EDGAR 10-K Filing

Company CIK: 6769
Filing Year: 2023
Filename: 6769_10-K_2023_0001784031-23-000008.json

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ITEM 1. BUSINESS
ITEMS 1 and 2. BUSINESS AND PROPERTIES
GENERAL
Apache Corporation, a direct, wholly owned subsidiary of APA Corporation (APA), 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). Prior to the BCP Business Combination defined below, the Company’s midstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas.
On March 1, 2021, the Company consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which the Company became a direct, wholly owned subsidiary of APA, and all of the Company’s outstanding shares automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to the Company pursuant to Rule 12g-3(a) under the Exchange Act and replaced the Company as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized APA’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have affiliates operating around the globe. Refer to Note 2-Transactions with Parent Affiliate in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K for more detail.
Through APA’s website, www.apacorp.com, you can access, free of charge, electronic copies of the 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. 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, 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, APA also posts announcements, updates, and investor information on its website in addition to copies of all recent press releases. Information on APA’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 Apache Corporation.
BUSINESS OVERVIEW
The following business overview further describes the operations and activities for the Company’s upstream exploration and production properties, by geographic region.
UPSTREAM EXPLORATION AND PRODUCTION
Operating Areas
Apache has exploration and production operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea.
The following table sets out a brief comparative summary of certain key 2022 data for each of Apache’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 73.9 52 % $ 3,949 573 67 % 74 74
Egypt(1)
52.8 38 % 3,521 184 21 % 97 82
North Sea(2)
14.4 10 % 1,558 99 12 % 2 2
Total 141.1 100 % $ 9,028 856 100 % 173 158
(1)Apache’s operations in Egypt, excluding the impacts of noncontrolling interests contributed 22 percent of 2022 production and accounted for 11 percent of year-end estimated proved reserves.
(2)Sales volumes from the Company’s North Sea assets for 2022 were 14.9 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.
United States
In 2022, Apache’s U.S. upstream oil and gas operations contributed approximately 52 percent of production, 44 percent of oil and gas revenues, and 67 percent of estimated year-end proved reserves, consistent with prior years. Apache has access to significant liquid hydrocarbons across its 3.5 million gross acres (1.7 million net acres) in the U.S., 74 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. Apache 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. Apache 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 Apache holds approximately 789,000 gross acres (451,000 net acres) in the Southern Midland Basin and the Eagle Ford shale and Austin Chalk areas of southeast Texas. During 2022, the Company averaged two rigs targeting oil plays in the Wolfcamp and Spraberry formations, drilling 52 gross development wells in this basin with a 100 percent success rate.
•Delaware Basin Apache holds approximately 223,000 gross acres (127,000 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 2022, the Company completed 22 gross development wells with a 100 percent success rate.
•Legacy Assets Apache holds approximately 2.5 million gross acres (1.1 million net acres) in legacy properties, of which 663,000 gross acres are in the offshore waters of the Gulf of Mexico. Consistent with the Company’s broader portfolio management efforts, certain non-strategic leasehold positions on its legacy acreage holdings provide additional monetization opportunities that continue to be evaluated.
•New Venture Assets Apache separately has undeveloped acreage positions across several states where it intends to pursue exploration interests and potential development opportunities over time.
The Company is committed to maintaining a safe, steady, and efficient level of activity as part of its three-year capital investment program. For 2023, 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 The Company sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. In addition, to satisfy a delivery commitment beginning in 2023, the Company will purchase third party natural gas to sell and deliver to a U.S. LNG export facility. 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. Apache strives to maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk.
Apache 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), WTI Midland, or West Texas Light (WTL) Midland) and some predominately Brent related international pricing indices, adjusted for quality, transportation, and a market-reflective differential. Apache’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.
Apache’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 Apache to deliver an average of 181 Bcf of natural gas per year for the period from 2023 through 2029, an average of 53 Bcf of natural gas per year for the period from 2030 through 2037, and an average of 5.7 MMbbls of crude oil per year for the period from 2023 through 2025, in each case, at variable, domestic and/or international, market-based pricing.
Apache currently expects to fulfill its delivery commitments with production from its proved reserves, production from continued development and/or third-party purchases. Apache 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 2022, international assets contributed 48 percent of Apache’s production and 56 percent of its oil and gas revenues. Approximately 33 percent of estimated proved reserves at year-end were located outside the U.S.
Apache 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.
Egypt Apache has 27 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 2022, the Company held 5.3 million gross acres in six separate concessions. The Company’s acreage is primarily held under one concession agreement that resulted from the ratification of a new merged concession agreement (MCA) 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 Apache with considerable exploration and development opportunities for the future.
Apache’s Egypt operations are conducted pursuant to production-sharing contracts (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 Apache’s Egypt operations despite impacting Apache’s production and reserves.
On December 27, 2021, the Company announced the ratification of a new MCA with EGPC having an effective date of April 1, 2021. The MCA consolidated 98 percent of gross acreage and 90 percent of gross production under one concession agreement and refreshed 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 Apache production covered under the new concession.
Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business. In conjunction with the ratification of the MCA with EGPC, Apache entered into an agreement with APA under which the historical value of existing concessions prior to ratifying the MCA was retained by Apache, with any excess value from the MCA terms being allocated to APA. In accordance with terms of the agreement, approximately 30 percent of the Company’s Egyptian operation net income and distributable cash flow, excluding Sinopec’s one-third interest, was allocated to APA during 2022.
The Company’s estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country’s share of reserves. Apache’s Egypt assets, including APA and Sinopec’s noncontrolling interests, contributed 38 percent of 2022 production and 21 percent of 2022 year-end estimated proved reserves. Excluding the impacts of APA and Sinopec’s noncontrolling interests, Egypt contributed 22 percent of 2022 production and 11 percent of 2022 year-end estimated proved reserves.
In 2022, the Company drilled 66 gross development and 31 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 Apache’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 three million acres, which has led to recent discoveries that build and enhance the Company’s drilling inventory in Egypt.
During 2022, the Company focused on several environmental initiatives in Egypt and has delivered on its 2022 upstream flaring reduction goal by flaring at least 40 percent less gas than would otherwise be flared without these initiatives, with the Company now compressing this gas into sales lines.
For 2023, the Company will continue to focus on driving efficiencies and managing costs after increasing activity under the MCA.
North Sea Apache has interests in approximately 294,000 gross acres in the U.K. North Sea. These assets contributed 10 percent of Apache’s 2022 production and approximately 11 percent of year-end estimated proved reserves.
Apache entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). Since acquiring Forties, Apache 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 Apache 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. Apache 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.
During 2022, Apache averaged two rigs in the North Sea and drilled one gross development well and one gross exploration well. Production was negatively impacted by considerable planned and unplanned downtime at Beryl and Forties during 2022, improving in the fourth quarter of 2022 following completion of these maintenance activities.
International Marketing Apache’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.
Apache’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.
Drilling Statistics
Worldwide in 2022, Apache drilled or participated in drilling 173 gross wells, with 158 wells (91 percent) completed as producers. Historically, Apache’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 during 2022, at year-end a number of wells had not yet reached completion: 89 gross (74.2 net) in the U.S., 41 gross (40.7 net) in Egypt, and 1 gross (0.6 net) in the North Sea.
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 - - - 40.7 - 40.7 40.7 - 40.7
Egypt 15.0 14.5 29.5 64.4 - 64.4 79.4 14.5 93.9
North Sea 1.0 - 1.0 1.0 - 1.0 2.0 - 2.0
Total 16.0 14.5 30.5 106.1 - 106.1 122.1 14.5 136.6
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
Total 10.6 14.5 25.1 98.2 1.5 99.7 108.8 16.0 124.8
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
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, 2022, is set forth below:
Oil Gas Total
Gross Net Gross Net Gross Net
United States 8,716 5,260 881 624 9,597 5,884
Egypt 1,076 1,037 116 113 1,192 1,150
North Sea 159 116 13 8 172 124
Total 9,951 6,413 1,010 745 10,961 7,158
Domestic 8,716 5,260 881 624 9,597 5,884
Foreign 1,235 1,153 129 121 1,364 1,274
Total 9,951 6,413 1,010 745 10,961 7,158
Gross natural gas and crude oil wells included 514 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 24.1 21.9 167.6 $ 10.96 $ 96.25 $ 33.47 $ 5.33
Egypt(1)
31.1 0.1 130.1 10.37 101.25 76.80 2.85
North Sea(2)
11.9 0.4 12.8 30.07 100.87 67.07 23.36
Total 67.1 22.4 310.5 12.75 99.39 34.62 4.97
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
(1)Includes production volumes attributable to noncontrolling interests in Egypt.
(2)Sales volumes from the Company’s North Sea assets for 2022, 2021, and 2020 were 14.9 MMboe, 16.1 MMboe, and 22.7 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, 2022:
Undeveloped Acreage Developed Acreage
Gross Acres Net Acres Gross Acres Net Acres
(In thousands)
United States 2,616 1,166 913 561
Egypt 3,589 3,589 1,711 1,661
North Sea 135 118 159 123
Total 6,340 4,873 2,783 2,345
As of December 31, 2022, Apache held 10,000 net undeveloped acres that are scheduled to expire by year-end 2023 if production is not established or the Company takes no action to extend the terms. The Company also held 118,000 and 12,000 net undeveloped acres set to expire by year-end 2024 and 2025, 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 new merged concession agreement 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.
As of December 31, 2022, approximately 97 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, Apache 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. Apache 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, 2022, based on average commodity prices in effect on the first day of each month in 2022, 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 169 153 1,128 510
Egypt(1)
108 - 400 175
North Sea 83 2 66 96
Total 360 155 1,594 781
Proved Undeveloped:
United States 16 16 189 64
Egypt(1)
9 - 1 9
North Sea 3 - 2 3
Total 28 16 192 76
Total Proved 388 171 1,786 857
(1)Includes total proved developed and total proved undeveloped reserves of 94 MMboe and 5 MMboe, respectively, attributable to noncontrolling interests in Egypt.
As of December 31, 2022, Apache had total estimated proved reserves of 388 MMbbls of crude oil, 171 MMbbls of NGLs, and 1.8 Tcf of natural gas. Combined, these total estimated proved reserves are the volume equivalent of 857 million boe, of which liquids represents approximately 65 percent. As of December 31, 2022, the Company’s proved developed reserves totaled 781 MMboe and estimated PUD reserves totaled 76 MMboe, or approximately 9 percent of worldwide total proved reserves. Apache 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, 2022, 2021, and 2020.
During 2022, the Company added 34 MMboe of proved reserves through exploration and development activity. There were also upward revisions of previously estimated reserves of 75 MMboe. Upward revisions related to miscellaneous changes accounted for 5 MMboe. Engineering and performance upward revisions accounted for 70 MMboe, with the new merged concession agreement in Egypt accounting for an increase of 43 MMboe. The North Sea contributed upward revisions of 9 MMboe from well performance and reactivations in both the Beryl and Forties programs. In the United States, the Company experienced positive revisions of 18 MMboe. The Company acquired 1 MMboe of proved reserves and sold 26 MMboe of proved reserves associated with U.S. divestitures, primarily related to the Permian Basin.
The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2022, 2021, and 2020, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 19-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 76 MMboe as of December 31, 2022, decreased by 9 MMboe from 85 MMboe of PUD reserves reported at year end 2021. During the year, Apache converted 20 MMboe of PUD reserves to proved developed reserves through development drilling activity. In the U.S., Apache converted 13 MMboe, with the remaining 7 MMboe in its international areas. Apache sold 0.4 MMboe of PUD reserves in the U.S. and did not acquire any PUD reserves during 2022. Apache added 14 MMboe of new PUD reserves through extensions and discoveries. Downward revisions totaled 5 MMboe, comprising 0.5 MMboe associated with engineering and interest revisions, 4 MMboe associated with revised development plans, and 0.5 MMboe associated with product prices.
During 2022, a total of approximately $215 million was spent on projects associated with proved undeveloped reserves. A portion of Apache’s costs incurred each year relate to development projects that will convert undeveloped reserves to proved developed reserves in future years. During 2022, Apache spent approximately $105 million on PUD reserve development activity in the U.S. and $110 million in the international areas. As of December 31, 2022, Apache 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
Apache’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.
Apache’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 Apache’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 Apache’s board of directors (the 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.
Apache’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 2022, the properties selected for each country ranged from 81 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 Apache’s international proved reserves and 96 percent of the value of Apache’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.
The percentages of total estimated proved reserves and volumes covered by Ryder Scott’s reviews for the years 2022, 2021, and 2020 were:
2022 2021 2020
Estimated proved reserves values 82 % 83 % 85 %
Estimated proved reserves volumes:
United States 80 % 80 % 80 %
Egypt 80 % 80 % 82 %
North Sea 81 % 81 % 83 %
Apache Worldwide 80 % 80 % 81 %
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 Apache, the overall procedures and methodologies utilized by Apache in determining the proved reserves comply with the current SEC regulations, and the overall proved reserves for the reviewed properties as estimated by Apache 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 Apache’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, Apache’s subsidiary contributed certain Alpine High midstream assets and options to acquire equity interests in five separate third-party pipeline projects to Altus Midstream LP and/or its subsidiaries. In exchange for the assets, Apache’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. As a result, Apache fully consolidated the assets and liabilities of ALTM in its consolidated financial statements, with a corresponding noncontrolling interest reflected separately.
Business Combination with BCP
On February 22, 2022, ALTM closed a previously announced transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). The combination created an integrated midstream company in the Texas Delaware Basin offering services for residue gas, NGLs, crude oil and water. Pursuant to the BCP Contribution Agreement, Contributor contributed 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 issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. The transaction closed during the first quarter of 2022. Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc.
After the transaction closed, Apache Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM common stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock. Subsequent to the close of the transaction, in March 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for $224 million, reducing the Company’s retained ownership percentage in Kinetik to approximately 13 percent. Upon closing the transaction, the Company no longer consolidated the assets and liabilities of ALTM in its consolidated financial statements.
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 2022, sales to EGPC accounted for approximately 15 percent of the Company’s worldwide crude oil, natural gas, and NGLs revenues. 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 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 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.
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 2022, the Company maintained offices in Midland, Texas; Houston, Texas; Cairo, Egypt; and Aberdeen, Scotland. Apache’s primary office space is leased. The current lease on the Company’s principal executive offices runs through December 31, 2024. The Company plans to move its principal executive offices in 2024 to One Briarlake Plaza in Houston, Texas, under an existing lease that expires on December 31, 2038, subject to the lessee’s option to extend the term by up to 20 years. 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 12-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
Apache and its wholly owned subsidiary, Apache Deepwater LLC (ADW), developed oil spill response plans (the Plans) for their respective offshore operations in the Gulf of Mexico and the North Sea, which ensure rapid and effective responses to spill events that may occur on such entities’ operated properties. Emergency preparedness drills are conducted to measure and maintain the effectiveness of the Plans.
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. OSRL maintains aircraft available for global dispersant application and has a number of active recovery boom systems that can be used for offshore, nearshore, or shoreline responses. In addition to the services and equipment provided to all members of OSRL, the Company maintains membership to supplementary services from OSRL, including the U.K. Continental Shelf (UKCS) Aerial Surveillance, OSPRAG Capping Stack, and Dispersant Stockpile, providing equipment and services specifically tailored for an emergency response in the North Sea.
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 and ADW. Both Apache and ADW are members 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. CGA was created to provide a means of effectively staging response equipment and to provide spill response capability for its member companies operating in the Gulf of Mexico. CGA equipment includes skimming vessels, barges, boom, and dispersants.
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
Global pandemics have previously, may continue to, and may in the future 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.
Global pandemics and the actions taken by third parties, including, but not limited to, governmental authorities, businesses, and consumers, in response to such pandemics, including the COVID-19 pandemic, have previously adversely impacted and may from time to time in the future adversely impact the global economy, resulting in significant volatility in the global financial markets. Previous business closures, restrictions on travel, “stay-at-home” or “shelter-in-place” orders, and other restrictions on movement within and among communities significantly reduced demand for, and the prices of, oil, natural gas, and NGLs, and such restrictions may be continued or reintroduced at any time. 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 or reformulate adequate treatments, including due to the emergence of new variants, and other adverse impacts from a pandemic may materially adversely affect the Company’s business, financial condition, cash flows, and results of operations. Actual results will depend on future events, which the Company cannot predict, including the scope, duration, and potential reoccurrence of any such pandemic, the emergence and impact of variants, the distribution and effectiveness of, and individual willingness to take, vaccines, therapeutics, and treatments, the demand for, and the prices of, oil, natural gas, and NGLs, and the actions taken by third parties in response to any of the foregoing.
The Company’s operations rely on its workforce having access to its wells, platforms, structures, offices, and facilities. 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), or other restrictions or adverse impacts resulting from a pandemic, the Company’s business, financial condition, cash flows, and results of operations may be materially adversely affected.
Crude oil, natural gas, and NGL prices and their volatility could adversely affect the Company’s operating results.
The Company’s revenues, operating results, and future rate of growth depend highly upon the prices it receives for its sales of crude oil, natural gas, and NGL products. 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 2022 ranged from a high of $123.64 per barrel to a low of $71.05 per barrel, and the NYMEX daily settlement price for the prompt month natural gas contract in 2022 ranged from a high of $9.85 per MMBtu to a low of $3.46 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 and/or inventories 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) and non-OPEC members that participate in OPEC initiatives (OPEC+);
•political conditions and events (including instabilities, changes in governments, or armed conflicts) 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 price and level of imported foreign or exported domestic crude oil, natural gas, and NGLs, including as a result of the availability of facilities that process, import, or export such products;
•increasing inflationary pressure;
•the price and availability of alternative fuels, including coal and biofuels;
•increased competitiveness of, and demand for, alternative energy sources;
•technological advances affecting energy supply and energy consumption, including those that alter fuel choices;
•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, including with respect to environmental, social, and governance matters;
•domestic and foreign governmental regulations and taxes, including legislative, regulatory, and policy changes or initiatives to address the impacts 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 or reallocate capital to different projects or regions;
•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, 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, cyberattacks or terrorist events, 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. Additionally, the Company may voluntarily curtail production in response to market conditions. If a substantial amount of the Company’s production is interrupted or curtailed at the same time, it could temporarily adversely affect the Company’s cash flows. Further, 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 has previously not realized, and may in the future 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. Management has previously determined, and may in the future determine, that future or further drilling or development activities will not, or are unlikely to, occur for a well or reservoir based on drilling results, current or future estimated commodity prices or demand for oil, natural gas, and NGLs, or other information, including drilling results in, or information related to, adjacent or nearby geographic areas or similar geologies or reservoirs. The seismic data and other technologies that 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, equipment, and labor.
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. Exploration costs and dry hole expenses incurred by the Company during the reporting period are further discussed in this Annual Report on Form 10-K and reflected in the consolidated financial statements included herein.
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 and the North Sea, 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 partners and the purchasers of the Company’s products or assets have had and could have an adverse impact on the Company in the event they are unable to reimburse the Company for their share of costs or to pay the Company for the products or services the Company provides.
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 divests 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 Decommissioning Obligations on Sold Properties” in Note 12-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 or joint ventures, and the parties to such agreements or ventures may fail to meet their obligations.
The Company conducts many of its exploration and production (E&P) operations through joint operating agreements or joint ventures with other parties. The Company may not control decisions made under such agreements or ventures, either because it does not have a controlling interest in the venture or is not an operator under the agreement. There is risk that the other parties to these arrangements may 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 such agreements or ventures 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 and the Company’s business and financial condition may be adversely affected.
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 2022, the Company’s credit rating was affirmed by Moody’s as Ba1/Positive and by Standard and Poor’s as BB+/Positive. 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.
APA Corporation’s syndicated credit facilities currently mature in April 2027. There is no assurance of the terms upon which potential lenders under future agreements will make loans or other extensions of credit available to APA, the Company, or APA’s other subsidiaries or the composition of such lenders.
Actions by advocacy groups to advance climate change and energy transition initiatives, 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 companies in the oil and gas industry, which could negatively impact the Company’s access to and costs of capital or the market for the Company’s securities.
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. Unfavorable ESG ratings may lead to negative investor and public sentiment toward the Company, which may cause the market for the Company’s securities to be negatively impacted.
In addition, a number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to influence change in the business strategies in oil and gas companies, including through the investment and voting practices of investment advisers, public pension funds, universities, and other members of the investing community. These activities include increasing attention and demands for action related to climate change and energy transition matters, such as promoting the use of substitutes to fossil fuel products and encouraging the divestment of investments in the oil and gas industry, as well as pressuring lenders and other financial services companies to limit or curtail activities with oil and gas companies. If investors or financial institutions shift funding away from companies in the oil and gas industry, the Company’s access to and costs of capital or the market for the Company’s securities may be negatively impacted.
RISKS RELATED TO FINANCIAL RESULTS
Future economic conditions in the U.S. and 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 11-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. 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.
On May 26, 2022, the U.K. Chancellor of the Exchequer announced a new tax (the Energy Profits Levy) on the profits of oil and gas companies operating in the U.K. and the U.K. Continental Shelf. Under the new law, an additional levy is assessed at a 25 percent rate and is effective for the period of May 26, 2022, through December 31, 2025. On November 17, 2022, the U.K. Chancellor of the Exchequer announced in the Autumn Statement 2022 further changes to the Energy Profits Levy, increasing the levy assessed from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023, through March 31, 2028. On November 22, 2022, the U.K. Government published draft legislation to implement this change, among other provisions, and on January 10, 2023, the Finance Act 2023 was enacted, receiving Royal Assent. The impact of this tax could adversely affect the Company’s future financial condition and cash flows.
On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). Among other changes, the IRA introduced a new 15% corporate alternative minimum tax (Corporate AMT) for taxable years beginning after December 31, 2022 on applicable corporations with an average annual adjusted financial statement income (AFSI) that exceeds $1.0 billion for any three consecutive tax years preceding the tax year at issue. If the Company were to meet this average AFSI test, any resulting Corporate AMT liability could adversely affect the Company’s future financial results, including earnings and cash flows.
RISKS RELATED TO CLIMATE CHANGE
The impacts of energy transition could adversely affect the Company’s business, operating results, and financial condition.
In recent years, increasing attention has been given to corporate activities related to climate change and energy transition. This focus, together with shifting preferences and attitudes with respect to the generation and consumption of energy, the use of hydrocarbons, and the use of products manufactured with, or powered by, hydrocarbons, may result in increased availability of, and demand for, energy sources other than oil and natural gas, including wind, solar, and hydroelectric power; technological advances with respect to the generation, transmission, storage, and consumption of alternative energy sources; and development of, and increased demand from consumers and industries for, lower-emission products and services, including electric vehicles and renewable residential and commercial power supplies, as well as more energy-efficient products and services.
These developments could adversely impact the demand for products powered by or manufactured with hydrocarbons and the demand for the Company’s, and in turn the prices it receives for its, crude oil, natural gas, and NGL products, which could materially and adversely affect the Company’s business and financial performance.
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 GHGs, including to monitor and limit existing emissions of GHGs and to restrict or eliminate future emissions. Moreover, in January 2021, the
President issued an executive order that commits to substantial action on climate change, calling for, among other things, 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 focus on ESG matters could have an adverse effect on the Company’s operations.
Enhanced focus 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 review, 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 the Company 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.
In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells to assess any relationship between seismicity and the use of such wells. 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.
Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the state to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. States may issue orders to temporarily shut down or to curtail the injection depth of existing wells in the vicinity of seismic events. Increased regulation and attention given to induced seismicity could also lead to greater opposition, including litigation to limit or prohibit oil and natural gas activities utilizing injection wells for produced water disposal. 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. On a barrel equivalent basis, approximately 47 percent of the Company’s 2022 production was outside the U.S., and approximately 32 percent of the Company’s estimated proved oil and gas reserves as of December 31, 2022, 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 noncontrolling interests, contributed 22 percent of the Company’s 2022 production and accounted for 11 percent of the Company’s year-end estimated proved reserves and 22 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.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable.

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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 12-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
Not applicable.
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
Apache is a wholly owned subsidiary of APA. Accordingly, all of Apache’s common stock, par value $0.625 per share, is owned by APA, and there is no market for Apache’s common stock.

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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 NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
The following discussion relates to Apache Corporation (Apache or the Company) and its consolidated subsidiaries and should be read together in conjunction with the Company’s Consolidated Financial Statements and accompanying notes included in Part IV, Item 15 of this Annual Report on Form 10-K, and the risk factors and related information set forth in Part I, Item 1A and Part II, Item 7A of this Annual Report on Form 10-K. This section of this Annual Report on Form 10-K generally discusses 2022 and 2021 items and year-to-year comparisons between 2022 and 2021. Discussions of 2020 items and year-to-year comparisons between 2021 and 2020 that are not included in this Annual Report on Form 10-K are incorporated by reference to “Management’s Narrative Analysis of Results of Operations” in Part II, Item 7 of Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2021 (filed with the SEC on February 22, 2022).
On March 1, 2021, Apache consummated a holding company reorganization (the Holding Company Reorganization), pursuant to which Apache became a direct, wholly owned subsidiary of APA Corporation (APA), and all of the Company’s outstanding shares automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to the Company pursuant to Rule 12g-3(a) under the Exchange Act and replaced the Company as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized APA’s operating and legal structure, making it more consistent with other companies that have affiliates operating around the globe. Refer to Note 2-Transactions with Parent Affiliate in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K for more detail.
Overview
Apache, a direct, wholly owned subsidiary of 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). Prior to the BCP Business Combination defined below, the Company’s midstream business was operated by Altus. Altus owned, developed, and operated a midstream energy asset network in the Permian Basin of West Texas.
Apache 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. Apache strives to meet those challenges while creating value for all its stakeholders.
Early in 2020, impacts of the coronavirus disease 2019 (COVID-19) pandemic and related governmental actions began to exert significant downward pressure on crude oil and natural gas prices. Since that time, commodity prices worldwide have largely rebounded; however, uncertainties in the global supply chain, commodity prices, and financial markets, including the impact of inflation, rising interest rates, and the conflict in Ukraine continue to impact oil supply and demand. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its shareholders. The Company continues to aggressively manage its cost structure regardless of the oil price environment and closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process.
During 2022, the Company reported net income of $3.5 billion compared to net income of $1.1 billion in 2021. Net income in 2022 benefited from higher commodity prices and increased revenues attributable to a new merged concession agreement in Egypt. The increase in realized prices was primarily driven by the effects of global inflation, the conflict in Ukraine on global commodity prices, and uncertainties around spare capacity and energy security globally.
The Company generated $4.9 billion of cash from operating activities in 2022, which was $1.3 billion, or 38 percent, higher than the prior year. Apache’s higher operating cash flows for 2022 were driven by higher crude oil and natural gas prices and associated revenues. Since year-end 2021, the Company has reduced its total outstanding debt and redeemable preferred interests by $2.6 billion and $712 million, respectively, through the deconsolidation of ALTM and the retirement of outstanding notes and debentures.
Operational Highlights
Key operational highlights for the year include:
United States
•Daily boe production from the Company’s U.S. assets, which decreased 12 percent from the prior year end, accounted for 52 percent of its total worldwide production during 2022. During 2022, the Company averaged 4 drilling rigs in the U.S., averaging 2 rigs each in the Southern Midland Basin and Delaware Basin assets. The Company’s core Midland Basin development program is expected to represent key growth areas for the U.S. assets.
International
•In December 2021, the Egyptian President signed and ratified the previously announced agreement with the Egyptian Ministry of Petroleum and the Egyptian General Petroleum Corporation (EGPC) to modernize the terms of the majority of the Company’s production-sharing contracts, having an effective date of April 1, 2021. The new merged concession agreement (MCA) consolidated 98 percent of gross acreage and 90 percent of gross production under one concession agreement and refreshes the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool that provides improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit-sharing rate of 30 percent for all the Company’s production covered under the new concession. The changes also simplify the contractual relationship with EGPC, facilitate recovery of prior investment, and update day-to-day operational governance. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s consolidated Egypt oil and gas business, and a portion of the remaining net income and distributable cash flow is allocated to APA in accordance with the terms of the agreement.
•Egypt gross equivalent production decreased 1 percent and net production increased 26 percent from 2021, primarily a function of improved cost recovery under the new merged concession agreement ratified at the end of 2021. The Company continues to build and enhance its drilling inventory in Egypt, supplemented with recent seismic acquisitions and new play concept evaluations on both new and existing acreage. The Company continues to increase drilling and workover activity as a result of the merged concession agreement. Egypt production growth is building on improvements in new well connections and recompletion activity.
•During 2022, the Company focused on several environmental initiatives in Egypt and has delivered on its 2022 upstream flaring reduction goal by flaring at least 40 percent less gas than would otherwise be flared without these initiatives, with the Company now compressing this gas into sales lines.
•The North Sea maintained two drilling rigs during 2022. Production was negatively impacted by considerable planned and unplanned downtime at Beryl and Forties during the third quarter of 2022, improving in the fourth quarter of 2022 following completion of these maintenance activities.
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 Apache’s portfolio of assets in response to these changes. Most recently, the Company has completed a series of acquisitions and divestitures designed to enhance the Company’s portfolio and monetize nonstrategic assets in order to allocate resources to more impactful exploration and development opportunities. These acquisitions and divestitures during 2022 include:
•BCP Business Combination On February 22, 2022, ALTM closed a transaction to combine with privately owned BCP Raptor Holdco LP (BCP and, together with BCP Raptor Holdco GP, LLC, the Contributed Entities) in an all-stock transaction, pursuant to the Contribution Agreement entered into by and among ALTM, Altus Midstream LP, New BCP Raptor Holdco, LLC (the Contributor), and BCP (the BCP Contribution Agreement). Upon closing the transaction, the combined entity was renamed Kinetik Holdings Inc. (Kinetik). As consideration for the contribution of the Contributed Interests, ALTM issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP’s unitholders.
ALTM’s stockholders continued to hold their existing shares of ALTM common stock. Apache Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM common stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock after the transaction closed. The Company deconsolidated ALTM upon closing the transaction and recognized a gain of approximately $609 million that reflects the difference of the Company’s share of ALTM’s deconsolidated balance sheet and the fair value of its 20 percent retained ownership in the combined entity.
Subsequent to the close of the transaction, in March 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for $224 million, reducing the Company’s retained ownership percentage in Kinetik to approximately 13 percent.
•Delaware Basin Divestitures During 2022, the Company completed a previously announced transaction to sell certain non-core mineral rights in the Delaware Basin, for total cash proceeds of $726 million.
•U.S. Leasehold Acquisitions During 2022, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of approximately $37 million.
•U.S. Leasehold Divestitures & Other During 2022, the Company completed the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $52 million.
For detailed information regarding Apache’s acquisitions and divestitures, refer to Note 3-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, Natural Gas, and Natural Gas Liquids Production Revenues
The Company’s production revenues and respective contribution to total revenues by country are as follows:
For the Year Ended December 31,
2022 2021 2020
$ Value % Contribution $ Value % Contribution $ Value % Contribution
($ in millions)
Oil Revenues:
United States $ 2,323 35 % $ 1,850 40 % $ 1,209 39 %
Egypt(1)
3,145 47 % 1,806 40 % 1,102 35 %
North Sea 1,232 18 % 929 20 % 795 26 %
Total(1)
$ 6,700 100 % $ 4,585 100 % $ 3,106 100 %
Natural Gas Revenues:
United States $ 894 58 % $ 754 62 % $ 251 42 %
Egypt(1)
370 24 % 270 23 % 280 47 %
North Sea 281 18 % 183 15 % 67 11 %
Total(1)
$ 1,545 100 % $ 1,207 100 % $ 598 100 %
NGL Revenues:
United States $ 732 93 % $ 673 95 % $ 304 91 %
Egypt(1)
6 1 % 9 1 % 8 3 %
North Sea 45 6 % 24 4 % 21 6 %
Total(1)
$ 783 100 % $ 706 100 % $ 333 100 %
Oil and Gas Revenues:
United States $ 3,949 44 % $ 3,277 50 % $ 1,764 44 %
Egypt(1)
3,521 39 % 2,085 32 % 1,390 34 %
North Sea 1,558 17 % 1,136 18 % 883 22 %
Total(1)
$ 9,028 100 % $ 6,498 100 % $ 4,037 100 %
(1)Includes revenues attributable to noncontrolling interests in Egypt.
Production
The following table presents production volumes by country:
For the Year Ended December 31,
2022 Increase
(Decrease) 2021 Increase
(Decrease) 2020
Oil Volumes - b/d:
United States(5)
66,142 (12)% 75,205 (15)% 88,249
Egypt(3)(4)
85,081 21% 70,349 (7)% 75,384
North Sea 32,578 (10)% 36,265 (28)% 50,386
Total 183,801 1% 181,819 (15)% 214,019
Natural Gas Volumes - Mcf/d:
United States(5)
459,123 (13)% 527,461 (6)% 561,731
Egypt(3)(4)
356,327 35% 263,653 (4)% 274,175
North Sea 35,327 (8)% 38,565 (33)% 57,464
Total 850,777 3% 829,679 (7)% 893,370
NGL Volumes - b/d:
United States(5)
59,887 (10)% 66,232 (11)% 74,136
Egypt(3)(4)
196 (63)% 531 (30)% 754
North Sea 1,111 (7)% 1,199 (38)% 1,936
Total 61,194 (10)% 67,962 (12)% 76,826
BOE per day:(1)
United States(5)
202,549 (12)% 229,348 (10)% 256,007
Egypt(3)(4)
144,665 26% 114,821 (6)% 121,834
North Sea(2)
39,577 (10)% 43,892 (29)% 61,899
Total 386,791 -% 388,061 (12)% 439,740
(1)The table shows production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the price ratio between the two products.
(2)Average sales volumes from the North Sea were 40,812 boe/d, 44,179 boe/d, and 62,157 boe/d for 2022, 2021, and 2020, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.
(3)Gross oil, natural gas, and NGL production in Egypt were as follows:
2022 2021 2020
Oil (b/d) 137,260 134,711 164,104
Natural Gas (Mcf/d) 555,562 586,663 641,069
NGL (b/d) 297 854 1,429
(4)Includes net production volumes per day attributable to noncontrolling interests in Egypt of:
2022 2021 2020
Oil (b/d) 45,216 23,504 25,206
Natural Gas (Mcf/d) 189,339 88,409 91,540
NGL (b/d) 104 177 251
(5)Production volumes per day in the Company’s Alpine High field were as follows:
2022 2021 2020
Oil (b/d) 777 1,485 2,718
Natural Gas (Mcf/d) 192,253 258,096 274,279
NGL (b/d) 18,362 22,950 24,942
Pricing
The following table presents pricing information by country:
For the Year Ended December 31,
2022 Increase
(Decrease) 2021 Increase
(Decrease) 2020
Average Oil Price - Per barrel:
United States $ 96.25 43% $ 67.37 80% $ 37.42
Egypt 101.25 44% 70.33 76% 39.95
North Sea 100.87 45% 69.67 62% 42.88
Total 99.39 44% 68.97 74% 39.60
Average Natural Gas Price - Per Mcf:
United States $ 5.33 36% $ 3.92 221% $ 1.22
Egypt 2.85 1% 2.81 1% 2.79
North Sea 23.36 80% 12.96 306% 3.19
Total 4.97 25% 3.99 118% 1.83
Average NGL Price - Per barrel:
United States $ 33.47 20% $ 27.85 148% $ 11.21
Egypt 76.80 57% 48.84 75% 27.83
North Sea 67.07 24% 54.30 83% 29.73
Total 34.62 22% 28.48 141% 11.84
Crude Oil Prices A substantial portion of the Company’s crude oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of the Company’s control. Average realized crude oil prices for 2022 were up 44 percent compared to 2021, a direct result of the rising benchmark oil prices over the past year. Crude oil prices realized in 2022 averaged $99.39 per barrel.
Continued volatility in the commodity price environment reinforces the importance of the Company’s asset portfolio. While the market price received for natural gas varies among geographic areas, crude oil tends to trade within a global market. Price movements for all types and grades of crude oil generally move in the same direction.
Natural Gas Prices Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions. The Company’s primary markets include North America, Egypt, and the U.K. An overview of the market conditions in the Company’s primary gas-producing regions follows:
•The Company sells its U.S. natural gas production at liquid index sales points within the U.S., at either monthly or daily index-based prices. The Company’s U.S. realizations averaged $5.33 per Mcf in 2022, a 36 percent increase from an average of $3.92 per Mcf in 2021.
•In Egypt, the Company’s natural gas is sold to EGPC, primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. Overall, the Company’s Egypt operations averaged $2.85 per Mcf in 2022, a 1 percent increase from an average of $2.81 per Mcf in 2021.
•Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The Company’s North Sea operations averaged $23.36 per Mcf in 2022, an 80 percent increase from an average of $12.96 per Mcf in 2021.
NGL Prices The Company’s U.S. NGL production, which accounted for 98 percent of the Company’s total 2022 NGL production, is sold under contracts with prices at market indices based on Gulf Coast supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.
Crude Oil Revenues
Crude oil revenues for 2022 totaled $6.7 billion, a $2.1 billion increase from the 2021 total of $4.6 billion. A 44 percent increase in average realized prices increased 2022 revenues by $2.0 billion compared to 2021, while 1 percent higher average daily production increased revenues by $98 million. Average daily production in 2022 was 184 Mb/d, with prices averaging $99.39 per barrel. Crude oil sales accounted for 74 percent of the Company’s 2022 oil and gas production revenues and 48 percent of its worldwide production.
The Company’s worldwide crude oil production increased 2 Mb/d compared to 2021, primarily a function of improved cost recovery under the merged concession agreement in Egypt ratified at the end of 2021, offset by extended operational downtime in the North Sea and natural production decline across all assets.
Natural Gas Revenues
Natural gas revenues for 2022 totaled $1.5 billion, a $338 million increase from the 2021 total of $1.2 billion. A 25 percent increase in average realized prices increased 2022 revenues by $303 million compared to 2021, while 3 percent higher average daily production increased revenues by $35 million. Average daily production in 2022 was 851 MMcf/d, with prices averaging $4.97 per Mcf. Natural gas sales accounted for 17 percent of the Company’s 2022 oil and gas production revenues and 36 percent of its worldwide production.
The Company’s worldwide natural gas production increased 21 MMcf/d compared to 2021, primarily a result of increased net production in Egypt resulting from improved cost recovery under the merged concession agreement ratified at the end of 2021, offset by extended operational downtime in the North Sea and natural production decline across all assets.
NGL Revenues
NGL revenues for 2022 totaled $783 million, a $77 million increase from the 2021 total of $706 million. A 22 percent increase in average realized prices increased 2022 revenues by $152 million compared to 2021, while 10 percent lower average daily production decreased revenues by $75 million. Average daily production in 2022 was 61 Mb/d, with prices averaging $34.62 per barrel. NGL sales accounted for 9 percent of the Company’s 2022 oil and gas production revenues and 16 percent of its worldwide production.
The Company’s worldwide NGL production decreased 7 Mb/d compared to 2021, primarily a result of natural production decline in the U.S.
Altus Midstream Revenues
Prior to the deconsolidation of Altus on February 22, 2022, the Company beneficially owned approximately 79 percent of ALTM’s outstanding voting common stock. Altus owned and operated a midstream energy asset network in the Permian Basin of West Texas primarily to service the Company’s production from its Alpine High resource play, which commenced production in May 2017.
Altus Midstream primarily generated revenue by providing fee-based natural gas gathering, compression, processing, and transmission services. For the years ended December 31, 2022 and 2021, Altus Midstream’s service revenues generated through its fee-based contractual arrangements with the Company totaled $16 million and $127 million, respectively. These affiliated revenues were eliminated upon consolidation.
Purchased Oil and Gas Sales
Purchased oil and gas sales represent volumes primarily attributable to transport, fuel, and physical in-basin gas purchases that were sold by the Company to fulfill natural gas takeaway obligations. Sales related to these purchased volumes increased $368 million for the year ended December 31, 2022 to $1.9 billion from $1.5 billion in the prior year. Purchased oil and gas sales were offset by associated purchase costs of $1.8 billion and $1.6 billion for the years ended December 31, 2022 and 2021, respectively. The increase is a result of higher average natural gas prices during 2022 compared to the prior year.
Operating Expenses
The table below presents a comparison of the Company’s operating expenses for the years ended December 31, 2022, 2021, and 2020. All operating expenses include costs attributable to a noncontrolling interest in Egypt and Altus.
For the Year Ended December 31,
2022 2021 2020
(In millions)
Lease operating expenses $ 1,435 $ 1,241 $ 1,127
Gathering, processing, and transmission 356 264 274
Purchased oil and gas costs 1,776 1,580 357
Taxes other than income 256 204 123
Exploration 146 127 274
General and administrative 462 357 290
Transaction, reorganization, and separation 26 22 54
Depreciation, depletion, and amortization:
Oil and gas property and equipment 1,130 1,255 1,643
Gathering, processing, and transmission assets 15 64 76
Other assets 32 41 53
Asset retirement obligation accretion 117 113 109
Impairments - 208 4,501
Financing costs, net 313 472 267
Lease Operating Expenses (LOE)
LOE includes several key components, such as direct operating costs, repairs and maintenance, and workover costs. Direct operating costs generally trend with commodity prices and are impacted by the type of commodity produced and the location of properties (i.e., offshore, onshore, remote locations, etc.). Fluctuations in commodity prices impact operating cost elements both directly and indirectly. They directly impact costs such as power, fuel, and chemicals, which are commodity price based. Commodity prices also affect industry activity and demand, thus indirectly impacting the cost of items such as rig rates, labor, boats, helicopters, materials, and supplies. Crude oil, which accounted for 48 percent of the Company’s total 2022 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.
During 2022, LOE increased $194 million, or 16 percent, compared to 2021. On a per-boe basis, LOE increased $1.14, or 13 percent, compared to 2021, from $8.75 per boe to $9.89 per boe. The increase in costs was driven by higher labor costs and operating costs trending with higher oil and gas prices and global inflation, coupled with higher workover activity in the U.S. during 2022.
Gathering, Processing, and Transmission (GPT)
GPT expenses include amounts paid to third-party carriers and to Altus Midstream for gathering and transmission services for the Company’s upstream natural gas production associated with its Alpine High play. GPT expenses also include midstream operating costs incurred by Altus Midstream. The following table presents a summary of these expenses:
For the Year Ended December 31,
2022 2021 2020
(In millions)
Third-party processing and transmission costs $ 260 $ 232 $ 236
Midstream service costs - ALTM 18 128 143
Midstream service costs - Kinetik 91 - -
Upstream processing and transmission costs 369 360 379
Midstream operating expenses 5 32 38
Intersegment eliminations (18) (128) (143)
Total Gathering, processing, and transmission $ 356 $ 264 $ 274
GPT costs increased $92 million compared to 2021. Third-party processing and transmission costs increased $28 million, primarily driven by an increase in average transportation rates during the year. Costs for services provided by ALTM in the first quarter of 2022 and prior to the BCP Business Combination totaling $18 million were eliminated in the Company’s consolidated financial statements and reflected as “Intersegment eliminations” in the table above. Subsequent to the BCP Business Combination and the Company’s deconsolidation of Altus on February 22, 2022, these midstream services continue to be provided by Kinetik but are no longer eliminated. Midstream services provided by Kinetik totaled $91 million for the year ended 2022.
Purchased Oil and Gas Costs
Purchased oil and gas costs increased $196 million compared to 2021, and were primarily offset by associated sales totaling $1.9 billion for the year ended 2022, as discussed above.
Taxes Other Than Income
Taxes other than income primarily consist of severance taxes on onshore properties and in state waters off the coast of the U.S. and ad valorem taxes on U.S. properties. Severance taxes are generally based on a percentage of oil and gas production revenues. The Company is also subject to a variety of other taxes, including U.S. franchise taxes.
Taxes other than income increased $52 million compared to 2021, primarily from higher severance taxes driven by higher commodity prices.
Exploration Expenses
Exploration expenses include unproved leasehold impairments, exploration dry hole expense, geological and geophysical expenses, and the costs of maintaining and retaining unproved leasehold properties. The following table presents a summary of these expenses:
For the Year Ended December 31,
2022 2021 2020
(In millions)
Unproved leasehold impairments $ 24 $ 31 $ 101
Dry hole expenses 69 55 110
Geological and geophysical expenses 6 8 20
Exploration overhead and other 47 33 43
Total Exploration $ 146 $ 127 $ 274
Exploration expenses increased $19 million compared to 2021, primarily the result of higher dry hole expenses in Egypt and higher exploration overhead, a function of increased exploration activities.
General and Administrative (G&A) Expenses
G&A expenses increased $105 million compared to 2021, primarily driven by higher cash-based stock compensation expense resulting from an increase in the Company’s stock price and achievement of performance and financial objectives as defined in the stock award plans. Higher overall wages across the Company and global inflationary pressures also impacted G&A expenses compared to the prior-year period.
Transaction, Reorganization, and Separation (TRS) Costs
TRS costs increased $4 million compared to 2021, primarily a result of transaction costs from the BCP Business Combination, partially offset by a decrease in costs associated with the Company’s prior year reorganization efforts that are substantially completed.
Depreciation, Depletion and Amortization (DD&A)
DD&A expenses on the Company’s oil and gas property for the year ended December 31, 2022 decreased $125 million compared to 2021. The Company’s oil and gas property DD&A rate decreased $1.06 per boe in 2022 compared to 2021, from $8.85 per boe to $7.79 per boe. The decrease on an absolute basis was driven by lower depletion rates in Egypt under the new merged concession agreement, partially offset by higher production volumes. DD&A expense on the Company’s GPT depreciation decreased $49 million compared to 2021, primarily driven by certain Egyptian assets being fully depreciated coupled with the deconsolidation of Altus during the first quarter of 2022.
Impairments
No asset impairments were recorded in 2022. During 2021, the Company recorded asset impairments totaling $208 million. The charges include $160 million for Altus’ equity method interests, $26 million in connection with inventory valuations in Egypt, and $22 million in connection with inventory valuations and expected equipment dispositions in the North Sea.
During 2020, the Company recorded asset impairments in connection with fair value assessments totaling $4.5 billion, including $4.3 billion for oil and gas proved properties in the U.S, Egypt, and the North Sea, $68 million for GPT facilities in Egypt, $87 million for goodwill in Egypt, and $27 million for inventory and other miscellaneous assets.
The following table presents a summary of asset impairments recorded for 2022, 2021, and 2020:
For the Year Ended December 31,
2022 2021 2020
(In millions)
Oil and gas proved property $ - $ - $ 4,319
GPT facilities - - 68
Equity method interests - 160 -
Goodwill - - 87
Inventory and other - 48 27
Total Impairments $ - $ 208 $ 4,501
Financing Costs, Net
Financing costs incurred during 2022, 2021, and 2020 comprised the following:
For the Year Ended December 31,
2022 2021 2020
(In millions)
Interest expense $ 312 $ 419 $ 438
Amortization of debt issuance costs 7 8 8
Capitalized interest (1) - (12)
Loss (gain) on extinguishment of debt 67 104 (160)
Interest income (9) (8) (7)
Interest income from APA Corporation, net (63) (51) -
Total Financing costs, net $ 313 $ 472 $ 267
Net financing costs during 2022 decreased $159 million compared to 2021, primarily the result of the reduction of fixed-rate debt during 2021 and the first half of 2022. Additionally, losses incurred on the extinguishment of debt were lower during 2022 compared to the prior year period.
Provision for Income Taxes
Income tax expense increased $1.1 billion from $578 million during 2021 to $1.7 billion during 2022. The Company’s year-to-date 2022 effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of the Energy (Oil and Gas) Profits Levy Act 2022 (the Energy Profits Levy) on July 14, 2022, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During 2021, the Company’s effective income tax rate was primarily impacted by asset impairments and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.
On May 26, 2022, the U.K. Chancellor of the Exchequer announced a new tax (the Energy Profits Levy) on the profits of oil and gas companies operating in the U.K. and the U.K. Continental Shelf. Under the new law, an additional levy is assessed at a 25 percent rate and is effective for the period of May 26, 2022, through December 31, 2025. The Company recorded a deferred tax expense of $208 million associated with the remeasurement of the U.K. deferred tax liability. On November 17, 2022, the U.K. Chancellor of the Exchequer announced in the Autumn Statement 2022 further changes to the Energy Profits Levy, increasing the levy assessed from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023, through March 31, 2028. On November 22, 2022, the U.K. Government published draft legislation to implement this change, among other provisions, and on January 10, 2023, the Finance Act 2023 was enacted, receiving Royal Assent. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, in the first quarter of 2023, the Company expects to record a deferred tax expense of approximately $170 million to $190 million related to the remeasurement of the December 31, 2022 U.K. deferred tax liability.
On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (Corporate AMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1 billion for any three consecutive years preceding the tax year at issue. The Corporate AMT is effective for tax years beginning after December 31, 2022. The Company is continuing to evaluate the provisions of the IRA and awaits further guidance from the U.S. Treasury Department to properly assess the impact of these provisions on the Company.
The Company recorded a full valuation allowance against its U.S. net deferred tax assets. The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize the existing deferred tax assets. A significant piece of negative evidence evaluated was the U.S. pre-tax book cumulative loss incurred over the three-year period ended December 31, 2022. This cumulative loss was primarily the result of low commodity prices and oil and gas impairments during this period. Such objective evidence limits the ability to consider other subjective evidence, such as the Company’s projections for future growth.
However, given the Company’s current and anticipated future domestic earnings, the Company believes that there is a reasonable possibility that within the next 12 months the U.S. will exit its cumulative loss, allowing the Company to reach a conclusion that a material portion of the U.S. valuation allowance may no longer be needed. A release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense, which could be material for the period the release is recorded. For additional information regarding income taxes, refer to Note 11-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.
Potential Decommissioning Obligations on Sold Properties
The Company has potential exposure to future obligations related to divested properties. Apache 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, Apache could be required to perform such actions under applicable federal laws and regulations. In such event, Apache 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.
By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notification to BSEE. Apache expects to receive such orders on the other Legacy GOM Assets included in GOM Shelf’s notification letter. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.
If Apache incurs costs to decommission any Legacy GOM Asset and GOM Shelf does not reimburse Apache for such costs, then Apache expects to obtain reimbursement from Trust A, the Bonds, and the Letters of Credit until such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets.
If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be ordered by BSEE to perform, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to effectively use its available cash to fund the deficit.
As of December 31, 2022, Apache estimates that its potential liability to fund decommissioning of Legacy GOM Assets it may be ordered to perform ranges from $1.2 billion to $1.4 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $1.2 billion as of December 31, 2022, representing the estimated costs of decommissioning it may be required to perform on Legacy GOM Assets. Of the total liability recorded, $738 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $450 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued.
As of December 31, 2022, the Company has also recorded a $667 million asset, which represents the amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $217 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $450 million is reflected under “Other current assets.” The Company recognized $157 million and $446 million during 2022 and 2021, respectively, of “Losses on previously sold Gulf of Mexico properties” to reflect the net impact of changes to the estimated decommissioning liability and decommissioning asset to the Company’s statement of consolidated operations.
Insurance Program
The Company is covered by insurance 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, such 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 is covered by a 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 significant judgment involved in these engineering estimates, the Company’s reserves are used throughout its financial statements. For example, since the Company uses the units-of-production method to amortize its oil and gas properties, the quantity of reserves could significantly impact DD&A expense. A material adverse change in the estimated volumes of reserves could result in property impairments. Finally, these reserves are the basis for the Company’s supplemental oil and gas disclosures. For more information regarding the Company’s supplemental oil and gas disclosures, refer to Note 19-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 potential decommissioning obligations on sold properties estimated and recorded in the third quarter of 2021, please refer to “Potential Decommissioning Obligation on Sold Properties” above and in Note 12-Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part IV, Item 5 of this Annual Report on Form 10-K. Changes in significant assumptions impacting the Company’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued.
Impairment of Equity Method Interests
Equity method interests are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income.
Altus recorded an impairment charge on its equity method interest in the EPIC crude oil pipeline (EPIC) in the fourth quarter of 2021. The fair value of the impaired interest was determined using the income approach. The income approach considered estimates of future throughput volumes, tariff rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using a discount rate believed to be consistent with that which would be applied by market participants. The Company has classified this nonrecurring fair value measurement as Level 3 in the fair value hierarchy. Refer to Note 7-Equity Method Interests, within Part IV, Item 15 of this Annual Report on Form 10-K for further details of Altus’ equity method interests.
Long-Lived Asset Impairments
Long-lived assets used in operations, including proved oil and gas properties and GPT assets, are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication that the carrying amount of an asset group may not be recovered, the asset is assessed by management through an established process in which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is assessed by management using the income approach.
Under the income approach, the fair value of each asset group is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, the success of future exploration for and development of unproved reserves, expected throughput volumes for GPT assets, discount rates, and other variables. Key assumptions used in developing a discounted cash flow model described above include estimated quantities of crude oil and natural gas reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative, and capital costs adjusted for inflation. The Company discounts the resulting future cash flows using a discount rate believed to be consistent with those applied by market participants.
To assess the reasonableness of our fair value estimate, when available, management uses a market approach to compare the fair value to similar assets. This requires management to make certain judgments about the selection of comparable assets, recent comparable asset transactions, and transaction premiums.
Although the fair value estimate of each asset group is based on assumptions believed to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimate. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the asset group, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an additional impairment of long-lived assets in future periods.
Over the past several years, the Company has experienced substantial volatility in commodity prices, which impacted its future development plans and operating cash flows. As such, material impairments of certain proved oil and gas properties and gathering, processing, and transmission facilities were recorded in 2020. For discussion of these impairments, see “Fair Value Measurements” of Note 1-Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements.
Asset Retirement Obligation (ARO)
The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms in the North Sea and Gulf of Mexico. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.
ARO associated with retiring tangible long-lived assets is recognized as a liability in the period in which the legal obligation is incurred and becomes determinable. The liability is offset by a corresponding increase in the underlying asset. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.
Income Taxes
The Company’s oil and gas exploration and production operations are subject to taxation on income in numerous jurisdictions worldwide. The Company records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in its financial statements and tax returns. Management routinely assesses the ability to realize the Company’s deferred tax assets. If management concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices).
The Company regularly assesses and, if required, establishes accruals for uncertain tax positions that could result from assessments of additional tax by taxing jurisdictions in countries where the Company operates. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. These accruals for uncertain tax positions are subject to a significant amount of judgment and are reviewed and adjusted on a periodic basis in light of changing facts and circumstances considering the progress of ongoing tax audits, case law, and any new legislation. The Company believes that its accruals for uncertain tax positions are adequate in relation to the potential for any additional tax assessments.

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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. The Company continually monitors its market risk exposure, as oil and gas supply and demand are impacted by uncertainties in the commodity and financial markets associated with the conflict in Ukraine, global inflation, and other current events.
The Company’s average crude oil price realizations increased 44 percent to $99.39 per barrel in 2022 from $68.97 per barrel in 2021. The Company’s average natural gas price realizations increased 25 percent to $4.97 per Mcf in 2022 from $3.99 per Mcf in 2021. The Company’s average NGL price realizations increased 22 percent to $34.62 per barrel in 2022 from $28.48 per barrel in 2021. Based on average daily production for 2022, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $67 million, a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the year by approximately $31 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 $22 million.
Interest Rate Risk
At December 31, 2022, Apache had $4.9 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 5.32 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 its syndicated credit facilities. As of December 31, 2022, the Company had approximately $185 million in cash and cash equivalents, approximately 80 percent of which was invested in money market funds and short-term investments with major financial institutions. As of December 31, 2022, Apache had no borrowings outstanding under APA’s syndicated revolving credit facilities. 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 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, 2022.

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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, 2022, 2021, and 2020, 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, 2022, 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
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.
This Annual Report on Form 10-K does not include an attestation report of the Company’s independent registered public accounting firm on the Company’s internal control over financial reporting. As a non-accelerated filer, the management report called for by Item 308(a) of Regulation S-K is not subject to attestation by the Company’s independent registered public accounting firm.
Changes in Internal Control over Financial Reporting
There was no change in our internal controls over financial reporting during the quarter ending December 31, 2022, 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
This section has been omitted pursuant to General Instruction I(2)(c) of Form 10-K.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
This section has been omitted pursuant to General Instruction I(2)(c) of Form 10-K.

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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
This section has been omitted pursuant to General Instruction I(2)(c) of Form 10-K.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
This section has been omitted pursuant to General Instruction I(2)(c) of Form 10-K.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Accountant fees and services paid to Ernst & Young LLP, the Company’s independent auditors, are included in amounts paid by APA on behalf of Apache. Information on APA’s principal accountant fees and services is set forth under the caption “Ratification of Appointment of Independent Auditors” in the APA Proxy Statement 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)
Statement of consolidated operations for each of the three years in the period ended December 31, 2022
Statement of consolidated comprehensive income (loss) for each of the three years in the period ended December 31, 2022
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2022
Consolidated balance sheet as of December 31, 2022 and 2021
Statement of consolidated changes in equity (deficit) and noncontrolling interest for each of the three years in the period ended December 31, 2022
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 Registrant, APA Corporation, and APA Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-4300).
3.1 - Amended and Restated Certificate of Incorporation of Registrant, dated March 1, 2021, as attached as Annex A to the Certificate of Merger of APA Merger Sub, Inc. with and into Registrant, filed with the Secretary of State of the State of Delaware on March 1, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-4300).
3.2 - Certificate of Amendment of Amended and Restated Certificate of Incorporation of Registrant, dated June 7, 2021, filed with the Secretary of State of the State of Delaware on June 10, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed June 14, 2021, SEC File No. 001-4300).
3.3 - Amended and Restated Bylaws of Registrant, dated March 1, 2021 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-4300).
4.1 - Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, SEC File No. 001-4300).
4.2 - Form of 7.70% Notes due 2026 (incorporated by referenced to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, filed on February 23, 1996, SEC File No. 001-4300).
4.3 - Form of 7.95% Notes due 2026 (incorporated by referenced to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, filed on April 23, 1996, SEC File No. 001-4300).
4.4 - Form of 7.625% Debentures due 2096 (incorporated by referenced to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, filed on November 4, 1996, SEC File No. 001-4300).
4.5 - Form of 7.375% Debentures due 2047 (incorporated by referenced to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, filed on August 8, 1997, SEC File No. 001-4300).
4.6 - Form of 6.000% Notes due 2037 (incorporated by referenced to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, filed on January 26, 2007, SEC File No. 001-4300).
4.7 - Form of 5.250% Notes due 2042 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated November 30, 2010, filed on December 3, 2010, SEC File No. 001-4300).
4.8 - Form of 5.100% Notes due 2040 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated August 17, 2010, filed on August 20, 2010, SEC File No. 001-4300).
4.9 - Form of 4.75% Notes due 2043 (incorporated by reference to Exhibit 4.3 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.10 - Form of 4.250% Notes due 2044 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated November 28, 2012, filed on December 4, 2012, SEC File No. 001-4300).
4.11 - Form of 4.375% Notes due 2028 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, filed on August 16, 2018, SEC File No. 001-4300).
4.12 - Form of 4.250% Notes due 2030 (incorporated by referenced to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, filed on June 10, 2019, SEC File No. 001-4300).
4.13 - Form of 5.350% Notes due 2049 (incorporated by referenced to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, filed on June 10, 2019, SEC File No. 001-4300).
4.14 - Form of 4.625% Notes due 2025 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, filed on August 6, 2020, SEC File No. 001-4300).
4.15 - Form of 4.875% Notes due 2027 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, filed on August 6, 2020, SEC File No. 001-4300).
4.16 - Form of 7.75% Notes due December 15, 2029 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K/A, filed on December 14, 1999, SEC File No. 001-4300).
4.17 - Senior Indenture, dated February 15, 1996, between Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.6 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).
4.18 - First Supplemental Indenture to the Senior Indenture, dated as of November 5, 1996, between Registrant and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as trustee, governing the senior debt securities and guarantees (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement on Form S-3, dated May 23, 2003, Reg. No. 333-105536).
EXHIBIT
NO. DESCRIPTION
4.19 - Second Supplemental Indenture, dated as of December 16, 2019, among Apache Corporation and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank, formerly Chemical Bank), as trustee under Indenture, dated as of February 15, 1996, as previously amended and supplemented (incorporated by reference to Exhibit 4.15 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
4.20 - Form of Indenture among Registrant, Apache Finance Canada Corporation and The Bank of New York Mellon Trust Company, N.A. (formerly known as the Bank of New York Trust Company, N.A., as successor-in-interest to The Chase Manhattan Bank), as trustee, governing the debt securities and guarantees (incorporated by reference to Exhibit 4.1 to Amendment No. 1 to Registrant’s Registration Statement on Form S-3, dated November 12, 1999, Reg. No. 333-90147).
4.21 - Supplemental Indenture, dated as of August 14, 2017, among Apache Finance Canada Corporation, Apache Corporation, and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank), as trustee (incorporated by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q filed November 3, 2017, SEC File No. 001-04300).
4.22 - Second Supplemental Indenture, dated as of December 16, 2019, among Apache Corporation (as successor to Apache Finance Canada Corporation) and The Bank of New York Mellon Trust Company, N.A. (as successor to JPMorgan Chase Bank, N.A., formerly The Chase Manhattan Bank), as trustee under Indenture, dated as of November 23, 1999, as previously amended and supplemented (incorporated by reference to Exhibit 4.18 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
4.23 - Senior Indenture, dated May 19, 2011, between Registrant and Wells Fargo Bank, National Association, as trustee, governing the senior debt securities of Apache Corporation (incorporated by reference to Exhibit 4.14 to Registrant’s Registration Statement on Form S-3, dated May 23, 2011, Reg. No. 333-174429).
4.24 - Supplemental Indenture, dated as of December 16, 2019, among Apache Corporation and Wells Fargo Bank, National Association, as trustee under Indenture, dated as of May 19, 2011 (incorporated by reference to Exhibit 4.20 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
4.25 - Indenture, dated August 14, 2018, by and between Apache Corporation and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.5 to Registrant’s Post-Effective Amendment No. 1 to Registration Statement on Form S-3 filed August 14, 2018, SEC File No. 333-219345).
10.1 - Guaranty [USD Facility], dated as of April 29, 2022, made by Apache Corporation in favor of each of the lenders, issuing banks, and agents party to the Credit Agreement, dated as of April 29, 2022, among APA Corporation, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed May 2, 2022, SEC File No. 001-4300).
10.2 - Credit Agreement [USD Facility], dated as of April 29, 2022, among APA Corporation, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., as Syndication Agent, Royal Bank of Canada, HSBC Bank USA, National Association, MUFG Bank, Ltd., Wells Fargo Bank, National Association, Goldman Sachs Bank USA, The Toronto-Dominion Bank, New York Branch, The Bank of Nova Scotia, Houston Branch, Truist Bank, and Mizuho Bank, Ltd., as Co-Documentation Agents (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed May 2, 2022, SEC File No. 001-4300).
10.3 - Guaranty [GBP Facility], dated as of April 29, 2022, made by Apache Corporation in favor of each of the lenders, issuing banks, and agents party to the Credit Agreement, dated as of April 29, 2022, among APA Corporation, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the other agents party thereto (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed May 2, 2022, SEC File No. 001-4300).
10.4 - Credit Agreement [GBP Facility], dated as of April 29, 2022, among APA Corporation, the lenders party thereto, the issuing banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, The Toronto-Dominion Bank, London Branch, as Syndication Agent, Bank of America, N.A., Royal Bank of Canada, HSBC Bank USA, National Association, MUFG Bank, Ltd., Wells Fargo Bank, N.A. London Branch, Goldman Sachs Bank USA, The Bank of Nova Scotia, Houston Branch, Truist Bank, and Mizuho Bank, Ltd., as Co-Documentation Agents (incorporated by reference to Exhibit 10.4 to Registrant’s Current Report on Form 8-K filed May 2, 2022, SEC File No. 001-4300).
†10.5 - Non-Qualified Retirement/Savings Plan of Apache Corporation, as amended and restated, dated July 16, 2014, effective January 1, 2015 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.6 - Amendment to Non-Qualified Retirement/Savings Plan of Apache Corporation, dated August 12, 2020, effective August 1, 2020 (incorporated by reference to Exhibit 10.1 to Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, SEC File No. 001-4300).
EXHIBIT
NO. DESCRIPTION
†10.7 - Amendment to Apache Corporation Non-Qualified Retirement/Savings Plan, dated March 1, 2021 (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-4300).
†10.8 - Non-Qualified Restorative Retirement Savings Plan of Apache Corporation, as amended and restated, dated July 16, 2014, effective January 1, 2015 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.9 - Amendment to Apache Corporation Non-Qualified Restorative Retirement Savings Plan, dated March 1, 2021 (incorporated by reference to Exhibit 10.4 to Registrant’s Current Report on Form 8-K filed March 1, 2021, SEC File No. 001-4300).
*23.1 - 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.