan, dated March 1, 2021 (incorporated by reference to Exhibit 10.4 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.12 - APA Corporation Deferred Delivery Plan, as amended and restated May 12, 2016 (incorporated by reference to Exhibit 10.3 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.13 - APA Corporation Non-Employee Directors’ Compensation Plan, as amended and restated July 13, 2017 (incorporated by reference to Exhibit 10.1 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, SEC File No. 001-4300).
†10.14 - APA Corporation Outside Directors’ Retirement Plan, as amended and restated July 16, 2014, effective June 30, 2014 (incorporated by reference to Exhibit 10.5 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.15 - APA Corporation Non-Employee Directors’ Restricted Stock Units Program, as amended and restated May 14, 2015 (incorporated by reference to Exhibit 10.6 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, SEC File No. 001-4300).
EXHIBIT
NO. DESCRIPTION
†10.16 - APA Corporation Non-Employee Directors’ Restricted Stock Units Program, effective May 12, 2016, pursuant to the Registrant’s 2016 Omnibus Compensation Plan (incorporated by reference to Exhibit 10.4 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.17 - APA Corporation Outside Directors’ Deferral Program, effective May 12, 2016, pursuant to the Registrant’s 2016 Omnibus Compensation Plan (incorporated by reference to Exhibit 10.5 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.18 - Form of 2018 Restricted Stock Unit Award Agreement dated January 16, 2018 (2016 Omnibus Compensation Plan) (incorporated by reference to Exhibit 10.43 to Apache Corporation’s Annual Report on Form 10-K for the year ended December 31, 2017, SEC File No. 001-04300).
†10.19 - Form of 2018 Cash-Settled Restricted Stock Unit Award Agreement dated January 16, 2018 (2016 Omnibus Compensation Plan) (incorporated by reference to Exhibit 10.44 to Apache Corporation’s Annual Report on Form 10-K for the year ended December 31, 2017, SEC File No. 001-04300).
†10.20 - Form of 2018 Performance Share Grant Agreement (2016 Omnibus Compensation Plan), dated January 16, 2018 (incorporated by reference to Exhibit 10.1 to Apache Corporation’s Current Report on Form 8-K filed January 19, 2018, SEC File No. 001-04300).
†10.21 - Form of 2018 Stock Option Grant Agreement (2016 Omnibus Compensation Plan), dated January 16, 2018 (incorporated by reference to Exhibit 10.2 to Apache Corporation’s Current Report on Form 8-K filed January 19, 2018, SEC File No. 001-04300).
†10.22 - Form of 2019 Performance Share Program (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.1 to Apache Corporation’s Current Report on Form 8-K filed January 7, 2019, SEC File No. 001-04300).
†10.23 - Form of 2019 Cash-Based Restricted Stock Unit Grant Agreement (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.2 to Apache Corporation’s Current Report on Form 8-K filed January 7, 2019, SEC File No. 001-04300).
†10.24 - Form of 2019 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.47 to Apache Corporation’s Annual Report on Form 10-K for the year ended December 31, 2018, SEC File No. 001-04300).
†10.25 - Form of 2019 Cash-Based Restricted Stock Unit Grant Agreement (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.48 to Apache Corporation’s Annual Report on Form 10-K for the year ended December 31, 2018, SEC File No. 001-04300).
†10.26 - Amendment of Performance Share Grant Agreement, dated July 29, 2019 (incorporated by reference to Exhibit 10.52 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.27 - Amendment of Restricted Stock Unit Award Agreement, dated July 29, 2019 (incorporated by reference to Exhibit 10.53 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.28 - Amendment of Stock Option Grant Agreement, dated July 29, 2019 (incorporated by reference to Exhibit 10.54 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.29 - Form of 2020 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.55 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.30 - Form of 2020 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.56 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.31 - Form of 2020 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.57 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.32 - Form of 2020 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.58 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.33 - Form of 2021 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021 (incorporated by reference to Exhibit 10.43 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2020, SEC File No. 001-04300).
†10.34 - Form of 2021 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021 (incorporated by reference to Exhibit 10.44 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2020, SEC File No. 001-4300).
EXHIBIT
NO. DESCRIPTION
†10.35 - Form of 2021 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021 (incorporated by reference to Exhibit 10.45 to Apache Corporation's Annual Report on Form 10-K for year ended December 31, 2020, SEC File No. 001-4300).
†10.36 - Form of 2021 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021 (incorporated by reference to Exhibit 10.46 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2020, SEC File No. 001-04300).
†10.37 - Amendment of Restricted Stock Unit Award Agreement, dated March 1, 2021 (incorporated by reference to Exhibit 10.7 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.38 - Amendment of Performance Share Grant Agreement, dated March 1, 2021 (incorporated by reference to Exhibit 10.8 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.39 - Amendment of Stock Option Grant Agreement, dated March 1, 2021 (incorporated by reference to Exhibit 10.9 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.40 - Form of 2022 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 4, 2022. (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 7, 2022, SEC File No. 001-40144)
*†10.41 - Form of 2022 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 4, 2022.
*†10.42 - Form of 2022 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 4, 2022.
*†10.43 - Form of 2022 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 4, 2022.
*21.1 - Subsidiaries of Registrant.
*23.1 - Consent of Ernst & Young LLP.
*23.2 - Consent of Ryder Scott Company, L.P., Petroleum Consultants.
*24.1 - Power of Attorney (included as a part of the signature pages to this report).
*31.1 - Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2 - Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1 - Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*99.1 - Report of Ryder Scott Company, L.P., Petroleum Consultants.
*101.INS - Inline XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).
*101.SCH - Inline XBRL Taxonomy Schema Document.
*101.CAL - Inline XBRL Calculation Linkbase Document.
*101.DEF - Inline XBRL Definition Linkbase Document.
*101.LAB - Inline XBRL Label Linkbase Document.
*101.PRE - Inline XBRL Presentation Linkbase Document.
*104 - Cover Page Interactive Data File (the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).
* Filed herewith.
† Management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15 hereof.
NOTE: Debt instruments of the Registrant defining the rights of long-term debt holders in principal amounts not exceeding 10 percent of the Registrant’s consolidated assets have been omitted and will be provided to the Commission upon request.