EDGAR 10-K Filing

Company CIK: 6769
Filing Year: 2021
Filename: 6769_10-K_2021_0001673379-21-000007.json

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ITEM 1. BUSINESS
ITEMS 1 and 2. BUSINESS AND PROPERTIES
GENERAL
Apache Corporation, a Delaware corporation formed in 1954, 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). Apache also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. Apache’s midstream business is operated by Altus Midstream Company (Nasdaq: ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas.
On January 4, 2021, Apache announced that its Board of Directors authorized the Company to proceed with the implementation of a holding company reorganization, in connection with which, Apache will create APA Corporation, a new holding company (APA). Upon completion of the holding company reorganization, Apache will be a wholly-owned subsidiary of APA, APA will be the successor issuer to Apache pursuant to Rule 12g-3(a) under the Exchange Act, and APA will replace Apache as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA” (the Holding Company Reorganization). The Holding Company Reorganization has not yet been implemented, but it is expected to be completed during the first half of 2021. Further details of the planned Holding Company Reorganization are included in the Company’s Current Report on Form 8-K filed with the SEC on January 4, 2021.
The Company’s common stock, par value $0.625 per share, is listed on the Nasdaq Global Select Market (Nasdaq). Through the Company’s website, www.apachecorp.com, you can access, free of charge, electronic copies of the charters of the committees of its Board of Directors, other documents related to corporate governance (including the Code of Business Conduct and Ethics and Apache’s Corporate Governance Principles), and documents the Company files with the SEC, including the Company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, and Current Reports on Form 8-K, as well as any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act. Included in the Company’s annual and quarterly reports are the certifications of its principal executive officer and its principal financial officer that are required by applicable laws and regulations. Access to these electronic filings is available as soon as reasonably practicable after the Company files such material with, or furnishes it to, the SEC. You may also request printed copies of the Company’s corporate charter, bylaws, committee charters, or other governance documents free of charge by writing to the Company’s corporate secretary at the address on the cover of this report. The Company’s reports filed with the SEC are made available on its website at www.sec.gov. From time to time, the Company also posts announcements, updates, and investor information on its website in addition to copies of all recent press releases. Information on the Company’s website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.
Certain properties referred to herein may be held by subsidiaries of Apache Corporation.
BUSINESS STRATEGY
Our VISION is to be the premier exploration and production company, contributing to global progress by helping meet the world’s energy needs.
Our MISSION is to grow in an innovative, safe, environmentally responsible, and profitable manner for the long-term benefit of our stakeholders.
Our STRATEGY is to take a differentiated approach to the exploration and production of cost-advantaged hydrocarbons through innovation, technology, optimization, continuous improvement, and relentless focus on costs to deliver top-tier, long-term returns.
Rigorous management of the Company’s asset portfolio plays a key role in optimizing shareholder value over the long term. Over the past several years, Apache has entered into a series of transactions that have upgraded its portfolio of assets, enhanced its capital allocation process to further optimize investment returns, and increased focus on internally generated exploration with full-cycle, returns-focused growth. These efforts included the monetization of certain non-strategic assets, including gas-weighted properties in the Midcontinent/Gulf Coast region and selling other non-core leasehold positions. The Company made strategic decisions to allocate the proceeds of these divestitures to more impactful development opportunities across its portfolio and exploration efforts in Suriname. In addition, in November 2018, the Company completed a transaction with Altus Midstream Company and its then wholly-owned subsidiary, Altus Midstream LP, to create a publicly-traded midstream C-corporation.
Apache’s U.S. upstream oil and gas assets are complemented by its international assets in Egypt and the North Sea, each of which adds to the Company’s inventory of exploration and development opportunities. Apache’s diverse international portfolio and asset inventory includes, at scale, both conventional and unconventional resources covering crude oil, rich natural gas with NGLs, and lean natural gas.
During 2020, the global economy and the energy industry were deeply impacted by the effects of the COVID-19 pandemic and related third-party actions. Uncertainty in the oil markets and the negative demand implications resulting from the COVID-19 pandemic continue to weigh on commodity prices. As with previous changes in a volatile price environment, Apache has continued to respond quickly and decisively, taking the following strategic actions:
•Establishing and implementing a wide range of fit-for-purpose protocols and procedures to ensure a safe and productive work environment across the Company’s diversified global onshore and offshore operations.
•Reducing upstream capital investments by over 50 percent from the comparative prior-year period, including eliminating nearly all U.S. drilling and completion activity by May 2020 and reducing planned activity in Egypt and the North Sea.
•Decreasing the Company’s dividend by 90 percent beginning in the first quarter of 2020, preserving approximately $340 million of cash flow on an annualized basis and strengthening liquidity.
•Completing an organizational redesign focused on centralizing certain operational activities in an effort to capture greater efficiencies, achieving an estimated cost savings of $400 million annually.
•Conducting, on a continuous basis, price sensitivity analyses and operational evaluations of producing wells across the Company’s portfolio that allow for a methodical and integrated approach to production shut-ins and curtailments with a focus on preserving cash flows in a distressed price environment and protecting the Company’s assets.
The Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of ongoing exploration and appraisal activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate excess cash flow that can be directed on a priority basis to debt reduction.
For a more in-depth discussion of the Company’s 2020 results, divestitures, strategy, and its capital resources and liquidity, please see Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K.
BUSINESS OVERVIEW
The following business overview further describes the operations and activities for the Company’s upstream exploration and production properties, by geographic region, and Altus Midstream.
UPSTREAM EXPLORATION AND PRODUCTION
Operating Areas
Apache has exploration and production operations in three geographic areas: the U.S., Egypt, and the North Sea. Apache also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. During 2020, as a result of the Company’s organizational redesign, Apache shifted from a region-based structure to a centralized structure focused on core asset groups and functions in each country.
The following table sets out a brief comparative summary of certain key 2020 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 93.7 58 % $ 1,764 587 67 % 60 59
Egypt(1)
44.6 28 % 1,390 178 20 % 61 54
North Sea(2)
22.6 14 % 883 109 13 % 8 6
Other International - - - - - 3 -
Total 160.9 100 % $ 4,037 874 100 % 132 119
(1)Apache’s operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 20 percent of 2020 production and accounted for 15 percent of year-end estimated proved reserves.
(2)Sales volumes from the North Sea for 2020 were 22.7 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.
United States
In 2020, Apache’s U.S. upstream oil and gas operations contributed approximately 58 percent of production and 67 percent of estimated year-end proved reserves. Apache has access to significant liquid hydrocarbons across its 4.9 million gross acres (2.5 million net acres) in the U.S., 78 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 more than 7,000 gross oil and gas wells across its acreage, with additional interests in over 4,000 non-operated wells. 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 and along the Gulf of Mexico, in the areas onshore and offshore south Texas and Louisiana.
Highlights of the Company’s operations in the U.S. include:
•Southern Midland Basin Apache holds approximately 360,000 gross acres (256,000 net acres) in the Southern Midland Basin. The Company began the year operating four rigs but suspended drilling and completion activity in May in response to collapsing commodity prices. During 2020, the Company averaged one rig targeting oil plays in the Wolfcamp, Spraberry, and lower Cline formations, drilling 33 gross development wells in this basin with a 100 percent success rate.
•Delaware Basin Apache holds approximately 370,000 gross acres (220,000 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. The Company began the year operating three rigs but suspended drilling in May. During 2020, the Company averaged one rig drilling 19 gross development wells with a 95 percent success rate, primarily targeting oil plays in the Bone Spring formation.
•Legacy Assets Apache holds approximately 3.6 million gross acres (1.7 million net acres) in legacy properties, primarily in the Central Basin Platform sub-basin of the Permian Basin, the Eagle Ford shale and Austin Chalk areas of southeast Texas, and in the offshore waters of the Gulf of Mexico and onshore Louisiana. The Company participated in drilling eight gross non-operated development wells in these areas during 2020. Although operated drilling activity was minimal during 2020, the Company continued to evaluate and high-grade inventory opportunities on its Austin Chalk acreage. The Company also monetized certain non-strategic leasehold positions on its legacy acreage holdings during the year and is continuing to evaluate additional opportunities.
•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.
With the improvement in oil prices, the Company is returning to a modest level of activity in the U.S. For 2021, the Company is currently running one drilling rig in the Permian Basin and plans to add a second rig in the middle of the year. In addition, the Company recently added a rig in the Austin Chalk oil play to retain core acreage positions and perform targeted tests. The Company also resumed completions activity in the Permian Basin during the fourth quarter of 2020 and began completing previously drilled but uncompleted wells in response to significantly lower service costs. As with prior periods, the Company will continue to monitor commodity prices and will adjust its capital budget accordingly to protect its cash flows.
U.S. Marketing In general, most of the Company’s U.S. natural gas production is sold at either monthly or daily index-based prices. The tenor of the Company’s sales contracts span from daily to multi-year transactions. Natural gas is sold to a variety of customers that include local distribution, utility, and midstream companies as well as end-users, marketers, and integrated major oil companies. Apache strives to maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk. Apache predominantly sells its natural gas production within the United States, including to U.S. LNG export facilities, although a portion is sold to markets in Mexico.
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), or WTI 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, which require Apache to deliver an average of 232 Bcf of natural gas per year for the period from 2021 through 2029 at variable, market-based pricing and deliver an average of 6.8 MMbbls of crude oil per year from 2020 through 2025 at variable, market-based pricing.
Apache currently expects to fulfill its delivery commitments with production from its proved reserves, production from continued development and/or spot market purchases as necessary. 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 2020, international assets contributed 42 percent of Apache’s production and 56 percent of 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 United Kingdom.
The Company also has an active offshore exploration program and planned appraisal operations ongoing in Suriname.
Egypt Apache has 25 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 2020, the Company held 5.2 million gross acres in 24 separate concessions. 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 contractor partner (Contractor) 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 Egyptian General Petroleum Corporation (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 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.
The Company’s estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country’s share of reserves. In addition, Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in Apache’s oil and gas operations in Egypt. Apache’s Egypt assets, including the one-third noncontrolling interest, contributed 28 percent of 2020 production and 20 percent of year-end estimated proved reserves. Excluding the impacts of the noncontrolling interest, Egypt contributed 20 percent of 2020 production and 15 percent of year-end estimated proved reserves.
In 2020, the Company drilled 36 gross development and 25 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 over 3 million acres to date and continues to build and enhance its drilling inventory in Egypt, supplemented with recent seismic acquisitions and new play concept evaluations, on both new and existing acreage.
For 2021, the Company plans to continue running a five rig drilling program for the year with a goal of stabilizing production and ultimately return Egypt to growth, both of which would require additional rigs. Apache is positioned to quickly flex spending in Egypt as conditions warrant and will continue to monitor oil prices and cash flow for the appropriate time to pursue increased activity.
North Sea Apache has interests in approximately 516,000 gross acres in the U.K. North Sea. These assets contributed 14 percent of Apache’s 2020 production and approximately 13 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 the 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. The North Sea assets plays a strategic role in Apache’s portfolio by providing competitive investment opportunities and potential reserve upside with high-impact exploration potential, near existing infrastructure.
During 2020, Apache averaged two rigs in the North Sea and drilled 6 gross development and two gross exploration wells.
The Company’s Storr exploration discovery came on-line in the fourth quarter of 2019, and its second well at Garten came on-line in the first quarter of 2020. The first well at the Company’s Storr development is a high-rate gas condensate well that is tied back to existing infrastructure at the Beryl Alpha platform. The Garten #2 well encountered approximately 1,200 feet of net pay, and Apache holds a 100 percent working interest in the Garten complex. Both of these exploration discoveries coming on-line, coupled with the modest drilling activity level for the year, increased the Company’s production in the North Sea compared to 2019.
In 2021, the expected capital program for the North Sea remains relatively unchanged to the prior year with one floating rig and one platform crew.
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.
Other Exploration
New Ventures Apache’s international New Ventures team provides exposure to new growth opportunities by looking outside of the Company’s traditional core areas and targeting higher-risk, higher-reward exploration opportunities located in frontier basins as well as new plays in more mature basins.
In December 2019, Apache entered into a joint venture agreement with Total S.A. to explore and develop Block 58 offshore Suriname. The Company holds a 50 percent working interest in Block 58, which comprises approximately 1.4 million gross acres in water depths ranging from less than 100 meters to more than 2,100 meters. Starting in late 2019 and throughout 2020, Apache drilled the first three wells in the block, the Maka Central-1, Sapakara West-1, and Kwaskwasi-1, all of which successfully tested for the presence of hydrocarbons in multiple stacked targets in the upper Cretaceous-aged Campanian and Santonian intervals, encountering both oil and gas condensate.
In January 2021, Apache and Total S.A announced the fourth consecutive discovery in Block 58 at Keskesi East-1, which confirmed oil in the eastern portion of the block. The Keskesi East-1 well is continuing to drill to deeper targets. In accordance with the joint venture agreement, Apache transferred operatorship of Block 58 to Total S.A. on January 1, 2021. Apache will continue to operate the Keskesi exploration well until completion of drilling operations.
Drilling Statistics
Worldwide in 2020, Apache drilled or participated in drilling 132 gross wells, with 119 wells (90 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, at year-end a number of wells had not yet reached completion: 80 gross (63.1 net) in the U.S., 24 gross (23.5 net) in Egypt, 1 gross (1 net) in the North Sea, and 1 gross (0.5 net) in Suriname.
The following table shows the results of the oil and gas wells drilled and completed for each of the last three fiscal years:
Net Exploratory Net Development Total Net Wells
Productive Dry Total Productive Dry Total Productive Dry Total
United States - - - 46.3 0.8 47.1 46.3 0.8 47.1
Egypt 17.7 7.0 24.7 35.7 - 35.7 53.4 7.0 60.4
North Sea 0.6 1.0 1.6 4.2 0.6 4.8 4.8 1.6 6.4
Other International - 1.5 1.5 - - - - 1.5 1.5
Total 18.3 9.5 27.8 86.2 1.4 87.6 104.5 10.9 115.4
United States 6.3 - 6.3 181.0 - 181.0 187.3 - 187.3
Egypt 8.5 13.5 22.0 37.2 1.5 38.7 45.7 15.0 60.7
North Sea - - - 8.4 - 8.4 8.4 - 8.4
Total 14.8 13.5 28.3 226.6 1.5 228.1 241.4 15.0 256.4
United States 47.6 5.3 52.9 188.9 2.0 190.9 236.5 7.3 243.8
Egypt 28.2 12.5 40.7 57.9 0.5 58.4 86.1 13.0 99.1
North Sea 1.0 0.5 1.5 6.3 - 6.3 7.3 0.5 7.8
Total 76.8 18.3 95.1 253.1 2.5 255.6 329.9 20.8 350.7
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, 2020, is set forth below:
Oil Gas Total
Gross Net Gross Net Gross Net
United States 11,377 6,627 1,135 799 12,512 7,426
Egypt 1,069 1,015 111 108 1,180 1,123
North Sea 163 122 12 7 175 129
Total 12,609 7,764 1,258 914 13,867 8,678
Domestic 11,377 6,627 1,135 799 12,512 7,426
Foreign 1,232 1,137 123 115 1,355 1,252
Total 12,609 7,764 1,258 914 13,867 8,678
Gross natural gas and crude oil wells include 558 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 32.3 27.1 205.6 $ 7.39 $ 37.42 $ 11.21 $ 1.22
Egypt(1)
27.6 0.3 100.4 10.35 39.95 27.83 2.79
North Sea(2)
18.4 0.7 21.0 15.60 42.88 29.73 3.19
Total 78.3 28.1 327.0 9.37 39.60 11.84 1.83
United States 38.3 25.0 233.5 $ 9.24 $ 54.71 $ 14.95 $ 1.26
Egypt(1)
30.9 0.3 104.4 10.77 63.76 33.87 2.83
North Sea(2)
18.2 0.6 19.9 16.75 65.10 36.83 4.48
Total 87.4 25.9 357.8 10.62 60.05 15.74 1.90
United States 38.3 21.0 216.5 $ 10.01 $ 59.36 $ 26.28 $ 2.12
Egypt(1)
34.2 0.3 119.3 8.71 70.09 39.17 2.84
North Sea(2)
17.1 0.4 16.6 18.92 69.02 45.84 7.33
Total 89.6 21.7 352.4 10.66 65.30 26.87 2.61
(1)Includes production volumes attributable to a one-third noncontrolling interest in Egypt.
(2)Sales volumes from the North Sea for 2020, 2019, and 2018 were 22.7 MMboe, 21.8 MMboe, and 20.3 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, 2020:
Undeveloped Acreage Developed Acreage
Gross Acres Net Acres Gross Acres Net Acres
(In thousands)
United States 3,818 1,808 1,064 656
Egypt 3,495 3,495 1,658 1,569
North Sea 331 301 185 139
Other International 2,308 1,111 - -
Total 9,952 6,715 2,907 2,364
As of December 31, 2020, approximately 46 percent of U.S. net undeveloped acreage was held by production.
As of December 31, 2020, Apache held 1.5 million net undeveloped acres that are scheduled to expire by year-end 2021 if production is not established or the Company takes no action to extend the terms. The Company also held 533,000 and 408,000 net undeveloped acres set to expire by year-end 2022 and 2023, 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.
Exploration concessions in the Company’s Egypt asset comprise a significant portion of its expiring net undeveloped acreage, with approximately 1.3 million, 74,000 and 343,000 net undeveloped acres set to expire during 2021, 2022, and 2023, respectively. No oil and gas reserves were recorded on this undeveloped acreage set to expire. The Company will continue to pursue acreage extensions and access to new concessions in areas in which it believes exploration opportunities exist.
Additionally, the Company has exploration interests in Suriname consisting of 390,000 net undeveloped acres in Block 53 set to expire in 2022 contingent on planned drilling activity. The Company has acquired 3-D seismic surveys over all acreages. No oil and gas reserves have been recorded on this undeveloped acreage.
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, 2020, based on average commodity prices in effect on the first day of each month in 2020, 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 207 151 1,053 533
Egypt(1)
96 1 409 165
North Sea 87 2 68 100
Total 390 154 1,530 798
Proved Undeveloped:
United States 26 15 76 54
Egypt(1)
11 - 13 13
North Sea 7 - 8 9
Total 44 15 97 76
Total Proved 434 169 1,627 874
(1)Includes total proved developed and total proved undeveloped reserves of 55 MMboe and 4 MMboe, respectively, attributable to a one-third noncontrolling interest in Egypt.
As of December 31, 2020, Apache had total estimated proved reserves of 434 MMbbls of crude oil, 169 MMbbls of NGLs, and 1.6 Tcf of natural gas. Combined, these total estimated proved reserves are the volume equivalent of 874 million barrels of oil or 5.2 Tcf of natural gas, of which oil represents 50 percent. As of December 31, 2020, the Company’s proved developed reserves totaled 798 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 does not have any fields that contain 15 percent or more of its total proved reserves for the years ended December 31, 2020, 2019, and 2018.
During 2020, the Company added 78 MMboe of proved reserves through exploration and development activity, partially offset by combined downward revisions of previously estimated reserves of 45 MMboe. Engineering and performance upward revisions accounted for 27 MMboe and downward revisions related to changes in product prices and interest accounted for (70) MMboe and 2 MMboe, respectively. The Company also sold 10 MMboe of proved reserves associated with U.S. divestitures, primarily related to Eastern Shelf and Magnet Withers/Pickett Ridge.
The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2020, 2019, and 2018, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 18-Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K. Estimated future net cash flows were calculated using a discount rate of 10 percent per annum, end of period costs, and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.
Proved Undeveloped Reserves
The Company’s total estimated PUD reserves of 76 MMboe as of December 31, 2020, decreased by 42 MMboe from 118 MMboe of PUD reserves reported at the end of 2019. During the year, Apache converted 35 MMboe of PUD reserves to proved developed reserves through development drilling activity. In the U.S., Apache converted 25 MMboe, with the remaining 10 MMboe in Apache’s international areas. Apache did not sell any PUD reserves in the U.S. and did not acquire any PUD reserves during the year. Apache added 43 MMboe of new PUD reserves through extensions and discoveries. Apache did not recognize an upward engineering revision in proved undeveloped reserves during the year. Downward revisions included 1 MMboe associated with engineering and interest revisions, 43 MMboe associated with revised development plans, and 6 MMboe associated with product prices.
During the year, a total of approximately $339 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 2020, Apache spent approximately $251 million on PUD reserve development activity in the U.S. and $88 million in the international areas. As of December 31, 2020, 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 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 our processes and the reasonableness of our 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 2020, the properties selected for each country ranged from 84 to 86 percent of the total future net cash flows discounted at 10 percent. These properties also accounted for 84 percent of the value of Apache’s international proved reserves and 94 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 81 percent of total proved reserves on a boe basis.
Ryder Scott’s review for the years 2020, 2019, and 2018 covered 85, 87, and 86 percent, respectively, of the value and 81, 85, and 83 percent, respectively, of the volume of the Company’s worldwide estimated proved reserves. Ryder Scott’s 2020 review covered 80, 82, and 83 percent of the estimated proved reserve volume in the U.S., Egypt, and U.K., respectively.
Ryder Scott’s review of 2019 covered 85 percent of U.S., 86 percent of Egypt, and 80 percent of the U.K.’s total proved reserves.
Ryder Scott’s review of 2018 covered 82 percent of U.S., 85 percent of Egypt, and 81 percent of the U.K.’s total proved reserves.
The Company has filed Ryder Scott’s independent report as an exhibit to this Annual Report on Form 10-K.
According to Ryder Scott’s opinion, based on their review, including the data, technical processes, and interpretations presented by 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 completed a transaction with Altus Midstream Company and its then wholly-owned subsidiary Altus Midstream LP (collectively, Altus) 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 contributed certain Alpine High midstream assets and options (the Pipeline Options) to acquire equity interests in five separate third-party pipeline projects (the Equity Method Interest Pipelines) to Altus Midstream LP and/or its subsidiaries. In exchange for the assets, Apache received economic voting and non-economic voting shares in Altus Midstream Company and limited partner interests in Altus Midstream LP, representing an approximate 79 percent ownership interest in the combined entities.
Apache fully consolidates the assets and liabilities of Altus in its consolidated financial statements, with a corresponding noncontrolling interest reflected separately.
Gathering, Processing, and Transmission Assets
Altus owns, develops, and operates gas gathering, processing, and transmission assets in the Permian Basin of West Texas. Altus generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services for Apache’s production from its Alpine High resource play. As of December 31, 2020, Altus’ assets included approximately 182 miles of in-service natural gas gathering pipelines, approximately 46 miles of residue-gas pipelines with four market connections, and approximately 38 miles of NGL pipelines. Three cryogenic processing trains, each with nameplate capacity of 200 MMcf/d, were placed into service during 2019. Other assets include an NGL truck loading terminal with six Lease Automatic Custody Transfer units and eight NGL bullet tanks with 90,000 gallon capacity per tank. Altus’ existing gathering, processing, and transmission infrastructure is expected to provide capacity levels capable of fulfilling its midstream contracts to service Apache’s production from Alpine High and third-party customers as market activity in the area continues to develop.
Pipeline Options and Equity Method Interest Pipelines
Gulf Coast Express Pipeline In December 2018, Altus Midstream LP closed on the exercise of its Pipeline Option with Kinder Morgan Texas Pipeline LLC (Kinder Morgan), thereby acquiring a 15 percent equity interest in the Gulf Coast Express Pipeline Project (GCX). Altus Midstream LP acquired an additional 1 percent equity interest in May 2019, for a total 16 percent equity interest in GCX. GCX is a long-haul natural gas pipeline with capacity of approximately 2.0 Bcf/d and transports natural gas from the Waha area in northern Pecos County, Texas to the Agua Dulce Hub near the Texas Gulf Coast. GCX is operated by Kinder Morgan and was placed into service in September 2019.
EPIC Crude Oil Pipeline In March 2019, Altus Midstream LP’s subsidiary closed on the exercise of its Pipeline Option with EPIC Pipeline LP, thereby acquiring a 15 percent equity interest in the EPIC crude oil pipeline (EPIC). The long-haul crude oil pipeline extends from the Orla area in northern Reeves County, Texas to the Port of Corpus Christi, Texas, and has Permian Basin initial throughput capacity of approximately 600 MBbl/d. The project includes terminals in Orla, Pecos, Crane, Wink, Midland, Hobson, and Gardendale, Texas with Port of Corpus Christi connectivity and export access. It services Delaware Basin, Midland Basin, and Eagle Ford Shale production. EPIC is operated by EPIC Consolidated Operations, LLC and was placed into service in February 2020.
Permian Highway Pipeline In May 2019, Altus Midstream LP’s subsidiary closed on the exercise of its Pipeline Option with Kinder Morgan, thereby acquiring an approximate 26.7 percent equity interest in the Permian Highway Pipeline (PHP). The long-haul natural gas pipeline has capacity of approximately 2.1 Bcf/d and transports natural gas from the Waha area in northern Pecos County, Texas to the Katy, Texas area with connections to U.S. Gulf Coast and Mexico markets. PHP, which is operated by Kinder Morgan, was in the commissioning phase and flowing partial volumes as of December 31, 2020 and was placed into service in January 2021.
Shin Oak NGL Pipeline In July 2019, Altus Midstream LP’s subsidiary closed on the exercise of its Pipeline Option with Enterprise Products Operating LLC (Enterprise Products), thereby acquiring a 33 percent equity interest in Breviloba LLC, which owns the Shin Oak NGL Pipeline (Shin Oak). The long-haul NGL pipeline has capacity of up to 550 MBbl/d and transports NGL production from the Orla area in northern Reeves County, Texas through the Waha area in northern Pecos County, Texas, and on to Mont Belvieu, Texas. Shin Oak is operated by Enterprise Products and was placed into service during 2019.
Salt Creek NGL Pipeline Altus Midstream LP’s subsidiary’s final Pipeline Option to acquire a 50 percent equity interest in the Salt Creek NGL Pipeline, an intra-basin NGL pipeline, was not exercised and expired on March 2, 2020.
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 2020, sales to EGPC and Vitol accounted for approximately 17 percent and 14 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2019, sales to BP and Sinopec, and their respective affiliates, each accounted for approximately 10 percent and 11 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2018, sales to BP, Sinopec, and EGPC, and their respective affiliates, each accounted for approximately 17 percent, 15 percent, and 10 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues.
Management does not believe that the loss of any one of these customers would have a material adverse effect on the results of operations.
HUMAN CAPITAL MANAGEMENT
As a company, Apache believes its people are its greatest asset. Exploring what’s possible at Apache is the union of curiosity, intellect, and hard work, built on mutual respect, honesty, integrity, and a keen sense of responsibility for the Company’s team, community, and the environment. With respect to its employees, the Company is focused on health and safety, diversity and inclusion, and total rewards, so that joining the Apache family is a positive experience for all.
In 2020, a major redesign of Apache’s organizational structure and operations and the global COVID-19 pandemic had significant impacts on the Company’s human capital management. In connection with the organizational and operational redesign and changes in the economic environment in which Apache operates, the Company offered voluntary retirement packages, made reductions-in-force, and began limiting hiring to critical business roles. In response to the global COVID-19 pandemic, Apache implemented significant operating environment changes that the Company determined were in the best interest of its employees and complied with government regulations. These changes include having the vast majority of Apache’s employees working from home, while implementing additional safety protocols and procedures for essential employees continuing critical on-site work.
Oversight and Management
Apache’s Board of Directors has three standing committees, each devoted to a separate aspect of risk oversight. The Corporate Governance and Nominating (CG&N) Committee, the Audit Committee, the Management Development and Compensation (MD&C) Committee, and/or the full Board of Directors receive regular reports on certain human capital matters, including the Company’s diversity and inclusion programs and initiatives.
•The MD&C Committee oversees Apache's compensation programs, leadership development and succession planning strategies, and seeks continuous improvement in the diversity and inclusion practices used in developing and deploying these processes.
•The Audit Committee oversees the integrity of the Company's financial statements and monitors human capital management risk against compliance with legal and regulatory requirements.
•The CG&N Committee oversees the nomination of candidates for election to the Board of Directors, the annual Board of Directors evaluation process, corporate governance and environmental, social, and governance (ESG) issues, as well as the Company’s annual sustainability report.
Reports and recommendations made to the Board of Directors and its committees are part of the framework that ensures the Company’s daily actions and decisions are guided by its core values, including upholding the health and safety of Apache’s team, stakeholders, and communities, investing in its workforce, ensuring environmental responsibility, and acting ethically and with integrity.
COVID-19 Response
During the early stages of the pandemic, Apache called upon its Crisis Management Team to lead and coordinate the Company's overall COVID-19 pandemic response. This team led efforts to develop and monitor mitigation and business continuity plans, track all relevant country, state and local government guidelines, directives and regulations, develop and adopt work-from-home plans, implement safe working protocols for production teams, assess and implement appropriate return-to-office protocols, and provide timely and transparent communications to global employees and key stakeholders.
In response to the COVID-19 pandemic, Apache began providing the following benefits to its employees:
•Covering the cost of COVID-19 testing at the Company’s onsite testing events and through expanded insurance coverage;
•Expanding telehealth benefits;
•Promoting mental health and well-being plans;
•Implementing enhanced hardship distributions and loan eligibility and repayment terms in the Apache 401(k) Savings Plan; and
•Providing additional paid sick leave for quarantined employees.
Employee Profile
As of December 31, 2020, Apache had approximately 2,272 full-time equivalent employees in locations across the organization as follows:
Employees
United States 1,430
United Kingdom 598
Egypt 237
Suriname 7
Total employees 2,272
The employment of approximately 637 employees globally were impacted by involuntary reductions-in-force in 2020. The impacted employees were provided severance packages that included Company-paid benefits and outplacement services. The voluntary workforce turnover for 2020 was 9.6 percent.
As of year-end 2020, Apache’s global workforce was 22.1 percent female and 77.9 percent male, and women represented 17.6 percent of leadership (defined as supervisor level and above or equivalent). In the U.S., Apache’s workforce self-identified as 66.9 percent White, 6 percent Black, 6.8 percent Asian, 18.6 percent Hispanic, and 1.7 percent other. For the Company’s U.S. leadership, the breakdown was 78 percent White, 3 percent Black, 6.3 percent Asian, 11.3 percent Hispanic, and 1.4 percent other.
Health and Safety
Safety underpins the Company’s core values and is at the forefront of decision-making at every level of the Apache organization. Apache is committed to driving a safety culture that empowers its team to act as needed to work safely and to stop the job if conditions are deemed unsafe. Apache’s goal is to demonstrate a continual reduction in Occupational Safety and Health Administration (OSHA) recordable incidents year over year. To this end, the Company’s annual OSHA recordable incident rate targets are set at a 10 percent reduction compared to the preceding 3-year average. During the fiscal year ended December 31, 2020, the recordable incident count for the Company declined by 21 percent compared to the fiscal year ended December 31, 2019.
Apache offers a wide range of training programs for employees and contractors to promote their full understanding of, and compliance with, the Company’s health and safety policies and programs and to help build the skills needed to work safely. In addition to providing specific skills, these training programs encourage personal responsibility for safe operating conditions and help build a culture of individual accountability for conducting job tasks in a safe and responsible manner.
A few key highlights from 2020:
•Egypt From drilling to driving, safe-work behavior improved dramatically. The joint-venture drilling team had 55 percent fewer injuries in the second half of 2020 as compared to the first half of 2020.
•Suriname With the complexities of working during the pandemic, stringent health and safety protocols have kept personnel safe as they rotate offshore. Rewarding excellence, the drilling team and Noble Sam Croft drillship achieved one year without any recordable incidents.
•U.K. In an effort to connect teams with management, Apache’s elected safety representatives have increased workforce engagement around offshore operations and safety. New platform meetings put safety at the forefront of conversations about performance, accidents and hazards, industry updates, and valuable topics such as mental health.
•U.S. Despite economic pressures and pandemic challenges, U.S. onshore operations and asset teams performed exceptionally. The Southern Midland Basin, Legacy, and Delaware Basin collectively achieved over 800 days without injuries.
Diversity and Inclusion
Diversity and inclusion (D&I) are vital to Apache’s long-term sustainability. The Company is committed to being a workplace where all employees are valued and can thrive with a sense of belonging, not just as an employee, but as a person. This benefits the individual, Apache and the Company’s stakeholders. Apache is better as an organization when various ideas and perspectives are brought to the table. As a part of the Company’s commitment to diversity and inclusion, in August 2020, Apache hired a D&I Lead and partnered with a prominent D&I consultant to better understand where the organization stands in its D&I efforts and to build a D&I strategy that directly supports the Company’s diversity and inclusion goals. To further the Company’s strategy, Apache conducted focus group sessions to gain insight into its employees’ experiences and to better understand its D&I strengths and opportunities. With this feedback in mind, Apache evaluated its recruiting, talent management, and learning efforts to identify and implement changes that would allow for increased employee opportunities, belonging, and workplace diversity.
To showcase a visible commitment, Apache launched a Diversity & Inclusion employee site that provides D&I and allyship trainings and information on how to join and initiate Employee Resource Groups (ERG). Apache currently has four ERGs: the Apache Women’s Network (AWN), Apache Young Professionals’ Network (AYPN), Apache D&I Council, and the newly formed Apache Black Professionals Network (ABPN). These groups encourage cultural awareness, professional development, community outreach, and networking. The Company looks forward to expanding its ERGs to help build employee connections and belonging, support Apache’s community outreach programs, and foster career development. Over the years to come, Apache will continue to actively support employees in forming additional demographic-based groups (e.g., ethnicity, nationality, age, sexual orientation, etc.), as well as interest-based groups (e.g., support, sports, hobbies, etc.).
Apache embraces the idea of continuous improvement in all that it does, and its D&I journey is no different. The Company is committed to continually improving and making changes throughout the organization to foster a more inclusive and diverse workforce.
Total Rewards
Apache’s total rewards are designed to attract, retain, and reward top talent. As part of its compensation philosophy, Apache offers and maintains a robust total compensation package that includes a competitive base salary, industry-leading benefits, and performance-driven incentives. The Company believes that a compensation program with both short-term and long-term incentives provides fair and competitive compensation and aligns employee and stockholder interests. Apache’s incentive compensation programs reward Company and individual performance by incorporating metrics related to Apache’s operations, financial, ESG, and workforce safety initiatives.
In addition to cash and equity compensation, the Company also promotes employee benefits that cultivate a family-friendly work environment and focus on its employees’ overall wellness. Apache’s robust benefits platform ranks among the best in the Company’s industry peer group and includes comprehensive healthcare, retirement benefits, as well as locally relevant well-being benefits.
Recent enhancements in Apache’s benefit offerings for employees include the following:
•The U.S. family leave policies include paid time off for all new parents, including adoptive and surrogate parents, and leave for employees providing elder care.
•The availability of mental health benefits to all U.S.-based employees and eligible family members, including 16 free sessions with a mental health therapist or coach each year.
•A global wellness platform, which encourages and promotes physical, financial, social, and emotional well-being.
OFFICES
Our principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. As of year-end 2020, the Company maintained offices in Midland, Texas; Houston, Texas; Cairo, Egypt; and Aberdeen, Scotland. Apache leases its primary office space. The current lease on our principal executive offices runs through December 31, 2024. The Company has an option to extend the lease through 2029. For information regarding the Company’s obligations under its office leases, please see Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations-Capital Resources and Liquidity-Contractual Obligations and Note 11-Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
TITLE TO INTERESTS
As is customary in our industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time we acquire properties. We believe that the Company’s 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 APACHE
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 Gulf of Mexico operations and offshore operations in the North Sea and Suriname, which ensure rapid and effective responses to spill events that may occur on such entities’ operated properties. Annually, drills are conducted to measure and maintain the effectiveness of the Plans.
Apache is a member of Oil Spill Response Limited (OSRL), a large international oil spill response cooperative, which entitles any Apache entity worldwide to access OSRL’s services. Apache also has a contract for response resources and services with National Response Corporation (NRC). NRC is the world’s largest commercial Oil Spill Response Organization and is the global leader in providing end-to-end environmental, industrial, and emergency response solutions with operating bases in 13 countries.
In the event of a spill in the Gulf of Mexico, Clean Gulf Associates (CGA) is the primary oil spill response association available to Apache 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.
Additionally, Apache is an active member of Wild Well Control’s WellCONTAINED Subsea Containment System for Suriname operations. This membership includes contingency planning, and response, to an uncontrolled subsea well event. Apache utilizes a detailed Source Control Emergency Response Plan (SCERP) for offshore Suriname planning. The SCERP has been designed to ensure that the goals of Apache’s source control emergency preparedness efforts will be met in the unlikely event of an actual response to an uncontrolled well event. This includes the use of subsea dispersant systems and field deployment of one of Wild Well Control’s containment system capping stacks.
Competitive Conditions
The oil and gas business 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 natural gas liquids. Our 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 our competitors may possess financial or other resources substantially larger than we possess or have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for leases or drilling rights.
However, we believe our diversified portfolio of core assets, which comprises large acreage positions and well-established production bases across three geographic areas, our balanced production mix between oil and gas, our management and incentive systems, and our experienced personnel give us a strong competitive position relative to many of our competitors who do not possess similar geographic and production diversity. Our global position provides a large inventory of geologic and geographic opportunities in the geographic areas in which we have producing operations to which we can reallocate capital investments in response to changes in commodity prices, local business environments, and markets. It also reduces the risk that we 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, we are subject to numerous federal, state, local, and foreign country 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, we do not believe that these requirements affect us differently, to any material degree, than other companies in our industry.
We have made and will continue to make expenditures in our efforts to comply with these requirements, which we believe are necessary business costs in the oil and gas industry. We have established policies for continuing compliance with environmental laws and regulations, including regulations applicable to our operations in all countries in which we do business. We have established operating procedures and training programs designed to limit the environmental impact of our 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 we are unable to separate expenses related to environmental matters; however, we do 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 our capital expenditures, earnings, or competitive position.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our business, financial condition, liquidity, and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments. Additional risks relating to our securities may be included in the prospectus supplements related to offerings of our securities from time to time in the future.
RISKS RELATED TO PRICING, DEMAND, AND PRODUCTION FOR CRUDE OIL, NATURAL GAS, AND NATURAL GAS LIQUIDS (NGLs)
The COVID-19 pandemic has and may continue to adversely impact the Company’s business, financial condition, and results of operations, the global economy, and the demand for and prices of oil, natural gas, and NGLs. The unprecedented nature of the current situation makes it impossible for the Company to identify all potential risks related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on its business.
The COVID-19 pandemic and the actions taken by third parties, including, but not limited to, governmental authorities, businesses, and consumers, in response to the pandemic have adversely impacted the global economy and created significant volatility in the global financial markets. Business closures, restrictions on travel, “stay-at-home” or “shelter-in-place” orders, and other restrictions on movement within and among communities have significantly reduced demand for and the prices of oil, natural gas, and NGLs. As of the date of this report, efforts to contain COVID-19 have not been successful in many regions, vaccination programs have encountered delays, and the global pandemic remains ongoing. A continued prolonged period of such reduced demand, the failure to timely distribute or the ineffectiveness of any vaccines, the failure to develop adequate treatments, and other adverse impacts from the pandemic may materially adversely affect the Company’s business, financial condition, cash flows, and results of operations.
The Company’s operations rely on its workforce being able to access its wells, platforms, structures, and facilities located upon or used in connection with its oil and gas leases. Additionally, because the Company has implemented remote working procedures for a significant portion of its workforce for health and safety reasons and/or to comply with applicable national, state, and/or local government requirements, the Company relies on such persons having sufficient access to its information technology systems, including through telecommunication hardware, software, and networks. If a significant portion of the Company’s workforce cannot effectively perform their responsibilities, whether resulting from a lack of physical or virtual access, quarantines, illnesses, governmental actions or restrictions, information technology or telecommunication failures, or other restrictions or adverse impacts resulting from the pandemic, the Company’s business, financial condition, cash flows, and results of operations may be materially adversely affected.
The unprecedented nature of the current situation resulting from the COVID-19 pandemic makes it impossible for the Company to identify all potential risks related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on its business, financial condition, cash flows, or results of operations. Such results will depend on future events, which the Company cannot predict, including the scope, duration, and potential reoccurrence of the COVID-19 pandemic or any other localized epidemic or global pandemic, the distribution and effectiveness of vaccines and treatments, the demand for and the prices of oil, natural gas, and NGLs, and the actions taken by third parties, including, but not limited to, governmental authorities, customers, contractors, and suppliers, in response to the COVID-19 pandemic or any other epidemics or pandemics. The COVID-19 pandemic and its unprecedented consequences have amplified, and may continue to amplify, the other risks identified in this report.
Crude oil, natural gas, and NGL price volatility could adversely affect our operating results and the price of our common stock.
Our revenues, operating results, and future rate of growth depend highly upon the prices we receive for our crude oil, natural gas, and NGL production. Historically, the markets for these commodities have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2020 ranged from a high of $63.27 per barrel to a low of -$36.98 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2020 ranged from a high of $3.14 per MMBtu to a low of $1.33 per MMBtu. The market prices for crude oil, natural gas, and NGLs depend on factors beyond our control. These factors include demand, which fluctuates with changes in market and economic conditions, and other factors, including:
•worldwide and domestic supplies of crude oil, natural gas, and NGLs;
•actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC);
•political conditions and events (including instability, changes in governments, or armed conflict) in oil and gas producing regions;
•the occurrence of global events such as epidemics or pandemics (including, specifically, the COVID-19 pandemic) and the actions taken by third parties, including, but not limited to, governmental authorities, customers, contractors, and suppliers, in response to such epidemics or pandemics;
•the level of global crude oil and natural gas inventories;
•the price and level of imported foreign crude oil, natural gas, and NGLs;
•the price and availability of alternative fuels, including coal and biofuels;
•the availability of pipeline capacity and infrastructure;
•the availability of crude oil transportation and refining capacity;
•weather conditions;
•domestic and foreign governmental regulations and taxes; and
•the overall economic environment.
Our results of operations, as well as the carrying value of our oil and gas properties, are substantially dependent upon the prices of oil, natural gas, and NGLs. Despite slight increases in oil and natural gas prices in 2020, prices have remained significantly lower than levels seen in recent years, which has adversely affected our revenues, operating income, cash flow, and proved reserves. Continued low prices could have a material adverse impact on our operations and limit our ability to fund capital expenditures. Without the ability to fund capital expenditures, we would be unable to replace reserves and production. Sustained low prices of crude oil, natural gas, and NGLs may further adversely impact our business as follows:
•weakening our financial condition and reducing our liquidity;
•limiting our ability to fund planned capital expenditures and operations;
•reducing the amount of crude oil, natural gas, and NGLs that we can produce economically;
•causing us to delay or postpone some of our capital projects;
•reducing our revenues, operating income, and cash flows;
•limiting our access to sources of capital, such as equity and long-term debt;
•reducing the carrying value of our oil and gas properties, resulting in additional non-cash impairments; or
•reducing the carrying value of our gathering, processing, and transmission facilities, resulting in additional impairments.
Our ability to sell crude oil, natural gas, or NGLs and/or receive market prices for these commodities and/or meet volume commitments under transportation services agreements may be adversely affected by pipeline and gathering system capacity constraints, the inability to procure and resell volumes economically, and various transportation interruptions.
A portion of our crude oil, natural gas, and NGL production in any region may be interrupted, limited, or shut in from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities, or interstate pipelines to transport our production, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flows. Additionally, if we are unable to procure and resell third-party volumes at or above a net price that covers the cost of transportation, our cash flows could be adversely affected.
We may not realize an adequate return on wells that we drill.
Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The wells we drill or participate in may not be productive, and we may not recover all or any portion of our investment in those wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that crude or natural gas is present or may be produced economically. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors including, but not limited to:
•unexpected drilling conditions;
•pressure or irregularities in formations;
•equipment failures or accidents;
•fires, explosions, blowouts, and surface cratering;
•marine risks, such as capsizing, collisions, and hurricanes;
•other adverse weather conditions; and
•increases in the cost of or shortages or delays in the availability of drilling rigs and equipment.
Future drilling activities may not be successful, and, if unsuccessful, this failure could have an adverse effect on our 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.
Our commodity price risk management and trading activities may prevent us from benefiting fully from price increases and may expose us to other risks.
To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from realizing the benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which:
•our production falls short of the hedged volumes;
•there is a widening of price-basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;
•the counterparties to our 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
Our operations involve a high degree of operational risk, particularly risk of personal injury, damage to or loss of equipment, and environmental accidents.
Our 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, and cratering;
•pipeline or other facility ruptures and spills;
•fires;
•formations with abnormal pressures;
•equipment malfunctions;
•hurricanes, storms, and/or cyclones, which could affect our operations in areas such as on and offshore the Gulf Coast, North Sea, and Suriname, and other natural and anthropogenic disasters and weather conditions; and
•surface spillage and surface or ground water contamination from petroleum constituents, saltwater, or hydraulic fracturing chemical additives.
Failure or loss of equipment, as the result of equipment malfunctions, cyberattacks, or natural disasters such as hurricanes, could result in property damages, personal injury, environmental pollution, and other damages for which we could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion, fire at a location where our equipment and services are used, or ground water contamination from hydraulic fracturing chemical additives 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 chemical additives could result in extensive environmental pollution and substantial remediation expenses. If a significant amount of our production is interrupted, our containment efforts prove to be ineffective, or litigation arises as the result of a catastrophic occurrence, our cash flows and, in turn, our results of operations could be materially and adversely affected.
Weather and climate may have a significant adverse impact on our revenues and production.
Demand for oil and gas are, to a significant degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. In addition, our exploration and development activities and equipment can be adversely affected by severe weather, such as freezing temperatures, hurricanes in the Gulf of Mexico, or storms in the North Sea, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. Our 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.
Our insurance policies do not cover all of the risks we face, 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. Our international operations are also subject to political risk. The insurance coverage that we maintain against certain losses or liabilities arising from our operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to us against all operational risks.
A terrorist or cyberattack targeting systems and infrastructure used by us or others in the oil and gas industry may adversely impact our operations.
Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, and production activities. We depend 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 our employees and third-party partners, and conduct many of our activities. Unauthorized access to our 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 United States and abroad, which are necessary to transport and market our production. A cyberattack directed at oil and gas distribution systems 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 our customers, suppliers, or others with whom we do business could have a material adverse effect on our business, cause us to incur a material financial loss, subject us to possible legal claims and liability, and/or damage our reputation.
While certain of our insurance policies may allow for coverage of associated damages resulting from such events, if we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our 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 we have experienced cyberattacks in the past, we have not suffered any material losses as a result of such attacks; however, there is no assurance that we will not suffer such losses in the future. Further, as cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyberattacks. In addition, cyberattacks against us or others in our 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 our 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.
We are involved in several large development projects, and the completion of these projects may be delayed beyond our anticipated completion dates. Our 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 our large development projects and our ability to participate in large-scale development projects in the future. In addition, our estimates of future development costs are based on our current expectations of prices and other costs of equipment and personnel we will need to implement such projects. Our actual future development costs may be significantly higher than we currently estimate. If costs become too high, our development projects may become uneconomic to us, and we 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 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 we add reserves through exploration and development activities, identify additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves through engineering studies, or acquire additional properties containing proved reserves, our estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves on an economic basis. Furthermore, if oil or gas prices increase, our cost for additional reserves could also increase.
We may fail to fully identify potential problems related to acquired reserves or to properly estimate those reserves.
Although we perform a review of properties that we acquire that we believe 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, we will focus our 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 us 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, we often assume 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 our operating results, particularly during the periods in which the operations of acquired businesses are being integrated into our 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. Our 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 our 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 our reserves likely will vary, possibly materially, from estimates.
Additionally, because some of our 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 our 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 our 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 our 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 our leases expire, we will lose our right to develop the related properties. Our 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 us.
We are 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 us to credit risk in the event of default of our counterparty. Deterioration in the credit or financial markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We may also have exposure to financial institutions in the form of derivative transactions in connection with any hedges. We also have exposure to insurance companies in the form of claims under our policies. In addition, if any lender under our credit facilities is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facilities.
We are 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 decline 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. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of our hedge providers or some other similar proceeding or liquidity constraint might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. During periods of falling commodity prices, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
The distressed financial conditions of our purchasers and partners could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or to reimburse us for their share of costs.
Concerns about global economic conditions and the volatility of oil, natural gas, and NGL prices have had a significant adverse impact on the oil and gas industry. We are exposed to risk of financial loss from trade, joint venture, joint interest billing, and other receivables. We sell our crude oil, natural gas, and NGLs to a variety of purchasers. As operator, we pay expenses and bill our non-operating partners for their respective shares of costs. As a result of current economic conditions and the severe decline in commodity prices, some of our customers and non-operating partners may experience severe financial problems that may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed customers or non-operating partners will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. Furthermore, the bankruptcy of one or more of our customers or non-operating partners or some other similar proceeding or liquidity constraint might make it unlikely that we 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.
Our liabilities could be adversely affected in the event one or more of our transaction counterparties become the subject of a bankruptcy case.
From time to time we have divested noncore or nonstrategic domestic and international assets. The agreements relating to these transactions contain provisions pursuant to which liabilities related to past and future operations have been allocated between the parties by means of liability assumptions, indemnities, escrows, trusts, and similar arrangements. One of the most significant of these liabilities involves the decommissioning of wells and facilities previously owned by us. 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 were to become 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 we collectively refer to as Insolvency Laws), the counterparty may not perform its obligations under the agreements related to these transactions. In that case, our 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 we have collateral from the counterparty for the performance of the obligations. Resolution of our claim for damages in such a proceeding may be delayed, and we 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 our agreements requiring purchasers of our 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, we would expect the relevant governmental authorities to require us to perform and hold us responsible for such liabilities and obligations. In such event, we 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 our cash flows, operations, or financial condition.
We do not always control decisions made under joint operating agreements, and the parties under such agreements may fail to meet their obligations.
We conduct many of our exploration and production (E&P) operations through joint operating agreements with other parties under which we may not control decisions, either because we do not have a controlling interest or are not an operator under the agreement. There is risk that these parties may at any time have economic, business, or legal interests or goals that are inconsistent with ours, and therefore, decisions may be made that we do not believe are in our best interest. Moreover, parties to these agreements may be unable to meet their economic or other obligations, and we may be required to fulfill those obligations alone. In either case, the value of our investment may be adversely affected.
We own an approximate 79 percent interest in Altus, which holds substantially all of our former gathering, processing and transmission assets in Alpine High. Altus may be subject to different risks than those described in this Form 10-K.
We own an approximate 79 percent interest in Altus, which holds substantially all of our former gathering, processing and transmission assets in Alpine High. Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas, anchored by midstream service contracts to service our production from our Alpine High resource play. Altus generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services and through its Equity Method Interest Pipelines. Given the nature of its business, Altus may be subject to different and additional risks than those described in this Annual Report on Form 10-K. For a description of these risks, refer to Altus’ most recently filed Annual Report on Form 10-K and any subsequently filed Quarterly Reports on Form 10-Q.
RISKS RELATED TO CAPITAL MARKETS
A downgrade in our credit rating could negatively impact our cost of and ability to access capital.
We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include 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 our ability to access debt markets in the future and increase the cost of future debt. During 2020, our credit rating was downgraded by Moody’s to Ba1/Negative and by Standard and Poor’s to BB+/Negative. These and other past ratings downgrades have required, and any future downgrades may require, us to post letters of credit or other forms of collateral for certain obligations.
Market conditions may restrict our ability to obtain funds for future development and working capital needs, which may limit our financial flexibility.
The financial markets are subject to fluctuation and are vulnerable to unpredictable shocks. We have a significant development project inventory and an extensive exploration portfolio, which will require substantial future investment. We and/or our partners may need to seek financing in order to fund these or other future activities. Our future access to capital, as well as that of our partners and contractors, could be limited if the debt or equity markets are constrained. This could significantly delay development of our property interests.
Our syndicated credit facility currently matures in March 2024. There is no assurance of the terms upon which potential lenders under future agreements will make loans or other extensions of credit available to Apache or its subsidiaries or the composition of such lenders.
The discontinuation and uncertain cessation date of LIBOR, and the adoption of an alternative reference rate, may have a material adverse impact on our floating rate indebtedness and financing costs.
Pursuant to the terms of our revolving credit facility (1) we may elect to use London Interbank Offering Rate (LIBOR) as a benchmark for establishing the interest rate on floating interest rate borrowings and (2) the commission payable to the lenders on the face amount of each outstanding letter of credit uses LIBOR as a benchmark. On November 30, 2020, the ICE Benchmark Administration (IBA) announced that it intends to continue publishing LIBOR until the end of June 2023, beyond the previously announced 2021 cessation date. The IBA announcement was supported by announcements from the United Kingdom’s Financial Conduct Authority (FCA), which regulates LIBOR, and the Board of Governors of the Federal Reserve System, Federal Deposit Insurance Corporation and Office of the Comptroller of the Currency (U.S. Regulators). However, both the FCA and U.S. Regulators in their announcements also advised banks to cease entering into new contracts referencing LIBOR after December 2021. These announcements indicate that the continuation of LIBOR on the current basis may not be assured after 2021 and will not be assured beyond 2023. In light of these recent announcements, the future of LIBOR at this time is uncertain, and any changes in the methods by which LIBOR is determined or regulatory activity related to LIBOR’s phaseout could cause LIBOR to perform differently than in the past or cease to exist.
In the United States, the Alternative Reference Rates Committee (the working group formed to recommend an alternative rate to LIBOR) has identified the Secured Overnight Financing Rate (SOFR) as its preferred alternative rate for LIBOR. There can be no guarantee that SOFR will become a widely-accepted benchmark in place of LIBOR. Although the full impact of the transition away from LIBOR, including the discontinuance of LIBOR publication and the adoption of SOFR as the replacement rate for LIBOR, remains unclear, these changes may have an adverse impact on our floating rate indebtedness and financing costs under our revolving credit facility.
Our ability to declare and pay dividends is subject to limitations.
The payment of future dividends on our capital stock is subject to the discretion of our board of directors, which considers, among other factors, our operating results, overall financial condition, credit-risk considerations, and capital requirements, as well as general business and market conditions. Our board of directors is not required to declare dividends on our common stock and may decide not to declare dividends.
Any indentures and other financing agreements that we enter into in the future may limit our ability to pay cash dividends on our capital stock, including our common stock. In addition, under Delaware law, dividends on capital stock may only be paid from “surplus,” which is the amount by which the fair value of our total assets exceeds the sum of our total liabilities, including contingent liabilities, and the amount of our capital; if there is no surplus, cash dividends on capital stock may only be paid
from our net profits for the then-current and/or the preceding fiscal year. Further, even if we are permitted under our contractual obligations and Delaware law to pay cash dividends on common stock, we may not have sufficient cash to pay dividends in cash on our common stock.
RISKS RELATED TO FINANCIAL RESULTS
Future economic conditions in the U.S. and certain international markets may materially adversely impact our operating results.
Current global market conditions and uncertainty, including the economic instability in Europe and certain emerging markets, are likely to have significant long-term effects on our 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 our oil and gas production as well as lower commodity prices, which would reduce our cash flows from operations and our profitability.
We face strong industry competition that may have a significant negative impact on our results of operations.
Strong competition exists in all sectors of the oil and gas E&P industry. We compete 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 our competitors have financial and other resources substantially larger than we possess and have established strategic, long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our 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. We also compete in attracting and retaining personnel, including geologists, geophysicists, engineers, and other specialists. These competitive pressures may have a significant negative impact on our results of operations.
The Company’s ability to utilize net operating losses and other tax attributes to reduce future taxable income may be limited if the Company experiences an ownership change.
As described in Note 10-Income Taxes of the Notes to Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K, the Company has substantial net operating loss carryforwards (NOLs) and other tax attributes available to potentially offset future taxable income. If the Company were to experience an “ownership change” under Section 382 of the Internal Revenue Code of 1986, as amended, which is generally defined as a greater than 50 percentage point change, by value, in the Company’s equity ownership by five-percent shareholders over a three-year period, the Company’s ability to utilize its pre-change NOLs and other pre-change tax attributes to potentially offset its post-change income or taxes may be limited. Such a limitation could materially adversely affect the Company’s operating results or cash flows by effectively increasing its future tax obligations.
RISKS RELATED TO GOVERNMENTAL REGULATION AND POLITICAL RISKS
We may incur significant costs related to environmental matters.
As an owner or lessee and operator of oil and gas properties, we are subject to various federal, state, local, and foreign country 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. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in significant adverse effects to our results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require us to make significant capital expenditures. Such capital expenditures could adversely impact our cash flows and our financial condition.
Our United States operations are subject to governmental risks.
Our United States 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. We are working closely with BOEM to make arrangements for the provision of such additional required security, if such security becomes necessary under the NTL. Additionally, we are 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 our United States operations, and increased liability for companies operating in this sector may adversely impact our results of operations.
Changes to existing regulations related to emissions and the impact of any changes in climate could adversely impact our business.
Certain countries where we operate, including the United Kingdom, either tax or assess some form of greenhouse gas (GHG) related fees on our operations. Exposure has not been material to date, although a change in existing regulations could adversely affect our cash flows and results of operations. Additionally, there has been discussion in other countries where we operate, including the United States, regarding legislation or regulation of GHG. Any such legislation or regulation, if enacted, could either tax or assess some form of GHG-related fees on our operations and could lead to increased operating expenses or cause us to make significant capital investments for infrastructure modifications.
In the event the predictions for rising temperatures and sea levels suggested by reports of the United Nations Intergovernmental Panel on Climate Change do transpire, we do not believe those events by themselves are likely to impact our assets or operations. However, any increase in severe weather could have a material adverse effect on our assets and operations.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, and explosions of natural gas transmission lines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines, and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens, and increased risk of litigation. 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 we require to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.
Changes in tax rules and regulations, or interpretations thereof, may adversely affect our business, financial condition, and results of operations.
On December 22, 2017, the Tax Cuts and Jobs Act (the TCJA) was signed into law. In addition to reducing the U.S. corporate income tax rate from 35 percent to 21 percent effective January 1, 2018, certain provisions in the TCJA move the U.S. away from a worldwide tax system and closer to a territorial system for earnings of foreign corporations, establishing a participation exemption system for taxation of foreign income. The new law includes a transition rule to effect this participation exemption regime. The TCJA also includes provisions which could impact or limit the Company’s ability to deduct interest expense or utilize net operating losses.
The U.S. federal and state income tax laws affecting oil and gas exploration, development, and extraction may be further 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 exploration and production 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. We are unable to predict whether any of these changes or other proposals will be enacted. Any such changes could adversely affect our business, financial condition, and results of operations.
Proposed federal, state, or local regulation regarding hydraulic fracturing could increase our 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. We routinely use 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 we conduct business could result in increased compliance costs or additional operating restrictions in the U.S.
RISKS RELATED TO INTERNATIONAL OPERATIONS
International operations have uncertain political, economic, and other risks.
Our operations outside the United States are based primarily in Egypt and the United Kingdom. On a barrel equivalent basis, approximately 42 percent of our 2020 production was outside the United States, and approximately 33 percent of our estimated proved oil and gas reserves as of December 31, 2020, were located outside the United States. As a result, a significant portion of our 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;
•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 United States affecting foreign trade, including trade sanctions;
•the 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 we currently operate;
•the possible inability to subject foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of courts in the United States; and
•difficulties in enforcing our 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 us by another country, our interests could decrease in value or be lost. Even our smaller international assets may affect our overall business and results of operations by distracting management’s attention from our more significant assets. Certain regions of the world in which we operate 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 ours. In an extreme case, such a change could result in termination of contract rights and expropriation of our assets. This could adversely affect our interests and our future profitability.
The impact that future terrorist attacks or regional hostilities, as have occurred in countries and regions in which we operate, may have on the oil and gas industry in general and on our 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. We may be required to incur significant costs in the future to safeguard our 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 our 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 our assets or resource nationalization, and/or forced renegotiation or modification of our existing contracts with EGPC, or threats or acts of terrorism could materially and adversely affect our business, financial condition, and results of operations. Our operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 20 percent of our 2020 production and accounted for 15 percent of our year-end estimated proved reserves and 24 percent of our estimated discounted future net cash flows.
Our operations are sensitive to currency rate fluctuations.
Our operations are sensitive to fluctuations in foreign currency exchange rates, particularly between the U.S. dollar and the British pound. Our 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 our results of operations, particularly through the weakening of the U.S. dollar relative to other currencies.
RISKS RELATED TO THE PLANNED HOLDING COMPANY REORGANIZATION
If the Holding Company Reorganization is implemented, APA Corporation, as the parent holding company of Apache, will be dependent on the operations and funds of its subsidiaries, including Apache.
If the Holding Company Reorganization is implemented, APA Corporation will become the successor issuer to, and parent holding company of, Apache. APA Corporation will have no business operations of its own. APA Corporation’s only significant assets will be the outstanding equity interests of its subsidiaries, including Apache. As a result, APA Corporation will rely on cash flows from Apache to pay dividends with respect to its common stock and to meet its financial obligations, including to service any debt obligations that APA Corporation may incur from time to time. Legal and contractual restrictions in agreements governing future indebtedness of Apache, as well as Apache’s financial condition and future operating
requirements, may limit Apache’s ability to distribute cash to APA Corporation. If Apache is limited in its ability to distribute cash to APA Corporation, or if Apache’s earnings or other available assets of are not sufficient to pay distributions or make loans to APA Corporation in the amounts or at the times necessary for APA Corporation to pay dividends with respect to its common stock and/or to meet its financial obligations, then APA Corporation’s business, financial condition, cash flows, results of operations, and reputation may be materially adversely affected.
If the Holding Company Reorganization is implemented, APA Corporation may not obtain the anticipated benefits of the reorganization into a holding company structure.
If the Holding Company Reorganization is implemented, we believe that our new operating structure will allow us to focus on running our diverse businesses independently with the goal of maximizing each of the business’ potential. However, the anticipated benefits of the planned Holding Company Reorganization may not be obtained if circumstances prevent us from taking advantage of the strategic and business opportunities that we expect it may afford us. As a result, we may incur the costs of a holding company structure without realizing the anticipated benefits, which could adversely affect our business, financial condition, cash flows, and results of operations.
Management is dedicating significant effort to the new operating structure. These efforts may divert management’s focus and resources from the Company’s operations, strategic initiatives, or development opportunities, which could adversely affect our prospects, business, financial condition, cash flows, and results of operations.
GENERAL RISK FACTORS
Certain anti-takeover provisions in our charter and Delaware law could delay or prevent a hostile takeover.
Our charter authorizes our board of directors to issue preferred stock in one or more series and to determine the voting rights and dividend rights, dividend rates, liquidation preferences, conversion rights, redemption rights, including sinking fund provisions and redemption prices, and other terms and rights of each series of preferred stock. In addition, Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15 percent or more of our outstanding common stock. These provisions may deter hostile takeover attempts that could result in an acquisition of us that would have been financially beneficial to our shareholders.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
As of December 31, 2020, we did not have any unresolved comments from the SEC staff that were received 180 or more days prior to year-end.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
The information set forth under “Legal Matters” and “Environmental Matters” in Note 11-Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K is incorporated herein by reference.

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

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Apache’s common stock, par value $0.625 per share, is traded on the Nasdaq Global Select Market (Nasdaq) under the symbol “APA.” The closing price of our common stock, as reported by the Nasdaq for January 29, 2021 (last trading day of the month), was $14.28 per share. As of January 29, 2021, there were 377,860,971 shares of our common stock outstanding held by approximately 3,500 stockholders of record and 166,000 beneficial owners.
We have paid cash dividends on our common stock for 56 consecutive years through December 31, 2020. In the first quarter of 2020, Apache’s Board of Directors approved a reduction in the Company’s quarterly dividend per share from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020. When, and if, declared by our Board of Directors, future dividend payments will depend upon our level of earnings, financial requirements, and other relevant factors.
Information concerning securities authorized for issuance under equity compensation plans is set forth under the caption “Equity Compensation Plan Information” in the proxy statement relating to the Company’s 2021 annual meeting of stockholders, which is incorporated herein by reference.
The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s 500 Index (S&P 500 Index) and of the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) from December 31, 2015, through December 31, 2020. The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that the Company specifically incorporates it by reference into such filing.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among Apache Corporation, the S&P 500 Index,
and the Dow Jones U.S. Exploration & Production Index
* $100 invested on 12/31/15 in stock or index, including reinvestment of dividends.
Fiscal year ending December 31.
2015 2016 2017 2018 2019 2020
Apache Corporation $ 100.00 $ 145.64 $ 98.84 $ 62.88 $ 63.54 $ 35.78
S&P 500 Index 100.00 111.96 136.40 130.42 171.49 203.04
Dow Jones U.S. Exploration & Production Index 100.00 124.48 126.10 103.69 115.51 76.64

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

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion relates to 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 2020 and 2019 items and year-to-year comparisons between 2020 and 2019. Discussions of 2018 items and year-to-year comparisons between 2019 and 2018 that are not included in this Annual Report on Form 10-K are incorporated by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2019 (filed with the SEC on February 28, 2020).
Overview
Apache Corporation, a Delaware corporation formed in 1954, 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). Apache also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. Apache’s midstream business is operated by Altus Midstream Company (Nasdaq: ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas.
Apache’s mission is to grow in an innovative, safe, environmentally responsible, and profitable manner for the long-term benefit of its stakeholders. Apache is focused on rigorous portfolio management, disciplined financial structure, and optimization of returns.
The global economy and the energy industry have been deeply impacted by the effects of the COVID-19 pandemic and related third-party actions. Uncertainty in the oil markets and the negative demand implications from the COVID-19 pandemic continue to impact oil supply and demand. As with previous changes in a volatile price environment, Apache has continued to respond quickly and decisively, taking the following actions:
•Establishing and implementing a wide range of fit-for-purpose protocols and procedures to ensure a safe and productive work environment across the Company’s diversified global onshore and offshore operations.
•Reducing upstream capital investments by over 50 percent from the comparative prior-year period, including eliminating nearly all U.S. drilling and completion activity by May 2020 and reducing planned activity in Egypt and the North Sea.
•Decreasing the Company’s dividend by 90 percent beginning in the first quarter of 2020, preserving approximately $340 million of cash flow on an annualized basis and strengthening liquidity.
•Completing an organizational redesign focused on centralizing certain operational activities in an effort to capture greater efficiencies, achieving an estimated cost savings of $400 million annually.
•Conducting, on a continuous basis, price sensitivity analyses and operational evaluations of producing wells across the Company’s portfolio that allow for a methodical and integrated approach to production shut-ins and curtailments with a focus on preserving cash flows in a distressed price environment and protecting the Company’s assets.
The Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of ongoing exploration and appraisal activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate excess cash flow that can be directed on a priority basis to debt reduction. The Company closely monitors hydrocarbon pricing fundamentals and will reallocate capital as part of its ongoing planning process. For additional detail on the Company’s forward capital investment outlook, refer to “Capital and Operational Outlook” below.
During 2020, Apache reported a net loss attributable to common stock of $4.9 billion, or $12.86 per share, compared to a net loss of $3.6 billion, or $9.43 per share, in 2019. The results for both periods were driven by asset impairments. In 2020, the Company recorded impairments totaling $4.5 billion in connection with fair value assessments stemming from the global crude oil price collapse on lower demand and economic activity resulting from the impacts of COVID-19 and related third-party actions. The Company recorded asset impairments during 2019 of $2.9 billion, primarily related to a material reduction in planned investment at Apache’s Alpine High development that triggered fair value assessments of the Company’s upstream Alpine High proved properties and Altus’ associated midstream assets.
Apache’s capital spending for the year aligned with its $1.4 billion of cash from operating activities generated in 2020, which was $1.5 billion or 52 percent lower than the prior year. Apache’s lower operating cash flows for 2020 were driven by lower crude oil prices and associated revenues. The reduced capital investment was the result of proactive measures taken by the Company to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows. Apache ended the year with a slightly higher cash balance of $262 million and comparable debt levels to the prior year-end, while actively managing its debt positions to reduce near-term debt maturities.
Operational Highlights
Key operational highlights for the year include:
United States
•Equivalent production from the Company’s U.S. assets, which accounted for 58 percent of total production during 2020, decreased nine percent from 2019 to 2020 as a result of reduced activity in response to commodity price weakness.
•The Company began 2020 with seven operated drilling rigs and three operated completion crews in the Permian Basin, which were both quickly and safely reduced to zero by May 2020 in response to commodity price weakness.
•In response to completion cost reductions when compared to the first quarter of 2020, the Company reinstated two operated completion crews in the Permian Basin during the fourth quarter of 2020 to begin completing its backlog of drilled but uncompleted well inventory.
International
•Egypt gross equivalent production decreased 13 percent and net production decreased 9 percent from 2019 primarily a result of natural decline given reduced drilling activity during the year. The Company continues to build and enhance its robust drilling inventory in Egypt, supplemented with recent seismic acquisitions and new play concept evaluations, on both new and existing acreage. As a result, the Egypt asset achieved a new record within the Matruh Basin with the Herunefer E-2 well, which encountered 555 feet of net pay.
•The North Sea maintained two drilling rigs during 2020 with notable discoveries at the Storr and Garten fields contributing to the two percent increase in production from 2019 to 2020. In addition, during the fourth quarter of 2020, the Company’s Losgann well confirmed a Tertiary oil discovery, offsetting other operator Norwegian discoveries in the area. In combination with two previous undeveloped Apache discoveries in the Tertiary, Losgann will add to a comprehensive development opportunity.
•In April 2020, Apache announced a significant oil discovery at the Sapakara West-1 well drilled offshore Suriname on Block 58. Sapakara West-1 was drilled to a depth of approximately 6,300 meters (approximately 20,700 feet) and successfully tested for the presence of hydrocarbons in multiple stacked targets in the upper Cretaceous-aged Campanian and Santonian intervals. This follows the January 2020 announcement of a discovery at the Maka Central-1 well. During 2020, the Company submitted a plan of appraisal for both of these discoveries. Apache holds a 50 percent working interest in Block 58.
•In July 2020, Apache announced a major oil discovery at the Kwaskwasi-1 well drilled offshore Suriname on Block 58. Kwaskwasi-1 was drilled to a depth of approximately 6,645 meters (approximately 21,800 feet) and successfully tested for the presence of hydrocarbons in multiple stacked targets in the upper Cretaceous-aged Campanian and Santonian intervals. Fluid samples and test results indicate at least 278 meters (approximately 912 feet) of net oil and oil/gas condensate pay in two intervals. This was the third consecutive oil discovery offshore Suriname.
•In late 2020, the Company commenced drilling a fourth exploration well in the block at the Keskesi prospect. In January 2021, Apache and Total S.A announced a discovery that confirmed oil in the eastern portion of the block. The Keskesi East-1 well is continuing to drill to deeper targets. Apache is transferring operatorship of Block 58 to its partner, Total S.A, which will conduct all exploration and appraisal activities subsequent to completion of drilling operations at Keskesi.
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 Apache’s history, the Company has repeatedly demonstrated its 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, Apache has completed a series of divestitures designed to monetize nonstrategic assets and enhance Apache’s portfolio in order to allocate resources to more impactful exploration and development opportunities. These divestitures include:
•U.S. Leasehold Divestitures & Other During 2020, the Company completed the sale of certain non-core producing assets and leasehold acreage, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $87 million. The Company also completed certain leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $4 million.
•Suriname Joint Venture Agreement In December 2019, Apache entered into a joint venture agreement with Total S.A. to explore and develop Block 58 offshore Suriname. Under the terms of the agreement, Apache and Total S.A. each hold a 50 percent working interest in Block 58. Apache operated the drilling of the first four wells and subsequently transferred operatorship of Block 58 to Total S.A. In connection with the agreement, Apache received $100 million upon closing in the fourth quarter of 2019 and $79 million upon satisfying certain closing conditions in the first quarter of 2020 for reimbursement of 50 percent of all costs incurred on Block 58 as of December 31, 2019.
Apache will also receive various other forms of consideration, including $5.0 billion of cash carry on Apache’s first $7.5 billion of appraisal and development capital, 25 percent cash carry on all of Apache’s appraisal and development capital beyond the first $7.5 billion, a $75 million cash payment upon achieving first oil production, and future contingent royalty payments from successful joint development projects.
•Midcontinent/Gulf Coast Divestiture In the second quarter of 2019, Apache completed the sale of non-core, gas-weighted assets in the Woodford-SCOOP and STACK plays for aggregate cash proceeds of approximately $223 million. In the third quarter of 2019, Apache completed the sale of non-core, gas-weighted assets in the western Anadarko Basin of Oklahoma and Texas for aggregate cash proceeds of approximately $322 million and the assumption of asset retirement obligations of $49 million.
•U.S. Leasehold Divestitures & Other During 2019, the Company also completed the sale of certain other non-core producing assets, gathering, processing, and transmission (GPT) assets, and leasehold acreage, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $73 million.
For detailed information regarding Apache’s acquisitions and divestitures, refer to Note 2-Acquisitions and Divestitures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Results of Operations
Oil and Gas Production Revenues
Apache’s oil and gas production revenues and respective contribution to total revenues by country are as follows:
For the Year Ended December 31,
2020 2019 2018
$ Value % Contribution $ Value % Contribution $ Value % Contribution
($ in millions)
Oil Revenues:
United States $ 1,209 39 % $ 2,098 40 % $ 2,271 39 %
Egypt(1)
1,102 35 % 1,969 38 % 2,396 41 %
North Sea 795 26 % 1,163 22 % 1,179 20 %
Total(1)
$ 3,106 100 % $ 5,230 100 % $ 5,846 100 %
Natural Gas Revenues:
United States $ 251 42 % $ 293 43 % $ 458 50 %
Egypt(1)
280 47 % 295 44 % 339 37 %
North Sea 67 11 % 90 13 % 122 13 %
Total(1)
$ 598 100 % $ 678 100 % $ 919 100 %
NGL Revenues:
United States $ 304 91 % $ 372 91 % $ 550 94 %
Egypt(1)
8 3 % 12 3 % 13 2 %
North Sea 21 6 % 23 6 % 20 4 %
Total(1)
$ 333 100 % $ 407 100 % $ 583 100 %
Oil and Gas Revenues:
United States $ 1,764 44 % $ 2,763 44 % $ 3,279 45 %
Egypt(1)
1,390 34 % 2,276 36 % 2,748 37 %
North Sea 883 22 % 1,276 20 % 1,321 18 %
Total(1)
$ 4,037 100 % $ 6,315 100 % $ 7,348 100 %
(1)Includes revenues attributable to a noncontrolling interest in Egypt.
Production
The following table presents production volumes by country:
For the Year Ended December 31,
2020 Increase
(Decrease) 2019 Increase
(Decrease) 2018
Oil Volumes - b/d:
United States 88,249 (16)% 105,051 - 104,800
Egypt(1)(2)
75,384 (11)% 84,617 (10)% 93,656
North Sea 50,386 1% 49,746 6% 46,953
Total 214,019 (11)% 239,414 (2)% 245,409
Natural Gas Volumes - Mcf/d:
United States 561,731 (12)% 639,580 8% 593,254
Egypt(1)(2)
274,175 (4)% 285,972 (12)% 326,811
North Sea 57,464 5% 54,642 20% 45,466
Total 893,370 (9)% 980,194 2% 965,531
NGL Volumes - b/d:
United States 74,136 8% 68,381 19% 57,451
Egypt(1)(2)
754 (19)% 931 1% 923
North Sea 1,936 11% 1,739 46% 1,189
Total 76,826 8% 71,051 19% 59,563
BOE per day:(3)
United States 256,007 (9)% 280,029 7% 261,126
Egypt(1)(2)
121,834 (9)% 133,209 (11)% 149,048
North Sea(4)
61,899 2% 60,592 9% 55,719
Total 439,740 (7)% 473,830 2% 465,893
(1)Gross oil, natural gas, and NGL production in Egypt were as follows:
2020 2019 2018
Oil (b/d) 164,104 193,886 206,378
Natural Gas (Mcf/d) 641,069 708,682 769,468
NGL (b/d) 1,429 1,722 1,502
(2)Includes net production volumes per day attributable to a noncontrolling interest in Egypt of:
2020 2019 2018
Oil (b/d) 25,206 28,220 31,240
Natural Gas (Mcf/d) 91,540 95,539 109,169
NGL (b/d) 251 310 308
(3)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.
(4)Average sales volumes from the North Sea were 62,157 boe/d, 59,797 boe/d, and 55,568 boe/d for 2020, 2019, and 2018, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.
Pricing
The following table presents pricing information by country:
For the Year Ended December 31,
2020 Increase
(Decrease) 2019 Increase
(Decrease) 2018
Average Oil Price - Per barrel:
United States $ 37.42 (32)% $ 54.71 (8)% $ 59.36
Egypt 39.95 (37)% 63.76 (9)% 70.09
North Sea 42.88 (34)% 65.10 (6)% 69.02
Total 39.60 (34)% 60.05 (8)% 65.30
Average Natural Gas Price - Per Mcf:
United States $ 1.22 (3)% $ 1.26 (41)% $ 2.12
Egypt 2.79 (1)% 2.83 - 2.84
North Sea 3.19 (29)% 4.48 (39)% 7.33
Total 1.83 (4)% 1.90 (27)% 2.61
Average NGL Price - Per barrel:
United States $ 11.21 (25)% $ 14.95 (43)% $ 26.28
Egypt 27.83 (18)% 33.87 (14)% 39.17
North Sea 29.73 (19)% 36.83 (20)% 45.84
Total 11.84 (25)% 15.74 (41)% 26.87
Crude Oil Prices A substantial portion of our 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 2020 were down 34 percent compared to 2019, a direct result of the decreasing benchmark oil prices over the past year resulting from the COVID-19 pandemic and related third-party actions. Crude oil prices realized in 2020 averaged $39.60 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. Apache’s primary markets include North America, Egypt, and the U.K. An overview of the market conditions in the Company’s primary gas-producing regions follows:
•The Company predominantly sells its natural gas production within the United States, including to U.S. LNG export facilities, although a portion is sold to markets in Mexico. Most of the Company’s U.S. natural gas is sold on a monthly or daily basis at either monthly or daily index-based prices. The Company’s U.S. realizations averaged $1.22 per Mcf in 2020, down from $1.26 per Mcf in 2019.
•In Egypt, the Company’s natural gas is sold to Egyptian General Petroleum Corporation (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 $2.79 per Mcf in 2020, a 1 percent decrease from 2019.
•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 $3.19 per Mcf in 2020, a 29 percent decrease from an average of $4.48 per Mcf in 2019.
NGL Prices Apache’s U.S. NGL production, which accounts for 96 percent of the Company’s total 2020 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 2020 totaled $3.1 billion, a $2.1 billion decrease from the 2019 total of $5.2 billion. A 34 percent decrease in average realized prices reduced 2020 revenues by $1.8 billion compared to 2019, while 11 percent lower average daily production decreased revenues by $343 million. Average daily production in 2020 was 214 Mb/d, with prices averaging $39.60 per barrel. Crude oil sales accounted for 77 percent of the Company’s 2020 oil and gas production revenues and 49 percent of its worldwide production.
The Company’s worldwide crude oil production decreased 25 Mb/d compared to 2019, primarily driven by natural decline in the U.S. and Egypt, a result of reduced activity in response to commodity price weakness. Production decreases for 2020 were partially offset by the Storr and Garten exploration discoveries in the North Sea coming on-line in late 2019 and early 2020, respectively.
Natural Gas Revenues
Natural gas revenues for 2020 totaled $598 million, an $80 million decrease from the 2019 total of $678 million. A 4 percent decrease in average realized prices reduced 2020 revenues by $24 million compared to 2019, while 9 percent lower average daily production decreased revenues by $56 million. Average daily production in 2020 was 893 MMcf/d, with prices averaging $1.83 per Mcf. Natural gas sales accounted for 15 percent of the Company’s 2020 oil and gas production revenues and 34 percent of its worldwide production.
The Company’s worldwide natural gas production decreased 87 MMcf/d compared to 2019, primarily a result of the sale of the Company’s Woodford-SCOOP and STACK plays and western Anadarko Basin assets in the U.S. in 2019 and natural decline in the U.S. and Egypt resulting from reduced activity levels.
NGL Revenues
NGL revenues for 2020 totaled $333 million, a $74 million decrease from the 2019 total of $407 million. A 25 percent decrease in average realized prices reduced 2020 revenues by $101 million compared to 2019, while 8 percent higher average daily production increased revenues by $27 million. Average daily production in 2020 was 77 Mb/d, with prices averaging $11.84 per barrel. NGL sales accounted for 8 percent of Apache’s 2020 oil and gas production revenues and 17 percent of its worldwide production.
The Company’s worldwide NGL production increased 6 Mb/d compared to 2019, primarily a result of the Alpine High development in recent years.
Altus Midstream Revenues
Apache beneficially owns approximately 79 percent of Altus’ outstanding voting common stock. Altus owns and operates a midstream energy asset network in the Permian Basin of West Texas primarily to service Apache’s production from its Alpine High resource play, which commenced production in May 2017.
Altus Midstream generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services. For the years ended December 31, 2020 and 2019, Altus Midstream’s services revenues generated through its fee-based contractual arrangements with Apache totaled $145 million and $136 million, respectively. These affiliated revenues are eliminated upon consolidation. The increase compared to the prior year was primarily driven by higher throughput of rich natural gas volumes at Alpine High due to increased capacity as a result of three cryogenic processing trains coming on line starting in the second quarter of 2019, partially offset by lower throughput of lean natural gas volumes.
Purchased Oil and Gas Sales
Purchased oil and gas sales increased $222 million for the year ended December 31, 2020 from $176 million to $398 million. Purchased oil and gas sales were primarily offset by associated purchase costs of $357 million and $142 million for the years ended December 31, 2020 and 2019, respectively.
Operating Expenses
The table below presents a comparison of the Company’s operating expenses for the years ended December 31, 2020, 2019, and 2018. All operating expenses include costs attributable to a noncontrolling interest in Egypt and Altus.
For the Year Ended December 31,
2020 2019 2018
(In millions)
Lease operating expenses $ 1,127 $ 1,447 $ 1,439
Gathering, processing, and transmission 274 306 348
Purchased oil and gas costs 357 142 340
Taxes other than income 123 207 215
Exploration 274 805 503
General and administrative 290 406 431
Transaction, reorganization, and separation 54 50 28
Depreciation, depletion, and amortization:
Oil and gas property and equipment 1,643 2,512 2,265
Gathering, processing, and transmission assets 76 105 83
Other assets 53 63 57
Asset retirement obligation accretion 109 107 108
Impairments 4,501 2,949 511
Financing costs, net 267 462 478
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 49 percent of the Company’s total 2020 production, is inherently more expensive to produce than natural gas. Repair and maintenance costs are typically higher on offshore properties.
During 2020, LOE decreased $320 million, or 22 percent, compared to 2019. On a per-boe basis, LOE decreased $1.38, or 16 percent, compared to 2019, from $8.38 per boe to $7.00 per boe, driven by reduced activity, labor costs, and fuel costs associated with lower commodity prices, the Company’s organizational redesign, and other cost cutting efforts. In addition, absolute dollar costs are lower in the current year as a result of the divestitures of the Company’s Woodford-SCOOP and STACK plays and western Anadarko Basin assets in the U.S. in the third quarter of 2019.
Gathering, Processing, and Transmission (GPT)
GPT expenses include amounts paid to third-party carriers and to Altus Midstream for gathering and transmission services for Apache’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,
2020 2019 2018
(In millions)
Third-party processing and transmission costs $ 236 $ 250 $ 294
Midstream service affiliate costs 143 134 77
Upstream processing and transmission costs 379 384 371
Midstream operating expenses 38 56 54
Intersegment eliminations (143) (134) (77)
Total Gathering, processing, and transmission $ 274 $ 306 $ 348
GPT costs decreased $32 million compared to 2019. Third-party processing and transmission costs decreased $14 million, primarily driven by a decrease in contracted pricing and the Company’s sale of non-core assets in Oklahoma and Texas. Midstream service affiliate costs increased $9 million compared to 2019, primarily driven by higher throughput of rich natural gas volumes at Alpine High. Midstream operating expenses, incurred primarily by Altus, decreased $18 million compared to 2019, primarily driven by increased operational efficiency as a result of transitioning from mechanical refrigeration units to Altus’ centralized Diamond cryogenic complex starting in the second quarter of 2019. The transition resulted in decreases in employee-related costs, contract labor, supplies expenses, and equipment rentals.
Purchased Oil and Gas Costs
Purchased oil and gas costs increased $215 million compared to 2019, and were more than offset by associated sales totaling $398 million for the year ended 2020.
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 decreased $84 million compared to 2019, primarily from lower severance taxes driven by lower commodity prices and the divestiture of the Company’s non-core assets in Oklahoma and Texas.
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,
2020 2019 2018
(In millions)
Unproved leasehold impairments $ 101 $ 619 $ 214
Dry hole expenses 110 57 137
Geological and geophysical expenses 20 59 55
Exploration overhead and other 43 70 97
Total Exploration $ 274 $ 805 $ 503
Exploration expenses decreased $531 million compared to 2019. Unproved leasehold impairments decreased $518 million, driven by higher leasehold impairments in 2019 associated with the Company’s decision to reallocate capital away from planned investment in the Alpine High play. Dry hole expense increased $53 million compared to 2019, primarily related to exploration wells in the U.S., Egypt, and the North Sea. Geological and geophysical expenses decreased $39 million and exploration overhead and other expenses decreased $27 million. The 2019 period reflects large-scale seismic surveys in Egypt and higher delay rentals in the U.S.
General and Administrative (G&A) Expenses
G&A expenses decreased $116 million compared to 2019, primarily related to cost-cutting measures associated with the Company’s organizational redesign efforts, as well as lower cash-based stock compensation expense resulting from a decrease in the Company’s stock price and a reduced payout of performance awards.
Transaction, Reorganization, and Separation (TRS) Costs
TRS costs increased $4 million compared to 2019, driven by costs associated with the Company’s reorganization efforts initiated in the second half of 2019.
In recent years, the Company has streamlined its portfolio through strategic divestitures and centralized certain operational activities in an effort to capture greater efficiencies and cost savings through shared services. During the second half of 2019, management initiated a comprehensive redesign of Apache’s organizational structure and operations that it believes will better position the Company to be competitive for the long-term and further reduce recurring costs. Reorganization efforts were substantially completed in 2020, and as a result of the reorganization, Apache has achieved an estimated cost savings of more than $400 million annually.
Depreciation, Depletion and Amortization (DD&A)
DD&A expenses on the Company’s oil and gas property for the year ended December 31, 2020, decreased $869 million compared to 2019. The Company’s oil and gas property DD&A rate decreased $4.35 per boe in 2020 compared to 2019, from $14.55 per boe to $10.20 per boe. The decrease was driven by lower production volumes and lower asset property balances associated with proved property impairments recorded in the first quarter of 2020 and in the fourth quarter of 2019. DD&A expense on the Company’s GPT depreciation decreased $29 million compared to 2019, driven by impairment charges recorded against the carrying value of Altus’ GPT facilities in the fourth quarter of 2019.
Impairments
During 2020, the Company recorded asset impairments in connection with fair value assessments totaling $4.5 billion, including $4.3 billion for oil and gas proved properties in the U.S, Egypt, and the North Sea, $68 million for GPT facilities in Egypt, $87 million for goodwill in Egypt, and $27 million for inventory and other miscellaneous assets, including lease assets and charges for the early termination of drilling rig leases.
During 2019, the Company recorded asset impairments totaling $2.9 billion in connection with fair value assessments, including $1.5 billion for oil and gas proved properties in the U.S. primarily in Alpine High, $1.3 billion impairment of GPT facilities primarily in the Altus Midstream reporting segment, $149 million on divested unproved properties and leasehold acreage in the western Anadarko Basin in Oklahoma and Texas, and $21 million of inventory and other miscellaneous assets, including office leasehold impairments from Apache’s announcement to close its San Antonio regional office. The impairments for Alpine High and Altus Midstream were associated with the Company’s fourth quarter 2019 capital plan allocation decision to materially reduce planned investment in the Alpine High play.
The following table presents a summary of asset impairments recorded for 2020, 2019, and 2018:
For the Year Ended December 31,
2020 2019 2018
(In millions)
Oil and gas proved property $ 4,319 $ 1,484 $ 328
GPT facilities 68 1,295 56
Equity method investment - - 113
Divested unproved properties and leasehold - 149 10
Goodwill 87 - -
Inventory and other 27 21 4
Total Impairments $ 4,501 $ 2,949 $ 511
Financing Costs, Net
Financing costs incurred during the period comprised the following:
For the Year Ended December 31,
2020 2019 2018
(In millions)
Interest expense $ 438 $ 430 $ 441
Amortization of debt issuance costs 8 7 9
Capitalized interest (12) (37) (44)
Loss (gain) on extinguishment of debt (160) 75 94
Interest income (7) (13) (22)
Total Financing costs, net $ 267 $ 462 $ 478
Net financing costs decreased $195 million compared to 2019, primarily the result of a $160 million gain on extinguishment of debt during 2020 compared to a $75 million loss on extinguishment of debt during 2019. In addition, capitalized interest decreased in the current year as a result of lower drilling activity and construction activity at Alpine High.
Provision for Income Taxes
Income tax expense decreased $610 million from $674 million during 2019 to $64 million during 2020. The Company’s year-to-date 2020 effective income tax rate was primarily impacted by oil and gas asset impairments, a goodwill impairment, and an increase in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s year-to-date 2019 effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets.
The Company recorded a full valuation allowance against its U.S. net deferred tax assets and will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance. For additional information regarding income taxes, refer to Note 10-Income Taxes in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Apache and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is currently under audit by the Internal Revenue Service (IRS) for the 2014-2017 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.
Capital and Operational Outlook
The Company continues to prudently manage its capital program against a volatile price environment and the prolonged effects of the COVID-19 pandemic. In response to the current crises, Apache’s immediate course of action has been to actively reduce its cost structure, protect its balance sheet, and manage operations to preserve cash flow. The Company plans to maintain a conservative investment approach into 2021, having announced an upstream capital program of $1.1 billion. The program consists of approximately $900 million for development activities and approximately $200 million for exploration, predominantly in Suriname.
The 2021 capital program assumes an average WTI price of $45 per barrel and a Henry Hub natural gas price of $3.00 per Mcf. In 2020, a higher percentage of development capital was directed toward international projects that generate better returns in a lower price environment. With the improvement in oil prices, the Company is returning to a modest level of activity in the U.S. Under the capital budget for 2021, activity includes:
•continuing to advance exploratory and appraisal programs in Suriname under the terms of the Company’s joint venture with Total S.A.;
•running one rig in the Permian Basin, with the expectation to add a second rig in the middle of the year, while resuming completion activity for its previously drilled but uncompleted well inventory in response to significantly lower service costs;
•continuing to run a five rig drilling program in Egypt with the ability to quickly flex spending as conditions warrant; and
•maintaining a capital program in the North Sea relatively unchanged from the prior year with one floating rig and one platform crew.
The Company’s proactive reduction in capital spending in 2020 directly impacted global oil volumes which decreased by 17 percent from the fourth quarter of 2019 to the fourth quarter of 2020. Based on its 2021 upstream investment plan and allocation, the Company is projecting a more moderate decline of one percent for the comparable 2021 period. Forecasting into 2022 and future years, Apache’s goal is to establish a development capital investment budget that will, at a minimum, at least sustain production volumes for the longer-term.
Apache’s strategic approach and multi-year outlook prioritizes retaining cash flow to reduce outstanding debt, focusing on long-term returns over short-term growth, aggressively managing its cost structure, and advancing exploration and appraisal activities in Suriname.
The Company’s diversified global portfolio provides the ability to quickly optimize capital allocation as market conditions change. The current crisis, however, is still evolving and may become more severe and complex. As a result, the COVID-19 pandemic may still materially and adversely affect Apache’s results in a manner that is either not currently known or that the Company does not currently consider to be a significant risk to its business. For additional information about the business risks relating to the COVID-19 pandemic and related governmental actions, refer to Part I, Item 1A - Risk Factors of this Annual Report on Form 10-K.
Separate from the Company’s upstream oil and gas activities, capital spending for Altus’ gathering and processing assets totaled $28 million in 2020, down from $327 million in 2019 when a majority of the midstream infrastructure construction was completed. Altus management believes its existing gathering, processing, and transmission infrastructure capacity is capable of fulfilling its midstream contracts to service Apache’s production from Alpine High and any third-party customers. As such, remaining capital requirements for its existing infrastructure assets during 2021 and 2022 are anticipated to be minimal.
Additionally, during the years ended December 31, 2020 and 2019, Altus made cash contributions totaling $327 million and $501 million, respectively, for its equity interests in the following Equity Method Interest Pipelines:
•16 percent in the Gulf Coast Express natural gas pipeline (GCX);
•15 percent in the EPIC crude pipeline (EPIC);
•an approximate 26.7 percent in the Permian Highway natural gas pipeline (PHP); and
•33 percent in the Shin Oak NGL pipeline (Shin Oak).
Altus estimates it will incur approximately $30 million of additional capital contributions during 2021 for its equity interest associated with the commissioning and remaining construction costs in the Equity Method Interest Pipelines, primarily associated with PHP. During 2020, Altus’ primary sources of cash were borrowings under the revolving credit facility, cash generated from operations, distributions from the Equity Method Interest Pipelines, and proceeds from the sale of assets. Based on Altus’ current financial plan and related assumptions, it believes that cash from operations, a reduced capital program for its midstream infrastructure, and distributions from equity method interests will generate cash flows significantly in excess of capital expenditures that will provide sufficient cash to fund its planned dividend program during 2021.
For further information on the Equity Method Interest Pipelines, refer to Note 6-Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Capital Resources and Liquidity
Operating cash flows are the Company’s primary source of liquidity. Apache’s operating cash flows, both in the short-term and the long-term, are impacted by highly volatile oil and natural gas prices, as well as costs and sales volumes. Significant changes in commodity prices impact Apache’s revenues, earnings and cash flows. These changes potentially impact Apache’s liquidity if costs do not trend with changes in commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.
Apache’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of Apache’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves. For the year ended December 31, 2020, Apache recognized negative reserve revisions of approximately 7 percent of its year-end 2019 estimated proved reserves as a result of lower prices. The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2020, 2019, and 2018, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 18-Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Combined with proactive measures to adjust its capital budget, decrease its dividend, protect further downside price risk through entering into new hedge positions, and reduce its operating cost structure in the current volatile commodity price environment, Apache believes the liquidity and capital resource alternatives available to the Company will be adequate to fund its operations and provide flexibility until commodity prices and industry conditions improve. This includes supporting the Company’s capital development program, repayment of debt maturities, payment of dividends, and any amount that may ultimately be paid in connection with commitments and contingencies.
The Company may also elect to utilize available cash on hand, committed borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for all other liquidity and capital resource needs.
For additional information, please see Part I, Items 1 and 2-Business and Properties and Part I, Item 1A - Risk Factors of this Annual Report on Form 10-K.
Sources and Uses of Cash
The following table presents the sources and uses of the Company’s cash and cash equivalents for the years presented:
For the Year Ended December 31,
2020 2019 2018
(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities $ 1,388 $ 2,867 $ 3,777
Proceeds from Apache credit facility, net 150 - -
Proceeds from Altus credit facility, net 228 396 -
Proceeds from Altus transaction - - 628
Proceeds from asset divestitures 166 718 138
Fixed-rate debt borrowings 1,238 989 992
Redeemable noncontrolling interest - Altus Preferred Unit limited partners - 611 -
3,170 5,581 5,535
Uses of Cash and Cash Equivalents:
Additions to oil and gas property(1)
$ 1,270 $ 2,594 $ 3,190
Additions to Altus gathering, processing, and transmission facilities(1)
28 327 581
Leasehold and property acquisitions 4 40 133
Contributions to Altus equity method interests 327 501 -
Acquisition of Altus equity method interests - 671 91
Payments on fixed-rate debt 1,243 1,150 1,370
Dividends paid 123 376 382
Distributions to noncontrolling interest - Egypt 91 305 345
Distributions to Altus Preferred Unit limited partners 23 - -
Shares repurchased - - 305
Other 46 84 92
3,155 6,048 6,489
Increase (decrease) in cash and cash equivalents $ 15 $ (467) $ (954)
(1)The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this Annual Report on Form 10-K, which include accruals.
Sources of Cash and Cash Equivalents
Net Cash Provided by Operating Activities Operating cash flows are the Company’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile crude oil and natural gas prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense.
Net cash provided by operating activities for the year ended December 31, 2020 totaled $1.4 billion, down $1.5 billion from the year ended December 31, 2019. The decrease primarily reflects lower commodity prices compared to the prior year.
For a detailed discussion of commodity prices, production, and operating expenses, refer to “Results of Operations” in this Item 7. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, refer to the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Proceeds from Apache Credit Facility, Net As of December 31, 2020, there were $150 million of borrowings outstanding under Apache’s credit facility, which is classified as long-term debt. The Company had no borrowings under the revolver as of December 31, 2019.
Proceeds from Altus Credit Facility, Net The initial construction of Altus’ gathering and processing assets and the exercise of its Pipeline Options for its equity interests in the Equity Method Interest Pipelines has historically required capital expenditures in excess of Altus’ cash on hand and operational cash flows. During the years ended December 31, 2020 and 2019, Altus Midstream borrowed $228 million and $396 million, respectively, under its revolving credit facility. With the initial midstream infrastructure construction complete and each of Shin Oak, GCX, PHP, and EPIC now in service, the Company anticipates that Altus’ existing capital resources will be sufficient to fund its continuing obligations and planned dividend program during 2021.
Proceeds from Asset Divestitures The Company recorded proceeds from non-core asset divestitures totaling $166 million and $718 million for the years ended December 31, 2020 and 2019, respectively. For more information regarding the Company’s acquisitions and divestitures, refer to Note 2-Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part IV set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Fixed-Rate Debt Borrowings On August 17, 2020, the Company closed offerings of $1.25 billion in aggregate principal amount of senior unsecured notes, comprised of $500 million in aggregate principal amount of 4.625% notes due 2025 and $750 million in aggregate principal amount of 4.875% notes due 2027. The senior unsecured notes are redeemable at any time, in whole or in part, at Apache’s option, at the applicable redemption price. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers, repay a portion of outstanding borrowings under the Company’s senior revolving credit facility, and for general corporate purposes.
On June 19, 2019, Apache closed offerings of $1.0 billion in aggregate principal amount of senior unsecured notes, comprised of $600 million in aggregate principal amount of 4.250% notes due January 15, 2030 (2030 notes) and $400 million in aggregate principal amount of 5.350% notes due July 1, 2049 (2049 notes). The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The aggregate net proceeds of $989 million from the sale of the notes were used to purchase certain outstanding notes in cash tender offers and for general corporate purposes.
Redeemable Noncontrolling Interest - Altus Preferred Unit Limited Partners On June 12, 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units for an aggregate issue price of $625 million in a private offering exempt from the registration requirements of the Securities Act of 1933, as amended. Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. For more information, refer to Note 13-Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Uses of Cash and Cash Equivalents
Additions to Oil & Gas Property Exploration and development cash expenditures were $1.3 billion and $2.6 billion for the years ended December 31, 2020 and 2019, respectively. The decrease in capital investment is reflective of the Company’s reduced capital program as the Company eliminated nearly all drilling and completion activities in the U.S. by May 2020 in response to commodity price impacts stemming from the COVID-19 pandemic. A majority of the current year expenditures shifted from the Company’s Permian Basin assets to its Egypt assets over the second half of 2020. The Company operated an average of 12 drilling rigs during 2020 compared to 23 drilling rigs during 2019.
Additions to Altus Gathering, Processing, and Transmission (GPT) Facilities The Company’s cash expenditures for GPT facilities totaled $28 million and $327 million during 2020 and 2019, respectively, nearly all comprising midstream infrastructure expenditures incurred by Altus, which were substantially completed as of December 31, 2019. Altus management believes its existing GPT infrastructure capacity is capable of fulfilling its midstream contracts to service Apache’s production from Alpine High and any third-party customers. As such, Altus expects capital requirements for its existing infrastructure assets for 2021 and 2022 to be minimal.
Leasehold and Property Acquisitions During 2020 and 2019, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $4 million and $40 million, respectively.
Contributions to Altus Equity Method Interests Altus made contributions of $327 million and $501 million during 2020 and 2019, respectively, for equity interests in the Equity Method Interest Pipelines. For more information regarding the Company’s equity method interests, refer to Note 6-Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Acquisitions of Altus Equity Method Interests Altus made acquisitions of equity method interests totaling $671 million during the year ended December 31, 2019. For more information regarding the Company’s equity method interests, refer to Note 6-Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Payments on Fixed-Rate Debt On August 18, 2020, the Company closed cash tender offers for certain outstanding notes. The Company accepted for purchase $644 million aggregate principal amount of certain notes covered by the tender offers. The Company paid holders an aggregate $644 million reflecting principal, aggregate discount to par of $38 million, early tender premium of $32 million, and accrued and unpaid interest of $6 million. The Company recorded a net gain of $2 million on extinguishment of debt, including an acceleration of unamortized debt discount and issuance costs, in connection with the note purchases.
During 2020, the Company purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $588 million for an aggregate purchase price of $428 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $168 million. These repurchases resulted in a $158 million net gain on extinguishment of debt. The net gain includes an acceleration of related discount and debt issuance costs. Additionally, on November 3, 2020, Apache redeemed the $183 million of 3.625% senior notes due February 1, 2021 at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The repurchases were financed by borrowings under the Company’s revolving credit facility.
On June 21, 2019, the Company closed cash tender offers for certain outstanding notes. Apache accepted for purchase $932 million aggregate principal amount of notes for approximately $1.0 billion, which included principal, the net premium to par, and an early tender premium totaling $28 million, as well as accrued and unpaid interest of $14 million. The Company recorded a net loss of $75 million on extinguishment of debt, including $7 million of unamortized debt issuance costs and discounts, in connection with the note purchases. Additionally, on July 1, 2019, Apache’s 7.625% senior notes in original principal amount of $150 million matured and were repaid.
Dividends The Company paid $123 million and $376 million cash dividends on its common stock for the years ended December 31, 2020 and 2019, respectively. In the first quarter of 2020, Apache’s Board of Directors approved a reduction in the Company’s quarterly dividend per share from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020.
Distributions to Noncontrolling Interests - Egypt Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in Apache’s oil and gas operations in Egypt. The Company made cash distributions totaling $91 million and $305 million to Sinopec during the years ended December 31, 2020 and 2019, respectively.
Distributions to Altus Preferred Units limited partners Altus Midstream LP paid cash distributions of $23 million to its limited partners holding Preferred Units for the year ended December 31, 2020. No cash distributions were made during 2019. For more information regarding the Preferred Units, refer to Note 13-Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Liquidity
The following table presents a summary of the Company’s key financial indicators as of December 31,:
2020 2019
(In millions)
Cash and cash equivalents $ 262 $ 247
Total debt - Apache 8,148 8,170
Total debt - Altus 624 396
Total equity (deficit) (645) 4,465
Available committed borrowing capacity - Apache 2,944 4,000
Available committed borrowing capacity - Altus 176 404
Cash and Cash Equivalents As of December 31, 2020, the Company had $262 million in cash and cash equivalents, of which approximately $24 million was held by Altus. The majority of the Company’s cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.
Debt As of December 31, 2020, outstanding debt, which consisted of notes, debentures, credit facility borrowings, and finance lease obligations, totaled $8.8 billion. As of December 31, 2020, current debt included $2 million of finance lease obligations. Apache intends to reduce debt outstanding under its indentures from time to time.
Available Credit Facilities In March 2018, the Company entered into a revolving credit facility with commitments totaling $4.0 billion. In March 2019, the term of this facility was extended by one year to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise of an extension option. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of December 31, 2020. The facility is for general corporate purposes. Letters of credit are available for security needs, including in respect of North Sea decommissioning obligations. The facility has no collateral requirements, is not subject to borrowing base redetermination, and has no drawdown restrictions or prepayment obligations in the event of a decline in credit ratings.
As of December 31, 2020, there were $150 million of borrowings and an aggregate £633 million and $40 million in letters of credit outstanding under this facility. As of December 31, 2019, there were no borrowings or letters of credit outstanding under this facility. The £633 million in outstanding letters of credit were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced the Company’s credit rating from BBB to BB+ on March 26, 2020.
At Apache’s option, the interest rate per annum for borrowings under the 2018 facility is either a base rate, as defined, plus a margin, or the London Inter-bank Offered Rate (LIBOR), plus a margin. Apache also pays quarterly a facility fee at a per annum rate on total commitments. The margins and the facility fee vary based upon the Company’s senior long-term debt rating. At December 31, 2020, the base rate margin was 0.5 percent, the LIBOR margin was 1.50 percent, and the facility fee was 0.25 percent. A commission is payable quarterly to lenders on the face amount of each outstanding letter of credit at a per annum rate equal to the LIBOR margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks.
The financial covenants of the credit facility require Apache to maintain an adjusted debt-to-capital ratio of not greater than 60 percent at the end of any fiscal quarter. For purposes of this calculation, capital excludes the effects of non-cash write-downs, impairments, and related charges occurring after June 30, 2015. At December 31, 2020, Apache’s debt-to-capital ratio as calculated under the credit facility was 32 percent. The 2018 facility’s negative covenants restrict the ability of Apache and its subsidiaries to create liens securing debt on their hydrocarbon-related assets, with exceptions for liens typically arising in the oil and gas industry; liens securing debt incurred to finance the acquisition, construction, improvement, or capital lease of assets, provided that such debt, when incurred, does not exceed the subject purchase price and costs, as applicable, and related expenses; liens on subsidiary assets located outside of the United States and Canada; and liens arising as a matter of law, such as tax and mechanics’ liens. Apache also may incur liens on assets if debt secured thereby does not exceed 15 percent of Apache’s consolidated net tangible assets, or approximately $1.7 billion as of December 31, 2020. Negative covenants also restrict Apache’s ability to merge with another entity unless it is the surviving entity, dispose of substantially all of its assets, and guarantee debt of non-consolidated entities in excess of the stated threshold.
In November 2018, Altus Midstream LP entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream LP’s two, one-year extension options). The agreement for this facility, as amended, provides aggregate commitments from a syndicate of banks of $800 million. All aggregate commitments include a letter of credit subfacility of up to $100 million and a swingline loan subfacility of up to $100 million. Altus Midstream LP may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of December 31, 2020 and 2019, there were $624 million and $396 million, respectively, of borrowings and no letters of credit outstanding under this facility.
The agreement for Altus Midstream LP’s credit facility, as amended, restricts distributions in respect of capital to Apache and other unit holders in certain circumstances. Unless the Leverage Ratio is less than or equal to 4.00:1.00, the agreement limits such distributions to $30 million per calendar year until either (i) the consolidated net income of Altus Midstream LP and its restricted subsidiaries, as adjusted pursuant to the agreement, for three consecutive calendar months equals or exceeds $350.0 million on an annualized basis or (ii) Altus Midstream LP has a specified senior long-term debt rating; in addition, before the occurrence of one of those two events, the Leverage Ratio must be less than or equal to 5.00:1.00. In no event can any distribution be made that would, after giving effect to it on a pro forma basis, result in a Leverage Ratio greater than (i) 5.00:1.00 or (ii) for a specified period after a qualifying acquisition, 5.50:1.00. The Leverage Ratio is the ratio of (1) the consolidated indebtedness of Altus Midstream LP and its restricted subsidiaries to (2) EBITDA (as defined in the agreement) of Altus Midstream LP and its restricted subsidiaries for the 12-month period ending immediately before the determination date. The Leverage Ratio as of December 31, 2020 was less than 4.00:1.00.
The terms of Altus Midstream LP’s Series A Cumulative Redeemable Preferred Units also contain certain restrictions on distributions in respect of capital, including the common units held by Apache and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation. Refer to Note 13-Redeemable Noncontrolling Interest - Altus set forth in Part IV, Item 15 of this Annual Report on Form 10-K for further information. In addition, the amount of any cash distributions to Altus Midstream LP by any entity in which it has an interest accounted for by the equity method is subject to such entity’s compliance with the terms of any debt or other agreements by which it may be bound, which in turn may impact the amount of funds available for distribution by Altus Midstream LP to its partners.
The Altus Midstream LP credit facility is unsecured and is not guaranteed by Apache or any of Apache’s other subsidiaries.
There are no clauses in either the agreement for Apache’s 2018 credit facility or for Altus Midstream LP’s 2018 credit facility that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. These agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, each agreement allows the lenders to accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches, and if a borrower or any of its subsidiaries defaults on other indebtedness in excess of the stated threshold, is insolvent, or has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold. Lenders may also accelerate payment maturity and terminate lending and issuance commitments under the applicable agreement if Apache or Altus Midstream LP, as applicable, undergoes a specified change in control or any borrower has specified pension plan liabilities in excess of the stated threshold. Each of Apache and Altus Midstream LP was in compliance with the terms of its 2018 credit facility as of December 31, 2020.
There is no assurance of the terms upon which potential lenders under future credit facilities will make loans or other extensions of credit available to Apache or its subsidiaries or the composition of such lenders.
There is no assurance that the financial condition of banks with lending commitments to Apache or Altus Midstream LP will not deteriorate. We closely monitor the ratings of the banks in our bank groups. Having large bank groups allows the Company to mitigate the potential impact of any bank’s failure to honor its lending commitment.
Commercial Paper Program Apache’s $3.5 billion commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days. As a result of downgrades in Apache’s credit ratings during 2020, the Company does not expect that its commercial paper program will be cost competitive with its other financing alternatives and does not anticipate using it under such circumstances. As of December 31, 2020 and 2019, the Company had no commercial paper outstanding.
Contractual Obligations
The following table summarizes the Company’s contractual obligations as of December 31, 2020. For additional information regarding these obligations, refer to Note 9-Debt and Financing Costs and Note 11-Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
On-Balance Sheet Off-Balance Sheet
Obligations by Period Debt, at Face Value Apache Credit Facility(1)
Altus Credit Facility(1)
Interest Payments Finance Leases(2)
Operating Leases(3)
Purchase Obligations(4)
Total(5)
(In millions)
2021 $ - $ - $ - $ 415 $ 3 $ 120 $ 236 $ 774
2022 213 - - 397 3 70 203 886
2023 123 - 624 392 3 33 203 1,378
2024 - 150 - 391 4 27 160 732
2025 500 - - 391 4 7 159 1,061
Thereafter 7,216 - - 4,404 29 25 600 12,274
Total $ 8,052 $ 150 $ 624 $ 6,390 $ 46 $ 282 $ 1,561 $ 17,105
(1)Includes outstanding principal amounts at December 31, 2020. This table does not include future commitment fees, interest expense, or other fees on the Company’s credit facilities because they are floating rate instruments, and management cannot determine with accuracy the timing of future loan advances, repayments, or future interest rates to be charged.
(2)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.
(3)Amounts represent future lease payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense.
(4)Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $120 million, $111 million, and $132 million for 2020, 2019, and 2018, respectively.
(5)This table does not include the Company’s liability for dismantlement, abandonment, and restoration costs of oil and gas properties or pension or postretirement benefit obligations. For additional information regarding these liabilities, please see Notes 8-Asset Retirement Obligation and Note 12-Retirement and Deferred Compensation Plans, respectively, in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Apache is also subject to various contingent obligations that become payable only if certain events or rulings were to occur. The inherent uncertainty surrounding the timing of and monetary impact associated with these events or rulings prevents any meaningful accurate measurement, which is necessary to assess settlements resulting from litigation. Apache’s management believes that it has adequately reserved for its contingent obligations, including approximately $2 million for environmental remediation and approximately $70 million for various contingent legal liabilities. For a detailed discussion of the Company’s lease obligations, purchase obligations, environmental and legal contingencies, and other commitments, please see Note 11-Commitments and Contingencies and Note 12-Retirement and Deferred Compensation Plans in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
As further described above under “Capital and Operational Outlook,” Altus Midstream LP and/or its subsidiaries have exercised four of the five Pipeline Options to acquire equity interests in the Equity Method Interest Pipelines. The fifth Pipeline Option to acquire an equity interest in a separate intra-basin NGL pipeline was not exercised and expired on March 2, 2020. Following the exercise of each Pipeline Option, Altus Midstream LP and/or its subsidiaries may be required to fund future capital expenditures for its equity interest share in the development of the applicable pipeline. The Company estimates that Altus, based on its equity interests in each pipeline, will incur approximately $30 million of additional capital contributions for its equity interests during 2021.
With respect to oil and gas operations in the Gulf of Mexico, the Bureau of Ocean Energy Management (BOEM) issued a Notice to Lessees (NTL No. 2016-N01) significantly revising the obligations of companies operating in the Gulf of Mexico to provide supplemental assurances of performance with respect to plugging, abandonment, and decommissioning obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies’ oil and gas leases. While the NTL was paused in mid-2017 and is currently listed on BOEM’s website as “rescinded,” if reinstated, the NTL will likely require that Apache provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to Apache’s current ownership interests in various Gulf of Mexico leases. The Company is working closely with BOEM to make arrangements for the provision of such additional required security, if such security becomes necessary under the NTL. Additionally, the Company is not able to predict the effect that these changes might have on counterparties to which Apache has sold Gulf of Mexico assets or with whom Apache has joint ownership. Such changes could cause the bonding obligations of such parties to increase substantially, thereby causing a significant impact on the counterparties’ solvency and ability to continue as a going concern.
Potential Asset Retirement Obligations
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 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 our Gulf of Mexico 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, the Company sold its Gulf of Mexico Shelf operations and properties (Transferred Assets) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, the Company received cash consideration of $3.75 billion and Fieldwood assumed $1.5 billion of discounted asset abandonment liabilities as of the disposition date. In respect of such abandonment liabilities, Fieldwood posted letters of credit in favor of the Company (Letters of Credit) and established a trust account (Trust A), which is funded by a 10 percent net profits interest depending on future oil prices and of which the Company is the beneficiary. 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 the Company agreed, inter alia, to accept bonds in exchange for certain of the Letters of Credit. Currently, the Company holds two bonds (Bonds) and the remaining Letters of Credit to secure Fieldwood’s asset retirement obligations (AROs) on the Transferred Assets as and when such abandonment and decommissioning obligations are required to be performed over the remaining life of the Transferred Assets.
On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Fieldwood has submitted a plan of reorganization, and the Company has been engaged in discussions with Fieldwood and other interested parties regarding such plan. If approved by the bankruptcy court, the submitted plan would separate the Transferred Assets into a standalone company, and proceeds of production of the Transferred Assets will be used for the AROs. If the proceeds of production are insufficient for such AROs, then Apache expects that it may be required by the relevant governmental authorities to perform such AROs, in which case it will apply the Bonds, remaining Letters of Credit, and Trust A to pay for the AROs. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan of up to $400 million for the new company to perform decommissioning, with such standby loan secured by a first and prior lien on the Transferred Assets. If the foregoing is insufficient, the Company may be forced to use available cash to cover any additional costs it incurs for performing such AROs.
Insurance Program
Apache maintains insurance policies that include coverage for physical damage to its assets, general liabilities, workers’ compensation, employers’ liability, sudden and accidental pollution, and other risks. The Company’s insurance coverage is subject to deductibles or retentions that it must satisfy prior to recovering on insurance. Additionally, the Company’s insurance is subject to policy exclusions and limitations. There is no assurance that insurance will adequately protect Apache 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.
Current insurance policies covering physical damage to the Company’s assets provide up to $1 billion in coverage per occurrence. These policies also provide sudden and accidental pollution coverage. The Company’s current insurance policies covering general liabilities provide $500 million in coverage, scaled to Apache’s interest. Service agreements, including drilling contracts, generally indemnify Apache for injuries and death of the service provider’s employees as well as subcontractors hired by the service provider.
Apache purchases multi-year political risk insurance from U.S. International Development Finance Corporation (DFC), successor to Overseas Private Investment Corporation (OPIC), and highly-rated insurers covering a portion of its investments in Egypt for losses arising from confiscation, nationalization, and expropriation risks. The Islamic Corporation for the Insurance of Investment and Export Credit (ICIEC, an agency of the Islamic Development Bank) reinsures DFC. In the aggregate, these insurance policies provide up to $750 million of coverage, subject to policy terms and conditions and a retention of approximately $500 million.
Apache has an additional insurance policy with DFC, which, subject to policy terms and conditions, provides up to $300 million of coverage through 2024 for losses arising from (1) non-payment by EGPC of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of exportable petroleum in the event that actions taken by the government of Egypt prevent Apache from exporting our share of production. The Multilateral Investment Guarantee Agency (MIGA), a member of the World Bank Group, provides $150 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
Apache prepares its financial statements and the accompanying notes in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions about future events that affect the reported amounts in the financial statements and the accompanying notes. Apache identifies certain accounting policies involving estimation as critical based on, among other things, their impact on the portrayal of Apache’s financial condition, results of operations, or liquidity and the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting estimates cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. Management routinely discusses the development, selection, and disclosure of each of the Company’s critical accounting estimates. The following is a discussion of Apache’s most critical accounting estimates.
Reserves Estimates
Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations.
Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time.
Despite the inherent imprecision in these engineering estimates, the Company’s reserves are used throughout its financial statements. For example, since the Company uses the units-of-production method to amortize its oil and gas properties, the quantity of reserves could significantly impact DD&A expense. A material adverse change in the estimated volumes of reserves could result in property impairments. Finally, these reserves are the basis for Apache’s supplemental oil and gas disclosures. For more information regarding Apache’s supplemental oil and gas disclosures, Refer to Note 18-Supplemental Oil and Gas Disclosures (Unaudited) in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report on Form 10-K.
Reserves are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 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.
Apache has elected not to disclose probable and possible reserves or reserve estimates in this filing.
Oil and Gas Exploration Costs
Apache 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.
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, 2019, and 2018. 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. Apache’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 Apache’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 our 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 we view and manage our ongoing market risk exposures.
Commodity Price Risk
The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. These factors have only been heightened as the result of continuing negative demand implications of the COVID-19 pandemic. The Company continually monitors its market risk exposure, including the impact and developments related to the COVID-19 pandemic, which introduced significant volatility in the financial markets subsequent to the year ended December 31, 2019.
The Company’s average crude oil realizations decreased 34 percent to $39.60 per barrel in 2020 from $60.05 per barrel in 2019. The Company’s average natural gas price realizations decreased 4 percent to $1.83 per Mcf in 2020 from $1.90 per Mcf in 2019. The Company’s average NGL realizations decreased 25 percent to $11.84 per barrel in 2020 from $15.74 per barrel in 2019. Based on average daily production for 2020, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $78 million, a $0.10 per Mcf change in the weighted average realized price of natural gas would have increased or decreased revenues for the year by approximately $33 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 $28 million.
Apache periodically enters into derivative positions on a portion of its projected oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Such derivative positions may include the use of futures contracts, swaps, and/or options. Apache does not hold or issue derivative instruments for trading purposes. As of December 31, 2020, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $11 million. The impact of a 10 percent movement in natural gas prices would be immaterial to the fair value of the commodity derivatives. These fair value changes assume volatility based on prevailing market parameters at December 31, 2020. See Note 4-Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Annual Report Form 10-K for notional volumes and terms with the Company’s derivative contracts.
Interest Rate Risk
At December 31, 2020, Apache had approximately $8.1 billion net carrying value of notes and debentures outstanding, all of which was fixed-rate debt, with a weighted average interest rate of 4.98 percent. Although near-term changes in interest rates may affect the fair value of Apache’s fixed-rate debt, they do not expose the Company to the risk of earnings or cash flow loss associated with that debt. Apache is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under its commercial paper program and credit facilities. As of December 31, 2020, the Company’s cash and cash equivalents totaled approximately $262 million, approximately 46 percent of which was invested in money market funds and short-term investments with major financial institutions. As of December 31, 2020, the Company had credit facility borrowings of $150 million and $624 million under its Apache and Altus credit facilities, respectively. A change in the interest rate applicable to the Company’s 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 under its commercial paper program, revolving credit facilities, and money market lines of credit.
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, and the majority of costs incurred are paid in British pounds. In Egypt, substantially all oil and gas production is sold under U.S. dollar contracts, and the majority of the 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. 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 $5 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of December 31, 2020.
The Company is subject to increased foreign currency risk associated with the effects of the U.K.’s withdrawal from the European Union. Apache has periodically entered into foreign exchange contracts in order to minimize the impact of fluctuating exchange rates for the British pound on the Company’s operating expenses. The Company had no outstanding foreign exchange derivative contracts as of December 31, 2020.

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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, 2020, 2019, and 2018, 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 our disclosure controls and procedures as of December 31, 2020, the end of the period covered by this report. 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 we are 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. We made no changes in internal controls over financial reporting during the quarter ending December 31, 2020, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
We periodically review the design and effectiveness of our disclosure controls, including compliance with various laws and regulations that apply to our operations both inside and outside the United States. We make modifications to improve the design and effectiveness of our disclosure controls and may take other corrective action, if our reviews identify deficiencies or weaknesses in our controls.
Management’s Annual Report on Internal Control Over Financial Reporting; Attestation Report of the Registered Public Accounting Firm
The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to the “Report of Management on Internal Control Over Financial Reporting,” included on Page in Part IV, Item 15 of this Annual Report on Form 10-K.
The independent auditors attestation report called for by Item 308(b) of Regulation S-K is incorporated herein by reference to the “Report of Independent Registered Public Accounting Firm,” included on Page through in Part IV, Item 15 of this Annual Report on Form 10-K.
Changes in Internal Control over Financial Reporting
There was no change in our internal controls over financial reporting during the quarter ending December 31, 2020, 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.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information set forth under the captions “Nominees for Election as Directors,” “Continuing Directors,” “Information About Our Executive Officers,” and “Securities Ownership and Principal Holders” in the proxy statement relating to the Company’s 2021 annual meeting of shareholders (the Proxy Statement) is incorporated herein by reference.
On January 4, 2021, the Company announced that its Board of Directors authorized the Company to proceed with the implementation of a holding company reorganization, in connection with which, the Company will create APA Corporation, a new holding company (APA). Upon completion of the holding company reorganization, the Company will be a wholly-owned subsidiary of APA, APA will be the successor issuer to the Company pursuant to Rule 12g-3(a) under the Exchange Act, and APA will replace the Company as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA”. If the holding company reorganization is completed prior to the date that the Proxy Statement is filed with the SEC, then the Proxy Statement will be filed by APA, as successor issuer to the Company.
Code of Business Conduct
Pursuant to Rule 303A.10 of the NYSE and Rule 5610 of the Nasdaq, we are required to adopt a code of business conduct and ethics for our directors, officers, and employees. In February 2004, the Board of Directors adopted the Code of Business Conduct and Ethics (Code of Conduct) and revised it in September 2020. The revised Code of Conduct also meets the requirements of a code of ethics under Item 406 of Regulation S-K. You can access the Company’s Code of Conduct on the Governance page of the Company’s website at www.apachecorp.com. Any shareholder who so requests may obtain a printed copy of the Code of Conduct by submitting a request to the Company’s corporate secretary at the address on the cover of this Annual Report on Form 10-K. Changes in and waivers to the Code of Conduct for the Company’s directors, chief executive officer and certain senior financial officers will be posted on the Company’s website within four business days and maintained for at least 12 months. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

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

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

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

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

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)Documents included in this report:
1. Financial Statements
Report of management on internal control over financial reporting
Report of independent registered public accounting firm
Report of independent registered public accounting firm
Statement of consolidated operations for each of the three years in the period ended December 31, 2020
Statement of consolidated comprehensive income (loss) for each of the three years in the period ended December 31, 2020
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2020
Consolidated balance sheet as of December 31, 2020 and 2019
Statement of consolidated changes in equity (deficit) and noncontrolling interest for each of the three years in the period ended December 31, 2020
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
3.1 - Restated Certificate of Incorporation of Registrant, dated September 19, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed September 20, 2013, SEC File No. 001-4300).
3.2 - Certificate of Amendment of Restated Certificate of Incorporation of Registrant, dated May 14, 2015, as filed with the Secretary of State of Delaware on May 14, 2015 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed May 20, 2015, SEC File No. 001-04300).
3.3 - Amended and Restated Bylaws of Registrant, dated October 31, 2019 (incorporated by reference to Exhibit 3.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, 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 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).
4.3 - 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).
4.4 - Form of 3.25% Note due 2022 (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K, dated April 3, 2012, filed on April 9, 2012, SEC File No. 001-4300).
4.5 - 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).
4.6 - Form of 2.625% Notes due 2023 (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K, dated November 28, 2012, filed on December 4, 2012, SEC File No. 001-4300).
4.7 - 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).
4.8 - 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).
4.9 - 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).
4.10 - Form of 4.875% Notes due 2027 (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).
4.11 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).
EXHIBIT
NO. DESCRIPTION
4.12 - 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).
4.13 - 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).
4.14 - 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).
4.15 - 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).
4.16 - 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).
4.17 - 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).
4.18 - 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).
4.19 - 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).
4.20 - 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).
4.21 - Description of Equity Securities of the Registrant (incorporated by reference to Exhibit 4.26 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
10.1 - Credit Agreement, dated as of March 14, 2018, among Apache 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, Citibank, N.A., Royal Bank of Canada, HSBC Bank USA, National Association, The Bank of Tokyo-Mitsubishi UFJ, Ltd, Wells Fargo Bank, National Association, Goldman Sachs Bank USA, The Toronto-Dominion Bank, New York Branch, and Mizuho Bank, Ltd., as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed March 19, 2018).
†10.2 - Apache Corporation 401(k) Savings Plan, as amended and restated, dated March 17, 2015, effective January 31, 2014 (incorporated by reference to Exhibit 10.15 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.3 - Amendment to Apache Corporation 401(k) Savings Plan, dated April 17, 2014 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, SEC File No. 001-4300).
†10.4 - Amendment to Apache Corporation 401(k) Savings Plan, dated May 16, 2014 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.5 - Amendment to Apache Corporation 401(k) Savings Plan, effective February 3, 2016 (incorporated by reference to Exhibit 10.18 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
EXHIBIT
NO. DESCRIPTION
†10.6 - 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).
†10.7 - 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).
†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 - Apache Corporation 2016 Omnibus Compensation Plan, dated February 3, 2016, effective May 12, 2016 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed May 16, 2016, SEC File No. 001-4300).
†10.10 - First Amendment to the Apache Corporation 2016 Omnibus Compensation Plan, dated July 29, 2019 (incorporated by reference to Exhibit 10.13 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.11 - Apache Corporation 2011 Omnibus Equity Compensation Plan, as amended and restated May 12, 2016 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.12 - First Amendment to the Apache Corporation 2011 Omnibus Equity Compensation Plan, dated July 29, 2019 (incorporated by reference to Exhibit 10.15 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.13 - Apache Corporation 2007 Omnibus Equity Compensation Plan, as amended and restated May 4, 2011 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).
†10.14 - Apache Corporation Income Continuance Plan, as amended and restated effective as of July 29, 2019 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, SEC File No. 001-4300).
†10.15 - Apache Corporation Deferred Delivery Plan, as amended and restated May 12, 2016 (incorporated by reference to Exhibit 10.3 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.16 - Apache Corporation Non-Employee Directors’ Compensation Plan, as amended and restated July 13, 2017 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, SEC File No. 001-4300).
†10.17 - Apache Corporation Outside Directors’ Retirement Plan, as amended and restated July 16, 2014, effective June 30, 2014 (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.18 - Apache Corporation Non-Employee Directors’ Restricted Stock Units Program, as amended and restated May 14, 2015 (incorporated by reference to Exhibit 10.6 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, SEC File No. 001-4300).
†10.19 - Apache Corporation Non-Employee Directors’ Restricted Stock Units Program, effective May 12, 2016, pursuant to Apache Corporation 2016 Omnibus Compensation Plan (incorporated by reference to Exhibit 10.4 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.20 - Apache Corporation Outside Directors’ Deferral Program, effective May 12, 2016, pursuant to Apache Corporation 2016 Omnibus Compensation Plan (incorporated by reference to Exhibit 10.5 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.21 - Retirement Agreement, dated January 19, 2015, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2014, SEC File No. 001-4300).
†10.22 - Apache Corporation Executive Termination Policy, as amended and restated effective as of July 29, 2019 (incorporated by reference to Exhibit 10.2 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, SEC File No. 001-4300).
†10.23 - 2016 Employee Release and Settlement Agreement between Registrant and Thomas E. Voytovich, effective November 30, 2015 (incorporated by reference to Exhibit 10.41 to Registrant's Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.24 - 2018 Employee Release and Benefits Agreement between Registrant and W. Kregg Olson, effective August 1, 2018 (incorporated by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018, SEC File No. 001-4300).
EXHIBIT
NO. DESCRIPTION
†10.25 - Form of 2017 Performance Share Program Award Notice and Agreement, dated December 13, 2016 (incorporated by reference to Exhibit 10.45 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2016, SEC File No. 001-4300).
†10.26 - Form of Stock Option Award Agreement, dated February 3, 2016 (incorporated by reference to Exhibit 10.61 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2015, SEC File No. 001-4300).
†10.27 - Form of Stock Option Grant Agreement, dated December 13, 2016 (2016 Omnibus Compensation Plan (incorporated by reference to Exhibit 10.48 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2016, SEC File No. 001-4300).
†10.28 - Form of 2018 Restricted Stock Unit Award Agreement dated January 16, 2018 (2016 Omnibus Compensation Plan) (incorporated by reference to Exhibit 10.43 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2017, SEC File No. 001-04300).
†10.29 - Form of 2018 Cash-Settled Restricted Stock Unit Award Agreement dated January 16, 2018 (2016 Omnibus Compensation Plan) (incorporated by reference to Exhibit 10.44 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2017, SEC File No. 001-04300).
†10.30 - Form of 2018 Performance Share Grant Agreement (2016 Omnibus Compensation Plan), dated January 16, 2018 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 19, 2018, SEC File No. 001-04300).
†10.31 - Form of 2018 Stock Option Grant Agreement (2016 Omnibus Compensation Plan), dated January 16, 2018 (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed January 19, 2018, SEC File No. 001-04300).
†10.32 - Form of 2019 Performance Share Program (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 7, 2019, SEC File No. 001-04300).
†10.33 - Form of 2019 Cash-Based Restricted Stock Unit Grant Agreement (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed January 7, 2019, SEC File No. 001-04300).
†10.34 - Form of 2019 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.47 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2018, SEC File No. 001-04300).
†10.35 - Form of 2019 Cash-Based Restricted Stock Unit Grant Agreement (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.48 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2018, SEC File No. 001-04300).
†10.36 - Amendment of Performance Share Grant Agreement, dated July 29, 2019 (incorporated by reference to Exhibit 10.52 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.37 - Amendment of Restricted Stock Unit Award Agreement, dated July 29, 2019 (incorporated by reference to Exhibit 10.53 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.38 - Amendment of Stock Option Grant Agreement, dated July 29, 2019 (incorporated by reference to Exhibit 10.54 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.39 - Form of 2020 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.55 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.40 - Form of 2020 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.56 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.41 - Form of 2020 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.57 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.42 - Form of 2020 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.58 to Registrant’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
*†10.43 - Form of 2021 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021.
*†10.44 - Form of 2021 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021.
EXHIBIT
NO. DESCRIPTION
*†10.45 - Form of 2021 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021.
*†10.46 - Form of 2021 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021.
*21.1 - Subsidiaries of Registrant.
*23.1 - Consent of Ernst & Young LLP.
*23.2 - Consent of Ryder Scott Company, L.P., Petroleum Consultants.
*24.1 - Power of Attorney (included as a part of the signature pages to this report).
*31.1 - Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2 - Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1 - Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*99.1 - Report of Ryder Scott Company, L.P., Petroleum Consultants.
*101.INS - Inline XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).
*101.SCH - Inline XBRL Taxonomy Schema Document.
*101.CAL - Inline XBRL Calculation Linkbase Document.
*101.DEF - Inline XBRL Definition Linkbase Document.
*101.LAB - Inline XBRL Label Linkbase Document.
*101.PRE - Inline XBRL Presentation Linkbase Document.
*104 - Cover Page Interactive Data File (the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).
* Filed herewith.
† Management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15 hereof.
NOTE: Debt instruments of the Registrant defining the rights of long-term debt holders in principal amounts not exceeding 10 percent of the Registrant’s consolidated assets have been omitted and will be provided to the Commission upon request.