Company: APA Corp
CIK: 1841666
SIC: 1311
Filing Date: 2022-02-22 00:00:00

ITEM 1 - BUSINESS

ITEM 1A - RISK FACTORS
ITEM 1A. RISK FACTORS
The Company’s business activities and the value of its securities are subject to significant hazards and risks, including those described below. If any of such events should occur, the Company’s business, financial condition, liquidity, and/or results of operations could be materially harmed, and holders and purchasers of APA’s securities could lose part or all of their investments. Additional risks relating to the Company’s securities may be included in the prospectus supplements related to offerings of such securities from time to time in the future.
RISKS RELATED TO PRICING, DEMAND, AND PRODUCTION FOR CRUDE OIL, NATURAL GAS, AND NGLs
The COVID-19 pandemic has and may continue to adversely impact the Company’s business, financial condition, and results of operations, the global economy, and the demand for and prices of oil, natural gas, and NGLs. The unprecedented nature of the current situation makes it impossible for the Company to identify all potential risks related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on its business.
The COVID-19 pandemic and the actions taken by third parties, including, but not limited to, governmental authorities, businesses, and consumers, in response to the pandemic have adversely impacted the global economy and created significant volatility in the global financial markets. Business closures, restrictions on travel, “stay-at-home” or “shelter-in-place” orders, and other restrictions on movement within and among communities have significantly reduced demand for and the prices of oil, natural gas, and NGLs. As of the date of this Annual Report on Form 10-K, efforts to contain COVID-19 have not been successful in many regions, vaccination distribution programs have encountered delays, new variants have emerged, and the global pandemic remains ongoing. While some geographic regions have lifted, relaxed, or otherwise modified their pandemic response measures to lessen the impact of such measures on business operations and commerce, these regions may reinstitute restrictions as circumstances change. A continued, prolonged period or a renewed period of reduced demand, the failure to timely distribute or the ineffectiveness of or reluctance or refusal of individuals to take any vaccines, the failure to develop adequate treatments, and other adverse impacts from the pandemic may materially adversely affect the Company’s business, financial condition, cash flows, and results of operations.
The Company’s operations rely on its workforce being able to access its wells, platforms, structures, and facilities located upon or used in connection with its oil and gas leases. Additionally, because the Company has previously implemented, and may elect to or be required in the future to reimplement, remote working procedures for a significant portion of its workforce for health and safety reasons and/or to comply with applicable national, state, and/or local government requirements, the Company relies on such persons having sufficient access to its information technology systems, including through telecommunication hardware, software, and networks. If a significant portion of the Company’s workforce cannot effectively perform their responsibilities, whether resulting from a lack of physical or virtual access, quarantines, illnesses, governmental actions or restrictions, including vaccine mandates and the reactions thereto, information technology or telecommunication failures, or other restrictions or adverse impacts resulting from the pandemic, the Company’s business, financial condition, cash flows, and results of operations may be materially adversely affected.
The unprecedented nature of the current situation resulting from the COVID-19 pandemic makes it impossible for the Company to identify all potential risks related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on its business, financial condition, cash flows, or results of operations. Such results will depend on future events, which the Company cannot predict, including the scope, duration, and potential reoccurrence of the COVID-19 pandemic, the emergence and impact of COVID-19 variants, or any other localized epidemic or global pandemic, the distribution and effectiveness of vaccines, therapeutics, and treatments, the demand for and the prices of oil, natural gas, and NGLs, and the actions taken by third parties, including, but not limited to, governmental authorities, customers, contractors, and suppliers, in response to the COVID-19 pandemic or any other epidemics or pandemics. The COVID-19 pandemic and its unprecedented consequences have amplified, and may continue to amplify, the other risks identified in this Annual Report on Form 10-K.
Crude oil, natural gas, and NGL price volatility could adversely affect the Company’s operating results and the price of APA’s common stock.
The Company’s revenues, operating results, and future rate of growth depend highly upon the prices it receives for its crude oil, natural gas, and NGL production. Historically, the markets for these commodities have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2021 ranged from a high of $85.64 per barrel to a low of $47.47 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2021 ranged from a high of $23.86 per MMBtu to a low of $2.43 per MMBtu. The market prices for
crude oil, natural gas, and NGLs depend on factors beyond the Company’s control. These factors include demand, which fluctuates with changes in market and economic conditions, and other factors, including:
•worldwide and domestic supplies of crude oil, natural gas, and NGLs;
•actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC);
•political conditions and events (including instability, changes in governments, or armed conflict) in oil and gas producing regions;
•the occurrence of global events such as epidemics or pandemics (including, specifically, the COVID-19 pandemic) and the actions taken by third parties, including, but not limited to, governmental authorities, customers, contractors, and suppliers, in response to such epidemics or pandemics;
•the level of global crude oil and natural gas inventories;
•the price and level of imported foreign crude oil, natural gas, and NGLs;
•the price and availability of alternative fuels, including coal and biofuels;
•the availability of pipeline capacity and infrastructure;
•the availability of crude oil transportation and refining capacity;
•weather conditions;
•the impact of political pressure and the influence of environmental groups and other stakeholders on decisions and policies related to the industries in which the Company and its affiliates operate;
•domestic and foreign governmental regulations and taxes, including legislative, regulatory, policy changes, or initiatives and addressing the impact of global climate change, hydraulic fracturing, methane emissions, flaring, or water disposal; and
•the overall economic environment.
The Company’s results of operations, as well as the carrying value of its oil and gas properties, are substantially dependent upon the prices of oil, natural gas, and NGLs. Low prices have previously adversely affected and could again adversely affect the Company’s revenues, operating income, cash flow, and proved reserves, and continued low prices could have a material adverse impact on the Company’s operations and limit its ability to fund capital expenditures. Without the ability to fund capital expenditures, the Company would be unable to replace reserves and production. Sustained low prices of crude oil, natural gas, and NGLs may further adversely impact the Company’s business as follows:
•weakening the Company’s financial condition and reducing its liquidity;
•limiting the Company’s ability to fund planned capital expenditures and operations;
•reducing the amount of crude oil, natural gas, and NGLs that the Company can produce economically;
•causing the Company to delay or postpone some of its capital projects;
•reducing the Company’s revenues, operating income, and cash flows;
•limiting the Company’s access to sources of capital, such as equity and long-term debt;
•reducing the carrying value of the Company’s oil and gas properties, resulting in additional non-cash impairments; or
•reducing the carrying value of the Company’s gathering, processing, and transmission facilities, resulting in additional impairments.
The Company’s ability to sell crude oil, natural gas, or NGLs and/or receive market prices for these commodities and/or meet volume commitments under transportation services agreements may be adversely affected by pipeline and gathering system capacity constraints, the inability to procure and resell volumes economically, and various transportation interruptions.
A portion of the Company’s crude oil, natural gas, and NGL production in any region may be interrupted, limited, or shut in from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or capital constraints that limit the ability of third parties to construct gathering
systems, processing facilities, or interstate pipelines to transport the Company’s production, or the Company might voluntarily curtail production in response to market conditions. If a substantial amount of the Company’s production is interrupted at the same time, it could temporarily adversely affect the Company’s cash flows. Additionally, if the Company is unable to procure and resell third-party volumes at or above a net price that covers the cost of transportation, the Company’s cash flows could be adversely affected.
The Company may not realize an adequate return on wells that it drills.
Drilling for oil and gas involves numerous risks, including the risk that the Company will not encounter commercially productive oil or gas reservoirs. The wells the Company drills or participates in may not be productive, and the Company may not recover all or any portion of its investment in those wells. The seismic data and other technologies the Company uses do not allow it to know conclusively prior to drilling a well that crude or natural gas is present or may be produced economically. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors including, but not limited to:
•unexpected drilling conditions;
•pressure or irregularities in formations;
•equipment failures or accidents;
•fires, explosions, blowouts, and surface cratering;
•marine risks, such as capsizing, collisions, and hurricanes;
•other adverse weather conditions; and
•increases in the cost of or shortages or delays in the availability of drilling rigs and equipment.
Future drilling activities may not be successful, and, if unsuccessful, such failure could have an adverse effect on the Company’s future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.
The Company’s commodity price risk management and trading activities may prevent it from benefiting fully from price increases and may expose it to other risks.
To the extent that the Company engages in price risk management activities to protect itself from commodity price declines, the Company may be prevented from realizing the benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, the Company’s hedging arrangements may expose it to the risk of financial loss in certain circumstances, including instances in which:
•the Company’s production falls short of the hedged volumes;
•there is a widening of price-basis differentials between delivery points for the Company’s production and the delivery point assumed in the hedge arrangement;
•the counterparties to the Company’s hedging or other price risk management contracts fail to perform under those arrangements; or
•an unexpected event materially impacts commodity prices.
RISKS RELATED TO OPERATIONS AND DEVELOPMENT PROJECTS
The Company’s operations involve a high degree of operational risk, particularly risk of personal injury, damage to or loss of equipment, and environmental accidents.
The Company’s operations are subject to hazards and risks inherent in the drilling, production, and transportation of crude oil, natural gas, and NGLs, including:
•well blowouts, explosions, fires, and cratering;
•pipeline or other facility ruptures and spills;
•formations with abnormal pressures;
•equipment malfunctions;
•hurricanes, major storms, and cyclones, which could affect the Company’s operations in areas such as on and offshore the Gulf Coast, North Sea, and Suriname, and other natural and anthropogenic disasters and weather conditions; and
•surface spillage and surface or ground water contamination from petroleum constituents, saltwater, or hydraulic fracturing chemical additives.
Failure or loss of equipment, as the result of equipment malfunctions, cyberattacks, or natural disasters, such as hurricanes, could result in property damages, personal injury, environmental pollution, and other damages for which the Company could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion, fire at a location where the Company’s equipment and services are used, or ground water contamination from chemical additives used in hydraulic fracturing may result in substantial claims for damages. Ineffective containment of a drilling well blowout or pipeline rupture or surface spillage and surface or ground water contamination from petroleum constituents or hydraulic fracturing could result in extensive environmental pollution and substantial remediation expenses. If a significant amount of the Company’s production is interrupted, containment efforts prove to be ineffective, or litigation arises as the result of a catastrophic occurrence, the Company’s cash flows and, in turn, its results of operations could be materially and adversely affected.
Weather and climate may have a significant adverse impact on the Company’s revenues and production.
Demand for oil and natural gas are, to a significant degree, dependent on weather and climate, which impact the price the Company receives for the commodities it produces. In addition, the Company’s exploration, development, and production activities and equipment have been and can be adversely affected by severe weather, such as freezing temperatures, hurricanes in the Gulf of Mexico, or major storms in the North Sea, which have previously caused and may cause a loss of production from temporary cessation of activity or lost or damaged equipment. The Company’s planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather conditions, and not all such effects can be predicted, eliminated, or insured against.
The Company’s insurance policies do not cover all of the risks the Company faces, which could result in significant financial exposure.
Exploration for and production of crude oil, natural gas, and NGLs can be hazardous, involving natural disasters and other events such as blowouts, cratering, fires, explosions, and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. The Company’s international operations are also subject to political risk. The insurance coverage that the Company maintains against certain losses or liabilities arising from its operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to the Company against all operational risks.
A terrorist or cyberattack targeting systems and infrastructure used by the Company or others in the oil and gas industry may adversely impact the Company’s operations.
The Company’s business has become increasingly dependent on digital technologies to conduct certain exploration, development, and production activities. The Company depends on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, communicate with personnel and third-party partners, and conduct many of the Company’s activities. Unauthorized access to the Company’s digital technology could lead to operational disruption, data corruption, communication interruption, loss of intellectual property, loss of confidential and fiduciary data, and loss or corruption of reserves or other proprietary information. Also, external digital technologies control nearly all of the oil and gas distribution and refining systems in the U.S. and abroad, which are necessary to transport and market the Company’s production. A cyberattack directed at oil and gas distribution systems have previously and could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets, and make it difficult or impossible to accurately account for production and settle transactions. Any such terrorist attack, environmental activist group activity, or cyberattack that affects the Company or its customers, suppliers, or others with whom it does business could have a material adverse effect on the Company’s business, cause it to incur a material financial loss, subject it to possible legal claims and liability, and/or damage its reputation.
While certain of the Company’s insurance policies may allow for coverage of associated damages resulting from such events, if the Company were to incur a significant liability for which it was not fully insured, that could have a material adverse effect on the Company’s financial position, results of operations, and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.
While the Company has experienced cyberattacks in the past, it has not suffered any material losses as a result of such attacks; however, there is no assurance that the Company will not suffer such losses in the future. Further, as cyberattacks continue to evolve, the Company may be required to expend significant additional resources to continue to modify or enhance its protective measures or to investigate and remediate any vulnerabilities to cyberattacks. In addition, cyberattacks against the Company or others in its industry could result in additional regulations, which could lead to increased regulatory compliance costs, insurance coverage cost, or capital expenditures. The Company cannot predict the potential impact that such additional regulations could have on its business and operations or the energy industry at large.
Material differences between the estimated and actual timing of critical events or costs may affect the completion and commencement of production from development projects.
The Company is involved in several large development projects, and the completion of these projects may be delayed beyond the Company’s anticipated completion dates. These projects may be delayed by project approvals from joint venture partners, timely issuances of permits and licenses by governmental agencies, weather conditions, manufacturing and delivery schedules of critical equipment, and other unforeseen events. Delays and differences between estimated and actual timing of critical events may adversely affect the Company’s large development projects and its ability to participate in large-scale development projects in the future. In addition, the Company’s estimates of future development costs are based on its current expectations of prices and other costs of equipment and personnel the Company will need to implement such projects. The actual future development costs may be significantly higher than the Company currently estimates. If costs become too high, the development projects may become uneconomic to the Company, and it may be forced to abandon such development projects.
RISKS RELATED TO RESERVES AND LEASEHOLD ACREAGE
Discoveries or acquisitions of additional reserves are needed to avoid a material decline in reserves and production.
The production rate from oil and natural gas properties generally declines as reserves are depleted, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. Therefore, unless the Company adds reserves through exploration and development activities, identifies additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves through engineering studies, or acquires additional properties containing proved reserves, the Company’s estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon the Company’s level of success in acquiring or finding additional reserves on an economic basis. Furthermore, as oil or natural gas prices increase, the Company’s cost for additional reserves could also increase.
The Company may fail to fully identify potential problems related to acquired reserves or to properly estimate those reserves.
Although the Company performs a review of properties that it acquires, which the Company believes is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in-depth every individual property involved in each acquisition. Ordinarily, the Company will focus its review efforts on the higher-value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit the Company as a buyer to become sufficiently familiar with the properties to assess fully and accurately their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the Company often assumes certain environmental and other risks and liabilities in connection with acquired properties. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future production rates and costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. In addition, there can be no assurance that acquisitions will not have an adverse effect upon the Company’s operating results, particularly during the periods in which the operations of acquired businesses are being integrated into the Company’s ongoing operations.
Crude oil, natural gas, and NGL reserves are estimates, and actual recoveries may vary significantly.
There are numerous uncertainties inherent in estimating crude oil, natural gas, and NGL reserves and their value. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, natural gas, and NGLs that cannot be measured in an exact manner. Because of the high degree of judgment involved, the accuracy of any reserve estimate is inherently imprecise and a function of the quality of available data and the engineering and geological interpretation. The Company’s reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore,
reserves quantities will change when actual prices increase or decrease. In addition, results of drilling, testing, and production may substantially change the reserve estimates for a given reservoir over time. The estimates of the Company’s proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including:
•historical production from the area compared with production from other areas;
•the effects of regulations by governmental agencies, including changes to severance and excise taxes;
•future operating costs and capital expenditures; and
•workover and remediation costs.
For these reasons, estimates of the economically recoverable quantities of crude oil, natural gas, and NGLs attributable to any particular group of properties, classifications of those reserves, and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to upward or downward adjustment, and actual production, revenue, and expenditures with respect to the Company’s reserves likely will vary, possibly materially, from estimates.
Additionally, because some of the Company’s reserves estimates are calculated using volumetric analysis, those estimates are less reliable than the estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. In addition, realization or recognition of proved undeveloped reserves will depend on the Company’s development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.
Certain of the Company’s undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
A sizeable portion of the Company’s acreage is currently undeveloped. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If the leases expire, the Company will lose its right to develop the related properties. The Company’s drilling plans for these areas are subject to change based upon various factors, including drilling results, commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.
RISKS RELATED TO COUNTERPARTIES
The credit risk of financial institutions could adversely affect the Company.
The Company is party to numerous transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, other investment funds, and other institutions. These transactions expose the Company to credit risk in the event of default of the counterparty. Deterioration in the credit or financial markets may impact the credit ratings of the Company’s current and potential counterparties and affect their ability to fulfill their existing obligations to the Company and their willingness to enter into future transactions with the Company. The Company may also have exposure to financial institutions in the form of derivative transactions in connection with any hedges. The Company also has exposure to insurance companies in the form of claims under the Company’s policies. In addition, if any lender under the Company’s credit facilities is unable to fund its commitment, the Company’s liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under the credit facilities.
The Company is exposed to a risk of financial loss if a counterparty fails to perform under a derivative contract. This risk of counterparty non-performance is of particular concern given the recent volatility of the financial markets and significant changes in commodity prices, which could lead to sudden changes in a counterparty’s liquidity and impair its ability to perform under the terms of the derivative contract. The Company is unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if the Company does accurately predict sudden changes, its ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of the Company’s hedge providers or some other similar proceeding or liquidity constraint might make it unlikely that the Company would be able to collect all or a significant portion of amounts owed to it by the distressed entity or entities. During periods of falling commodity prices, the Company’s hedge receivable positions increase, which increases the Company’s exposure. If the creditworthiness of the counterparties deteriorates and results in their nonperformance, the Company could incur a significant loss.
The distressed financial conditions of the Company’s purchasers and partners have had and could have an adverse impact on the Company in the event they are unable to pay the Company for the products or services it provides or to reimburse it for their share of costs.
Concerns about global economic conditions and the volatility of oil, natural gas, and NGL prices have had a significant adverse impact on the oil and gas industry. The Company is exposed to risk of financial loss from trade, joint venture, joint interest billing, and other receivables. The Company sells its crude oil, natural gas, and NGLs to a variety of purchasers. As operator, the Company pays expenses and bills its non-operating partners for their respective shares of costs. As a result of recent economic conditions and the previously severe decline in commodity prices, some of the Company’s customers and non-operating partners experienced severe financial problems that had a significant impact on their creditworthiness. The Company cannot provide assurance that one or more of its financially distressed customers or non-operating partners will not default on their obligations to the Company or that such a default or defaults will not have a material adverse effect on the Company’s business, financial position, future results of operations, or future cash flows. Furthermore, the bankruptcy of one or more of the Company’s customers or non-operating partners or some other similar proceeding or liquidity constraint have made it and might make it unlikely that the Company will or would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. Nonperformance by a trade creditor or non-operating partner could result in significant financial losses.
The Company’s liabilities could be adversely affected in the event one or more of its transaction counterparties become the subject of a bankruptcy case.
From time to time the Company has divested noncore or nonstrategic domestic and international assets. The agreements relating to these transactions contain provisions pursuant to which liabilities related to past and future operations have been allocated between the parties by means of liability assumptions, indemnities, escrows, trusts, bonds, letters of credit, and similar arrangements. One of the most significant of these liabilities involves the decommissioning of wells and facilities previously owned by the Company. One or more of the counterparties in these transactions could fail to perform its obligations under these agreements as a result of financial distress. In the event that any such counterparty becomes the subject of a case or proceeding under Title 11 of the United States Code or any other relevant insolvency law or similar law (which are collectively referred to as Insolvency Laws), the counterparty may not perform its obligations under the agreements related to these transactions. In that case, the Company’s remedy in the proceeding would be a claim for damages for the breach of the contractual arrangements, which may be either a secured claim or an unsecured claim depending on whether or not the Company has collateral from the counterparty for the performance of the obligations. Resolution of the Company’s claim for damages in such a proceeding may be delayed, and the Company may be forced to use available cash to cover the costs of the obligations assumed by the counterparties under such agreements should they arise, pending final resolution of the proceeding.
Despite the provisions in the Company’s agreements requiring purchasers of its state or federal leasehold interests to assume certain liabilities and obligations related to such interests, if a purchaser of such interests becomes the subject of a case or proceeding under relevant Insolvency Laws or becomes unable financially to perform such liabilities or obligations, the Company would expect the relevant governmental authorities to require it to perform and hold it responsible for such liabilities and obligations. In such event, the Company may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.
If a court or a governmental authority were to make any of the foregoing determinations or take any of the foregoing actions, or any similar determination or action, it could adversely impact the Company’s cash flows, operations, or financial condition.
For additional information regarding Apache’s prior Gulf of Mexico properties and the bankruptcy of the purchaser of those properties, see the information set forth under “Potential Obligation to Decommission Sold Properties” in Note 11-Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Item 15 of this Annual Report on Form 10-K.
The Company does not always control decisions made under joint operating agreements, and the parties under such agreements may fail to meet their obligations.
The Company conducts many of its exploration and production (E&P) operations through joint operating agreements with other parties under which the Company may not control decisions, either because it does not have a controlling interest or is not an operator under the agreement. There is risk that these parties may at any time have economic, business, or legal interests or goals that are inconsistent with the Company’s, and therefore, decisions may be made that the Company does not believe are in its best interest. Moreover, parties to these agreements may be unable to meet their economic or other obligations,
and the Company may be required to fulfill those obligations alone. In either case, the value of the investment may be adversely affected.
The Company own an approximate 79 percent interest in Altus, which holds substantially all of Apache’s former gathering, processing, and transmission assets in Alpine High. Altus may be subject to different risks than those described in this Annual Report on Form 10-K.
The Company owns an approximate 79 percent interest in Altus, which holds substantially all of Apache’s former gathering, processing, and transmission assets in Alpine High. Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas, anchored by midstream service contracts to service the Company’s production from Apache’s Alpine High resource play. Altus generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services and through its Equity Method Interest Pipelines. Given the nature of its business, Altus may be subject to different and additional risks than those described in this Annual Report on Form 10-K. For a description of these risks, refer to Altus’ most recently filed Annual Report on Form 10-K and any subsequently filed Quarterly Reports on Form 10-Q.
On October 21, 2021, ALTM announced that it will combine with privately owned BCP in an all-stock transaction. The transaction is expected to close during the first quarter of 2022, following completion of customary closing conditions. Upon closing of the transaction, the Company will no longer control Altus.
RISKS RELATED TO CAPITAL MARKETS
A downgrade in the Company’s credit rating could negatively impact its cost of and ability to access capital.
The Company receives debt ratings from the major credit rating agencies in the U.S. Factors that may impact the Company’s credit ratings include its debt levels, planned asset purchases or sales, and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, product mix, commodity pricing levels, and other factors are also considered by the rating agencies. A ratings downgrade could adversely impact the Company’s ability to access debt markets in the future and increase the cost of future debt. During 2021, the Company’s credit rating was affirmed by Moody’s to Ba1/Stable and by Standard and Poor’s to BB+/Stable. Past ratings downgrades have required, and any future downgrades may require, the Company to post letters of credit or other forms of collateral for certain obligations.
Market conditions may restrict the Company’s ability to obtain funds for future development and working capital needs, which may limit its financial flexibility.
The financial markets are subject to fluctuation and are vulnerable to unpredictable shocks. The Company has a significant development project inventory and an extensive exploration portfolio, which will require substantial future investment. The Company and/or its partners may need to seek financing to fund these or other future activities. The Company’s future access to capital, as well as that of its partners and contractors, could be limited if the debt or equity markets are constrained. This could significantly delay development of the Company’s property interests.
The Company’s syndicated credit facility currently matures in March 2024. There is no assurance of the terms upon which potential lenders under future agreements will make loans or other extensions of credit available to the Company or its subsidiaries or the composition of such lenders.
The discontinuation and uncertain cessation date of LIBOR, and the adoption of an alternative reference rate, may have a material adverse impact on the Company’s floating rate indebtedness and financing costs.
Pursuant to the terms of the Company’s revolving credit facility (1) the Company may elect to use the London Interbank Offering Rate (LIBOR) as a benchmark for establishing the interest rate on floating interest rate borrowings and (2) the commission payable to the lenders on the face amount of each outstanding letter of credit uses LIBOR as a benchmark. On November 30, 2020, the ICE Benchmark Administration (IBA) announced that it intends to continue publishing LIBOR until the end of June 2023, beyond the previously announced 2021 cessation date. The IBA announcement was supported by announcements from the U.K.’s Financial Conduct Authority (FCA), which regulates LIBOR, and the Board of Governors of the Federal Reserve System, Federal Deposit Insurance Corporation and Office of the Comptroller of the Currency (U.S. Regulators). However, both the FCA and U.S. Regulators in their announcements also advised banks to cease entering into new contracts referencing LIBOR after December 2021. These announcements indicate that the continuation of LIBOR in existing contracts may not be assured after 2021 and will not be assured beyond 2023. In light of these recent announcements, the future
of LIBOR at this time is uncertain, and any changes in the methods by which LIBOR is determined or regulatory activity related to LIBOR’s phaseout could cause LIBOR to perform differently than in the past or cease to exist.
In the U.S., the Alternative Reference Rates Committee (the working group formed to recommend an alternative rate to LIBOR) has identified the Secured Overnight Financing Rate (SOFR) as its preferred alternative rate for LIBOR. There can be no guarantee that SOFR will become a widely-accepted benchmark in place of LIBOR. Although the full impact of the transition away from LIBOR, including the discontinuance of LIBOR publication and the adoption of SOFR as the replacement rate for LIBOR, remains unclear, these changes may have an adverse impact on the Company’s floating rate indebtedness and financing costs under its revolving credit facility.
The Company’s ability to declare and pay dividends is subject to limitations.
The payment of future dividends on the Company’s capital stock is subject to the discretion of the Company’s board of directors, which considers, among other factors, the Company’s operating results, overall financial condition, credit-risk considerations, and capital requirements, as well as general business and market conditions. The board of directors is not required to declare dividends on APA’s common stock and may decide not to declare dividends.
Any indentures and other financing agreements that the Company enters into in the future may limit its ability to pay cash dividends on its capital stock, including APA common stock. In addition, under Delaware law, dividends on capital stock may only be paid from “surplus,” which is the amount by which the fair value of the Company’s total assets exceeds the sum of its total liabilities, including contingent liabilities, and the amount of its capital; if there is no surplus, cash dividends on capital stock may only be paid from the Company’s net profits for the then-current and/or the preceding fiscal year. Further, even if the Company is permitted under its contractual obligations and Delaware law to pay cash dividends on common stock, the Company may not have sufficient cash to pay dividends in cash on its common stock.
Unfavorable ESG ratings and funding limitation initiatives may lead to negative investor and public sentiment toward the Company and to the diversion of capital from the Company’s industry.
Organizations that provide information to investors on corporate governance and related matters have developed ratings for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform and advise their investment and voting decisions. In addition, certain organizations and stakeholders may encourage lenders to limit funding to E&P companies. Unfavorable ESG ratings and funding limitation initiatives may lead to negative investor and public sentiment toward the Company and to the diversion of capital from the Company’s industry, which could have a negative impact on the Company’s access to and costs of capital.
RISKS RELATED TO FINANCIAL RESULTS
Future economic conditions in the U.S. and certain international markets may materially adversely impact the Company’s operating results.
Current global market conditions and uncertainty, including economic instability in emerging markets, are likely to have significant long-term effects on the Company’s operating results. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate could result in decreased demand growth for the Company’s oil and natural gas production as well as lower commodity prices, which would reduce the Company’s cash flows from operations and its profitability.
The Company faces strong industry competition that may have a significant negative impact on the Company’s results of operations.
Strong competition exists in all sectors of the oil and gas E&P industry. The Company competes with major integrated and other independent oil and gas companies for acquisitions of oil and gas leases, properties, and reserves, equipment and labor required to explore, develop, and operate those properties, and marketing of crude oil, natural gas, and NGL production. Crude oil, natural gas, and NGL prices impact the costs of properties available for acquisition and the number of companies with the financial resources to pursue acquisition opportunities. Many of the Company’s competitors have financial and other resources substantially larger than the Company possesses and have established strategic, long-term positions and maintain strong governmental relationships in countries in which the Company may seek new entry. As a consequence, the Company may be at a competitive disadvantage in bidding for drilling rights. In addition, many of the Company’s larger competitors may have a competitive advantage when responding to factors that affect demand for oil and gas production, such as fluctuating worldwide commodity prices and levels of production, the cost and availability of alternative fuels, and the application of
government regulations. The Company also competes in attracting and retaining personnel, including geologists, geophysicists, engineers, and other specialists. These competitive pressures may have a significant negative impact on the Company’s results of operations.
The Company’s ability to utilize net operating losses and other tax attributes to reduce future taxable income may be limited if the Company experiences an ownership change.
As described in Note 10-Income Taxes of the Notes to Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K, the Company has substantial net operating loss carryforwards (NOLs) and other tax attributes available to potentially offset future taxable income. If the Company were to experience an “ownership change” under Section 382 of the Internal Revenue Code of 1986, as amended, which is generally defined as a greater than 50 percentage point change, by value, in the Company’s equity ownership by five-percent shareholders over a three-year period, the Company’s ability to utilize its pre-change NOLs and other pre-change tax attributes to potentially offset its post-change income or taxes may be limited. Such a limitation could materially adversely affect the Company’s operating results or cash flows by effectively increasing its future tax obligations.
RISKS RELATED TO GOVERNMENTAL REGULATION AND POLITICAL RISKS
The Company may incur significant costs related to environmental matters.
As an owner or lessee and operator of oil and gas properties, the Company is subject to various federal, state, local, and foreign laws and regulations relating to the discharge of materials into and protection of the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution cleanup and other remediation activities resulting from operations, subject the lessee to liability for pollution and other damages, limit or constrain operations in affected areas, and require suspension or cessation of operations in affected areas. The Company’s efforts to limit its exposure to such liability and cost may prove inadequate and result in significant adverse effects to the Company’s results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require the Company to make significant capital expenditures. Such capital expenditures could adversely impact the Company’s cash flows and its financial condition.
The Company’s U.S. operations are subject to governmental risks.
The Company’s U.S. operations have been, and at times in the future may be, affected by political developments and by federal, state, and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls, and environmental protection laws and regulations.
In response to the Deepwater Horizon incident in the U.S. Gulf of Mexico in April 2010 and as directed by the Secretary of the U.S. Department of the Interior, the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE) issued guidelines and regulations regarding safety, environmental matters, drilling equipment, and decommissioning applicable to drilling in the Gulf of Mexico. These regulations imposed additional requirements and caused delays with respect to development and production activities in the Gulf of Mexico.
With respect to oil and gas operations in the Gulf of Mexico, the BOEM issued a Notice to Lessees (NTL No. 2016-N01) significantly revising the obligations of companies operating in the Gulf of Mexico to provide supplemental assurances of performance with respect to plugging, abandonment, and decommissioning obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies’ oil and gas leases. While the NTL was paused in mid-2017 and is currently listed on BOEM’s website as “rescinded,” if reinstated, the NTL will likely require that Apache provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to Apache’s current ownership interests in various Gulf of Mexico leases. The Company is working closely with BOEM to make arrangements for the provision of such additional required security, if such security becomes necessary under the NTL. Additionally, the Company is not able to predict the effect that these changes might have on counterparties to which Apache has sold Gulf of Mexico assets or with whom Apache has joint ownership. Such changes could cause the bonding obligations of such parties to increase substantially, thereby causing a significant impact on the counterparties’ solvency and ability to continue as a going concern.
New political developments, the enactment of new or stricter laws or regulations or other governmental actions impacting the Company’s U.S. operations, and increased liability for companies operating in this sector may adversely impact the Company’s results of operations.
Proposed federal, state, or local regulation regarding hydraulic fracturing could increase the Company’s operating and capital costs.
Several proposals are before the U.S. Congress that, if implemented, would either prohibit or restrict the practice of hydraulic fracturing or subject the process to regulation under the Safe Drinking Water Act. Several states and political subdivisions are considering legislation, ballot initiatives, executive orders, or other actions to regulate hydraulic fracturing practices that could impose more stringent permitting, transparency, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. Hydraulic fracturing of wells and subsurface water disposal are also under public and governmental scrutiny due to potential environmental and physical impacts, including possible contamination of groundwater and drinking water and possible links to induced seismicity. In addition, some municipalities have significantly limited or prohibited drilling activities and/or hydraulic fracturing or are considering doing so. The Company routinely uses fracturing techniques in the U.S. and other regions to expand the available space for natural gas and oil to migrate toward the wellbore. It is typically done at substantial depths in formations with low permeability.
Although it is not possible at this time to predict the final outcome of the governmental actions regarding hydraulic fracturing, any new federal, state, or local restrictions on hydraulic fracturing that may be imposed in areas in which the Company conducts business could result in increased compliance costs or additional operating restrictions in the U.S.
Changes in tax rules and regulations, or interpretations thereof, may adversely affect the Company’s business, financial condition, and results of operations.
The U.S. federal and state income tax laws affecting oil and gas exploration, development, and extraction may be modified by administrative, legislative, or judicial interpretation at any time. Previous legislative proposals, if enacted into law, could make significant changes to such laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas E&P companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures. The passage or adoption of these changes, or similar changes, could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development. The Company is unable to predict whether any of these changes or other proposals will be enacted. Any such changes could adversely affect the Company’s business, financial condition, and results of operations.
RISKS RELATED TO CLIMATE CHANGE
Changes to existing regulations related to emissions and the impact of any changes in climate could adversely impact the Company’s business.
Certain countries where the Company operates, including the U.K., either tax or assess some form of greenhouse gas (GHG) related fees on the Company’s operations. Exposure has not been material to date, although a change in existing regulations could adversely affect the Company’s cash flows and results of operations. Additionally, there has been discussion in other countries where the Company operates, including the U.S., regarding legislation or regulation of GHG. Numerous proposals have been made and could continue to be made at the national, regional, and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. Moreover, on January 27, 2021, the President issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and increased emphasis on climate-related risk across governmental agencies and economic sectors.
Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, restriction of emissions, electric vehicle mandates, and combustion engine phaseouts. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil, natural gas, and NGLs. Additionally, political, litigation, and financial risks related to climate change may result in curtailed refinery activity, increased regulation, or other adverse direct and indirect effects on the Company’s business, financial condition, and results of operations. For example, there is a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector.
Any such legislation, regulations, or other regulatory initiatives, if enacted, or additional or increased taxes, assessments, or GHG-related fees on the Company’s operations could lead to increased operating expenses or cause the Company to make significant capital investments for infrastructure modifications.
Enhanced scrutiny on ESG matters could have an adverse effect on the Company’s operations.
Enhanced scrutiny on ESG matters related to, among other things, concerns raised by advocacy groups about climate change, hydraulic fracturing, waste disposal, oil spills, and explosions of natural gas transmission pipelines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines, and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens, increased risk of litigation, and adverse impacts on the Company’s access to capital. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance, and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits the Company requires to conduct its operations to be withheld, delayed, or burdened by requirements that restrict the Company’s ability to profitably conduct its business.
The Company’s estimates used in various scenario planning analyses could differ materially from actual results and could expose us to new or additional risks.
In 2021, the Company undertook a scenario planning analysis in alignment with recommendations of the Financial Stability Board’s Taskforce on Climate-related Financial Disclosures (“TCFD”). This expanded climate-focused scenario planning framework included forecasts of future demand and pricing in energy markets, as well as changes in government regulations and policy. Given the dynamic nature of the Company’s business, the Company generally performs annual scenario analyses with five-year time horizons. When analyzing longer-term TCFD scenarios, the Company relies on external analysis for demand scenarios, carbon pricing, and comparison-pricing scenarios, which are then compared to the Company’s internally prepared base-case pricing analysis averaged out to 2040. Given the numerous estimates that are required to run these scenarios, the Company’s estimates could differ materially from actual results. Additionally, by electing to set and share publicly these metrics in the Company’s sustainability report and the Company’s commitment to expand upon its disclosures, the Company’s business may also face increased scrutiny related to ESG initiatives. As a result, the Company could damage its reputation if it fails to act responsibly in the areas in which it reports. Any harm to the Company’s reputation resulting from setting these metrics, expanding its disclosures, or its failure or perceived failure to meet such metrics or disclosures could adversely affect the Company’s business, financial performance, and growth.
The Company operates in Gulf Coast wetlands, which face threats from climate change and human activities.
A changing climate creates uncertainty and could result in broad changes, both physical and financial, to the areas in which the Company operates, including Gulf Coast wetlands. For several decades, the State of Louisiana has lost an estimated 20 square miles of wetlands per year, due to natural processes of subsidence, saltwater intrusion, and shoreline erosion, as well as human activities, such as levee construction along the Mississippi River and the dredging of navigation canals. A possible result of climate change is more frequent and more severe weather events, such as hurricanes and major flooding events. The risk of increased or more severe hurricanes or flooding events along or near the Gulf Coast could increase the Company’s costs to repair damaged facilities and restore production. Additionally, federal, state, and local laws and regulations may impose numerous obligations applicable to the Company’s operations including: (i) the limitation or prohibition of certain activities on wetlands; (ii) the imposition of substantial liabilities for pollution resulting from operations; (iii) the reporting of the types and quantities of various substances that are generated, stored, processed, or released in connection with protected properties; and (iv) the installation of costly emission monitoring and/or pollution control equipment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of the Company’s operations. In addition, the Company may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt the Company’s operations or specific projects and limit its growth and revenue.
The guidance upon which the Company’s consumptive water use reporting was modified and could be revised in the future, resulting in the over or underreporting of the Company’s consumptive water use, and could expose the Company to financial risk.
Based on Ipieca’s Sustainability Reporting Guidance of the Oil and Gas Industry (2020), the Company modified the way it reports its water data compared to previous years and also restated data from past years. Previously, the Company included produced water usage in its consumptive use calculations, which led to an over-reporting of consumptive water use. Based on re-evaluation of water reporting definitions and guidance, the Company determined that produced water - non-potable water
released from deep underground formations and brought to the surface during oil and gas exploration and production - should not be classified as consumed in the same sense as fresh water. Produced water is generally not of the quality that most users would be able to utilize and is therefore not available for third-party usage outside of the oilfield. The Company’s revised reporting now reflects only fresh water and non-potable water from surface water or shallow groundwater that are consumed in oil and gas operations.
The treatment and disposal of produced water is becoming more highly regulated and restricted and could expose the Company to additional costs or limit certain operations.
The treatment and disposal of produced water is becoming more highly regulated and restricted. The Company’s ability to accurately report and track its water use is necessary for its continued ability to reuse and recycle water, when possible. While the Company remains focused on reusing or recycling water over disposal of water, the Company’s costs for obtaining and disposing of water could increase significantly if reusing and recycling water becomes impractical. Further, compliance with reporting and environmental regulations governing the withdrawal, storage, use, and discharge of water may increase the Company’s operating costs, which could materially and adversely affect its business, results of operations, and financial conditions. For example, the Railroad Commission of Texas (RRC) has been developing data associated with seismic activity, particularly such activity related to injection wells used for produced water disposal. In September 2021, the RRC began to limit saltwater disposal in the Midland Basin under what is known as a Seismic Response Action (or SAR) due to increased seismic activity. These developments could result in restriction of disposal wells that could have a material effect on the Company’s capital expenses and operating costs or limit production in certain areas.
RISKS RELATED TO INTERNATIONAL OPERATIONS
International operations have uncertain political, economic, and other risks.
The Company’s operations outside the U.S. are based primarily in Egypt and the U.K., with significant exploration and appraisal activities offshore Suriname. On a barrel equivalent basis, approximately 41 percent of the Company’s 2021 production was outside the U.S., and approximately 32 percent of the Company’s estimated proved oil and gas reserves as of December 31, 2021, were located outside the U.S. As a result, a significant portion of the Company’s production and resources are subject to the increased political and economic risks and other factors associated with international operations including, but not limited to:
•general strikes and civil unrest;
•the risk of war, acts of terrorism, expropriation and resource nationalization, and forced renegotiation or modification of existing contracts, including through prospective or retroactive changes in the laws and regulations applicable to such contracts;
•import and export regulations;
•taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions;
•price control;
•transportation regulations and tariffs;
•constrained oil or natural gas markets dependent on demand in a single or limited geographical area;
•exchange controls, currency fluctuations, devaluations, or other activities that limit or disrupt markets and restrict payments or the movement of funds;
•laws and policies of the U.S. affecting foreign trade, including trade sanctions;
•the long-term effects of the U.K.’s withdrawal from the European Union, including any resulting instability in global financial markets or the value of foreign currencies such as the British pound;
•the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where the Company currently operates;
•the possible inability to subject foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of courts in the U.S.; and
•difficulties in enforcing the Company’s rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.
Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to the Company by another country, the Company’s interests could decrease in value or be lost. Even the Company’s smaller international assets may affect its overall business and results of operations by distracting management’s attention from its more significant assets. Certain regions of the world in which the Company operates have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investments such as the Company’s. In an extreme case, such a change could result in termination of contract rights and expropriation of the Company’s assets. This could adversely affect the Company’s interests and its future profitability.
The impact that future terrorist attacks or regional hostilities, as have occurred in countries and regions in which the Company operates, may have on the oil and gas industry in general and on the Company’s operations in particular is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants, and refineries, could be direct targets or indirect casualties of an act of terror or war. The Company may be required to incur significant costs in the future to safeguard its assets against terrorist activities.
A deterioration of conditions in Egypt or changes in the economic and political environment in Egypt could have an adverse impact on the Company’s business.
Deterioration in the political, economic, and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of the Company’s assets or resource nationalization, and/or forced renegotiation or modification of the Company’s existing contracts with Egyptian General Petroleum Corporation (EGPC), or threats or acts of terrorism could materially and adversely affect the Company’s business, financial condition, and results of operations. The Company’s operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 22 percent of the Company’s 2021 production and accounted for 16 percent of the Company’s year-end estimated proved reserves and 20 percent of the Company’s estimated discounted future net cash flows.
The Company’s operations are sensitive to currency rate fluctuations.
The Company’s operations are sensitive to fluctuations in foreign currency exchange rates, particularly between the U.S. dollar and the British pound. The Company’s financial statements, presented in U.S. dollars, may be affected by foreign currency fluctuations through both translation risk and transaction risk. Volatility in exchange rates may adversely affect the Company’s results of operations, particularly through the weakening of the U.S. dollar relative to other currencies.
RISKS RELATED TO THE HOLDING COMPANY REORGANIZATION
APA, as the parent holding company of Apache, is dependent on the operations and funds of its subsidiaries, including Apache.
As a result of the Holding Company Reorganization APA became the successor issuer to, and parent holding company of, Apache. APA has no business operations of its own, and its only significant assets are the outstanding equity interests of its subsidiaries, including Apache. As a result, APA relies on cash flows from its subsidiaries, including Apache, to pay dividends with respect to APA’s common stock and to meet its financial obligations, including to service any debt obligations that the Company may incur from time to time. Legal and contractual restrictions in agreements governing future indebtedness of Apache, as well as Apache’s financial condition and future operating requirements, may limit Apache’s ability to distribute cash to the Company. If Apache is limited in its ability to distribute cash to the Company, or if Apache’s earnings or other available assets of are not sufficient to pay distributions or make loans to the Company in the amounts or at the times necessary for it to pay dividends with respect to its common stock and/or to meet its financial obligations, then the Company’s business, financial condition, cash flows, results of operations, and reputation may be materially adversely affected.
The Company may not obtain the anticipated benefits of the reorganization into a holding company structure.
The Company believes that its new operating structure will allow it to focus on running its diverse businesses independently, with the goal of maximizing each of the business’ potential. However, the anticipated benefits of the Holding Company Reorganization may not be obtained if circumstances prevent the Company from taking advantage of the strategic and business opportunities that it expects the structure may afford the Company. As a result, the Company may incur the costs of a holding company structure without realizing the anticipated benefits, which could adversely affect the Company’s business, financial condition, cash flows, and results of operations.
Management is dedicating significant effort to the new operating structure. These efforts may divert management’s focus and resources from the Company’s operations, strategic initiatives, or development opportunities, which could adversely affect the Company’s prospects, business, financial condition, cash flows, and results of operations.
GENERAL RISK FACTORS
Certain anti-takeover provisions in the Company’s charter and Delaware law could delay or prevent a hostile takeover.
The Company’s charter authorizes the board of directors to issue preferred stock in one or more series and to determine the voting rights and dividend rights, dividend rates, liquidation preferences, conversion rights, redemption rights, including sinking fund provisions and redemption prices, and other terms and rights of each series of preferred stock. In addition, Delaware law imposes restrictions on mergers and other business combinations between the Company and any holder of 15 percent or more of APA’s outstanding common stock. These provisions may deter hostile takeover attempts that could result in an acquisition of the Company that would have been financially beneficial to APA’s shareholders.

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

ITEM 2 - PROPERTIES

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

ITEM 4 - RESERVED
ITEM 4. MINE SAFETY DISCLOSURES
None.
PART II

ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
APA’s common stock, par value $0.625 per share, is traded on the Nasdaq Global Select Market (Nasdaq) under the symbol “APA.” The closing price of APA’s common stock, as reported by the Nasdaq for January 31, 2022, was $33.21 per share. As of January 31, 2022, there were 346,776,379 shares of APA’s common stock outstanding held by approximately 3,300 stockholders of record and 152,000 beneficial owners.
The Company has paid cash dividends on its common stock for 57 consecutive years through December 31, 2021. In the third quarter of 2021, APA’s Board of Directors approved an increase in the Company’s quarterly dividend per share from $0.025 per share to $0.0625 per share, effective for all dividends payable after September 14, 2021, and further increased the quarterly dividend in the fourth quarter of 2021 to $0.125 per share to be paid on February 22, 2022. When, and if, declared by the Company’s Board of Directors, future dividend payments will depend upon the Company’s level of earnings, financial requirements, and other relevant factors.
Information concerning securities authorized for issuance under equity compensation plans is set forth under the caption “Equity Compensation Plan Information” in the proxy statement relating to the Company’s 2022 annual meeting of stockholders, which is incorporated herein by reference.
Issuer Purchases of Equity Securities
The table below sets forth information with respect to shares of common stock repurchased by APA during 2021.
(1)During the fourth quarter of 2018, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of an additional 40 million shares of the Company’s common stock. In both cases, shares may be purchased either in the open market or through privately held negotiated transactions.
The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to two broad-based stock performance indices. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance. The graph compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s 500 Index (S&P 500 Index) and of the Dow Jones U.S. Exploration & Production Index (formerly Dow Jones Secondary Oil Stock Index) from December 31, 2016, through December 31, 2021. The stock performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that the Company specifically incorporates it by reference into such filing.
COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN*
Among APA Corporation, the S&P 500 Index,
and the Dow Jones U.S. Exploration & Production Index
* $100 invested on 12/31/16 in stock or index, including reinvestment of dividends.
Fiscal year ending December 31.

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

ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together in conjunction with the Company’s Consolidated Financial Statements and accompanying notes included in Part IV, Item 15 of this Annual Report on Form 10-K, and the risk factors and related information set forth in Part I, Item 1A and Part II,

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

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.

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

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

ITEM 9B - OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
PART III

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

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.

ITEM 12 - SECURITY OWNERSHIP
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.

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.

ITEM 14 - PRINCIPAL ACCOUNTANT 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

ITEM 15 - EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)Documents included in this report:
1. Financial Statements
Report of management on internal control over financial reporting
Report of independent registered public accounting firm (PCAOB ID: 42)
Report of independent registered public accounting firm (PCAOB ID: 42)
Statement of consolidated operations for each of the three years in the period ended December 31, 2021
Statement of consolidated comprehensive income (loss) for each of the three years in the period ended December 31, 2021
Statement of consolidated cash flows for each of the three years in the period ended December 31, 2021
Consolidated balance sheet as of December 31, 2021 and 2020
Statement of consolidated changes in equity (deficit) and noncontrolling interest for each of the three years in the period ended December 31, 2021
Notes to consolidated financial statements
2. Financial Statement Schedules
Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in the Company’s financial statements and related notes.
3. Exhibits
EXHIBIT
NO. DESCRIPTION
2.1 - Agreement and Plan of Merger, dated as of March 1, 2021, by and among Apache Corporation, Registrant, and APA Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
3.1 - Amended and Restated Certificate of Incorporation of Registrant, dated March 1, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
3.2 - Amended and Restated Bylaws of Registrant, dated September 14, 2021 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed September 20, 2021, SEC File No. 001-40144).
4.1 - Form of Certificate for Registrant’s Common Stock (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
4.2 - Description of Equity Securities of the Registrant (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
10.1 - Assignment and Assumption Agreement, dated as of March 1, 2021, by and between Registrant and Apache Corporation (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.2 - APA Corporation Income Continuance Plan, as amended and restated effective as of March 1, 2021 (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.3 - APA Corporation Executive Termination Policy, as amended and restated effective as of March 1, 2021 (incorporated by reference to Exhibit 10.3 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.4 - APA Corporation 2016 Omnibus Compensation Plan, dated February 3, 2016, effective May 12, 2016 (incorporated by reference to Exhibit 10.1 to Apache Corporation’s Current Report on Form 8-K filed May 16, 2016, SEC File No. 001-4300).
†10.5 - First Amendment to the Registrant’s 2016 Omnibus Compensation Plan, dated July 29, 2019 (incorporated by reference to Exhibit 10.13 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.6 - Second Amendment to the Registrant’s 2016 Omnibus Compensation Plan, dated March 1, 2021 (incorporated by reference to Exhibit 10.6 to the Registrant’s Current Report on Form 8-K12B filed on March 1, 2021, SEC File No. 001-40144).
†10.7 - APA Corporation 2011 Omnibus Equity Compensation Plan, as amended and restated May 12, 2016 (incorporated by reference to Exhibit 10.1 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.8 - First Amendment to the Registrant’s 2011 Omnibus Equity Compensation Plan, dated July 29, 2019 (incorporated by reference to Exhibit 10.15 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.9 - Second Amendment to the Registrant’s 2011 Omnibus Equity Compensation Plan, dated March 1, 2021 (incorporated by reference to Exhibit 10.5 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.10 - APA Corporation 2007 Omnibus Equity Compensation Plan, as amended and restated May 4, 2011 (incorporated by reference to Exhibit 10.1 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, SEC File No. 001-4300).
†10.11 - First Amendment to the Registrant’s 2007 Omnibus Equity Compensation Plan, dated March 1, 2021 (incorporated by reference to Exhibit 10.4 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.12 - APA Corporation Deferred Delivery Plan, as amended and restated May 12, 2016 (incorporated by reference to Exhibit 10.3 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.13 - APA Corporation Non-Employee Directors’ Compensation Plan, as amended and restated July 13, 2017 (incorporated by reference to Exhibit 10.1 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017, SEC File No. 001-4300).
†10.14 - APA Corporation Outside Directors’ Retirement Plan, as amended and restated July 16, 2014, effective June 30, 2014 (incorporated by reference to Exhibit 10.5 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, SEC File No. 001-4300).
†10.15 - APA Corporation Non-Employee Directors’ Restricted Stock Units Program, as amended and restated May 14, 2015 (incorporated by reference to Exhibit 10.6 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, SEC File No. 001-4300).
EXHIBIT
NO. DESCRIPTION
†10.16 - APA Corporation Non-Employee Directors’ Restricted Stock Units Program, effective May 12, 2016, pursuant to the Registrant’s 2016 Omnibus Compensation Plan (incorporated by reference to Exhibit 10.4 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.17 - APA Corporation Outside Directors’ Deferral Program, effective May 12, 2016, pursuant to the Registrant’s 2016 Omnibus Compensation Plan (incorporated by reference to Exhibit 10.5 to Apache Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, SEC File No. 001-4300).
†10.18 - Form of 2018 Restricted Stock Unit Award Agreement dated January 16, 2018 (2016 Omnibus Compensation Plan) (incorporated by reference to Exhibit 10.43 to Apache Corporation’s Annual Report on Form 10-K for the year ended December 31, 2017, SEC File No. 001-04300).
†10.19 - Form of 2018 Cash-Settled Restricted Stock Unit Award Agreement dated January 16, 2018 (2016 Omnibus Compensation Plan) (incorporated by reference to Exhibit 10.44 to Apache Corporation’s Annual Report on Form 10-K for the year ended December 31, 2017, SEC File No. 001-04300).
†10.20 - Form of 2018 Performance Share Grant Agreement (2016 Omnibus Compensation Plan), dated January 16, 2018 (incorporated by reference to Exhibit 10.1 to Apache Corporation’s Current Report on Form 8-K filed January 19, 2018, SEC File No. 001-04300).
†10.21 - Form of 2018 Stock Option Grant Agreement (2016 Omnibus Compensation Plan), dated January 16, 2018 (incorporated by reference to Exhibit 10.2 to Apache Corporation’s Current Report on Form 8-K filed January 19, 2018, SEC File No. 001-04300).
†10.22 - Form of 2019 Performance Share Program (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.1 to Apache Corporation’s Current Report on Form 8-K filed January 7, 2019, SEC File No. 001-04300).
†10.23 - Form of 2019 Cash-Based Restricted Stock Unit Grant Agreement (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.2 to Apache Corporation’s Current Report on Form 8-K filed January 7, 2019, SEC File No. 001-04300).
†10.24 - Form of 2019 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.47 to Apache Corporation’s Annual Report on Form 10-K for the year ended December 31, 2018, SEC File No. 001-04300).
†10.25 - Form of 2019 Cash-Based Restricted Stock Unit Grant Agreement (2016 Omnibus Compensation Plan), dated January 3, 2019 (incorporated by reference to Exhibit 10.48 to Apache Corporation’s Annual Report on Form 10-K for the year ended December 31, 2018, SEC File No. 001-04300).
†10.26 - Amendment of Performance Share Grant Agreement, dated July 29, 2019 (incorporated by reference to Exhibit 10.52 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.27 - Amendment of Restricted Stock Unit Award Agreement, dated July 29, 2019 (incorporated by reference to Exhibit 10.53 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.28 - Amendment of Stock Option Grant Agreement, dated July 29, 2019 (incorporated by reference to Exhibit 10.54 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.29 - Form of 2020 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.55 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.30 - Form of 2020 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.56 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.31 - Form of 2020 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.57 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.32 - Form of 2020 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 3, 2020 (incorporated by reference to Exhibit 10.58 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2019, SEC File No. 001-4300).
†10.33 - Form of 2021 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021 (incorporated by reference to Exhibit 10.43 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2020, SEC File No. 001-04300).
†10.34 - Form of 2021 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021 (incorporated by reference to Exhibit 10.44 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2020, SEC File No. 001-4300).
EXHIBIT
NO. DESCRIPTION
†10.35 - Form of 2021 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021 (incorporated by reference to Exhibit 10.45 to Apache Corporation's Annual Report on Form 10-K for year ended December 31, 2020, SEC File No. 001-4300).
†10.36 - Form of 2021 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 5, 2021 (incorporated by reference to Exhibit 10.46 to Apache Corporation’s Annual Report on Form 10-K for year ended December 31, 2020, SEC File No. 001-04300).
†10.37 - Amendment of Restricted Stock Unit Award Agreement, dated March 1, 2021 (incorporated by reference to Exhibit 10.7 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.38 - Amendment of Performance Share Grant Agreement, dated March 1, 2021 (incorporated by reference to Exhibit 10.8 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.39 - Amendment of Stock Option Grant Agreement, dated March 1, 2021 (incorporated by reference to Exhibit 10.9 to Registrant’s Current Report on Form 8-K12B filed March 1, 2021, SEC File No. 001-40144).
†10.40 - Form of 2022 Performance Share Program Agreement (2016 Omnibus Compensation Plan), dated January 4, 2022. (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed January 7, 2022, SEC File No. 001-40144)
*†10.41 - Form of 2022 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 4, 2022.
*†10.42 - Form of 2022 Cash-Based Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 4, 2022.
*†10.43 - Form of 2022 Restricted Stock Unit Award Agreement (2016 Omnibus Compensation Plan), dated January 4, 2022.
*21.1 - Subsidiaries of Registrant.
*23.1 - Consent of Ernst & Young LLP.
*23.2 - Consent of Ryder Scott Company, L.P., Petroleum Consultants.
*24.1 - Power of Attorney (included as a part of the signature pages to this report).
*31.1 - Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
*31.2 - Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
*32.1 - Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*99.1 - Report of Ryder Scott Company, L.P., Petroleum Consultants.
*101.INS - Inline XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).
*101.SCH - Inline XBRL Taxonomy Schema Document.
*101.CAL - Inline XBRL Calculation Linkbase Document.
*101.DEF - Inline XBRL Definition Linkbase Document.
*101.LAB - Inline XBRL Label Linkbase Document.
*101.PRE - Inline XBRL Presentation Linkbase Document.
*104 - Cover Page Interactive Data File (the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document).
* Filed herewith.
† Management contracts or compensatory plans or arrangements required to be filed herewith pursuant to Item 15 hereof.
NOTE: Debt instruments of the Registrant defining the rights of long-term debt holders in principal amounts not exceeding 10 percent of the Registrant’s consolidated assets have been omitted and will be provided to the Commission upon request.
ITEM 16. FORM 10-K SUMMARY
None.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
APA CORPORATION
/s/ John J. Christmann IV
John J. Christmann IV
Chief Executive Officer and President
Dated: February 22, 2022
POWER OF ATTORNEY
The officers and directors of APA Corporation, whose signatures appear below, hereby constitute and appoint John J. Christmann IV, Stephen J. Riney, and Rebecca A. Hoyt, and each of them (with full power to each of them to act alone), the true and lawful attorney-in-fact to sign and execute, on behalf of the undersigned, any amendment(s) to this report and each of the undersigned does hereby ratify and confirm all that said attorneys shall do or cause to be done by virtue thereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Name Title Date
/s/ John J. Christmann IV
John J. Christmann IV
Director, Chief Executive Officer, and President
(principal executive officer)
February 22, 2022
/s/ Stephen J. Riney
Stephen J. Riney
Executive Vice President and Chief Financial Officer
(principal financial officer) February 22, 2022
/s/ Rebecca A. Hoyt
Rebecca A. Hoyt
Senior Vice President, Chief Accounting Officer, and Controller
(principal accounting officer) February 22, 2022
/s/ Annell R. Bay
Annell R. Bay
Director February 22, 2022
/s/ Juliet S. Ellis
Juliet S. Ellis
Director February 22, 2022
/s/ Charles W. Hooper
Charles W. Hooper
Director February 22, 2022
/s/ Chansoo Joung
Chansoo Joung
Director February 22, 2022
/s/ John E. Lowe
John E. Lowe
Independent, Non-Executive Chairman of the Board and Director February 22, 2022
/s/ H. Lamar McKay
H. Lamar McKay
Director February 22, 2022
/s/ William C. Montgomery
William C. Montgomery
Director February 22, 2022
/s/ Amy H. Nelson
Amy H. Nelson
Director February 22, 2022
/s/ Daniel W. Rabun
Daniel W. Rabun
Director February 22, 2022
/s/ Peter A. Ragauss
Peter A. Ragauss
Director February 22, 2022
REPORT OF MANAGEMENT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management of the Company is responsible for the preparation and integrity of the consolidated financial statements appearing in this annual report on Form 10-K. The financial statements were prepared in conformity with accounting principles generally accepted in the United States and include amounts that are based on management’s best estimates and judgments.
Management of the Company is responsible for establishing and maintaining effective internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by a program of internal audits and appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel and a written code of business conduct adopted by our Company’s board of directors, applicable to all Company directors and all officers and employees of our Company and subsidiaries.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control - Integrated Framework (2013). Based on our assessment, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2021.
The Company’s independent auditors, Ernst & Young LLP, a registered public accounting firm, are appointed by the Audit Committee of the Company’s board of directors. Ernst & Young LLP have audited and reported on the consolidated financial statements of APA Corporation and subsidiaries and the effectiveness of the Company’s internal control over financial reporting. The reports of the independent auditors follow this report on pages and.
/s/ John J. Christmann IV
Chief Executive Officer and President
(principal executive officer)
/s/ Stephen J. Riney
Executive Vice President and Chief Financial Officer
(principal financial officer)
/s/ Rebecca A. Hoyt
Senior Vice President, Chief Accounting Officer and Controller
(principal accounting officer)
Houston, Texas
February 22, 2022
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of APA Corporation:
Opinion on Internal Control Over Financial Reporting
We have audited APA Corporation and subsidiaries’ internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, APA Corporation and subsidiaries (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2021 and 2020, the related statements of consolidated operations, comprehensive income (loss), cash flows and changes in equity and noncontrolling interest for each of the three years in the period ended December 31, 2021, and the related notes and our report dated February 22, 2022 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Houston, Texas
February 22, 2022
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of APA Corporation:
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of APA Corporation and subsidiaries (the Company) as of December 31, 2021 and 2020, the related statements of consolidated operations, comprehensive income (loss), cash flows and changes in equity and noncontrolling interest for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 22, 2022 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Depreciation, depletion and amortization of property and equipment
Description of
the Matter At December 31, 2021, the carrying value of the Company’s property and equipment was $8,335 million, and depreciation, depletion and amortization (DD&A) expense was $1,360 million for the year then ended. As described in Note 1, the Company follows the successful efforts method of accounting for its oil and gas properties. DD&A of the cost of proved oil and gas properties is calculated using the unit-of-production method based on proved oil and gas reserves, as estimated by the Company’s internal reservoir engineers.
Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and natural gas liquids, 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. Significant judgment is required by the Company’s internal reservoir engineers in evaluating geological and engineering data when estimating oil and gas reserves. Estimating reserves also requires the selection of inputs, including oil and gas price assumptions, future operating and capital costs assumptions, and tax rates by jurisdiction, among others. Because of the complexity involved in estimating oil and gas reserves, management engaged independent petroleum engineers to audit the proved oil and gas reserve estimates prepared by the Company’s internal reservoir engineers for select properties as of December 31, 2021.
Auditing the Company’s DD&A calculations is complex because of the use of the work of the internal reservoir engineers and the independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating oil and gas reserves.
How We
Addressed the
Matter in Our
Audit We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the engineers for use in estimating oil and gas reserves.
Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s internal reservoir engineers primarily responsible for overseeing the preparation of the reserve estimates and the independent petroleum engineers used to audit the proved oil and gas reserve estimates for select properties. In addition, in assessing whether we can use the work of the engineers, we evaluated the completeness and accuracy of the financial data and inputs described above used by the engineers in estimating oil and gas reserves by agreeing them to source documentation, and we identified and evaluated corroborative and contrary evidence. For proved undeveloped reserves, we evaluated management’s development plan for compliance with the SEC rule that undrilled locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time, by assessing consistency of the development projections with the Company’s development plan and the availability of capital relative to the development plan. We also tested the mathematical accuracy of the DD&A calculation, including comparing the oil and gas reserve amounts used in the calculation to the Company’s reserve reports.
Accounting for asset retirement obligation for the North Sea segment
Description of
the Matter
At December 31, 2021, the asset retirement obligation (ARO) balance totaled $2,130 million. As further described in Note 8, the Company’s ARO reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The estimation of the ARO related to the North Sea segment requires significant judgment given the magnitude of the expected retirement costs and higher estimation uncertainty related to the timing of settlements and settlement amounts.
Auditing the Company’s ARO for the North Sea segment is complex and highly judgmental because of the significant estimation required by management in determining the obligation. In particular, the estimate was sensitive to significant subjective assumptions such as retirement cost estimates and the estimated timing of settlements, which are both affected by expectations about future market and economic conditions.
How We
Addressed the
Matter in Our
Audit
We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s internal controls over its ARO estimation process, including management’s review of the significant assumptions that have a material effect on the determination of the obligations. We also tested management’s controls over the completeness and accuracy of financial data used in the valuation.
To test the ARO for the North Sea segment, our audit procedures included, among others, assessing the significant assumptions and inputs used in the valuation, such as retirement cost estimates and timing of settlement assumptions. For example, we evaluated retirement cost estimates by comparing the Company’s estimates to recent offshore activities and costs. Additionally, we compared assumptions for the timing of settlements to production forecasts. We also involved our internal specialists in testing the underlying retirement cost estimates.
Accounting for decommissioning contingency for sold Gulf of Mexico properties
Description of
the Matter
At December 31, 2021, the decommissioning contingency for sold Gulf of Mexico properties (decommissioning contingency) balance totaled $1,186 million. As further described in Note 11, the Company’s decommissioning contingency reflects the estimated undiscounted potential liability to fund decommissioning of the sold Gulf of Mexico properties. The estimation of the decommissioning contingency requires significant judgment given the magnitude and higher estimation uncertainty of the expected retirement costs.
Auditing the Company’s decommissioning contingency is complex and highly judgmental because of the significant estimation required by management in determining the decommissioning contingency. In particular, the estimate was sensitive to retirement cost and duration estimates, which are subjective assumptions affected by expectations about future market and economic conditions.
How We
Addressed the
Matter in Our
Audit
We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s internal controls over its decommissioning contingency estimation process, including management’s review of the significant assumptions that have a material effect on the determination of the contingency. We also tested management’s controls over the completeness and accuracy of financial data used in the valuation.
To test the decommissioning contingency, our audit procedures included, among others, assessing the significant assumptions and inputs used in the valuation, such as retirement cost and duration estimates. For example, we evaluated retirement cost estimates by comparing the Company’s estimates to recent offshore activities and costs as well as current bids obtained from service providers. We also involved our internal specialists in testing the underlying retirement cost and duration estimates.
/s/ Ernst & Young LLP
We have served as the Company’s auditor since 2002.
Houston, Texas
February 22, 2022
APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
The accompanying notes to consolidated financial statements are an integral part of this statement.
APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
The accompanying notes to consolidated financial statements are an integral part of this statement.
APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
The accompanying notes to consolidated financial statements are an integral part of this statement.
APA CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
The accompanying notes to consolidated financial statements are an integral part of this statement.
APA CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CHANGES IN EQUITY (DEFICIT) AND NONCONTROLLING INTEREST
The accompanying notes to consolidated financial statements are an integral part of this statement.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Nature of Operations
APA Corporation (APA or the Company) is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. The Company’s upstream business has exploration and production operations in three geographic areas: the United States (U.S.), Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active exploration and appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. The Company’s midstream business (Altus Midstream) is operated by Altus Midstream Company (Nasdaq: ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas.
On January 4, 2021, Apache Corporation announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, Apache Corporation became a direct, wholly owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares were automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache Corporation pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache Corporation as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the Company’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have subsidiaries operating around the globe.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Accounting policies used by APA and its subsidiaries reflect industry practices and conform to accounting principles generally accepted in the U.S. (GAAP). The Company’s financial statements for prior periods include reclassifications that were made to conform to the current-year presentation. Significant accounting policies are discussed below.
Principles of Consolidation
The implementation of the Holding Company Reorganization was accounted for as a merger under common control. APA recognized the assets and liabilities of Apache at carryover basis. The consolidated financial statements of APA present comparative information for prior years on a combined basis, as if both APA and Apache were under common control for all periods presented.
The accompanying consolidated financial statements include the accounts of APA and its subsidiaries after elimination of intercompany balances and transactions. The Company’s undivided interests in oil and gas exploration and production ventures and partnerships are proportionately consolidated.
The Company consolidates all other investments in which, either through direct or indirect ownership, it has more than a 50 percent voting interest or controls the financial and operating decisions. ALTM is consolidated and qualifies as a variable interest entity (VIE) under GAAP. Additionally, in November of 2021, the Company determined that a limited partnership and APA subsidiary, which has control over APA’s Egyptian operations, qualifies as a VIE under GAAP. Apache consolidates the activities of ALTM and APA’s Egyptian operations because it has concluded that wholly owned subsidiaries have a controlling financial interest in ALTM and APA’s Egyptian operations, respectively, and were determined to be the primary beneficiaries of the VIEs. Additionally, the assets of ALTM may only be used to settle obligations of ALTM. There is no recourse to the Company for ALTM’s liabilities.
Noncontrolling interests represent third-party ownership in the net assets of a consolidated subsidiary of APA and are reflected separately in the Company’s financial statements. Sinopec International Petroleum Exploration and Production Corporation (Sinopec) owns a one-third minority participation in the Company’s Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate component of equity in the Company’s consolidated balance sheet. Additionally, third-party investors own a minority interest of approximately 21 percent of Altus Midstream Company (ALTM), which is reflected as a separate noncontrolling interest component of equity in the Company’s consolidated balance sheet. APA regularly reassesses whether changes in the facts and circumstances regarding the Company’s involvement with a VIE could cause a change in its conclusions related to consolidation. Changes in consolidation status, if any, are applied prospectively.
On June 12, 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units (the Preferred Units) through a private offering that admitted additional limited partners with separate rights for the Preferred Unit holders. Refer to Note 13-Redeemable Noncontrolling Interest - Altus for further detail.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Investments in which the Company holds less than 50 percent of the voting interest are typically accounted for under the equity method of accounting. These investments are recorded separately as “Equity method interests” in the Company’s consolidated balance sheet. The Company’s proportionate share of the results of operations generated by the equity method interests are recorded as a component of “Other, net” under “Revenues and Other” in the Company’s statement of consolidated operations. Refer to Note 6-Equity Method Interests for further detail.
Use of Estimates
Preparation of financial statements in conformity with GAAP and disclosure of contingent assets and liabilities requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. The Company evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of the Company’s financial statements and changes in these estimates are recorded when known.
Significant estimates with regard to these financial statements include the estimates of fair value for long-lived assets (refer to “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), the fair value determination of acquired assets and liabilities (refer to Note 2-Acquisitions and Divestitures), the fair value of equity method interests (refer to “Equity Method Interests” within this Note 1 below and Note 6-Equity Method Interests), the assessment of asset retirement obligations (refer to Note 8-Asset Retirement Obligation), the estimate of income taxes (refer to Note 10-Income Taxes), the estimation of the contingent liability representing the Company’s potential obligation to decommission sold properties in the Gulf of Mexico (refer to Note 11-Commitments and Contingencies), and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (refer to Note 18-Supplemental Oil and Gas Disclosures (Unaudited)).
Fair Value Measurements
Certain assets and liabilities are reported at fair value on a recurring basis in the Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
Recurring fair value measurements are presented in further detail in Note 4-Derivative Instruments and Hedging Activities, Note 9-Debt and Financing Costs, Note 12-Retirement and Deferred Compensation Plans, and Note 13-Redeemable Noncontrolling Interest - Altus.
The Company also uses fair value measurements on a nonrecurring basis when certain qualitative assessments of its assets indicate a potential impairment. The following table presents a summary of asset impairments recorded in connection with fair value assessments:
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
For the year ended December 31, 2021, the Company recorded asset impairments totaling $208 million. These charges include a $160 million impairment on the Company’s equity method interest in the EPIC crude oil pipeline (EPIC) as part of Altus’ review of the fair value of its assets in relation to the announced BCP Business Combination. Refer to “Equity Method Interests” within this Note 1 below and Note 2-Acquisitions and Divestitures for further detail on the BCP Business Combination. The Company also recorded other impairments during 2021 of approximately $26 million in connection with inventory valuations in Egypt and $22 million in connection with inventory valuations and expected equipment dispositions in the North Sea.
For the year ended December 31, 2020, the Company recorded asset impairments totaling $4.5 billion in connection with non-recurring fair value assessments. Given the crude oil price collapse on lower demand and economic activity resulting from the coronavirus disease 2019 (COVID-19) global pandemic and related governmental actions, the Company assessed its oil and gas property and gathering, processing, and transmission (GPT) facilities for impairment based on the net book value of its assets as of March 31, 2020. The Company recognized proved property impairments of $3.9 billion, $354 million, and $7 million in the U.S., Egypt, and North Sea, respectively, all of which were impaired to their estimated fair values as a result of lower forecasted commodity prices, changes to planned development activity, and increasing market uncertainty. Similarly, the Company recognized GPT facility impairments of $68 million in Egypt. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property” and “Property and Equipment - Gathering, Processing, and Transmission Facilities.”
The Company also performed an interim impairment analysis of the goodwill related to its Egypt reporting unit. Reductions in estimated net present value of expected future cash flows from oil and gas properties resulted in implied fair values below the carrying values of the Company’s Egypt reporting unit. As a result of these assessments, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the Egypt reporting unit of $87 million in the first quarter of 2020.
During the remainder of 2020, the Company recorded additional proved property impairments totaling $20 million in Egypt, as well as $13 million for the early termination of drilling rig leases, $5 million for inventory revaluations, and $9 million of other asset impairments, all in the U.S.
During the fourth quarter of 2019, following a material reduction to planned investment in the Company’s Alpine High development, the Company recorded impairments totaling $1.4 billion for its Alpine High proved properties and upstream infrastructure which were written down to their fair values. Altus separately assessed its long-lived infrastructure assets for impairment based on expected reductions to future throughput volumes from Alpine High. Altus subsequently recorded impairments totaling $1.3 billion on its GPT facilities. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property” and “Property and Equipment - Gathering, Processing, and Transmission Facilities.”
Separate from the Company’s Alpine High and Altus impairments, the Company entered into agreements to sell certain of its assets in the Western Anadarko Basin in Oklahoma and Texas. As a result of these agreements, a separate impairment analysis was performed for each of the assets within the disposal groups. The analyses were based on the agreed-upon proceeds less costs to sell for the transaction, a Level 1 fair value measurement. The carrying value of the net assets to be divested exceeded the fair value implied by the expected net proceeds, resulting in impairments in the second and fourth quarters of 2019 totaling $255 million, including $101 million on the Company’s proved properties, $149 million on its unproved properties, and $5 million on other working capital. For more information regarding this transaction, refer to Note 2-Acquisitions and Divestitures.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Revenue Recognition
Upstream
The Company’s upstream oil and gas segments primarily generate revenue from contracts with customers from the sale of its crude oil, natural gas, and natural gas liquids production volumes. In addition to APA-related production volumes, the Company also sells commodity volumes purchased from third-parties to fulfill sales obligations and commitments as the Company’s production fluctuates with potential operational issues and changes to development plans. Under these short-term commodity sales contracts, the physical delivery of each unit of quantity represents a single, distinct performance obligation on behalf of the Company. Contract prices are determined based on market-indexed prices, adjusted for quality, transportation, and other market-reflective differentials. Revenue is measured by allocating an entirely variable market price to each performance obligation and recognized at a point in time when control is transferred to the customer. The Company considers a variety of facts and circumstances in assessing the point of control transfer, including but not limited to: whether the purchaser can direct the use of the hydrocarbons, the transfer of significant risks and rewards, and the Company’s right to payment. Control typically transfers to customers upon the physical delivery at specified locations within each contract and the transfer of title.
APA’s Egypt operations are conducted pursuant to production-sharing contracts (PSCs). Under the terms of the Company’s PSCs, the Company is the contractor partner (Contractor) with the Egyptian General Petroleum Corporation (EGPC) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the Contractor’s income taxes, which remain the liability of the Contractor under domestic law, are paid by EGPC on behalf of the Contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Because Contractor cost recovery entitlement and income taxes paid on its behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on the Company’s Egypt operations despite impacting the Company’s production and reserves. Revenues related to Egypt’s tax volumes are considered revenue from a non-customer.
On December 27, 2021, the Company announced the ratification of a modernized PSC with the Egyptian Ministry of Petroleum and the EGPC, having an effective date of April 1, 2021. The new PSC consolidates 98 percent of gross acreage and 90 percent of gross production into a single concession and refreshes the existing development lease terms for 20 years and exploration leases for 5 years. The consolidated concession has a single cost recovery pool to provide improved access to cost recovery, a fixed 40 percent cost recovery limit, and a fixed profit-sharing rate of 30 percent for all the Company’s production covered under the new concession. The APA subsidiary that became the sole Contractor under the PSC is owned by an APA-operated joint venture owned two-thirds by APA and one-third by Sinopec.
Refer to Note 17-Business Segment Information for a disaggregation of revenue by product and reporting segment.
Altus Midstream
The Company’s Altus Midstream segment is operated by ALTM, through its subsidiary, Altus Midstream LP. Altus generates revenue from contracts with customers from its gathering, compression, processing, and transmission services provided on the Company’s natural gas and natural gas liquid production volumes. Under these long-term commercial service contracts, providing the related service represents a single, distinct performance obligation on behalf of Altus that is satisfied over time. In accordance with the terms of these agreements, Altus primarily receives a fixed fee for each contract year, subject to yearly fee escalation recalculations. Revenue is primarily measured using the output method and recognized in the amount to which Altus has the right to invoice, as performance completed to date corresponds directly with the value to its customers. For the periods presented, Altus Midstream segment revenues were primarily attributable to sales between Altus and APA, which are fully eliminated upon consolidation.
Payment Terms and Contract Balances
Payments under all contracts with customers are typically due and received within a short-term period of one year or less, after physical delivery of the product or service has been rendered. Receivables from contracts with customers, net of allowance for credit losses, totaled $956 million and $670 million as of December 31, 2021 and 2020, respectively.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In accordance with the provisions of ASC 606, “Revenue from Contracts with Customers,” variable market prices for each short-term commodity sale are allocated entirely to each performance obligation as the terms of payment relate specifically to the Company’s efforts to satisfy its obligations. As such, the Company has elected the practical expedients available under the standard to not disclose the aggregate transaction price allocated to unsatisfied, or partially unsatisfied, performance obligations as of the end of the reporting period.
Cash and Cash Equivalents
The Company considers all highly liquid short-term investments with a maturity of three months or less at the time of purchase to be cash equivalents. These investments are carried at cost, which approximates fair value. As of December 31, 2021 and 2020, the Company had $302 million and $262 million, respectively, of cash and cash equivalents, of which approximately $132 million and $24 million, respectively, was held by Altus. The Company had no restricted cash as of December 31, 2021 and 2020.
Accounts Receivable and Allowance for Credit Losses
Accounts receivable are stated at amortized cost net of an allowance for credit losses. The Company routinely assesses the collectability of its financial assets measured at amortized cost. In June 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-13, “Financial Instruments-Credit Losses.” The standard changes the impairment model for trade receivables, held-to-maturity debt securities, net investments in leases, loans, and other financial assets measured at amortized cost. This ASU requires the use of a new forward-looking “expected loss” model compared to the previous “incurred loss” model, resulting in accelerated recognition of credit losses. The Company adopted this update in the first quarter of 2020. This ASU primarily applies to the Company’s accounts receivable balances, of which the majority are received within a short-term period of one year or less. The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analyses. The Company develops its estimated allowance for credit losses primarily using an aging method and analyses of historical loss rates as well as consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. The adoption and implementation of this ASU did not have a material impact on the Company’s financial statements.
The following table presents changes to the Company’s allowance for credit loss:
Inventories
Inventories consist principally of tubular goods and equipment and are stated at the lower of weighted-average cost or net realizable value. Oil produced but not sold, primarily in the North Sea, is also recorded to inventory and is stated at the lower of the cost to produce or net realizable value.
Property and Equipment
The carrying value of the Company’s property and equipment represents the cost incurred to acquire the property and equipment, including capitalized interest, net of any impairments. For business combinations, property and equipment cost is based on the fair values at the acquisition date.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Oil and Gas Property
The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs such as exploratory geological and geophysical costs, delay rentals, and exploration overhead are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, 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 expensed.
Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.
Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized well costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.
Oil and gas properties are grouped for depreciation in accordance with ASC 932 “Extractive Activities-Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
When circumstances indicate that the carrying value of proved oil and gas properties may not be recoverable, the Company compares unamortized capitalized costs to the expected undiscounted pre-tax future cash flows for the associated assets grouped at the lowest level for which identifiable cash flows are independent of cash flows of other assets. If the expected undiscounted pre-tax future cash flows, based on the Company’s estimate of future crude oil and natural gas prices, operating costs, anticipated production from proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is generally estimated using the income approach described in ASC 820. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments, a Level 3 fair value measurement.
The significant decline in crude oil and natural gas prices, as well as longer-term commodity price outlooks, related to reduced demand for oil and natural gas as a result of the COVID-19 pandemic and related governmental actions indicated possible impairment of the Company’s proved and unproved oil and gas properties in early 2020. In addition to estimating risk-adjusted reserves and future production volumes, estimated future commodity prices are the largest driver in variability of undiscounted pre-tax cash flows. Expected cash flows were estimated based on management’s views of published West Texas Intermediate (WTI), Brent, and Henry Hub forward pricing as of the balance sheet dates. Other significant assumptions and inputs used to calculate estimated future cash flows include estimates for future development activity, exploration plans and remaining lease terms. A 10 percent discount rate, based on a market-based weighted-average cost of capital estimate, was applied to the undiscounted cash flow estimate to value all of the Company’s asset groups that were subject to impairment charges in 2019.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table represents non-cash impairments charges of the carrying value of the Company’s proved and unproved properties:
Proved properties impaired had aggregate fair values as of the most recent date of impairment of $1.9 billion and $628 million for 2020 and 2019, respectively.
Unproved leasehold impairments are typically recorded as a component of “Exploration” expense in the Company’s statement of consolidated operations. However, in 2019, unproved impairments of $149 million were recorded as a component of “Impairments” in connection with an agreement to sell certain non-core leasehold properties in Oklahoma and Texas.
Gains and losses on divestitures of the Company’s oil and gas properties are recognized in the statement of consolidated operations upon closing of the transaction. Refer to Note 2-Acquisitions and Divestitures for more detail.
Gathering, Processing, and Transmission Facilities
GPT facilities totaled $673 million and $670 million at December 31, 2021 and 2020, respectively, with accumulated depreciation for these assets totaling $386 million and $323 million for the respective periods. GPT facilities are depreciated on a straight-line basis over the estimated useful lives of the assets. The estimation of useful life takes into consideration anticipated production lives from the fields serviced by the GPT assets, whether APA-operated or third party-operated, as well as potential development plans by the Company for undeveloped acreage within or in close proximity to those fields.
The Company assesses the carrying amount of its GPT facilities whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount of these facilities is more than the sum of the undiscounted cash flows, an impairment loss is recognized for the excess of the carrying value over its fair value.
The Company assessed its long-lived infrastructure assets for impairment as of March 31, 2020, and recorded an impairment of $68 million on its GPT facilities in Egypt during the first quarter of 2020. The fair values of the impaired assets, which were determined to be $46 million, were estimated using the income approach, which considers internal estimates based on future throughput volumes from applicable development concessions in Egypt and estimated costs to operate. These assumptions were applied based on throughput assumptions developed in relation to the oil and gas proved property impairment assessment, as discussed above, to develop future cash flow projections that were then discounted to estimated fair value, using a 10 percent discount rate, based on a market-based weighted-average cost of capital estimate. The Company has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy.
As discussed under “Fair Value Measurements” above, the Company decided to materially reduce its planned investment in the Alpine High play during its fourth-quarter 2019 capital planning review. Altus management subsequently assessed its long-lived infrastructure assets for impairment given the expected reduction to future throughput volumes and recorded impairments of $1.3 billion on its gathering, processing, and transmission assets. The fair values of the impaired assets were determined to be $203 million as of the time of the impairment and were estimated using the income approach. The income approach considered internal estimates of future throughput volumes, processing rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using discount rates believed to be consistent with those applied by market participants. The Company has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Other Property and Equipment
Other property and equipment includes computer software and equipment, buildings, vehicles, furniture and fixtures, land, and other equipment. These assets are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 20 years. Other property and equipment totaled $1.1 billion at each of December 31, 2021 and 2020, with accumulated depreciation for these assets totaling $901 million and $864 million at December 31, 2021 and 2020, respectively.
Asset Retirement Costs and Obligations
The initial estimated asset retirement obligation related to property and equipment and subsequent revisions are recorded as a liability at fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of an asset’s retirement. Asset retirement costs are depreciated using a systematic and rational method similar to that used for the associated property and equipment. Accretion expense on the liability is recognized over the estimated productive life of the related assets.
Capitalized Interest
For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Significant oil and gas investments in unproved properties actively being explored, significant exploration and development projects that have not commenced production, significant midstream development activities that are in progress, and investments in equity method affiliates that are undergoing the construction of assets that have not commenced principal operations qualify for interest capitalization. Interest is capitalized until the asset is ready for service. Capitalized interest is determined by multiplying the Company’s weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once an asset subject to interest capitalization is completed and placed in service, the associated capitalized interest is expensed through depreciation.
Goodwill
Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. The Company currently carries no goodwill, but, in comparative periods, it was recorded in “Deferred charges and other” in the Company’s consolidated balance sheet. The Company assessed the carrying amount of goodwill by testing for impairment annually and when impairment indicators arose. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The Company assessed each country as a reporting unit, with Egypt being the only reporting unit to have associated goodwill during the periods presented. The fair value of the reporting unit was determined and compared to the book value of the reporting unit. If the fair value of the reporting unit was less than the book value, including goodwill, then goodwill was written down to its implied fair value through a charge to expense.
The following presents the changes to goodwill for the years ended 2020 and 2019:
Reductions in estimated net present value of expected future cash flows from oil and gas properties during 2020 resulted in implied fair values below the carrying values of the Company’s Egypt reporting unit. As a result of this assessment, the Company recognized non-cash impairments of the entire amount of recorded goodwill in the Egypt reporting unit of $87 million in 2020. This goodwill impairment was recorded in “Impairments” in the Company’s statement of consolidated operations.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Equity Method Interests
The Company follows the equity method of accounting when it does not exercise control over its equity interests, but can exercise significant influence over the operating and financial policies of the entity. Under this method, the equity interests are carried originally at acquisition cost, increased by the Company’s proportionate share of the equity interest’s net income and contributions made by the Company, and decreased by the Company’s proportionate share of the equity interest’s net losses and distributions received by the Company.
Equity method interests are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in income. In the fourth quarter of 2021, Altus, as part of its review of the fair value of its assets in relation to the announced BCP Business Combination, determined the current fair value of its investment in EPIC was below carrying value. Altus subsequently determined that this loss in value to be other than temporary. As such, in the fourth quarter of 2021, Altus recorded an impairment charge of $160 million on its equity method interest in EPIC. The fair value of the impaired interest was determined using the income approach. The income approach considered estimates of future throughput volumes, tariff rates, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimated fair value, using a discount rate believed to be consistent with that which would be applied by market participants. Altus has classified this nonrecurring fair value measurement as Level 3 in the fair value hierarchy. Refer to Note 6-Equity Method Interests for further details of the Company’s equity method interests.
Commitments and Contingencies
Accruals for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change. For more information regarding loss contingencies, refer to Note 11-Commitments and Contingencies.
Derivative Instruments and Hedging Activities
The Company periodically enters into derivative contracts to manage its exposure to commodity price, interest rate, and/or foreign exchange risk. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options.
All derivative instruments, other than those that meet the normal purchases and sales exception, are recorded on the Company’s consolidated balance sheet as either an asset or liability measured at fair value. The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses from the change in fair value of derivative instruments are reported in current-period income as “Derivative instrument losses, net” under “Revenues and Other” in the statement of consolidated operations. Refer to Note 4-Derivative Instruments and Hedging Activities for further information.
Income Taxes
The Company records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The Company routinely assesses the ability to realize its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is 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) and changing tax laws.
Earnings Per Share
The Company’s basic earnings per share (EPS) amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects potential dilution, using the treasury stock method, which assumes that options were exercised and restricted stock was fully vested. The Company uses the “if-converted method” to determine the potential dilutive effect of an assumed exchange of the outstanding Preferred Units of Altus Midstream LP for shares of ALTM’s common stock. The impact to net income (loss) attributable to common stock on an assumed conversion of the redeemable noncontrolling Preferred Units interest in Altus Midstream LP were anti-dilutive for the years ended December 31, 2021, 2020, and 2019.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Stock-Based Compensation
The Company grants various types of stock-based awards including stock options, restricted stock, cash-settled restricted stock units, and performance-based awards. Stock compensation equity awards granted are valued on the date of grant and are expensed over the required vesting service period. Cash-settled awards are recorded as a liability based on the Company’s stock price and remeasured at the end of each reporting period over the vesting terms. The Company has elected to account for forfeitures as they occur rather than estimate expected forfeitures. The Company’s stock-based compensation plans and related accounting policies are defined and described more fully in Note 14-Capital Stock.
Treasury Stock
The Company follows the weighted-average-cost method of accounting for treasury stock transactions.
Transaction, Reorganization, and Separation (TRS)
In recent years, the Company streamlined its portfolio through strategic divestitures and centralized certain operational activities in an effort to capture greater efficiencies and cost savings through shared services. In light of the continued streamlining of the Company’s asset portfolio through divestitures and strategic transactions, in late 2019 management initiated a comprehensive redesign of the Company’s organizational structure and operations. Efforts related to this organization were substantially completed during 2020. The Company incurred and paid a cumulative total of $79 million of reorganization costs through December 31, 2020. An additional $17 million of reorganization costs were incurred during the year ended December 31, 2021, primarily related to ongoing consulting and separation activities in the Company’s international operations.
The Company recorded $22 million, $54 million, and $50 million of TRS costs in 2021, 2020, and 2019, respectively. TRS costs incurred in 2021 relate to $11 million for consulting costs associated with the reorganization, $6 million of separation costs associated with the reorganization, and $5 million for costs associated with the BCP Business Combination. TRS costs incurred in 2020 relate to $51 million of separation costs associated with the reorganization, $2 million for transaction consulting fees, and $1 million of office closure costs. TRS costs incurred in 2019 associated with the reorganization include $26 million for employee termination benefits and $2 million for consulting fees. The Company also incurred $15 million of expenses for employee termination benefits and office closures associated with other reorganization efforts and $7 million for consulting and legal fees on various transactions throughout 2019.
New Pronouncements Issued But Not Yet Adopted
In March 2020, the FASB issued ASU 2020-04, “Reference Rate Reform (Topic 848),” which provides optional expedients and exceptions for applying U.S. GAAP to contracts, hedging relationships, and other transactions affected by the discontinuation of the London Interbank Offered Rate (LIBOR) or by another reference rate expected to be discontinued. In January 2021, the FASB issued ASU 2021-01, which clarified the scope and application of the original guidance. The guidance was effective beginning March 12, 2020 and can be applied prospectively through December 31, 2022. The Company is evaluating whether to apply any of these expedients and, if elected, will adopt these standards when LIBOR is discontinued.
In August 2020, the FASB issued ASU 2020-06, “Debt-Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging-Contracts in Entity’s Own Equity (Subtopic 815-40)” to improve financial reporting associated with accounting for convertible instruments and contracts in an entity’s own equity. This update is effective for the Company beginning in the first quarter of 2022 using either the modified or fully retrospective method with a cumulative effect adjustment to the opening balance of retained earnings. The Company does not believe it will have a material impact on its financial statements.
2. ACQUISITIONS AND DIVESTITURES
2022 Activity
In February 2022, the Company entered into an agreement to sell certain non-core mineral rights in the Delaware Basin for cash consideration of approximately $805 million, subject to customary post-closing adjustments. The transaction is expected to close in late February 2022, subject to regulatory approvals.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
2021 Activity
During the second quarter of 2021, the Company completed the sale of certain non-core assets in the Permian Basin with a net carrying value of $157 million for cash proceeds of $176 million and the assumption of asset retirement obligations of $44 million. The Company recognized a gain of approximately $63 million in connection with the sale. The transaction is subject to normal post-closing adjustments.
During 2021, the Company also completed the sale of other non-core assets and leasehold, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $80 million. The Company recognized a gain of approximately $4 million upon closing of these transactions.
During 2021, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $9 million.
On October 21, 2021, ALTM announced that it will combine with privately-owned BCP Raptor Holdco LP (BCP) in an all-stock transaction (the BCP Business Combination). BCP is the parent company of EagleClaw Midstream, which includes EagleClaw Midstream Ventures, the Caprock Midstream and Pinnacle Midstream businesses, and a 26.7 percent interest in the Permian Highway Pipeline.
As consideration for the transaction, ALTM will issue 50 million shares of Class C Common Stock (and its subsidiary, Altus Midstream LP, will issue a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. The transaction is expected to close during the first quarter of 2022, following completion of customary closing conditions.
2020 Activity
During 2020, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $4 million. Also during 2020, the Company completed the sale of certain non-core assets and leasehold, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $87 million, and recognized a gain of $13 million.
2019 Activity
U.S. Divestitures and Leasehold, Property, and Other Acquisitions
In the third quarter of 2019, the Company completed the sale of non-core 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. These assets met the criteria to be classified as held for sale in the second quarter of 2019. Accordingly, the Company performed a fair value assessment of the assets and recorded impairments of $240 million to the carrying value of proved and unproved oil and gas properties, other fixed assets, and working capital. The transaction closed in the third quarter of 2019, and the Company recognized a $7 million loss in connection with the sale.
In the second quarter of 2019, the Company completed the sale of certain non-core assets in Oklahoma that had a net carrying value of $206 million for aggregate cash proceeds of approximately $223 million. The Company recognized a $17 million gain in connection with the sale.
During 2019, the Company also completed the sale of certain other non-core producing assets, GPT assets, and leasehold acreage, primarily in the Permian Basin, in multiple transactions for total cash proceeds of $73 million. The Company recognized a net gain of approximately $33 million upon closing of these transactions.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
During 2019, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $40 million.
Suriname Joint Venture Agreement
In December 2019, the Company entered into a joint venture agreement with TotalEnergies (formerly, Total S.A.) to explore and develop Block 58 offshore Suriname. Under the terms of the agreement, the Company and TotalEnergies each hold a 50 percent working interest in Block 58. Pursuant to the agreement, the Company operated the drilling of the first four wells, the Maka Central-1, Sapakara West-1, Kwaskwasi-1, and Keskesi East-1, and subsequently transferred operatorship of Block 58 to TotalEnergies on January 1, 2021. The Company continued to operate the Keskesi exploration well until completion of drilling operations during the first half of 2021.
In connection with the agreement, the Company received $100 million from TotalEnergies 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. All proceeds were applied against the carrying value of the Company’s Suriname properties and associated inventory. The Company recognized a $19 million gain in the first quarter of 2020 associated with the transaction.
Key terms of the agreement provide for TotalEnergies to pay a proportionately larger share of appraisal and development costs, which would be recoverable through hydrocarbon participation. For the first $10 billion of gross capital expenditures, TotalEnergies pays 87.5 percent, and the Company pays 12.5 percent; for the next $5 billion in gross expenditures, TotalEnergies pays 75 percent and the Company pays 25 percent; and for all gross expenditures above $15 billion, TotalEnergies pays 62.5 percent and the Company pays 37.5 percent. The Company will also receive various other forms of consideration, including a $75 million cash payment upon achieving first oil production, and future contingent royalty payments from successful joint development projects.
3. CAPITALIZED EXPLORATORY WELL COSTS
The following summarizes the changes in capitalized exploratory well costs for the years ended December 31, 2021, 2020, and 2019. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.
The following provides an aging of capitalized exploratory well costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling as of December 31:
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether reserves can be attributed to these projects. Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling were $123 million at December 31, 2021, with $90 million related to Suriname. Analysis of well results is ongoing as is additional exploration and appraisal activity. Exploration and appraisal well activity in the North Sea accounted for $24 million, where subsurface evaluation and project viability assessment is ongoing. The remaining projects pertain to onshore drilling activity in Egypt for which continued testing and evaluation is ongoing.
Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling at December 31, 2020 and 2019, relate to onshore projects in Egypt and the U. S. Drilling activity and testing has continued for several of these projects in Egypt throughout 2021, and are currently being evaluated for potential development. The costs related to the U.S. projects were charged to exploration expense based on management’s assessment and development efforts.
In December 2019, the Company entered into the joint venture agreement with TotalEnergies, pursuant to which the Company sold 50 percent of its ownership interest in Block 58 to TotalEnergies. Proceeds received from TotalEnergies upon closing were applied against the carrying value of its Suriname properties.
The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2021, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed:
4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Objectives and Strategies
The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company utilizes various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices or foreign currency values.
Counterparty Risk
The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, the Company utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of December 31, 2021, the Company had derivative positions with 10 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments resulting from lower commodity prices or changes in currency exchange rates.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Derivative Instruments
Commodity Derivative Instruments
As of December 31, 2021, the Company had the following open natural gas financial basis swap contracts:
Foreign Currency Derivative Instruments
The Company has open foreign currency costless collar contracts in GBP/USD for £15 million per month for the calendar year 2022 with a weighted average floor and ceiling price of $1.39 and $1.29, respectively.
Embedded Derivatives
Altus Preferred Units Embedded Derivative
During the second quarter of 2019, Altus Midstream LP issued and sold the Preferred Units. Certain redemption features embedded within the Preferred Units require bifurcation and measurement at fair value. For further discussion of this derivative, refer to “Fair Value Measurements” below and Note 13-Redeemable Noncontrolling Interest - Altus.
Pipeline Capacity Embedded Derivatives
During the fourth quarter of 2019 and first quarter of 2020, the Company entered into an agreement to assign a portion of its contracted capacity under an existing transportation agreement to a third party. Embedded in this agreement is an arrangement under which the Company has the potential to receive payments calculated based on pricing differentials between Houston Ship Channel and Waha during calendar years 2020 and 2021. This feature requires bifurcation and measurement of the change in market value for each period. Unrealized gains or losses in the fair value of this feature are recorded as “Derivative instrument gains (losses), net” under “Revenues and Other” in the statement of consolidated operations. Any proceeds received are deferred and reflected in income over the original tenure of the host contract.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Fair Value Measurements
The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:
(1)The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.
The fair values of the Company’s derivative instruments and pipeline capacity embedded derivatives are not actively quoted in the open market. The Company primarily uses a market approach to estimate the fair values of these derivatives on a recurring basis, utilizing futures pricing for the underlying positions provided by a reputable third party, a Level 2 fair value measurement.
The fair value of the Preferred Units embedded derivative is calculated using an income approach, a Level 3 fair value measurement. The fair value determination is based on a range of factors, including expected future interest rates using the Black-Karasinski model, Altus’ imputed interest rate, interest rate volatility, the expected timing of periodic cash distributions, any anticipated early redemptions of the Preferred Units, the estimated timing for the potential exercise of the exchange option, and anticipated dividend yields of the Preferred Units. As of the December 31, 2021 valuation date, the Company used the forward B-rated Energy Bond Yield curve to develop the following key unobservable inputs used to value this embedded derivative:
In addition, no early redemptions of the Preferred Units were assumed for the December 31, 2020 valuation. As a result of the announced BCP Business Combination and associated publicly filed information, the December 31, 2021 valuation assumed 250,000 Preferred Units would be redeemed before the Preferred Unit holders had the right to exercise their exchange option. This early redemption assumption significantly reduced the value of the derivative liability year over year.
A one percent increase in the imputed interest rate assumption would significantly increase the value of the embedded derivative as of December 31, 2021, while a one percent decrease would lead to a similar decrease in value as of December 31, 2021. The assumed expected timing until exercise of the exchange option at December 31, 2021 was 4.45 years.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Derivative Activity Recorded in the Consolidated Balance Sheet
All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
Derivative Activity Recorded in the Statement of Consolidated Operations
The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:
Derivative instrument gains and losses are recorded in “Derivative instrument gains (losses), net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains (losses) for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument losses (gains), net” in “Adjustments to reconcile net income (loss) to net cash provided by operating activities.”
The Company seeks to maintain a balance between “first of month” and “gas daily pricing” for its U.S. natural gas portfolio and sales activities in a given month as part of its ordinary course of business. This is typically implemented through a combination of physical and financial contracts that settle monthly.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
5. OTHER CURRENT ASSETS
The following table provides detail of the Company’s other current assets as of December 31:
6. EQUITY METHOD INTERESTS
As of December 31, 2021 and 2020, the Company, through its ownership of Altus, has the following equity method interests in four Permian Basin long-haul pipeline entities, which are accounted for under the equity method of accounting. For each of the equity method interests, Altus has the ability to exercise significant influence based on certain governance provisions and its participation in activities and decisions that impact the management and economic performance of the equity method interests.
As of December 31, 2021 and 2020, unamortized basis differences included in the equity method interest balances were $34 million and $38 million, respectively. These amounts represent differences in Altus’ initial costs paid to acquire the equity method interests and its initial underlying equity in the respective entities, as well as capitalized interest related to Permian Highway Pipeline (PHP) construction costs. Unamortized basis differences are amortized into equity income (loss) over the useful lives of the underlying pipeline assets when they are placed into service.
The following table presents the activity in Altus’ equity method interests for the years ended December 31, 2021 and 2020:
(1)Altus’ proportionate share of the PHP construction costs is funded with Altus’ revolving credit facility. Accordingly, Altus capitalized $8 million of related interest expense during 2020, which is included in the basis of the PHP equity interest.
(2)The Company impaired its investment in EPIC in the fourth quarter of 2021. Refer to Note 1-Summary of Significant Accounting Policies for further details on this impairment charge.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Summarized Combined Financial Information
The following presents summarized information of combined statement of operations for Altus’ equity method interests (on a 100 percent basis):
(1)Although Altus’ interests in EPIC Crude Holdings, LP, Permian Highway Pipeline LLC, and Breviloba, LLC were acquired in March, May, and July 2019, respectively, the combined financial results are presented for the full year ended December 31, 2019 for comparability.
The following presents summarized combined balance sheet information for Altus’ equity method interests (on a 100 percent basis) as of December 31:
7. OTHER CURRENT LIABILITIES
The following table provides detail of the Company’s other current liabilities as of December 31:
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
8. ASSET RETIREMENT OBLIGATION
The following table describes changes to the Company’s asset retirement obligation (ARO) liability:
The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the Company’s oil and gas properties and other long-lived assets. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. The Company estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property or other long-lived asset balance.
During 2021 and 2020, the Company recorded $3 million and $10 million, respectively, in abandonment liabilities resulting from the Company’s exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. During 2021, approximately $146 million net abandonment costs were revised upward to reflect changes in estimates of higher current activity costs and long-term inflation assumptions, primarily in the U.S. During 2020, approximately $23 million net abandonment costs were revised upward to reflect changes in estimates of timing and costs, primarily in the North Sea.
9. DEBT AND FINANCING COSTS
Overview
The debt of Apache and Altus Midstream LP is senior unsecured debt and has equal priority with respect to the payment of both principal and interest. All indentures of Apache for the notes and debentures described below place certain restrictions on Apache, including limits on Apache’s ability to incur debt secured by certain liens. Certain of these indentures also restrict Apache’s ability to enter into certain sale and leaseback transactions and give holders the option to require Apache to repurchase outstanding notes and debentures upon certain changes in control. None of the indentures contain prepayment obligations in the event of a decline in credit ratings.
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 and $400 million in aggregate principal amount of 5.350% notes due July 1, 2049. The notes are redeemable at any time, in whole or in part, at Apache’s option, subject to a make-whole premium. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers and for general corporate purposes.
On June 21, 2019, Apache closed cash tender offers for certain outstanding notes. Apache accepted for purchase $932 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of approximately $1.0 billion reflecting principal, the net premium to par, early tender premium, and accrued and unpaid interest. The Company recorded a net loss of $75 million on extinguishment of debt, including $7 million of unamortized debt issuance costs and discount, in connection with the note purchases.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
On August 17, 2020, Apache closed offerings of $1.25 billion in aggregate principal amount of senior unsecured notes, comprised of $500 million in aggregate principal amount of 4.625% notes due 2025 and $750 million in aggregate principal amount of 4.875% notes due 2027. The senior unsecured notes are redeemable at any time, in whole or in part, at Apache’s option, at the applicable redemption price. The net proceeds from the sale of the notes were used to purchase certain outstanding notes in cash tender offers, repay a portion of outstanding borrowings under Apache’s senior revolving credit facility, and for general corporate purposes.
On August 18, 2020, Apache closed cash tender offers for certain outstanding notes. Apache accepted for purchase $644 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of $644 million, reflecting principal, aggregate discount to par of $38 million, early tender premium of $32 million, and accrued and unpaid interest of $6 million. The Company recorded a net gain of $2 million on extinguishment of debt, including an acceleration of unamortized debt discount and issuance costs, in connection with the note purchases.
During 2020, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $588 million for an aggregate purchase price of $428 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $168 million. These repurchases resulted in a $158 million net gain on extinguishment of debt. The net gain includes an acceleration of related discount and debt issuance costs. Additionally, on November 3, 2020, Apache redeemed the remaining $183 million of outstanding 3.625% senior notes due February 1, 2021 at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The repurchases were financed by borrowings under Apache’s revolving credit facility.
During the quarter ended September 30, 2021, Apache closed cash tender offers for certain outstanding notes, accepting for purchase $1.7 billion aggregate principal amount of notes covered by the tender offers. Apache paid holders an aggregate cash purchase price of $1.8 billion, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $105 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs, in connection with the note purchases.
During 2021, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $22 million for an aggregate purchase price of $20 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $2 million. The Company recognized a $1 million net gain on extinguishment of debt as part of these transactions.
The Company records gains and losses on extinguishment of debt in “Financing costs, net” in the Company’s statement of consolidated operations.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table presents the carrying value of the Company’s debt:
(1)On January 18, 2022, Apache redeemed the 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date.
(2)These notes are redeemable, as a whole or in part, at Apache’s option, subject to a make-whole premium, except that the 7.75% notes due 2029 are only redeemable as whole for principal and accrued interest in the event of certain Canadian tax law changes. The remaining notes and debentures are not redeemable.
(3)Assumed by Apache in August 2017 as permitted by terms of these notes originally issued by a subsidiary and guaranteed by Apache.
(4)The fair values of Apache’s notes and debentures were $7.1 billion and $8.5 billion as of December 31, 2021 and 2020, respectively. The Company uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).
(5)The carrying amount of borrowings on credit facilities approximates fair value because the interest rates are variable and reflective of market rates.
Maturities for the Company’s notes and debentures excluding discount and debt issuance costs as of December 31, 2021 are as follows:
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Uncommitted Lines of Credit
The Company from time to time has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of December 31, 2021 and 2020, there were no outstanding borrowings under these facilities. As of December 31, 2021, there were £117 million and $17 million in letters of credit outstanding under these facilities. As of December 31, 2020, there were £34 million and $17 million in letters of credit outstanding under these facilities.
Unsecured Committed Bank Credit Facilities
In March 2018, Apache entered into a revolving credit facility with commitments totaling $4.0 billion. In March 2019, the term of this facility was extended by one year to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise of an extension option. Apache can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of December 31, 2021. The facility is for general corporate purposes. As of December 31, 2021, there were $542 million of borrowings and an aggregate of £748 million and $20 million in letters of credit outstanding under this facility. As of December 31, 2020, there were $150 million of borrowings and an aggregate of £633 million and $40 million in letters of credit outstanding under this facility. The outstanding letters of credit were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020.
At Apache’s option, the interest rate per annum for borrowings under the 2018 facility is either a base rate, as defined, plus a margin, or the LIBOR, plus a margin. Apache also pays quarterly a facility fee at a per annum rate on total commitments. The margins and the facility fee vary based upon Apache’s senior long-term debt rating. At December 31, 2021, the base rate margin was 0.5 percent, the LIBOR margin was 1.50 percent, and the facility fee was 0.25 percent. A commission is payable quarterly to lenders on the face amount of each outstanding letter of credit at a per annum rate equal to the LIBOR margin then in effect. Customary letter of credit fronting fees and other charges are payable to issuing banks.
The financial covenants of the 2018 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.
The 2018 facility’s negative covenants restrict the ability of Apache and its subsidiaries to create liens securing debt on its hydrocarbon-related assets, with exceptions for liens typically arising in the oil and gas industry; liens securing debt incurred to finance the acquisition, construction, improvement, or capital lease of assets, provided that such debt, when incurred, does not exceed the subject purchase price and costs, as applicable, and related expenses; liens on subsidiary assets located outside of the U. S. and Canada; and liens arising as a matter of law, such as tax and mechanics’ liens. Apache also may incur liens on assets if debt secured thereby does not exceed 15 percent of Apache’s consolidated net tangible assets, or approximately $1.9 billion as of December 31, 2021. Negative covenants also restrict Apache’s ability to merge with another entity unless it is the surviving entity, dispose of substantially all of its assets, and guarantee debt of non-consolidated entities in excess of the stated threshold.
In November 2018, Altus Midstream LP entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream LP’s two, one-year extension options). The agreement for this facility, as amended, provides aggregate commitments from a syndicate of banks of $800 million. All aggregate commitments include a letter of credit subfacility of up to $100 million and a swingline loan subfacility of up to $100 million. Altus Midstream LP may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of December 31, 2021, there were $657 million of borrowings and a $2.0 million of letter of credit outstanding under this facility. As of December 31, 2020, there were $624 million of borrowings and no letters of credit outstanding under this facility.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The agreement for Altus Midstream LP’s credit facility, as amended, restricts distributions in respect of capital to ALTM and other unit holders in certain circumstances. Unless the Leverage Ratio is less than or equal to 4.00:1.00, the agreement limits such distributions to $30 million per calendar year until either (i) the consolidated net income of Altus Midstream LP and its restricted subsidiaries, as adjusted pursuant to the agreement, for three consecutive calendar months equals or exceeds $350 million on an annualized basis or (ii) Altus Midstream LP has a specified senior long-term debt rating; in addition, before the occurrence of one of those two events, the Leverage Ratio must be less than or equal to 5.00:1.00. In no event can any distribution be made that would, after giving effect to it on a pro forma basis, result in a Leverage Ratio greater than (i) 5.00:1.00 or (ii) for a specified period after a qualifying acquisition, 5.50:1.00. The Leverage Ratio is the ratio of (1) the consolidated indebtedness of Altus Midstream LP and its restricted subsidiaries to (2) EBITDA (as defined in the agreement) of Altus Midstream LP and its restricted subsidiaries for the 12-month period ending immediately before the determination date. The Leverage Ratio as of December 31, 2021 was less than 4.00:1.00.
The terms of Altus Midstream LP’s Preferred Units also contain certain restrictions on distributions in respect of capital, including the common units held by ALTM 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 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 the Company, Apache, or any of the Company’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, 2021.
Commercial Paper Program
As of December 31, 2020, Apache had no commercial paper outstanding. Apache did not use its commercial paper program in 2021 and terminated the program during the third quarter of 2021.
Financing Costs, Net
The following table presents the components of Apache’s financing costs, net:
As of December 31, 2021, the Company had $39 million of debt issuance costs, which will be charged to interest expense over the life of the related debt issuances. Discount amortization of $6 million, $7 million, and $2 million was recorded as interest expense in 2021, 2020, and 2019, respectively.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
10. INCOME TAXES
Income (loss) before income taxes is composed of the following:
The total income tax provision consists of the following:
The total income tax provision differs from the amounts computed by applying the U.S. statutory income tax rate to income (loss) before income taxes. A reconciliation of the tax on the Company’s income (loss) before income taxes and total tax expense is shown below:
(1)The change in state valuation allowance is included as a component of state income tax.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The net deferred income tax liability reflects the net tax impact of temporary differences between the asset and liability amounts carried on the balance sheet under GAAP and amounts utilized for income tax purposes. The net deferred income tax liability consists of the following as of December 31:
Net deferred tax assets and liabilities are included in the consolidated balance sheet as of December 31 as follows:
The Company assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to realize existing deferred tax assets. A significant piece of negative evidence evaluated was the pre-tax book cumulative loss incurred over the three-year period ended December 31, 2021. This cumulative loss was primarily the result of low commodity prices and oil and gas impairments during this period. Such objective evidence limits the ability to consider other subjective evidence, such as the Company’s projections for future growth.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In 2021, 2020, and 2019, the Company’s valuation allowance decreased by $89 million, increased by $1.0 billion, and increased by $1.0 billion, respectively, as detailed in the table below:
(1)Reported as a component of state income taxes.
On December 31, 2021, the Company had net operating losses as follows:
The Company has a U.S. net operating loss carryforward of $9.7 billion, which includes $177 million of net operating loss subject to annual limitation under Section 382 of the Internal Revenue Code (Code). Net operating losses generated in tax years beginning after 2017 are subject to an 80 percent taxable income limitation with indefinite carryover under the 2017 Tax Cuts and Jobs Act. The Company also has a net interest expense carryover of $660 million under Section 163(j) of the Code subject to indefinite carryover, a U.S. capital loss carryforward of $1.9 billion, which has a five year carryover period expiring in 2023 and a Canadian capital loss carryforward of $836 million which has an indefinite carryover. The Company has recorded a full valuation allowance against the U.S. net operating losses, the state net operating losses, the net interest expense carryover, the U.S. capital loss, and the Canadian capital loss because it is more likely than not that these attributes will not be realized.
On December 31, 2021, the Company had foreign tax credits as follows:
The Company has a $2.2 billion U.S. foreign tax credit carryforward. The Company has recorded a full valuation allowance against the U.S. foreign tax credits listed above because it is more likely than not that these attributes will expire unutilized.
The Company accounts for income taxes in accordance with ASC Topic 740, “Income Taxes,” which prescribes a minimum recognition threshold that a tax position must meet before being recognized in the financial statements. Tax positions generally refer to a position taken in a previously filed income tax return or expected to be included in a tax return to be filed in the future that is reflected in the measurement of current and deferred income tax assets and liabilities. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
The Company records interest and penalties related to unrecognized tax benefits as a component of income tax expense. Each quarter, the Company assesses the amounts provided for and, as a result, may increase or reduce the amount of interest and penalties. During each of the years ended December 31, 2021, 2020, and 2019, the Company recorded tax expense of $1 million for interest and penalties. At December 31, 2021, 2020, and 2019, the Company had an accrued liability for interest and penalties of $4 million, $3 million, and $2 million, respectively.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In 2021, 2020, and 2019, the Company recorded a $23 million net increase, an $11 million net increase, and a $58 million net increase, respectively, in its reserve for uncertain tax positions. The Company is currently under IRS audit for the 2014 through 2017 tax years.
Apache and its subsidiaries are subject to U.S. federal income tax as well as income tax in various states and foreign jurisdictions. The Company’s uncertain tax positions are related to tax years that may be subject to examination by the relevant taxing authority. Apache’s earliest open tax years in its key jurisdictions are as follows:
Jurisdiction
11. COMMITMENTS AND CONTINGENCIES
Legal Matters
The Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory control, which also may include controls related to the potential impacts of climate changes. As of December 31, 2021, the Company has an accrued liability of approximately $84 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. The Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to the Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. For material matters that the Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.
Argentine Environmental Claims
On March 12, 2014, the Company and its subsidiaries completed the sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad Anonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, except that Company subsidiaries have agreed to indemnify YPF for certain environmental, tax, and royalty obligations capped at an aggregate of $100 million. The indemnity is subject to specific agreed conditions precedent, thresholds, contingencies, limitations, claim deadlines, loss sharing, and other terms and conditions. On April 11, 2014, YPF provided its first notice of claims pursuant to the indemnity. Company subsidiaries have not paid any amounts under the indemnity but will continue to review and consider claims presented by YPF. Further, Company subsidiaries retain the right to enforce certain Argentina-related indemnification obligations against Pioneer Natural Resources Company (Pioneer) in an amount up to $45 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer.
Louisiana Restoration
Louisiana surface owners often file lawsuits or assert claims against oil and gas companies, including the Company, claiming that operators and working interest owners in the chain of title are liable for environmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to its original condition, regardless of the value of the underlying property. From time to time, restoration lawsuits and claims are resolved by the Company for amounts that are not material to the Company, while new lawsuits and claims are asserted against the Company. With respect to each of the pending lawsuits and claims, the amount claimed is not currently determinable or is not material. Further, the overall exposure related to these lawsuits and claims is not currently determinable. While adverse judgments against the Company are possible, the Company intends to actively defend these lawsuits and claims.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Starting in November of 2013 and continuing into 2021, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including the Company. These cases were all removed to federal courts in Louisiana. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While adverse judgments against the Company might be possible, the Company intends to vigorously oppose these claims.
Apollo Exploration Lawsuit
In a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs alleged damages in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to purchase and sale agreements, mineral leases, and area of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The trial court entered final judgment in favor of the Company, ruling that the plaintiffs take nothing by their claims and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The court of appeals affirmed in part and reversed in part the trial court’s judgment thereby reinstating some of plaintiff’s claims. Further appeal is pending.
Australian Operations Divestiture Dispute
Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the Company and its subsidiaries divested their remaining Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company believes that Quadrant’s claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.
Canadian Operations Divestiture Dispute
Pursuant to a Sale and Purchase Agreement dated July 6, 2017 (Paramount SPA), the Company and its subsidiaries divested their remaining Canadian operations to Paramount Resources LTD (Paramount). Closing occurred on August 16, 2017. On September 11, 2019, four ex-employees of Apache Canada LTD on behalf of themselves and individuals employed by Apache Canada LTD on July 6, 2017, filed an Amended Statement of Claim in a matter styled Stephen Flesch et. al. v Apache Corporation et. al., No. 1901-09160 Court of Queen’s Bench of Alberta against the Company and others seeking class certification and a finding that the Paramount SPA amounted to a Change of Control of the Company, entitling them to accelerated vesting under the Company’s equity plans. In the suit, the class seeks approximately $60 million USD and punitive damages. The Company believes that Plaintiffs’ claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.
California and Delaware Litigation
On July 17, 2017, in three separate actions, San Mateo County, California, Marin County, California, and the City of Imperial Beach, California, all filed suit individually and on behalf of the people of the state of California against over 30 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County and in a separate action on January 22, 2018, the City of Richmond, filed similar lawsuits against many of the same defendants. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants. After removal of all such lawsuits to federal court, the district court remanded them back to state court. The 9th Circuit Court of Appeals’ affirmance of this remand decision was appealed to the U.S. Supreme Court. That appeal was decided by the U.S. Supreme Court ruling in a similar case, BP p.l.c. v. Mayor and City Council of Baltimore. As a result, the California cases have been sent back to the 9th Circuit for further appellate review of the decision to remand the cases to state court. Further activity in the cases has been stayed pending further appellate review.
On September 10, 2020, the State of Delaware filed suit, individually and on behalf of the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. After removal of this lawsuit to federal court, the district court remanded it
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
back to state court. The remand order is being appealed to the 3rd Circuit Court of Appeals. Further activity in the case has been stayed pending this appellate review.
The Company believes that it is not subject to jurisdiction of the California courts and that claims made against it in the California and Delaware litigation are baseless. The Company intends to challenge jurisdiction in California and to vigorously defend the Delaware lawsuit.
Castex Lawsuit
In a case styled Apache Corporation v. Castex Offshore, Inc., et. al., Cause No. 2015-48580, in the 113th Judicial District Court of Harris County, Texas, Castex filed claims for alleged damages of approximately $200 million, relating to overspend on the Belle Isle Gas Facility upgrade, and the drilling of five sidetracks on the Potomac #3 well. After a jury trial, a verdict of approximately $60 million, plus fees, costs, and interest was entered against the Company. The Fourteenth Court of Appeals of Texas reversed the judgment, in part, reducing the judgment to approximately $13.5 million, plus fees, costs, and interest against the Company. Further appeal is pending.
Oklahoma Class Actions
The Company is a party to two purported class actions in Oklahoma styled Bigie Lee Rhea v. Apache Corporation, Case No. 6:14-cv-00433-JH, and Albert Steven Allen v. Apache Corporation, Case No. CJ-2019-00219. The Rhea case has been certified and includes a class of royalty owners seeking damages of approximately $200 million for alleged breach of the implied covenant to market relating to post-production deductions and alleged NGL uplift value. The Allen case has not been certified and seeks to represent a group of owners who have allegedly received late royalty and other payments under Oklahoma statutes. Without acknowledging or admitting any liability and solely to avoid the expense and uncertainty of future litigation, Apache has agreed to a settlement in the Rhea case under which Apache will pay $25 million to resolve all claims against the Company asserted by the class. The settlement is subject to court approval and is expected to be finalized in the first quarter of 2022.
Shareholder and Derivative Lawsuits
On February 23, 2021, a case captioned Plymouth County Retirement System v. Apache Corporation, et al. was filed in the United States District Court for the Southern District of Texas (Houston Division) against the Company and certain current and former officers. The complaint, which is a shareholder lawsuit styled as a class action, (1) alleges that the Company intentionally used unrealistic assumptions regarding the amount and composition of available oil and gas in Alpine High; (2) alleges that the Company did not have the proper infrastructure in place to safely and/or economically drill and/or transport those resources even if they existed in the amounts purported; (3) alleges that these statements and omissions artificially inflated the value of the Company’s operations in the Permian Basin; and (4) alleges that, as a result, the Company’s public statements were materially false and misleading. The Company believes that plaintiffs’ claims lack merit and intends to vigorously defend this lawsuit.
On March 16, 2021, a case captioned William Wessels, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 334th District Court of Harris County, Texas. The case purports to be a derivative action brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserts claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants believe the plaintiff’s claims lack merit and intend to vigorously defend this lawsuit.
Environmental Matters
The Company, as an owner or lessee and operator of oil and gas properties, is subject to various 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 and subject the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. The Company maintains insurance coverage, which it believes is customary in the industry, although the Company is not fully insured against all environmental risks.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The Company also conducts periodic reviews, on a Company-wide basis, to identify changes in its environmental risk profile. These reviews evaluate whether there is a probable liability, the amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, the Company may exclude a property from the acquisition, require the seller to remediate the property to the Company’s satisfaction, or agree to assume liability for the remediation of the property. The Company’s general policy is to limit any reserve additions to any incidents or sites that are considered probable to result in an expected remediation cost exceeding $300,000. Any environmental costs and liabilities that are not reserved for are treated as an expense when actually incurred. In the Company’s estimation, neither these expenses nor expenses related to training and compliance programs are likely to have a material impact on its financial condition.
As of December 31, 2021, the Company had an undiscounted reserve for environmental remediation of approximately $2 million.
On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.
On December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.
The Company is not aware of any environmental claims existing as of December 31, 2021 that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.
Potential Decommissioning Obligations on Sold Properties
In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Currently, Apache holds two bonds (Bonds) and five Letters of Credit to secure Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets.
On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets will be used to fund decommissioning of Legacy GOM Assets.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In September 2021, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notification to BSEE. Apache expects to receive such orders on the other Legacy GOM Assets included in GOM Shelf’s notification letter. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.
If Apache incurs costs to decommission any Legacy GOM Asset and GOM Shelf does not reimburse Apache for such costs, then Apache will obtain reimbursement from Trust A, the Bonds, and the Letters of Credit until such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets.
If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be ordered by BSEE to perform, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to effectively use its available cash to fund the deficit.
As of December 31, 2021, Apache estimates that its potential liability to fund decommissioning of Legacy GOM Assets it may be ordered to perform ranges from $1.2 billion to $1.4 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, during 2021, the Company recorded a contingent liability of $1.2 billion, representing the estimated costs of decommissioning it may be required to perform on Legacy GOM Assets. Of the total liability recorded, $1.1 billion is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $100 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. The Company also recorded a $740 million asset, which represents the amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $640 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $100 million is reflected under “Other current assets.” A “Loss on previously sold Gulf of Mexico properties” in the amount of $446 million was recognized in the third quarter of 2021 to reflect the net impact to the Company’s statement of consolidated operations. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. In addition, significant changes in the market price of oil, gas, and NGLs could further impact Apache’s estimate of its contingent liability to decommission Legacy GOM Assets.
Leases and Contractual Obligations
On January 1, 2019, the Company adopted ASU 2016-02, “Leases (Topic 842),” which requires lessees to recognize separate right-of-use (ROU) assets and lease liabilities for most leases classified as operating leases under previous GAAP. As allowed under the standard, the Company applied practical expedients permitting an entity the option to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases, as well as permitting an entity the option to carry forward its historical assessments of whether existing agreements contain a lease, classification of existing lease agreements, and treatment of initial direct lease costs.
The Company determines if an arrangement is an operating or finance lease at the inception of each contract. If the contract is classified as an operating lease, the Company records an ROU asset and corresponding liability reflecting the total remaining present value of fixed lease payments over the expected term of the lease agreement. The expected term of the lease may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. If the Company’s lease does not provide an implicit rate in the contract, the Company uses its incremental borrowing rate when calculating the present value. In the normal course of business, the Company enters into various lease agreements for real estate, drilling rigs, vessels, aircrafts, and equipment related to its exploration and development activities, which are typically classified as operating leases under the provisions of the standard. ROU assets are reflected within “Deferred charges and other assets” on the Company’s consolidated balance sheet, and the associated operating lease liabilities are reflected within “Other current liabilities” and “Other” within “Deferred Credits and Other Noncurrent Liabilities,” as applicable.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Operating lease expense associated with ROU assets is recognized on a straight-line basis over the lease term. Lease expense is reflected on the statement of consolidated operations commensurate with the leased activities and nature of the services performed. Gross fixed operating lease expense, inclusive of amounts billable to partners and other working interest owners, was $128 million, $149 million, and $222 million for the full years of 2021, 2020, and 2019, respectively. The Company elected to exclude short-term leases (those with terms of 12 months or less) from the balance sheet presentation. Costs incurred for short-term leases, which is primarily related to drilling activities in Block 58 offshore Suriname, was $20 million, $80 million and $18 million in 2021, 2020, and 2019, respectively.
In addition, the Company periodically enters into finance leases that are similar to those leases classified as capital leases under previous GAAP. Finance lease assets are included in “Property, Plant, and Equipment” on the consolidated balance sheet, and the associated finance lease liabilities are reflected within “Current debt” and “Long-term debt,” as applicable. Depreciation on the Company’s finance lease asset was $2 million, $2 million, and $7 million in 2021, 2020, and 2019, respectively. Interest on the Company’s finance lease asset was $2 million, $2 million, and $3 million in 2021, 2020, and 2019, respectively.
The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2021:
At December 31, 2021, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:
(1)Excludes commitments for jointly owned fields and facilities for which the Company is not the operator.
(2)Amounts represent future 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.
(3)Amounts represent the Company’s finance lease obligation related to the Company’s Midland, Texas regional office building.
(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 $198 million, $120 million, and $111 million in 2021, 2020, and 2019, respectively.
(5)Under terms agreed to in the Egypt modernized PSC, the Company committed to spend a minimum of $3.5 billion on exploration, development, and operating activities by March 31, 2026. The Company believes it will be able to satisfy this obligation within its current exploration and development program.
The lease liability reflected in the table above represents the Company’s fixed minimum payments that are settled in accordance with the lease terms. Actual lease payments during the period may also include variable lease components such as common area maintenance, usage-based sales taxes and rate differentials, or other similar costs that are not determinable at the inception of the lease. Gross variable lease payments, inclusive of amounts billable to partners and other working interest owners were $64 million, $41 million, and $78 million in 2021, 2020, and 2019, respectively.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
12. RETIREMENT AND DEFERRED COMPENSATION PLANS
The Company provides retirement benefits to its U.S. employees through the use of multiple plans: a 401(k) savings plan, a money purchase retirement plan, a non-qualified retirement savings plan, and a non-qualified restorative retirement savings plan. The 401(k) savings plan provides participating employees the ability to elect to contribute up to 50 percent of eligible compensation, as defined, to the plan with the Company making matching contributions up to a maximum of 8 percent of each employee’s annual eligible compensation. In addition, the Company contributes 6 percent of each participating employee’s annual eligible compensation to a money purchase retirement plan. The 401(k) savings plan and the money purchase retirement plan are subject to certain annually-adjusted, government-mandated restrictions that limit the amount of employee and Company contributions. For certain eligible employees, the Company also provides a non-qualified retirement savings plan or a non-qualified restorative retirement savings plan. These plans allow the deferral of up to 50 percent of eligible employee’s base salary, up to 75 percent of each employee’s annual bonus (that accepts employee contributions) and the Company’s matching contributions in excess of the government mandated limitations imposed in the 401(k) savings plan and money purchase retirement plan.
Vesting in the Company’s contributions in the 401(k) savings plan, the money purchase retirement plan, the non-qualified retirement savings plan and the non-qualified restorative retirement savings plan occurs at the rate of 20 percent for every completed year of employment. Upon a qualifying change in control of ownership of APA, immediate and full vesting occurs.
Additionally, Apache North Sea Limited maintains a separate retirement plan, as required under the laws of the U.K.
The aggregate annual cost to the Company of all U.S. and international savings plans, the money purchase retirement plan, non-qualified retirement savings plan, and non-qualified restorative retirement savings plan was $31 million, $43 million, and $52 million for 2021, 2020, and 2019, respectively.
The Company also provides a funded noncontributory defined benefit pension plan (U.K. Pension Plan) covering certain employees of the Company’s North Sea operations in the U.K. The plan provides defined pension benefits based on years of service and final salary. The plan applies only to employees who were part of BP North Sea’s pension plan as of April 2, 2003, prior to the acquisition of BP North Sea by the Company effective July 1, 2003.
Additionally, the Company offers postretirement medical benefits to U.S. employees who meet certain eligibility requirements. Eligible participants receive medical benefits up until the age of 65 or at the date they become eligible for Medicare, provided the participant remits the required portion of the cost of coverage. The plan is contributory with participants’ contributions adjusted annually. The postretirement benefit plan does not cover benefit expenses once a covered participant becomes eligible for Medicare.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2021, 2020, and 2019, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. The Company uses a measurement date of December 31 for its pension and postretirement benefit plans.
As of December 31, 2021, 2020, and 2019, the accumulated benefit obligation for the U.K. Pension Plan was $205 million, $207 million, and $181 million, respectively.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company’s defined benefit pension plan assets are held by a non-related trustee who has been instructed to invest the assets in a blend of equity securities and low-risk debt securities. The Company intends that this blend of investments will provide a reasonable rate of return such that the benefits promised to members are provided. The U.K. Pension Plan policy is to target an ongoing funding level of 100 percent through prudent investments and includes policies and strategies such as investment goals, risk management practices, and permitted and prohibited investments. A breakout of previous allocations for plan asset holdings and the target allocation for the Company’s plan assets are summarized below:
The plan’s assets do not include any direct ownership of equity or debt securities of the Company. The fair value of plan assets at December 31, 2021 and 2020 are based upon unadjusted quoted prices for identical instruments in active markets, which is a Level 1 fair value measurement. The following tables present the fair values of plan assets for each major asset category based on the nature and significant concentration of risks in plan assets at December 31, 2021 and 2020:
The expected long-term rate of return on assets assumptions are derived relative to the yield on long-dated fixed-interest bonds issued by the U.K. government (gilts). For equities, outperformance relative to gilts is assumed to be 3.5 percent per year.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following tables set forth the components of the net periodic cost and the underlying weighted average actuarial assumptions used for the pension and postretirement benefit plans as of December 31, 2021, 2020, and 2019:
The Company expects to contribute approximately $5 million to its pension plan and $2 million to its postretirement benefit plan in 2022. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
13. REDEEMABLE NONCONTROLLING INTEREST - ALTUS
Preferred Units Issuance
On June 12, 2019, Altus Midstream LP issued and sold 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 (the Closing). Altus Midstream LP received approximately $611 million in cash proceeds from the sale after deducting transaction costs and discounts to certain purchasers. Pursuant to the partnership agreement of Altus Midstream LP:
•The Preferred Units bear quarterly distributions at a rate of 7 percent per annum, increasing to 10 percent per annum after the fifth anniversary of Closing and upon the occurrence of specified events. Altus Midstream LP may pay distributions in-kind for the first six quarters after the Preferred Units are issued.
•The Preferred Units are redeemable at Altus Midstream LP’s option at any time in cash at a redemption price (the Redemption Price) equal to the greater of an 11.5 percent internal rate of return (increasing after the fifth anniversary of Closing to 13.75 percent) and a 1.3x multiple of invested capital. The Preferred Units will be redeemable at the holder’s option upon a change of control or liquidation of Altus Midstream LP and certain other events, including certain asset dispositions.
•The Preferred Units will be exchangeable for shares of ALTM’s Class A common stock at the holder’s election after the seventh anniversary of Closing or upon the occurrence of specified events. Each Preferred Unit will be exchangeable for a number of shares of ALTM’s Class A common stock equal to the Redemption Price divided by the volume-weighted average trading price of ALTM’s Class A common stock on the Nasdaq Capital Market for the 20 trading days immediately preceding the second trading day prior to the applicable exchange date, less a 6 percent discount.
•Each outstanding Preferred Unit has a liquidation preference equal to the Redemption Price payable before any amounts are paid in respect of Altus Midstream LP’s common units and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation.
•Preferred Units holders have rights to approve certain partnership business, financial, and governance-related matters.
•Altus Midstream LP is restricted from declaring or making cash distributions on its common units until all required distributions on the Preferred Units have been paid. In addition, before the fifth anniversary of Closing, aggregate cash distributions on, and redemptions of, Altus Midstream LP’s common units are limited to $650 million of cash from ordinary course operations if permitted under its credit facility. Cash distributions on, and redemptions of, Altus Midstream LP’s common units also are subject to satisfaction of leverage ratio requirements specified in its partnership agreement.
Classification
The Preferred Units are accounted for on the Company’s consolidated balance sheets as a redeemable noncontrolling interest classified as temporary equity based on the terms of the Preferred Units, including the redemption rights with respect thereto.
Initial Measurement
Altus recorded the net transaction price of $611 million, calculated as the negotiated transaction price of $625 million, less issue discounts of $4 million and transaction costs totaling $10 million.
Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Altus bifurcated and recognized at fair value an embedded derivative related to the Preferred Units at inception of $94 million for a redemption option of the Preferred Unit holders. The derivative is reflected in “Other” within “Deferred Credits and Other Noncurrent Liabilities” on the Company’s consolidated balance sheet at its current fair value of $57 million as of December 31, 2021. The fair value of the embedded derivative, a Level 3 fair value measurement, was based on numerous factors including expected future interest rates using the Black-Karasinski model, Altus’ imputed interest rate, the timing of periodic cash distributions, and dividend yields of the Preferred Units. Refer to Note 4-Derivative Instruments and Hedging Activities for more detail.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The net transaction price was allocated to the preferred redeemable noncontrolling interest and the embedded features according to the associated initial fair value measurements as follows:
Subsequent Measurement
Altus applies a two-step approach to subsequent measurement of the redeemable noncontrolling interest related to the Preferred Units by first allocating a portion of the net income of Altus Midstream LP in accordance with the terms of the partnership agreement. An additional adjustment to the carrying value of the Preferred Unit redeemable noncontrolling interest at each period end may be recorded, if applicable. The amount of such adjustment is determined based upon the accreted value method to reflect the passage of time until the Preferred Units are exchangeable at the option of the holder. Pursuant to this method, the net transaction price is accreted using the effective interest method to the Redemption Price calculated at the seventh anniversary of the Closing. The total adjustment is limited to an amount such that the carrying amount of the Preferred Unit redeemable noncontrolling interest at each period end is equal to the greater of (a) the sum of (i) the carrying amount of the Preferred Units, plus (ii) the fair value of the embedded derivative liability and (b) the accreted value of the net transaction price.
Activity related to the Preferred Units for the years ended December 31, 2021 and 2020 is as follows:
(1)The Preferred Units are redeemable at Altus Midstream LP’s option at a redemption price (the Redemption Price), which as of December 31, 2021 is calculated as the greater of (i) an 11.5 percent internal rate of return and (ii) a 1.3 times multiple of invested capital. As of December 31, 2021, the Redemption Price would have been based on an 11.5 percent internal rate of return, which would equate to a redemption value of $739 million.
(2)Certain redemption features embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. Refer to Note 4-Derivative Instruments and Hedging Activities for discussion of the fair value changes in the embedded derivative liability during the period.
N/A - not applicable.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
14. CAPITAL STOCK
Common Stock Outstanding
The following table provides changes to the Company’s common shares outstanding for the years ended December 31, 2021, 2020, and 2019:
Net Income (Loss) per Common Share
The following table provides a reconciliation of the components of basic and diluted net income (loss) per common share for the years ended December 31, 2021, 2020, and 2019:
The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 3.3 million, 4.5 million, and 5.0 million for the years ended December 31, 2021, 2020, and 2019, respectively. The impact to net income (loss) attributable to common stock on an assumed conversion of the redeemable noncontrolling Preferred Units interest in Altus Midstream LP was anti-dilutive for the years ended December 31, 2021, 2020 and 2019.
Stock Repurchase Program
During 2018, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. No shares were purchased under this authorization through December 31, 2020. During 2021, the Company’s Board of Directors authorized the purchase of an additional 40 million shares of the Company’s common stock. Shares may be purchased either in the open market or through privately held negotiated transactions.
In the fourth quarter of 2021, the Company repurchased 31.2 million shares at an average price of $27.14 per share, and as of December 31, 2021, the Company had remaining authorization to repurchase 48.8 million shares. The Company is not obligated to acquire any additional shares.
Common Stock Dividend
In the first quarter of 2020, the Company’s Board of Directors approved a reduction in the Company’s quarterly dividends from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020. During the third quarter of 2021, the Company’s Board of Directors approved an increase in its quarterly dividend from $0.025 per share to $0.0625 per share, and in the fourth quarter of 2021, approved a further increase in its quarterly dividend to $0.125 per share. For the years ended December 31, 2021, 2020, and 2019, the Company declared common stock dividends totaling $0.2375 per share, $0.10 per share, and $1.00 per share, respectively.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Stock Compensation Plans
The Company maintains several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans. In 2021, pursuant to the Holding Company Reorganization, Apache’s outstanding common shares were converted into equivalent corresponding shares of APA. APA assumed sponsorship of all stock compensation plans. All cash-settled awards previously indexed to Apache’s stock price were subsequently indexed to APA’s stock price, and all unvested stock-settled awards will be settled in APA stock upon vesting.
On May 12, 2016, the Company’s shareholders approved the 2016 Omnibus Compensation Plan (the 2016 Plan), which is used to provide eligible employees with equity-based incentives by granting incentive stock options, non-qualified stock options, performance awards, restricted stock awards, restricted stock units, stock appreciation rights, cash awards, or any combination of the foregoing. As of December 31, 2021, 11.0 million shares were authorized and available for grant under the 2016 Plan. Previously approved plans remain in effect solely for the purpose of governing grants still outstanding that were issued prior to approval of the 2016 Plan. All new grants are issued from the 2016 Plan. In 2018, the Company began issuing cash-settled awards (phantom units) under the restricted stock and conditional restricted stock unit plans. The phantom units represent a hypothetical interest in the Company’s stock and, once vested, are settled in cash.
Costs related to the plans are capitalized or expensed to “Lease operating expenses,” “Exploration,” or “General and administrative” in the Company’s statement of consolidated operations based on the nature of each employee’s activities. The following table summarizes the Company’s stock-settled and cash-settled compensation costs:
Stock Options
As of December 31, 2021, the Company had outstanding options to purchase shares of its common stock under the 2016 Plan, the 2011 Omnibus Equity Compensation Plan (the 2011 Plan), and the 2007 Omnibus Equity Compensation Plan (the 2007 Plan and, collectively with the 2016 Plan and the 2011 Plan, the Omnibus Plans). The Omnibus Plans were submitted to and approved by the Company’s shareholders. New shares of common stock will be issued for employee stock option exercises. Under the Omnibus Plans, the exercise price of each option equals the closing price of APA’s common stock on the date of grant. Options granted become exercisable ratably over a three-year period and expire 10 years after granted.
The following table summarizes stock option activity for the years ended December 31, 2021, 2020, and 2019:
(1)As of December 31, 2021, options outstanding had a weighted average remaining contractual life of 3.1 years and no intrinsic value.
(2)As of December 31, 2021, options exercisable had a weighted average remaining contractual life of 3.1 years and no intrinsic value.
There were no options issued and no options exercised during the years ended December 31, 2021, 2020, and 2019.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Restricted Stock Units and Restricted Stock Phantom Units
The Company has restricted stock unit and restricted stock phantom unit plans for eligible employees, including officers. The value of the stock-settled restricted stock unit awards is established by the market price on the date of grant and is recorded as compensation expense ratably over the vesting terms. The restricted stock phantom unit awards represent a hypothetical interest in either the Company’s common stock or in ALTM’s common stock, as applicable, and, once vested, are settled in cash. Compensation expense related to the cash-settled awards is recorded as a liability and remeasured at the end of each reporting period over the applicable vesting term.
For the years ended December 31, 2021, 2020, and 2019, compensation costs charged to expense for the restricted stock units and restricted stock phantom units was $95 million, $39 million, and $104 million, respectively. As of December 31, 2021, 2020, and 2019, capitalized compensation costs for the restricted stock units and restricted stock phantom units were $15 million, $6 million, and $24 million, respectively.
The following table summarizes stock-settled restricted stock unit activity for the years ended December 31, 2021, 2020, and 2019:
(1)As of December 31, 2021, there was $14 million of total unrecognized compensation cost related to 2,073,419 unvested stock-settled restricted stock units.
(2)As of December 31, 2021, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.8 years.
(3)The grant date fair values of the stock-settled awards vested during 2021, 2020, and 2019 were approximately $25 million, $94 million, and $103 million, respectively.
The following table summarizes cash-settled restricted stock phantom unit activity for the years ended December 31, 2021, 2020, and 2019:
(1)On June 30, 2020, ALTM executed a 1-for-20 reverse stock split of its outstanding common stock. Outstanding cash-settled awards are based on the per-share market price of ALTM stock.
(2)Restricted stock phantom units granted during 2021 and 2020 included 4,375,546 and 3,378,486 awards, respectively, based on the per-share market price of APA common stock and 65,327 and 83,239 awards, respectively, based on the per-share market price of ALTM common stock. The restricted stock phantom units granted during 2020 based on ALTM’s per-share market price reflect the 1-for-20 reverse stock split described above.
(3)The outstanding liability for the unvested cash-settled restricted stock phantom units that had not been recognized as of December 31, 2021 was approximately $74 million.
In January 2022, the Company awarded 775,942 restricted stock units and 2,512,602 restricted stock phantom units based on APA’s weighted-average per-share market price of $29.46 under the 2016 Plan to eligible employees. Total compensation cost for the restricted stock units and the restricted stock phantom units, absent any forfeitures, is estimated to be $23 million and $76 million, respectively, and was calculated based on the per-share fair market value of a share of the Company’s common stock as of the grant date. Compensation cost will be recognized over a three-year vesting period for both plans. The phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of the Company’s common stock.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Also during January 2022, the Company awarded 27,643 restricted stock phantom units based on ALTM’s weighted-average per-share market price of $63.63. The restricted stock phantom units represent a hypothetical interest in ALTM’s common stock and, once vested, are settled in cash. Total compensation cost for these restricted stock phantom units, absent any forfeitures, is estimated to be $2 million and was calculated based on the fair market value of ALTM’s common stock as of the grant date. The restricted stock phantom units will be classified as a liability and remeasured at the end of each reporting period based on the change in fair value of one share of ALTM’s common stock.
Performance Program
To provide long-term incentives for the Company’s employees to deliver competitive shareholder returns, the Company makes annual grants of conditional restricted stock units to eligible employees. APA has a performance program for certain eligible employees with payout for 50 percent of the shares based upon measurement of total shareholder return (TSR) of APA common stock as compared to a designated peer group during a three-year performance period. Payout for the remaining 50 percent of the shares is based on performance and financial objectives as defined in the plan. The overall results of the objectives are calculated at the end of the award’s stated performance period and, if a payout is warranted, applied to the target number of restricted stock units awarded. The performance shares will immediately vest 50 percent at the end of the three-year performance period, with the remaining 50 percent vesting at the end of the following year. Grants from the performance programs outstanding at December 31, 2021, are as described below:
•In January 2017, the Company’s Board of Directors approved the 2017 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial stock-settled conditional restricted stock unit awards totaling 620,885 units. A total of 1,868 restricted stock units were outstanding as of December 31, 2021. The results for the performance period yielded a payout of 54 percent of target.
•In January 2018, the Company’s Board of Directors approved the 2018 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 931,049 units. A total of 97,645 phantom units were outstanding as of December 31, 2021. The results for the performance period yielded a payout of 23 percent of target.
•In January 2019, the Company’s Board of Directors approved the 2019 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,679,832 units. A total of 1,247,706 phantom units were outstanding as of December 31, 2021. The results for the performance period yielded a payout of 100 percent of target.
•In January 2020, the Company’s Board of Directors approved the 2020 Performance Program, pursuant to the 2016 Plan. Eligible employees received initial cash-settled conditional phantom units totaling 1,687,307 units. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,330,823 phantom units were outstanding as of December 31, 2021, from which a minimum of zero to a maximum of 2,661,646 phantom units could be awarded.
•In January 2021, the Company’s Board of Directors approved the 2021 Performance Program, pursuant to the 2016 Plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,959,856 units. The actual amount of phantom units awarded will be between zero and 200 percent of target. A total of 1,854,736 phantom units were outstanding as of December 31, 2021, from which a minimum of zero to a maximum of 3,709,472 units could be awarded.
The fair value cost of the stock-settled awards was estimated on the date of grant and is recorded as compensation expense ratably over the applicable vesting term. The fair value of the cash-settled awards is remeasured at the end of each reporting period over the applicable vesting term. Compensation costs charged to expense under the performance programs were an expense of $57 million, a credit of $8 million, and an expense of $24 million during 2021, 2020, and 2019, respectively. Capitalized compensation costs under the performance programs were an expense of $3 million, a credit of $1 million, and an expense of $3 million during 2021, 2020, and 2019, respectively.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table summarizes cash-settled conditional restricted stock unit activity for the year ended December 31, 2021:
(1)As of December 31, 2021, the outstanding liability for the unvested cash-settled conditional restricted stock units that had not been recognized was approximately $36 million.
In January 2022, the Company’s board of directors approved the 2022 Performance Program, pursuant to the 2016 Plan. Payout for 50 percent of the shares is based upon measurement of TSR of APA common stock as compared to a designated peer group and the S&P 500 Index during a three-year performance period. Payout for the remaining 50 percent of the shares is based on performance and financial objectives as defined in the plan. Eligible employees received the initial cash-settled conditional phantom units totaling 1,093,034 units, with the ultimate number of phantom units to be awarded ranging from zero to a maximum of 2,186,068 units. These phantom units represent a hypothetical interest in the Company’s common stock, and, once vested, are settled in cash. The TSR component of the award had a grant date fair value per award of $41.88 based on a Monte Carlo simulation. The grant date fair value per award for the remaining 50 percent was $29.46 based on the weighted-average fair market value of a share of common stock of the Company as of the grant date. These phantom units will be classified as a liability and remeasured at the end of each reporting period.
15. ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Components of accumulated other comprehensive income (loss) include the following:
16. MAJOR CUSTOMERS
The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. During 2021, sales to EGPC and CFE International accounted for approximately 14 percent and 10 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2020, sales to EGPC and Vitol accounted for approximately 17 percent and 14 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues. During 2019, sales to BP PLC and Sinopec, and their respective affiliates, each accounted for approximately 10 percent and 11 percent, respectively, of the Company’s worldwide crude oil, natural gas, and NGLs production revenues.
Management does not believe that the loss of any one of these customers would have a material adverse effect on the results of operations.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
17. BUSINESS SEGMENT INFORMATION
As of December 31, 2021, the Company is engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. The Company also has active exploration and appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. The Company’s Upstream business explores for, develops, and produces natural gas, crude oil and NGLs. The midstream business is operated by Altus, which owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas. Financial information for each segment is presented below:
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)Includes revenue from non-customers for the years ended December 31, 2021, 2020, and 2019 of:
(2)Includes a noncontrolling interest in Egypt and Altus Midstream.
(3)Intercompany balances are excluded from total assets.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
18. SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)
Oil and Gas Operations
The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities. The Company has no long-term agreements to purchase oil or gas production from foreign governments or authorities.
(1)Includes a noncontrolling interest in Egypt.
(2)Reflects DD&A of capitalized costs of oil and gas properties and, therefore, does not agree with DD&A reflected on Note 17-Business Segment Information.
(3)Reflects only amounts directly related to oil and gas producing properties and, therefore, does not agree with taxes other than income reflected on Note 17-Business Segment Information.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities
In 2021, in connection with APA’s agreement to enter into a modernized PSC agreement with EGPC, as referenced in Note 1-Summary of Significant Accounting Policies, the Company recorded a reduction in proved properties totaling $165 million and an increase in unproved properties of $20 million, reflecting $247 million of incremental value due to the Company for the period between the effective date of April 1, 2021 and closing, partially offset by a $100 million signing bonus and $2 million of other post-closing adjustments.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Capitalized Costs
The following table sets forth the capitalized costs and associated accumulated depreciation, depletion, and amortization relating to the Company’s oil and gas acquisition, exploration, and development activities:
(1)Includes a noncontrolling interest in Egypt.
Oil and Gas Reserve Information
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, the Company uses several different traditional methods that can be classified in three general categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy with similar properties. The Company will, at times, utilize additional technical analysis such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of the Company’s reserve estimates.
There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1)Includes proved reserves of 39 MMbbls, 36 MMbbls, 38 MMbbls, and 40 MMbbls as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1) Includes proved reserves of 159 Mbbls, 281 Mbbls, 252 Mbbls, and 187 Mbbls as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1) Includes proved reserves of 158 Bcf, 141 Bcf, 153 Bcf, and 170 Bcf as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(1) Includes total proved reserves of 66 MMboe, 59 MMboe, 64 MMboe, and 68 MMboe as of December 31, 2021, 2020, 2019, and 2018, respectively, attributable to a noncontrolling interest in Egypt.
During 2021, the Company added approximately 102 MMboe from extensions, discoveries, and other additions. The Company recorded 77 MMboe of exploration and development adds in the U.S., comprising 59 MMboe in the Permian Basin with the remaining 18 MMboe in the Texas Gulf Coast. The Permian Basin drilling programs targeted the Woodford, Barnett, Bone Springs, and Spraberry, while the Texas Gulf Coast focused on the Austin Chalk. International operations contributed 25 MMboe of exploration and development adds, with Egypt contributing 22 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area concession post-PSC modernization. The North Sea contributed 3 MMboe. The Company had combined upward revisions of previously estimated reserves of 107 MMboe. Upward revisions related to changes in product prices accounted for 85 MMboe. Engineering and performance upward revisions accounted for 22 MMboe, with the modernized PSC in Egypt resulting in an increase of 57 MMboe, partially offset by other downward revisions of 35 MMboe across all of the Company’s geographic areas of operation. The Company also sold 28 MMboe of proved reserves associated with U.S. divestitures, primarily related to Permian Basin assets.
As previously discussed, in December 2021, the Egyptian government signed into law an agreement to modernize and consolidate a majority of the Company’s Egypt PSCs. The impact of the consolidated PSC to proved reserves based on the modernized terms is an estimated increase of 53 MMboe and 4 MMboe in developed and undeveloped reserves, respectively, and approximately $750 million in discounted future net cash flows. Approximately 96 percent of the Company’s Egypt reserves are now consolidated within the modernized PSC. These estimates include Sinopec’s noncontrolling interest in Egypt.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
During 2020, the Company added approximately 78 MMboe from extensions, discoveries, and other additions. The Company recorded 39 MMboe of exploration and development adds in the U.S., primarily in the Southern Midland Basin (26 MMboe) associated with the Wolfcamp and Spraberry drilling programs and the remainder in the Delaware Basin and Austin Chalk. The international operations contributed 39 MMboe of exploration and development adds during 2020, with Egypt contributing 32 MMboe from onshore exploration and appraisal activity primarily in the Khalda Area and Umbarka Area concessions. The North Sea contributed 7 MMboe from drilling success, primarily in the Beryl Field. The Company had combined downward revisions of previously estimated reserves of 45 MMboe. Downward revisions related to changes in product prices accounted for 70 MMboe, engineering and performance upward revisions accounted for 27 MMboe, and downward interest revisions accounted for 2 MMboe. The Company also sold 10 MMboe of proved reserves associated with U.S. divestitures, primarily related to Eastern Shelf and Magnet Withers/Pickett Ridge.
During 2019, the Company added approximately 176 MMboe from extensions, discoveries, and other additions. The Company recorded 135 MMboe of exploration and development adds in the U.S., primarily associated with Woodford, Bone Springs, Spraberry, Barnett, and Wolfcamp drilling programs in the Permian Basin (129 MMboe) and various offset drilling activity in the Midcontinent region (6 MMboe). The Company’s international assets contributed 41 MMboe of exploration and development adds during 2019. Egypt contributed 27 MMboe from onshore exploration and appraisal activity in the Khalda Extension 2, Khalda, Khalda Extension 3, East Bahariya Extension 3, and West Kanayis concessions. The North Sea contributed 14 MMboe from drilling success in the Beryl and Forties fields. The Company had combined downward revisions of previously estimated reserves of 119 MMboe. Downward revisions related to changes in product prices accounted for 139 MMboe and engineering and performance upward revisions accounted for 20 MMboe. The Company also sold 107 MMboe of proved reserves associated with U.S. divestitures, primarily related to the sale of the Company’s Woodford-SCOOP and STACK plays and Western Anadarko Basin assets.
Approximately 12 percent of the Company’s year-end 2021 estimated proved developed reserves are classified as proved not producing. These reserves relate to zones that are either behind pipe, or that have been completed but not yet produced, or zones that have been produced in the past, but are not now producing because of mechanical reasons. These reserves are considered to be a lower tier of reserves than producing reserves because they are frequently based on volumetric calculations rather than performance data. Future production associated with behind pipe reserves is scheduled to follow depletion of the currently producing zones in the same wellbores. Additional capital may have to be spent to access these reserves. The capital and economic impact of production timing are reflected in this Note 18, under “Future Net Cash Flows.”
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Future Net Cash Flows
Future cash inflows as of December 31, 2021, 2020, and 2019 were calculated using an unweighted arithmetic average of oil and gas prices in effect on the first day of each month in the respective year, 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. Future development costs include abandonment and dismantlement costs.
The following table sets forth unaudited information concerning future net cash flows for proved oil and gas reserves, net of income tax expense. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities. This information does not purport to present the fair market value of the Company’s oil and gas assets, but does present a standardized disclosure concerning possible future net cash flows that would result under the assumptions used.
(1)Includes discounted future net cash flows of approximately $1.1 billion, $563 million, and $1.0 billion as of December 31, 2021, 2020, and 2019, respectively, attributable to a noncontrolling interest in Egypt.
(2)Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $15.3 billion, $7.1 billion, and $12.4 billion as of December 31, 2021, 2020, and 2019, respectively.
APA CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table sets forth the principal sources of change in the discounted future net cash flows:

Market Capitalization: 10763927.35748291
1-Year Return: -0.03482583910226822
252-Day Return: $252_day_return