Portions of registrant’s proxy statement relating to registrant’s 2020 annual meeting of stockholders have been incorporated by reference in Part II and Part III of this Annual Report on Form 10-K.

---

---

•	the market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services;

•	our commodity hedging arrangements;

•	the supply and demand for oil, natural gas, NGLs, and other products or services;

•	production and reserve levels;

•	drilling risks;

•	economic and competitive conditions;

•	the availability of capital resources;

•	capital expenditure and other contractual obligations;

•	currency exchange rates;

•	weather conditions;

•	inflation rates;

•	the availability of goods and services;

•	legislative, regulatory, or policy changes, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring, or water disposal;

•	our performance on environmental, social, and governance measures;

•	terrorism or cyberattacks;

•	occurrence of property acquisitions or divestitures;

•	the integration of acquisitions;

•	the securities or capital markets and related risks such as general credit, liquidity, market, and interest-rate risks; and

•	other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in this Form 10-K.

---

---

---

(1)	Apache’s operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 21 percent of 2019 production and accounted for 13 percent of year-end estimated proved reserves.

(2)	Sales volumes from the North Sea for 2019 were 21.8 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

---

•	Over 2.9 million gross acres (1.8 million net acres) with exposure to numerous plays focused primarily in the Midland Basin, the Central Basin Platform/Northwest Shelf, and the Delaware Basin.

•	Estimated proved reserves of 665.8 MMboe at year-end 2019, representing 66 percent of the Company’s worldwide proved reserves.

•	In 2019, the Permian region averaged 11 rigs and drilled or participated in 232 wells, 206 of which were horizontal, with a 100 percent success rate.

•	Annual production of 254.3 Mboe/d increased 21 percent from 2018. Fourth-quarter 2019 production increased 13 percent from the prior sequential quarter and 22 percent from the fourth quarter of 2018, a reflection of the success of the Company’s Midland Basin oil-focused drilling program and production from its Alpine High field.

---

•	The Egypt region, which includes onshore conventional assets in Egypt’s Western Desert.

•	The North Sea region, which includes offshore assets based in the United Kingdom.

---

---

---

(1)	Includes production volumes attributable to a one-third noncontrolling interest in Egypt.

(2)	Sales volumes from the North Sea for 2019, 2018, and 2017 were 21.8 MMboe, 20.3 MMboe, and 21.2 MMboe, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

(3)	During the third quarter of 2017, Apache finalized the sale and complete exit of its Canadian operations.

---

---

(1)	Includes total proved developed and total proved undeveloped reserves of 59 MMboe and 5 MMboe, respectively, attributable to a one-third noncontrolling interest in Egypt.

---

---

---

(1)	Sales to BP plc were reported as revenue in the Company’s U.S., Egypt, and North Sea upstream segments in the years ended 2019, 2018, and 2017.

(2)	Sales to Sinopec were reported as revenue in the Company’s Egypt upstream segment in the year ended 2019 and in the Company’s Egypt and North Sea upstream segments in the years ended 2018 and 2017.

(3)	Sales to EGPC were reported as revenue in the Company’s Egypt upstream segment in the years ended 2019, 2018, and 2017.

---

---

•	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 level of global crude oil and natural gas inventories;

•	the price and level of imported foreign crude oil, natural gas, and NGLs;

•	the price and availability of alternative fuels, including coal and biofuels;

•	the availability of pipeline capacity and infrastructure;

•	the availability of crude oil transportation and refining capacity;

•	weather conditions;

•	domestic and foreign governmental regulations and taxes; and

•	the overall economic environment.

•	limiting our financial condition, liquidity, and/or ability to fund planned capital expenditures and operations;

•	reducing the amount of crude oil, natural gas, and NGLs that we can produce economically;

•	causing us to delay or postpone some of our capital projects;

•	reducing our revenues, operating income, and cash flows;

•	limiting our access to sources of capital, such as equity and long-term debt;

•	reducing the carrying value of our oil and gas properties, resulting in additional non-cash impairments;

•	reducing the carrying value of our gathering, processing, and transmission facilities, resulting in additional impairments; or

•	reducing the carrying value of goodwill.

---

•	well blowouts, explosions, and cratering;

•	pipeline or other facility ruptures and spills;

•	fires;

•	formations with abnormal pressures;

•	equipment malfunctions;

•	hurricanes, storms, and/or cyclones, which could affect our operations in areas such as on and offshore the Gulf Coast and North Sea, and other natural and anthropogenic disasters and weather conditions; and

•	surface spillage and surface or ground water contamination from petroleum constituents, saltwater, or hydraulic fracturing chemical additives.

---

•	our production falls short of the hedged volumes;

•	there is a widening of price-basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

•	the counterparties to our hedging or other price risk management contracts fail to perform under those arrangements; or

•	an unexpected event materially impacts commodity prices.

---

---

•	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.

---

•	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.

---

---

---

•	general strikes and civil unrest;

•	the risk of war, acts of terrorism, expropriation and resource nationalization, and forced renegotiation or modification of existing contracts;

•	import and export regulations;

•	taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions;

•	price control;

•	transportation regulations and tariffs;

•	constrained oil or natural gas markets dependent on demand in a single or limited geographical area;

•	exchange controls, currency fluctuations, devaluations, or other activities that limit or disrupt markets and restrict payments or the movement of funds;

•	laws and policies of the United States affecting foreign trade, including trade sanctions;

•	the effects of the U.K.’s withdrawal from the European Union, including any resulting instability in global financial markets or the value of foreign currencies such as the British pound;

•	the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where we currently operate;

•	the possible inability to subject foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of courts in the United States; and

•	difficulties in enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.

---

---

---

---

---

---

---

•	Equivalent production from the Permian region, which accounts for 91 percent of Apache’s total U.S. production, increased 21 percent from 2018 to 2019 driven by the success of the Midland Basin oil-focused drilling program and production increases at its Alpine High field. The Permian region averaged 11 operated rigs during the year, drilling 233 gross wells.

•	The Egypt region’s gross equivalent production decreased 7 percent and net production decreased 11 percent from 2018 primarily a result of natural decline and fewer wells brought on-line during the period. The region continues to build and enhance its robust drilling inventory, supplemented with recent seismic acquisitions and new play concept evaluations, on both new and existing acreage.

•	The North Sea region averaged 3 rigs during 2019, drilling 11 gross development wells with a 100 percent success rate. During the year, the region averaged production of 61 Mboe/d and contributed $1.3 billion of revenues. Production increased 9 percent from 2018, primarily the result of production from the Garten field, which came on-line in November 2018.

•

The North Sea region’s Storr exploration discovery came on-line in the fourth quarter of 2019, and its second well at Garten came on-line in the first quarter of 2020. The first well at the Company’s Storr development is a high-rate gas condensate well that is tied back to existing infrastructure at the Beryl Alpha platform. The Garten #2 well encountered approximately 1,200 feet of net pay and compares favorably to the Garten #1 well, which came on-line in November 2018 with initial 30-day production rates of 13 Mb/d and 17 MMcf/d from 700 feet of net pay. Apache holds a 100 percent working interest in the Garten complex.

•

During 2019, the Company drilled an exploration well, the Maka Central-1, in Block 58 offshore Suriname and announced a significant oil discovery in January 2020. The well successfully tested the presence of hydrocarbons in multiple stacked targets in the upper Cretaceous-aged Campanian and Santonian intervals. The well confirmed 73 meters of oil pay and 50 meters of light oil and gas condensate pay, and appraisal planning is underway. The Company began drilling its second exploration well, Sapakara West-1, in January 2020. Following completion of the Sapakara West-1, the Company will drill a third, and likely a fourth exploration test in Block 58 during 2020.

•

In December 2019, Apache entered into a joint venture agreement to explore and develop Block 58 offshore Suriname. Under the terms of the agreement, Apache and Total S.A. will each hold a 50 percent working interest in Block 58, which comprises approximately 1.4 million acres in water depths ranging from less than 100 meters to more than 2,100 meters. In exchange for a 50 percent interest, Apache will receive various forms of consideration, including $5 billion of carry for its first $7.5 billion of appraisal and development capital and 25 percent carry on all appraisal and development capital beyond its first $7.5 billion. The Company also received $100 million at closing and $75 million in the first quarter of 2020 for reimbursement of 50 percent of all costs incurred on Block 58 to date. Apache will receive an additional $75 million upon achievement of first oil production. Apache will operate the drilling of the first three exploration wells in the block (and may operate a fourth), including the Maka Central-1 well, and subsequently transfer operatorship to Total.

•	Midcontinent/Gulf Coast Divestiture In the second quarter of 2019, Apache completed the sale of non-core, gas-weighted assets in the Woodford-SCOOP and STACK plays for aggregate cash proceeds of approximately $223 million. In the third quarter of 2019, Apache completed the sale of non-core, gas-weighted assets in the western Anadarko Basin of

---

•	U.S. Leasehold Divestitures & Other During 2019, the Company also completed the sale of certain other non-core producing assets, GPT assets, and leasehold acreage, primarily in the Permian region, in multiple transactions for total cash proceeds of $73 million.

•

Altus Transaction In the fourth quarter of 2018, the Company completed the previously announced agreement with Altus Midstream Company and its then wholly-owned subsidiary Altus Midstream LP (collectively, Altus). Altus owns gas gathering, processing, and transmission assets in the Permian Basin of West Texas, anchored by midstream contracts to service Apache’s production from its Alpine High resource play. Altus primarily generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services.

•

Altus Pipeline Options As part of the Altus transaction, Apache contributed options to acquire equity interests in five separate third-party pipeline projects to Altus Midstream LP and/or its subsidiaries. As of December 31, 2019, four of the five joint venture equity options had been exercised by Altus to acquire various ownership interests in the associated third-party pipeline limited liability entities.

•	U.S. and North Sea Divestitures During 2018, Apache completed the sale of certain non-core assets, primarily leasehold acreage in the U.S. and North Sea regions, in multiple transactions for total cash proceeds of approximately $138 million.

•	Canadian Operations On June 30, 2017, Apache completed the sale of its Canadian assets at Midale and House Mountain for total cash proceeds of approximately $228 million. In August of 2017, Apache completed the sale of its remaining Canadian operations for cash proceeds of approximately $478 million, effectively exiting operations in Canada.

•	U.S. Leasehold Divestitures During 2017, Apache completed the sale of certain non-core assets, primarily leasehold acreage in the Permian and Midcontinent/Gulf Coast regions, in multiple transactions for total cash proceeds of $798 million.

•	North Sea Gathering, Processing, and Transmission (GPT) Facility In November 2017, Apache completed the sale of its 30.28 percent interest in the Scottish Area Gas Evacuation (SAGE) gas plant and its 60.56 percent interest in the Beryl pipeline in the North Sea to Ancala Midstream Acquisitions Limited for cash proceeds of $134 million.

---

(1)	Amounts include revenue attributable to a noncontrolling interest in Egypt.

---

(1)	Gross oil, natural gas, and NGL production in Egypt were as follows:

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

(3)	The table shows production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a ratio of 6 Mcf to 1 bbl. This ratio is not reflective of the price ratio between the two products.

(4)	Average sales volumes from the North Sea were 59,797 boe/d, 55,568 boe/d, and 58,177 boe/d for 2019, 2018, and 2017, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

---

•

North America has a common market. Most of the Company’s gas is sold on a monthly or daily basis at either monthly or daily index-based prices. The Company’s U.S. regions averaged $1.26 per Mcf in 2019, down from $2.12 per Mcf in 2018. Current year prices realized by Apache were negatively influenced by limited pipeline takeaway capacity from the Permian Basin that resulted in over supply at various locations in the basin.

•	In Egypt, our gas is sold to Egyptian General Petroleum Corporation (EGPC), primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu,

---

•	Natural gas from the North Sea Beryl field is processed through the SAGE gas plant. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The region averaged $4.48 per Mcf in 2019, a 39 percent decrease from an average of $7.33 per Mcf in 2018.

---

---

---

---

---

•	maintain its current dividend;

•	retain cash flow to initiate progress on debt reduction goals;

•	allocate approximately $200 million to exploration; and

•	achieve flat-to-low single-digit corporate oil production growth, year-over-year.

•	16 percent in the Gulf Coast Express natural gas pipeline (GCX);

•	15 percent in the EPIC crude pipeline (EPIC);

•	26.7 percent in the Permian Highway natural gas pipeline (PHP); and

•	33 percent in the Shin Oak NGL pipeline (Shin Oak).

---

(1)	The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this document, which include accruals.

---

---

---

---

---

(1)	Includes outstanding principal amounts at December 31, 2019. This table does not include future commitment fees, interest expense, or other fees on Altus’ credit facility because they are floating rate instruments, and management cannot determine with accuracy the timing of future loan advances, repayments, or future interest rates to be charged.

(2)	Amounts represent the Company’s undiscounted finance lease obligation related to physical power generators being leased on a one-year term with the right to purchase and a separate lease for the Company’s Midland, Texas regional office building.

(3)	Amounts represent future lease payments associated with oil and gas operations inclusive of amounts billable to partners and other working interest owners. Such payments may be capitalized as a component of oil and gas properties and subsequently depreciated, impaired, or written off as exploration expense.

(4)

Amounts represent any agreements to purchase goods or services that are enforceable and legally binding and that specify all significant terms. These include minimum commitments associated with take-or-pay contracts, NGL processing agreements, drilling work program commitments, and agreements to secure capacity rights on third-party pipelines. Amounts exclude certain product purchase obligations related to marketing and trading activities for which there are no minimum purchase requirements or the amounts are not fixed or determinable. Total costs incurred under take-or-pay and throughput obligations were $111 million, $132 million, and $134 million for 2019, 2018, and 2017, respectively.

(5)	Subsequent to December 31, 2019, Apache entered into an agreement to assign approximately $171 million of its firm transportation obligations beginning in March 2020.

(6)	This table does not include the Company’s liability for dismantlement, abandonment, and restoration costs of oil and gas properties or pension or postretirement benefit obligations. For additional information regarding these liabilities, please see Notes 8 and 12, respectively, in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

---

---

---

---

---

---

---

(a)	Documents included in this report:

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

Nature of Operations

Accounting policies used by Apache 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 accompanying consolidated financial statements include the accounts of Apache 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, Apache has more than a 50 percent voting interest or controls the financial and operating decisions. Noncontrolling interests represent third-party ownership in the net assets of a consolidated Apache subsidiary 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 Apache’s Egypt oil and gas business as a noncontrolling interest, which is reflected as a separate component of equity in Apache’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 Apache’s consolidated balance sheet. Apache consolidates the activities of ALTM, which qualifies as a variable interest entity (VIE) under GAAP. Apache has concluded that it is the primary beneficiary of the VIE, as defined in the accounting standards, since Apache has the power, through its ownership, to direct those activities that most significantly impact the economic performance of ALTM and the obligation to absorb losses or the right to receive benefits that could be potentially significant to ALTM. This conclusion was based on a qualitative analysis that considered ALTM’s governance structure, the commercial agreements between ALTM, Altus Midstream LP, and Apache, and the voting rights established between the members, which provide Apache with the ability to control the operations of Altus. 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. For further details on the terms of the Preferred Units and rights of the holders, refer to Note 13—Redeemable Noncontrolling Interest - Altus.

Investments in which Apache holds less than 50 percent of the voting interest are typically accounted for under the equity method of accounting, with the balance recorded separately as “Equity method interests” in Apache’s consolidated balance sheet and results of operations recorded as a component of “Other” under “Revenues and Other” in the Company’s statement of consolidated operations. Refer to Note 6—Equity Method Interests for more 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. Apache evaluates its estimates and assumptions on a regular basis. Actual results may differ from these estimates and assumptions used in preparation of its financial statements and changes in these estimates are recorded when known. Significant estimates with regard to these financial statements include the fair value determination of acquired assets and liabilities (see Note 2—Acquisitions and Divestitures), the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom

---

(see Note 18—Supplemental Oil and Gas Disclosures (Unaudited)), the assessment of asset retirement obligations (see Note 8—Asset Retirement Obligation), the estimates of fair value for long-lived assets (see “Fair Value Measurements” and “Property and Equipment” sections in this Note 1 below), and the estimate of income taxes (see Note 10—Income Taxes).

 

Fair Value Measurements

Certain assets and liabilities are reported at fair value on a recurring basis in Apache’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.

Apache 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 for 2019, 2018, and 2017:

		For the Year Ended December 31,
		2019				2018				2017
		(In millions)
Oil and gas proved property		$	1,484			$	328			$	—
GPT facilities		1,295				56				—
Equity method investment		—				113				—
Divested unproved properties and leasehold		149				10				—
Inventory and other		21				4				8
Total Impairments		$	2,949			$	511			$	8

For the year ended December 31, 2019, the Company recorded asset impairments totaling $2.9 billion in connection with fair value assessments. During the fourth quarter of 2019, following a material reduction to planned investment in Apache’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. These impairments are discussed in further detail below in “Property and Equipment - Oil and Gas Property.”

During the fourth quarter of 2019 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 gathering, processing, and transmission (GPT) facilities. In the third quarter of 2019, Altus also recorded an impairment charge of $9 million related to the cancellation of construction on a previously planned compressor station. These impairments are discussed in further detail below in “Property and Equipment - Gathering, Processing, and Transmission Facilities.”

Separate from the Company’s Alpine High and Altus impairments, Apache 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.

For the year ended December 31, 2018, the Company recorded asset impairments totaling $511 million in connection with fair value assessments. Impairments totaling $328 million and $56 million were recorded for proved properties, and a gathering and processing facility in Oklahoma, respectively, which were written down to their fair values. These impairments are discussed in further detail below in “Property and Equipment.” During the third quarter of 2018, Apache agreed to sell certain of its unproved properties offshore the U.K. in the North Sea (North Sea). As a result, the Company performed a fair value assessment of the properties and recorded a $10 million impairment on the carrying values of the associated capitalized exploratory well costs. The fair value of the impaired assets was determined using the negotiated sales price, a Level 1 fair value measurement. Also in 2018, the Company recorded $113 million for the impairment of an equity method investment in the U.S. based on a negotiated sales price and $4 million for inventory write-downs in the U.S. for obsolescence.

For the year ended December 31, 2017, the Company recorded asset impairments totaling $8 million in connection with fair value assessments. In 2016, the U.K. government enacted Finance Bill 2016, providing tax relief to exploration and production (E&P) companies operating in the U.K. North Sea. Under the enacted legislation, the U.K. Petroleum Revenue Tax (PRT) rate was reduced to zero from the previously enacted 35 percent rate in effect from January 1, 2016. PRT expense ceased prospectively from that date. During 2017, the Company fully impaired the aggregate remaining value of the recoverable PRT decommissioning asset of $8 million that would have been realized from future abandonment activities. The recoverable value of the PRT decommissioning asset was estimated using the income approach. The expected future cash flows used in the determination were based on anticipated spending and timing of planned future abandonment activities for applicable fields, considering all available information at the date of review. Apache has classified this fair value measurement as Level 3 in the fair value hierarchy.

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, 2019 and 2018, Apache had $247 million and $714 million, respectively, of cash and cash equivalents. As of December 31, 2019, and 2018, the Company had no restricted cash. Approximately $6 million and $450 million of the cash and cash equivalents balance at December 31, 2019 and 2018, respectively, was held by Altus.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for doubtful accounts. The carrying amount of Apache’s accounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables. Many of Apache’s receivables are from joint interest owners on properties Apache operates. The Company may have the ability to withhold future revenue disbursements to recover any non-payment of these joint interest billings. The Company accrues a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of any reserve may be reasonably estimated. As of December 31, 2019, 2018, and 2017, the Company had an allowance for doubtful accounts of $88 million, $92 million, and $84 million, respectively.

The following table describes changes to the Company’s allowance for doubtful accounts for 2019, 2018, and 2017:

		2019				2018				2017
		(In millions)
Allowance for doubtful accounts at beginning of year		$	92			$	84			$	93
Additional provisions for the year		3				9				4
Uncollectible accounts written off net of recoveries		(7		)		(1		)		(13		)
Allowance for doubtful accounts at end of year		$	88			$	92			$	84

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 Apache’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.

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 Apache’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. If applicable, the Company utilizes prices and other relevant information generated by market transactions involving assets and liabilities that are identical or comparable to the item being measured as the basis for determining fair value. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review, a Level 3 fair value measurement.

---

The following table represents non-cash impairments of the carrying value of the Company’s proved and unproved properties for 2019, 2018, and 2017:

		For the Year Ended December 31,
		2019				2018				2017
		(In millions)
Proved Properties:
U.S.		$	1,484			$	265			$	—
Egypt		—				63				—
Total Proved		$	1,484			$	328			$	—
Unproved Properties:
U.S.		$	760			$	96			$	244
Egypt		8				—				—
North Sea		—				128				—
Canada		—				—				2
Total Unproved		$	768			$	224			$	246

Proved properties impaired had aggregate fair values as of the most recent date of impairment of $628 million and $323 million for 2019 and 2018, respectively.

On the statement of consolidated operations, unproved leasehold impairments are typically recorded as a component of “Exploration” expense; however, in 2019, unproved impairments of $149 million were recorded in “Impairments” in connection with an agreement to sell certain non-core leasehold properties in Oklahoma and Texas. In 2018, unproved impairments of $10 million were recorded in “Impairments” in connection with an agreement to sell certain unproved properties in the North Sea. No unproved leasehold impairments were recorded in “Impairments” during 2017.

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. See Note 2—Acquisitions and Divestitures for more detail.

Gathering, Processing, and Transmission Facilities

GPT facilities totaled $799 million and $1.9 billion at December 31, 2019 and 2018, respectively, with accumulated depreciation for these assets totaling $310 million and $264 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 Apache-operated or third party, as well as potential development plans by Apache 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 their 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.

As part of Apache’s fourth quarter 2019 capital planning review, the Company decided to materially reduce its planned investment in the Alpine High play. 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. In the third quarter of 2019, Altus separately recorded an impairment charge of $9 million related to the cancellation of construction on a previously planned compressor station based on estimated sales proceeds for the associated equipment. Apache has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy.

During 2018, the Company recorded impairments of the entire net book value of certain GPT assets in the U.S. in the amount of $56 million associated with a proposed divestiture package. During 2017, the Company recorded no impairments on GPT assets.

---

The costs of GPT facilities sold or otherwise disposed of and associated accumulated depreciation are removed from Apache’s consolidated financial statements, and the resulting gain or loss is reflected in “Gain on divestitures” under “Revenues and Other” in the Company’s statement of consolidated operations. During 2017, Apache recorded a gain totaling $6 million associated with the Company’s divestiture of its 30.28 percent interest in the Scottish Area Gas Evacuation (SAGE) system and its 60.56 percent interest in the Beryl pipeline in the North Sea. For more information regarding this transaction, please refer to Note 2—Acquisitions and Divestitures. No gain or loss on the sales of GPT facilities was recognized during 2019 or 2018.

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, 2019 and 2018, with accumulated depreciation for these assets totaling $817 million and $786 million at December 31, 2019 and 2018, 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 or impairment.

Goodwill

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed, and it is recorded in “Deferred charges and other” in the Company’s consolidated balance sheet. The Company assesses the carrying amount of goodwill by testing for impairment annually and when impairment indicators arise. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. Apache assesses each country as a reporting unit, with Egypt being the only reporting unit to have associated goodwill. The fair value of the reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then goodwill is written down to its implied fair value through a charge to expense.

When there is a disposal of a reporting unit or a portion of a reporting unit that constitutes a business, goodwill associated with that business is included in the carrying amount to determine the gain or loss on disposal. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. The amount of goodwill to be included in that carrying amount is based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained.

There were no changes to goodwill for the years ended 2019, 2018, and 2017. The balance in goodwill was $87 million for each of the years ended 2019, 2018, and 2017.

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, please refer to Note 11—Commitments and Contingencies.

---

Revenue Recognition

On January 1, 2018, Apache adopted Accounting Standards Update (ASU) 2014-09, “Revenue from Contracts with Customers (Topic 606),” using the modified retrospective method on all contracts at the date of initial application. No cumulative effect adjustment to the opening balance of retained earnings was recognized. As a result of the adoption, gas processing fees previously netted in revenue are recorded as “Gathering, processing, and transmission” in the Company’s statement of consolidated operations upon adoption. This accounting treatment has no impact on net income (loss), the consolidated balance sheet, the statement of consolidated cash flows, nor the statement of consolidated changes in equity and noncontrolling interest. Prior comparative periods have not been restated and continue to be reported under the accounting standards in effect for those periods.

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. Because the Company’s production fluctuates with potential operational issues, it is occasionally necessary to purchase third-party oil and gas to fulfill sales obligations and commitments. Sales proceeds related to third-party oil and gas purchases are also classified as revenue from customers. 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.

The Company’s Egyptian operations are conducted pursuant to production sharing contracts under which the contractor partners (Contractors) pay all operating and capital costs for exploring and developing defined concessions. A percentage of the production, generally up to 40 percent, is available to Contractors to recover these operating and capital costs over contractually defined periods. The balance of the production is split among the Contractors and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. Additionally, the Contractors’ income taxes, which remain the liability of the Contractors under domestic law, are paid by EGPC on behalf of the Contractors out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of Apache as Contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Revenues related to Egypt’s tax volumes are considered revenue from a non-customer.

Midstream

The Company’s Altus segment generates revenue from contracts with its customer from its gathering, compression, processing, and transmission services provided on Apache’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 receives a fixed fee for each contract year, subject to yearly fee escalation recalculations. Revenue is 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 all periods presented, all midstream segment revenues were attributable to sales between Altus and Apache. All midstream revenues between Apache and Altus are fully eliminated upon consolidation.

---

Consolidated Revenues from Contracts with Customers

The following table represents consolidated revenues from contracts with customers for the years ended December 31, 2019 and 2018:

		For the Year Ended December 31,
		2019				2018
		(In millions)
Oil and gas production revenues from customers		$	6,315			$	7,348
Less: oil and gas production revenues from non-customer(1)		(451		)		(652		)
Purchased oil and gas sales from customers(2)		176				357
Revenues from contracts with customers		$	6,040			$	7,053

(1)	Oil and gas production revenues from non-customer represents income taxes paid to the Arab Republic of Egypt by EGPC on behalf of the Company. Revenue and associated expenses related to such tax volumes are recorded as “Oil and gas production revenues” and “Current income tax provision,” respectively, in the Company’s statement of consolidated operations.

(2)

Purchased oil and gas sales represent proceeds from the sale of commodity volumes which were purchased from third parties to fulfill volume commitments. Proceeds and associated costs related to such volumes are both recorded as “Other” under “Revenues and Other” in the Company’s statement of consolidated operations. Associated purchase costs totaled $142 million and $340 million for the years ended December 31, 2019 and 2018, respectively.

Refer to Note 17—Business Segment Information for a disaggregation of revenue by product and reporting segment.

Payment Terms and Contract Balances

Payment terms 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 doubtful accounts, totaled $945 million and $1.0 billion as of December 31, 2019 and 2018, respectively.

In accordance with the provisions of ASC 606, 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, we have 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.

Derivative Instruments and Hedging Activities

Apache 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.

Apache records all derivative instruments, other than those that meet the normal purchases and sales exception, on the 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 “Other” under “Revenues and Other” in the statement of consolidated operations. For more information, please refer to Note 4—Derivative Instruments and Hedging Activities.

Income Taxes

Apache 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.

Foreign Currency Transaction Gains and Losses

The U.S. dollar is the functional currency for each of Apache’s international operations. The functional currency is determined country-by-country based on relevant facts and circumstances of the cash flows, commodity pricing environment and financing arrangements in each country. Foreign currency transaction gains and losses arise when monetary assets and liabilities denominated in foreign currencies are remeasured to their U.S. dollar equivalent at the exchange rate in effect at the end of each reporting period.

---

Foreign currency gains and losses also arise when revenue and disbursement transactions denominated in a country’s local currency are converted to a U.S. dollar equivalent based on the average exchange rates during the reporting period.

Foreign currency transaction gains and losses related to current taxes payable and deferred tax assets and liabilities are recorded as components of the provision for income taxes. All other foreign currency transaction gains and losses are reflected in “Other” under “Revenues and Other” in the statement of consolidated operations. The Company’s other foreign currency gains and losses netted to losses of $1 million, $1 million, and $11 million in 2019, 2018, and 2017, respectively.

Insurance Coverage

The Company recognizes an insurance receivable when collection of the receivable is deemed probable. Any recognition of an insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between insurance recoveries and insurance receivables is recorded as a capitalized cost or as an expense, consistent with its original treatment.

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 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 year ended December 31, 2019.

Stock-Based Compensation

Apache 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.

New Pronouncements Issued But Not Yet Adopted

In June 2016, the Financial Accounting Standards Board (FASB) issued 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 current “incurred loss” model, resulting in accelerated recognition of credit losses. This update is effective for the Company beginning in the first quarter of 2020. The Company has completed its initial assessment of credit losses and continues to evaluate and monitor standard setting activity. The adoption and implementation of this ASU will not have a material impact on its financial statements.

In August 2018, the FASB issued ASU 2018-13, “Disclosure Framework: Changes to the Disclosure Requirements for Fair Value Measurement,” which changes the disclosure requirements for fair value measurements by removing, adding, and modifying certain disclosures. This update is effective for the Company beginning in the first quarter of 2020. The adoption and implementation of this ASU will not have a material impact on the disclosures of its financial statements.

In August 2018, the FASB issued ASU 2018-15, “Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract.” This pronouncement clarifies the requirements for capitalizing implementation costs in cloud computing arrangements and aligns them with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. This update is effective for the Company beginning in the first quarter of 2020. The adoption and implementation of this ASU will not have a material impact on its financial statements.

In August 2018, the FASB issued ASU 2018-14, “Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans,” which eliminates, modifies, and adds disclosure requirements for defined benefit plans. This update is effective for the Company beginning in the first quarter of 2021. The Company does not expect the adoption of this ASU to have a material impact on its financial statements.

---

In December 2019, the FASB issued ASU 2019-12, “Simplifying the Accounting for Income Taxes.” This pronouncement is part of the Simplification Initiative and simplifies the accounting for income taxes by removing certain exceptions to the general principles of ASC Topic 740 “Income Taxes.” In addition, the amendment improves consistent application of and simplifies GAAP for other areas of ASC Topic 740 by clarifying and amending existing guidance. This update is effective for the Company beginning in the first quarter of 2021, with early adoption permitted. The Company is currently evaluating the new guidance and does not believe this standard will have a material impact on its financial statements.

2019 Activity

U.S. Divestitures

In the third quarter of 2019, Apache 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 association with the sale.

In the second quarter of 2019, Apache 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 association 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 region, 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.

Suriname Joint Venture Agreement

In December 2019, Apache entered into a joint venture agreement with Total S.A. to explore and develop Block 58 offshore Suriname. Under the terms of the agreement, Apache and Total S.A. will each hold a 50 percent working interest in Block 58. Apache will operate the drilling of the first three exploration wells in the block (and may operate a fourth), including the Maka Central-1 well, and subsequently transfer operatorship to Total. In connection with the agreement, Apache received $100 million from Total S.A. upon closing, which was applied against the carrying value of its Suriname properties, and $75 million upon satisfying certain closing conditions in the first quarter of 2020 for reimbursement of 50 percent of all costs incurred on Block 58 to date.

Apache will also receive various other forms of consideration, including $5 billion of cash carry on Apache’s first $7.5 billion of appraisal and development capital, 25 percent cash carry on all of Apache’s appraisal and development capital beyond the first $7.5 billion, a $75 million cash payment upon achieving first oil production, and future contingent royalty payments from successful joint development projects.

Leasehold, Property, and Other Acquisitions

During 2019, Apache completed leasehold and property acquisitions for total cash consideration of $40 million, primarily in its U.S. onshore regions.

As part of the Altus transaction described below, Apache contributed options to acquire equity interests in five separate third-party pipeline projects to Altus Midstream LP and/or its subsidiaries. As of December 31, 2019, four of the five joint venture equity options had been exercised to acquire various ownership interests in the associated third-party pipeline limited liability entities. For discussion on the Company’s acquisition of equity method interests during the period, refer to Note 6—Equity Method Interests.

2018 Activity

Altus Transaction

In November 2018, Apache completed a transaction with Altus Midstream Company to create a pure-play, Permian Basin to Gulf Coast midstream C-corporation anchored by Apache’s gathering, processing, and transmission assets at Alpine High. Pursuant to the agreement, Apache contributed certain Alpine High midstream assets and options to acquire equity interests in five

---

separate third-party pipeline projects (the Pipeline Options) to Altus and/or its subsidiaries. Altus Midstream Company contributed approximately $628 million of cash, net of transaction expenses. The transaction was accounted for by Altus as a reverse recapitalization. Under this method of accounting, Altus Midstream Company was treated as the “acquired” company, and Apache’s contributed assets of approximately $1.1 billion remained at historical cost, with no goodwill or other intangible assets recorded. Apache owns an approximate 79 percent ownership interest in Altus.

Apache fully consolidates the assets and liabilities of Altus in its consolidated financial statements, with a corresponding noncontrolling interest reflected separately. Apache recorded a noncontrolling interest of $406 million upon closing, which is reflected as a separate component of equity in the Company’s consolidated balance sheet. This represents approximately 21 percent third party ownership of the net assets in Altus at the time of the transaction. The cash contributions in excess of the noncontrolling interest were recognized as additional paid-in capital.

Other Activity

During 2018, Apache completed the sale of certain non-core assets and leasehold, primarily in the North Sea and Permian regions, in multiple transactions for total cash proceeds of $138 million. The Company recognized gains of approximately $23 million during 2018 upon the closing of these transactions.

Apache completed $133 million of leasehold and property acquisitions during 2018, primarily in its U.S. onshore regions.

2017 Activity

Canada Divestitures

During 2017, Apache announced the sale of its subsidiary Apache Canada Ltd. (ACL) and complete exit of its Canadian operations. On June 30, 2017, Apache completed the sale of its Canadian assets at Midale and House Mountain, located in Saskatchewan and Alberta, for aggregate cash proceeds of approximately $228 million. The Company recognized a $52 million loss during the second quarter of 2017 in association with this sale.

In August of 2017, Apache completed the sale of its remaining Canadian operations for aggregate cash proceeds of approximately $478 million. The Company recognized a $74 million gain upon closing of these transactions in the third quarter of 2017. A summary of the Company’s Canadian assets and liabilities at the time of close is detailed below:

		(In millions)
ASSETS:
Cash		$	46
Other current assets		64
Property, plant & equipment		1,132
Total assets		$	1,242
LIABILITIES:
Current liabilities, excluding asset retirement obligation		$	120
Asset retirement obligation		780
Other long-term liabilities		46
Total liabilities		$	946

The net carrying value of the assets disposed included a currency translation loss of $109 million, which was recorded in “Accumulated other comprehensive income (loss)” on the Company’s consolidated balance sheet at December 31, 2016. The currency translation loss was recognized as a reduction of the net gain on sale during the third quarter of 2017 upon closing of the transactions.

Apache’s Canadian operations recorded a pretax loss of $141 million for the year ended 2017.

Other Activity

During 2017, Apache completed the sale of certain non-core assets, primarily leasehold acreage in the Permian and Midcontinent/Gulf Coast regions, in multiple transactions for cash proceeds of $798 million. The Company recognized gains of approximately $605 million during 2017 in connection with these transactions.

Apache completed $188 million of leasehold and property acquisitions during 2017, primarily in its North America onshore regions.

---

Transaction, Reorganization, and Separation (TRS)

Apache recorded $50 million, $28 million, and $16 million of expenses during 2019, 2018, and 2017, respectively, primarily related to company reorganization, including separation costs, investment banking fees on various divestiture transactions, and other associated costs.

In recent years, the Company has centralized certain operational activities in an effort to capture greater efficiencies 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 Apache’s organizational structure and operations, which is expected to be substantially completed for the technical functions by the end of the first quarter of 2020. Changes for the corporate support functions will be ongoing through most of 2020. TRS costs incurred in 2019 associated with this reorganization include $26 million and $2 million for employee termination benefits and consulting fees, respectively, which will be paid throughout 2020. Apache expects to incur additional expenses associated with this reorganization throughout 2020; however, reorganization efforts are ongoing, and the Company is unable to reasonably estimate additional costs at this time. 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.

The following summarizes the changes in capitalized exploratory well costs for each of the last three years ended December 31, 2019, 2018, and 2017. Additions pending the determination of proved reserves excludes amounts capitalized and subsequently charged to expense within the same year.

		2019				2018				2017
		(In millions)
Balance at January 1		$	159			$	350			$	264
Additions pending determination of proved reserves		286				602				477
Divestitures and other		(100		)		(82		)		(3		)
Reclassifications to proved properties		(179		)		(647		)		(373		)
Charged to exploration expense		(25		)		(64		)		(15		)
Balance at December 31		$	141			$	159			$	350

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 at year-end 2019, 2018, and 2017:

		2019				2018				2017
		(In millions)
Exploratory well costs capitalized for a period of one year or less		$	108			$	126			$	160
Exploratory well costs capitalized for a period greater than one year		33				33				190
Balance at December 31		$	141			$	159			$	350
Number of projects with exploratory well costs capitalized for a period greater than one year		2				2				4

Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling at December 31, 2019, relate to separate onshore projects in the United States and Egypt. Drilling activity and testing has continued for both projects throughout 2019 and are currently being evaluated for potential development.

Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling at December 31, 2018, included $28 million related to exploratory drilling in Suriname. In December 2019, Apache entered into a joint venture agreement with Total S.A. selling down 50 percent of its ownership interest in Block 58. In connection with the agreement, proceeds received from Total S.A. upon closing were applied against the carrying value of its Suriname properties.

---

Suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling at December 31, 2017, included $160 million related to three separate projects in the North Sea. The Seagull assets with exploratory costs of $82 million were divested during 2018, and the remaining two projects were reclassified to proved properties or charged to exploration expense based on management’s assessment and development efforts during 2018.

The following table summarizes aging by geographic area of those exploratory well costs that, as of December 31, 2019, have been capitalized for a period greater than one year, categorized by the year in which drilling was completed:

														2016 and
		Total				2018				2017				Prior
		(In millions)
United States		$	24			$	24			$	—			$	—
Egypt		9				9				—				—
		$	33			$	33			$	—			$	—

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.

Objectives and Strategies

Apache 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 also utilizes various types of derivative financial instruments 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, Apache utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. 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, Apache may not realize the benefit of some of its derivative instruments resulting from changes in commodity prices, currency exchange rates, or interest rates.

Derivative Instruments

Commodity Derivative Instruments

As of December 31, 2019, Apache had no open commodity derivative positions.

Foreign Currency Derivative Instruments

Apache has open foreign currency costless collar contracts in GBP/USD for £13.5 million per each calendar month for 2020 with a weighted average floor and ceiling price of $1.26 and $1.38, respectively.

Embedded Derivatives

Altus Preferred Units Embedded Derivative

During the second quarter of 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units. Certain redemption features (the Redemption Option) embedded within the terms of the Preferred Units require bifurcation and measurement at fair value. For further discussion of this derivative, see “Fair Value Measurements” below and Note 13—Redeemable Noncontrolling Interest - Altus.

---

Pipeline Capacity Embedded Derivative

During the fourth quarter of 2019, Apache 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 Apache 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 “Other” under “Revenues and Other” in the statement of consolidated operations. Any proceeds received during the two-year period will be recorded as a deferred gain and reflected in income over the tenure of the host contract.

Fair Value Measurements

The fair values of the Company’s derivative instruments and pipeline capacity embedded derivative 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 Redemption Option, a Level 3 fair value measurement, was based on numerous factors including expected future interest rates using the Black-Karasinski model, the imputed interest rate of Altus, the timing of periodic cash distributions, and dividend yields of the Preferred Units. Increases or decreases in interest rates would result in a higher/lower fair value measurement.

The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:

		Fair Value Measurements Using
		Quoted Price in Active Markets (Level 1)				Significant Other Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total Fair Value				Netting(1)				Carrying Amount
		(In millions)
December 31, 2019
Assets:
Pipeline Capacity Embedded Derivative		$	—			$	8			$	—			$	8			$	—			$	8
Foreign Currency Derivative Instruments		—				1				—				1				—				1
Liabilities:
Preferred Units Embedded Derivative		—				—				103				103				—				103
December 31, 2018
Assets:
Commodity Derivative Instruments		$	—			$	69			$	—			$	69			$	(14	)		$	55
Liabilities:
Commodity Derivative Instruments		—				25				—				25				(14		)		11

(1)	The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties.

---

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:

		December 31, 2019				December 31, 2018
		(In millions)
Current Assets: Other current assets		$	2			$	55
Noncurrent Assets: Deferred charges and other		7				—
Total Assets		$	9			$	55
Current Liabilities: Other current liabilities		$	—			$	11
Deferred Credits and Other Noncurrent Liabilities: Other		103				—
Total Liabilities		$	103			$	11

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:

		For the Year Ended December 31,
		2019				2018				2017
		(In millions)
Realized gain (loss):
Derivative settlements, realized gain (loss)		$	9			$	(81	)		$	24
Amortization of put premium, realized loss		—				(39		)		(100		)
Unrealized gain (loss)		(44		)		103				(59		)
Derivative instrument losses, net		$	(35	)		$	(17	)		$	(135	)

Derivative instrument gains and losses are recorded in “Other” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized gains and losses for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows as a component of “Other” in “Adjustments to reconcile net income (loss) to net cash provided by operating activities.”

5.	OTHER CURRENT ASSETS

The following table provides detail of the Company’s other current assets as of December 31, 2019 and December 31, 2018:

		December 31, 2019				December 31, 2018
		(In millions)
Inventories		$	502			$	401
Drilling advances		92				218
Prepaid assets and other		58				160
Total Other current assets		$	652			$	779

---

6.	EQUITY METHOD INTERESTS

Apache, 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.

		December 31, 2019							December 31, 2018
		Interest			Amount				Interest			Amount
		($ in millions)
Gulf Coast Express Pipeline LLC		16.0	%		$	291			15.0	%		$	91
EPIC Crude Holdings, LP		15.0	%		163				—			—
Permian Highway Pipeline LLC		26.7	%		311				—			—
Shin Oak Pipeline (Breviloba, LLC)		33.0	%		493				—			—
					$	1,258						$	91

As of December 31, 2019 and December 31, 2018, unamortized basis differences included in the equity method interest balances were $30 million and $6 million, respectively. These amounts represent differences in contributions to date and Altus’ underlying equity in the separate net assets within the financial statements of the respective entities. Unamortized basis differences are amortized into net income 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 year ended December 31, 2019:

		Gulf Coast Express Pipeline LLC				EPIC Crude Holdings, LP				Permian Highway Pipeline LLC				Breviloba, LLC				Total(2)
		(In millions)
Balance at December 31, 2018		$	91			$	—			$	—			$	—			$	91
Acquisitions		15				52				162				442				671
Capital contributions		184				123				147				47				501
Distributions		(16		)		—				—				(9		)		(25		)
Capitalized interest(1)		—				—				2				—				2
Equity income (loss), net		17				(11		)		—				13				19
Accumulated other comprehensive loss		—				(1		)		—				—				(1		)
Balance at December 31, 2019		$	291			$	163			$	311			$	493			$	1,258

(1)	Altus’ proportionate share of the Permian Highway Pipeline (PHP) construction costs is funded with Altus’ revolving credit facility. Accordingly, Altus capitalized $2 million of related interest expense, which is included in the basis of the PHP equity interest.

(2)	At December 31, 2019, consolidated retained earnings, net of amortized basis differences, included $5 million related to undistributed earnings of equity method investments.

Summarized Combined Financial Information

The following presents summarized combined statement of operations information for Altus’ equity method interests (on a 100 percent basis):

		For the Year Ended December 31,
		2019(1)				2018(1)
		(In millions)
Operating revenues		$	302			$	2
Operating expenses		181				8
Operating income (loss)		121				(6		)
Net income (loss)		115				(6		)
Other comprehensive loss		(8		)		—

(1)	The financial results for all equity method interests are presented for the entire twelve months for both periods for comparability.

---

The following presents summarized combined balance sheet information for Altus’ equity method interests (on a 100 percent basis):

		December 31,
		2019				2018
		(In millions)
Current assets		$	441			$	451
Noncurrent assets		6,431				2,377
Total assets		$	6,872			$	2,828
Current liabilities		$	478			$	805
Noncurrent liabilities		958				1
Equity		5,436				2,022
Total liabilities and equity		$	6,872			$	2,828

As of December 31, 2018, Apache also held an investment in Marine Well Containment Company. This investment was sold in the first quarter of 2019 for $30 million, with no gain or loss recorded on the sale.

The following table provides detail of the Company’s other current liabilities at December 31, 2019 and 2018:

 

		December 31,
		2019				2018
		(In millions)
Accrued operating expenses		$	143			$	65
Accrued exploration and development		319				667
Accrued gathering, processing, and transmission - Altus		17				81
Accrued compensation and benefits		212				177
Accrued interest		135				137
Accrued income taxes		51				58
Current asset retirement obligation		47				66
Current operating lease liability		169				—
Other		56				90
Total Other current liabilities		$	1,149			$	1,341

---

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the years ended December 31, 2019 and 2018:

 

		2019				2018
		(In millions)
Asset retirement obligation at beginning of year		$	1,932			$	1,835
Liabilities incurred		41				51
Liabilities divested		(56		)		—
Liabilities settled		(56		)		(52		)
Accretion expense		107				108
Revisions in estimated liabilities		(110		)		(10		)
Asset retirement obligation at end of year		1,858				1,932
Less current portion		(47		)		(66		)
Asset retirement obligation, long-term		$	1,811			$	1,866

The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with Apache’s oil and gas properties and other long-lived assets. The Company utilizes current retirement costs to estimate the expected cash outflows for retirement obligations. 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 2019 and 2018, the Company recorded $41 million and $51 million, respectively, in abandonment liabilities resulting from Apache’s exploration and development capital program. Liabilities settled primarily relate to individual properties, platforms, and facilities plugged and abandoned during the period. During 2019, approximately $110 million net abandonment costs were revised downward to reflect changes in estimates of timing and costs, primarily in the North Sea. During 2018, approximately $10 million of abandonment costs were revised downward, primarily in the U.S. and North Sea.

---

Overview

All of the Company’s debt is senior unsecured debt and has equal priority with respect to the payment of both principal and interest. All indentures for the notes and debentures described below place certain restrictions on the Company, including limits on Apache’s ability to incur debt secured by certain liens. Certain of these indentures also restrict the Company’s ability to enter into certain sale and leaseback transactions and give holders the option to require the Company 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.

In January 2017, the Company purchased and canceled $69 million aggregate principal amount of senior notes for $71 million in cash, including accrued interest and $1 million of premium, which completed the open market $250 million repurchase program initiated in 2016. These repurchases resulted in a $1 million net loss on extinguishment of debt, which is included in “Financing costs, net” in the Company’s consolidated statement of operations. The net loss includes an acceleration of related discount and deferred financing costs.

In August 2018, Apache closed an offering of $1.0 billion in aggregate principal amount of senior unsecured 4.375% notes due October 15, 2028. 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, repay notes that matured in September 2018, and for general corporate purposes.

Also in August 2018, Apache closed cash tender offers for certain outstanding notes. Apache accepted for purchase $731 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate of approximately $828 million reflecting principal, the discount to par, early tender premium, and accrued and unpaid interest. The Company recorded a net loss of $94 million on extinguishment of debt, including $5 million of unamortized debt issuance costs and discount, in connection with the note purchases.

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, the Company 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 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.

---

The following table presents the carrying value of the Company’s debt at December 31, 2019 and 2018:

		December 31,
		2019				2018
		(In millions)
Commercial paper		$	—			$	—
7.625% notes due 2019(1)		—				150
3.625% notes due 2021(2)		293				393
3.25% notes due 2022(2)		463				687
2.625% notes due 2023(2)		181				403
7.7% notes due 2026		79				79
7.95% notes due 2026		133				133
4.375% notes due 2028(2)		1,000				1,000
7.75% notes due 2029(2)(3)		247				300
4.25% notes due 2030(2)		600				—
6.0% notes due 2037(2)		467				800
5.1% notes due 2040(2)		1,499				1,499
5.25% notes due 2042(2)		500				500
4.75% notes due 2043(2)		1,413				1,413
4.25% notes due 2044(2)		753				753
7.375% debentures due 2047		150				150
5.35% notes due 2049(2)		400				—
7.625% debentures due 2096		39				39
Notes and debentures before unamortized discount and debt issuance costs(4)		8,217				8,299
Altus credit facility(5)		396				—
Finance lease obligations		48				40
Unamortized discount		(42		)		(44		)
Debt issuance costs		(53		)		(51		)
Total debt		8,566				8,244
Current maturities		(11		)		(151		)
Long-term debt		$	8,555			$	8,093

(1)	On July 1, 2019, Apache’s 7.625% senior notes due 2019 in original principal amount of $150 million matured and were repaid.

(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. Since these notes historically have been included in Apache’s long-term debt, the assumption did not change Apache’s long-term debt or total debt.

(4)	The fair value of the Company’s notes and debentures was $8.4 billion and $7.8 billion as of December 31, 2019 and 2018, respectively. Apache 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 by Altus Midstream LP on its credit facility approximate 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, 2019 are as follows:

	(In millions)
2020	$	—
2021	293
2022	463
2023	181
2024	—
Thereafter	7,280
Notes and debentures, excluding discounts and debt issuance costs	$	8,217

---

Money Market and Overdraft Lines of Credit

The Company has certain uncommitted money market and overdraft lines of credit that are used from time to time for working capital purposes. As of December 31, 2019 and 2018, there were no outstanding balances on Apache’s lines of credit.

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. The Company can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of December 31, 2019. The facility is for general corporate purposes and committed borrowing capacity fully supports Apache’s commercial paper program. Letters of credit are available for security needs, including in respect of abandonment obligations assumed in various North Sea acquisitions. As of December 31, 2019, there were no borrowings or letters of credit outstanding under this facility. As of December 31, 2018, letters of credit aggregating approximately £112.5 million and no borrowings were outstanding under this facility. In February 2019, £109.4 million of these letters of credit no longer were required and were terminated. In connection with entry into this facility, Apache terminated $3.5 billion and £900 million in commitments under two former credit facilities and wrote off $4 million of associated debt issuance costs, which is included in “Financing costs, net” in the Company’s consolidated statement of operations.

At Apache’s option, the interest rate per annum for borrowings under the 2018 facility is either a base rate, as defined, plus a margin, or the London Inter-bank Offered Rate (LIBOR), plus a margin. Apache also pays quarterly a facility fee at a per annum rate on total commitments. The margins and the facility fee vary based upon the Company’s senior long-term debt rating. At December 31, 2019, the base rate margin was 0.075 percent, the LIBOR margin was 1.075 percent, and the facility fee was 0.175 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 United States and Canada; and liens arising as a matter of law, such as tax and mechanics’ liens. Apache also may incur liens on assets if debt secured thereby does not exceed 15 percent of Apache’s consolidated net tangible assets, or approximately $2.4 billion as of December 31, 2019. 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, 2019, there were $396 million of borrowings and no letters of credit outstanding under this facility. There were no outstanding borrowings or letters of credit under this facility as of December 31, 2018.

The agreement for Altus Midstream LP’s credit facility, as amended, restricts distributions in respect of capital to Apache and other unit holders in certain circumstances. Unless the Leverage Ratio is less than or equal to 4.00:1.00, the agreement limits such distributions to $30 million per calendar year until either (i) the consolidated net income of Altus Midstream LP and its restricted subsidiaries, as adjusted pursuant to the agreement, for three consecutive calendar months equals or exceeds $350.0 million on an annualized basis or (ii) Altus Midstream LP has a specified senior long-term debt rating; in addition, before the occurrence of one of those two events, the Leverage Ratio must be less than or equal to 5.00:1.00. In no event can any distribution be made that would, after giving effect to it on a pro forma basis, result in a Leverage Ratio greater than (i) 5.00:1.00 or (ii) for a specified period after a qualifying acquisition, 5.50:1.00. The Leverage Ratio is the ratio of (1) the consolidated indebtedness of Altus Midstream LP and its restricted subsidiaries to (2) EBITDA (as defined in the agreement) of Altus Midstream LP and its

---

restricted subsidiaries for the 12-month period ending immediately before the determination date. The Leverage Ratio as of December 31, 2019 was less than 4.00:1.00.

The terms of Altus Midstream LP’s Series A Cumulative Redeemable Preferred Units also contain certain restrictions on distributions in respect of capital, including the common units held by Apache and any other units that rank junior to the Preferred Units with respect to distributions or distributions upon liquidation. Refer to Note 13—Redeemable Noncontrolling Interest - Altus for further information. In addition, the amount of any cash distributions to Altus Midstream LP by any entity in which it has an interest accounted for by the equity method is subject to such entity’s compliance with the terms of any debt or other agreements by which it may be bound, which in turn may impact the amount of funds available for distribution by Altus Midstream LP to its partners. 

The Altus Midstream LP credit facility is unsecured and is not guaranteed by Apache or any of Apache’s other subsidiaries.

There are no clauses in either the agreement for Apache’s 2018 credit facility or for Altus Midstream LP’s 2018 credit facility that permit the lenders to accelerate payments or refuse to lend based on unspecified material adverse changes. These agreements do not have drawdown restrictions or prepayment obligations in the event of a decline in credit ratings. However, each agreement allows the lenders to accelerate payment maturity and terminate lending and issuance commitments for nonpayment and other breaches, and if a borrower or any of its subsidiaries defaults on other indebtedness in excess of the stated threshold, is insolvent, or has any unpaid, non-appealable judgment against it for payment of money in excess of the stated threshold. Lenders may also accelerate payment maturity and terminate lending and issuance commitments under the applicable agreement if Apache or Altus Midstream LP, as applicable, undergoes a specified change in control or any borrower has specified pension plan liabilities in excess of the stated threshold. Each of Apache and Altus Midstream LP was in compliance with the terms of its 2018 credit facility as of December 31, 2019.

Commercial Paper Program

As of December 31, 2019, Apache has available a $3.5 billion commercial paper program which, subject to market availability, facilitates Apache borrowing funds for up to 270 days at competitive interest rates. The commercial paper program is fully supported by available borrowing capacity under Apache’s 2018 $4.0 billion committed credit facility. At December 31, 2019 and 2018, Apache had no commercial paper outstanding.

Financing Costs, Net

The following table presents the components of Apache’s financing costs, net:

 

		For the Year Ended December 31,
		2019				2018				2017
		(In millions)
Interest expense		$	430			$	441			$	457
Amortization of debt issuance costs		7				9				9
Capitalized interest		(37		)		(44		)		(51		)
Loss on extinguishment of debt		75				94				1
Interest income		(13		)		(22		)		(19		)
Financing costs, net		$	462			$	478			$	397

 

As of December 31, 2019, the Company has $42 million of debt discounts, which will be charged to interest expense over the life of the related debt issuances. Discount amortization of $2 million was recorded as interest expense in 2019 and $3 million in each of 2018 and 2017.

---

Income (loss) before income taxes is composed of the following:

 

		For the Year Ended December 31,
		2019				2018				2017
		(In millions)
U.S.		$	(4,397	)		$	(723	)		$	(3,620	)
Foreign		1,389				1,681				4,538
Total		$	(3,008	)		$	958			$	918

The total income tax provision (benefit) consists of the following:

 

		For the Year Ended December 31,
		2019				2018				2017
		(In millions)
Current income taxes:
Federal		$	1			$	(1	)		$	(38	)
State		—				—				(8		)
Foreign		659				895				641
		660				894				595
Deferred income taxes:
Federal		67				(65		)		(1,010		)
State		—				2				—
Foreign		(53		)		(159		)		(170		)
		14				(222		)		(1,180		)
Total		$	674			$	672			$	(585	)

 

The total income tax provision (benefit) 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:

		For the Year Ended December 31,
		2019				2018				2017
		(In millions)
Income tax expense (benefit) at U.S. statutory rate		$	(631	)		$	201			$	321
State income tax, less federal effect(1)		1				2				(6		)
Taxes related to foreign operations		328				436				(105		)
Tax credits		(6		)		(13		)		(33		)
Tax on deemed repatriation of foreign earnings		—				103				419
Foreign tax credits		—				(336		)		(201		)
Deferred tax on undistributed foreign earnings		—				—				(1,872		)
Change in U.S. tax rate		—				161				516
Net change in tax contingencies		1				(2		)		(1		)
Sale of Canadian assets		—				—				279
Sale of North Sea assets		—				(30		)		(48		)
Valuation allowances(1)		972				118				161
All other, net		9				32				(15		)
		$	674			$	672			$	(585	)

(1)	The change in state valuation allowance is included as a component of state income tax.

---

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:

 

		December 31,
		2019				2018
		(In millions)
Deferred tax assets:
U.S. and state net operating losses		$	2,108			$	1,633
Capital losses		626				636
Tax credits and other tax incentives		32				39
Foreign tax credits		2,241				2,241
Accrued expenses and liabilities		97				117
Asset retirement obligation		618				649
Equity investments		—				4
Investment in Altus Midstream LP		107				—
Net interest expense limitation		162				65
Lease liability		108				—
Other		88				97
Total deferred tax assets		6,187				5,481
Valuation allowance		(4,959		)		(3,947		)
Net deferred tax assets		1,228				1,534
Deferred tax liabilities:
Deferred income		1				10
Investment in Altus Midstream LP		—				73
Property and equipment		1,432				1,747
Right-of-use asset		106				—
Other		6				4
Total deferred tax liabilities		1,545				1,834
Net deferred income tax liability		$	317			$	300

 

Net deferred tax assets and liabilities are included in the consolidated balance sheet as follows:

 

		December 31,
		2019				2018
		(In millions)
Assets:
Deferred charges and other		$	29			$	91
Liabilities:
Deferred income taxes		346				391
Net deferred income tax liability		$	317			$	300

On December 22, 2017, the Tax Cuts and Jobs Act (the TCJA) was signed into law. In addition to reducing the corporate income tax rate from 35 percent to 21 percent effective January 1, 2018, certain provisions in the TCJA move the U.S. away from a worldwide tax system and closer to a territorial system for earnings of foreign corporations, establishing a participation exemption system for taxation of foreign income. The new law includes a transition rule to effect this participation exemption regime. As a result of the enacted legislation, taxpayers were required to include in taxable income for the tax year ending December 31, 2017, the pro rata share of deferred income of each specified foreign corporation with respect to which the taxpayer is a U.S. shareholder. In 2017, the Company recorded a $419 million provisional deferred tax expense attributable to the deemed repatriation of foreign earnings required under the TCJA.

---

Also on December 22, 2017, the SEC staff issued Staff Accounting Bulletin No. 118 (SAB 118) which provides guidance for the application of ASC Topic 740, Income Taxes, for the income tax effects of the TCJA. SAB 118 provides a measurement period which should not extend beyond one year of the enactment date of the TCJA. In 2018, the Company recorded an additional $103 million deferred tax expense attributable to the deemed repatriation of foreign earnings. This deferred tax expense combined with the provisional amount recorded in 2017 were fully offset by available foreign tax credits. Additional guidance issued by the Internal Revenue Service in 2018 clarified, among other things, the ability for taxpayers generating current tax losses to utilize foreign tax credits to fully offset taxes attributable to the deemed repatriation of foreign earnings, rather than utilizing 2017 current year losses. In light of the new guidance, the Company increased its 2017 net operating losses by $1.2 billion, which resulted in incremental $161 million deferred tax expense associated with the remeasurement of the 2017 net operating loss deferred tax asset from 35 percent to 21 percent. The Company completed its analysis of the income tax effects of the TCJA in the fourth quarter of 2018.

The Company has recorded an increase in valuation allowance against certain deferred tax assets, primarily driven by asset impairments. The Company has assessed the future potential to realize these deferred tax assets and has concluded that it is more likely than not that these deferred tax assets will not be realized based on current economic conditions and expectations for the future.

In 2019, 2018, and 2017, the Company’s valuation allowance increased by $1.0 billion, increased by $131 million, and decreased by $1.6 billion, respectively, as detailed in the table below:

 

		2019				2018				2017
		(In millions)
Balance at beginning of year		$	3,947			$	3,816			$	5,401
State(1)		41				15				139
U.S.		971				124				905
Foreign(2)		—				(8		)		(2,629		)
Balance at end of year		$	4,959			$	3,947			$	3,816

(1)	Reported as a component of state income taxes.

(2)	In 2017, the Company completed the sale of its Canadian assets. As such, except for capital losses incurred on the sale, the deferred tax assets, liabilities, and valuation allowance related to these assets were removed for 2017.

On December 31, 2019, the Company had net operating losses as follows:

 

		Amount				Expiration
		(In millions)
Net operating losses:
U.S.		$	8,052			2019 - Indefinite
State		6,090				Various

The Company has a U.S. net operating loss carryforward of $8.1 billion, which includes $196 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 TCJA. The Company also has a net interest expense carryover of $735 million under Section 163(j) of the Code subject to indefinite carryover, a U.S. capital loss carryforward of $1.8 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 probable that these attributes will not be realized.

On December 31, 2019, the Company had foreign tax credits as follows:

 

		Amount				Expiration
		(In millions)
Foreign tax credits		$	2,241			2025-2026

---

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 probable 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 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:

 

		2019				2018				2017
		(In millions)
Balance at beginning of year		$	24			$	26			$	15
Additions based on tax positions related to prior year		49				—				—
Additions based on tax positions related to the current year		9				—				12
Reductions for tax positions of prior years		—				(2		)		(1		)
Balance at end of year		$	82			$	24			$	26

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 the years ended December 31, 2019, 2018, and 2017, the Company recorded tax expense of $1 million, $1 million, and nil, respectively, for interest and penalties. At December 31, 2019, 2018, and 2017, the Company had an accrued liability for interest and penalties of $2 million, $1 million, and nil, respectively.

In 2019, 2018, and 2017, the Company recorded a $58 million net increase, $2 million net reduction, and an $11 million net increase, respectively, in its reserve for uncertain tax positions. The 2019 increase of unrecognized tax benefits is primarily related to the Company’s interpretation of certain proposed regulations issued since the passage of the TCJA. 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

U.S.	2014
Egypt	2005
U.K.	2018

---

Legal Matters

Apache is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls. As of December 31, 2019, the Company has an accrued liability of approximately $21 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. Apache’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 Apache’s financial position, results of operations, or liquidity after consideration of recorded accruals. For material matters that Apache 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 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 Apache, 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 an adverse judgment against the Company is possible, the Company intends to actively defend these lawsuits and claims.

Starting in November of 2013 and continuing into 2019, several parishes in Louisiana have pending lawsuits against many oil and gas producers, including Apache. These cases were all removed to federal courts in Louisiana. Some of the cases have been remanded to state court with the remand orders being appealed. Other of the cases have been stayed pending appeal. 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 an adverse judgment against the Company is 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 areas of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The Court recently 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 plaintiffs have appealed.

---

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, Apache filed suit against Quadrant for breach of the Quadrant SPA. In its suit, Apache seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to Apache’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 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 purported 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 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, gas, and coal 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. The Company believes that the claims made against it are baseless and intends to vigorously defend these lawsuits.

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 Company is appealing.

Oklahoma Class Actions

Apache is a party to two 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 the appeal of the certification was recently denied. The case includes a class of royalty owners seeking damages of over $100 million for alleged breach of the implied covenant to market relating to post-production deductions and NGL uplift value. The Allen case has not been certified and seeks to represent a group of owners who have allegedly received late payments under Oklahoma statutes. The amount of this claim is not yet reasonably determinable. While an adverse judgment against the Company is possible, the Company intends to vigorously defend these lawsuits and claims.

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.

Apache 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 Apache’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 Apache’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, 2019, the Company had an undiscounted reserve for environmental remediation of approximately $2 million. The Company is not aware of any environmental claims existing as of December 31, 2019 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.

Leases and Contractual Obligations

On January 1, 2019, Apache 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. Prior to adoption, the FASB issued transition guidance 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 an option to apply the provisions of the new standard at its adoption date instead of the earliest comparative period presented in the financial statements. Apache elected both transitional practical expedients. Under these transition options, comparative reporting was not required, and the provisions of the standard were applied prospectively to leases in effect at the date of adoption.

As allowed under the standard, the Company also applied practical expedients 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. Apache also elected to exclude short-term leases (those with terms of 12 months or less) from the balance sheet presentation and accounts for non-lease and lease components as a single lease component for all asset classes. Short-term lease expense in 2019 was $18 million, primarily related to drilling activities in Block 58 offshore Suriname.

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, Apache 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, Apache enters into various lease agreements for real estate, drilling rigs, vessels, aircraft, 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” within “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.

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 $222 million in 2019.

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 “Other” within “Property and Equipment” on the consolidated balance sheet, and the associated finance lease liabilities are reflected within “Current debt” and “Long-term debt,” as applicable. Prior periods include the reclassification of $39 million finance lease obligations from “Other” within “Deferred Credits and Other Noncurrent Liabilities” to “Long-term debt” on the Company’s consolidated balance sheet to conform with this presentation. There was no material impact to the Company’s statement of consolidated operations and statement of consolidated cash flows for its treatment of finance leases. Depreciation on the Company’s finance lease assets was $7 million in 2019. Interest on the Company’s finance lease assets was $3 million in 2019.

---

The following table represents the Company’s weighted average lease term and discount rate as of December 31, 2019:

		Operating Leases			Finance Leases
Weighted average remaining lease term		3.8 years			10.9 years
Weighted average discount rate		4.4	%		4.3	%

At December 31, 2019, contractual obligations for long-term operating leases, finance leases, and purchase obligations are as follows:

Net Minimum Commitments(1)		Operating Leases(2)				Finance Leases(3)				Purchase Obligations(4)(5)
		(In millions)
2020		$	165			$	13			$	152
2021		82				3				191
2022		50				3				181
2023		33				3				213
2024		27				3				195
Thereafter		32				37				910
Total future minimum payments		389				62				$	1,842
Less: imputed interest		(23		)		(14		)		N/A
Total lease liabilities		366				48				N/A
Current portion		169				11				N/A
Non-current portion		$	197			$	37			N/A

(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 physical power generators being leased on a one-year term with the right to purchase and a separate lease for 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 $111 million, $132 million, and $134 million for 2019, 2018, and 2017, respectively.

(5)	Subsequent to December 31, 2019, Apache entered into an agreement to assign approximately $171 million of its firm transportation obligations beginning in March 2020.

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 in 2019 was $78 million.

---

As a result of electing the transitional practical expedient to apply the provisions of the standard at its adoption date instead of the earliest comparative period presented, below are the required ASU Leases (Topic 840) disclosures for prior periods:

		Operating Leases(1)				Finance Leases(2)
		(In millions)
Year ended December 31, 2018
2019		$	61			$	1
2020-2021		64				3
2022-2023		53				4
2024 & Beyond		42				32
Total		$	220			$	40
Year ended December 31, 2017
2018		$	54			$	1
2019-2020		81				3
2021-2022		57				3
2023 & Beyond		41				34
Total		$	233			$	41

(1)

Includes leases for buildings, facilities, and related equipment with varying expiration dates through 2042. 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. Total rent expense, net of amounts capitalized and sublease income was $76 million and $82 million for 2018, and 2017, respectively.

(2)	This represents the Company’s capital lease obligation related to its Midland, Texas office building. The imputed interest rate necessary to reduce the net minimum lease payments to present value of the lease term is 4.4 percent, or $16 million and $18 million as of December 31, 2018 and December 31, 2017, respectively.

Apache Corporation 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 annually 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 each 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 change in control of ownership of Apache Corporation, 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 Apache 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 $52 million, $52 million, and $55 million for 2019, 2018, and 2017, respectively.

Apache 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.

 

The following tables set forth the benefit obligation, fair value of plan assets and funded status as of December 31, 2019, 2018, and 2017, and the underlying weighted average actuarial assumptions used for the U.K. Pension Plan and U.S. postretirement benefit plan. Apache uses a measurement date of December 31 for its pension and postretirement benefit plans.

		2019								2018								2017
		Pension Benefits				Postretirement Benefits				Pension Benefits				Postretirement Benefits				Pension Benefits				Postretirement Benefits
		(In millions)
Change in Projected Benefit Obligation
Projected benefit obligation at beginning of year		$	187			$	27			$	216			$	27			$	202			$	26
Service cost		3				2				4				2				4				2
Interest cost		5				1				5				1				6				1
Foreign currency exchange rates		7				—				(11		)		—				20				—
Actuarial losses (gains)		15				(9		)		(11		)		(2		)		(4		)		1
Plan settlements		(14		)		—				(11		)		—				—				—
Benefits paid		(4		)		(2		)		(5		)		(3		)		(12		)		(4		)
Retiree contributions		—				1				—				2				—				1
Projected benefit obligation at end of year		199				20				187				27				216				27
Change in Plan Assets
Fair value of plan assets at beginning of year		208				—				238				—				206				—
Actual return on plan assets		25				—				(6		)		—				17				—
Foreign currency exchange rates		8				—				(13		)		—				22				—
Employer contributions		5				1				5				2				5				3
Plan settlements		(14		)		—				(11		)		—				—				—
Benefits paid		(4		)		(2		)		(5		)		(4		)		(12		)		(4		)
Retiree contributions		—				1				—				2				—				1
Fair value of plan assets at end of year		228				—				208				—				238				—
Funded status at end of year		$	29			$	(20	)		$	21			$	(27	)		$	22			$	(27	)
Amounts recognized in Consolidated Balance Sheet
Current liability		$	—			$	(2	)		$	—			$	(2	)		$	—			$	(2	)
Non-current asset (liability)		29				(18		)		21				(25		)		22				(25		)
		$	29			$	(20	)		$	21			$	(27	)		$	22			$	(27	)
Pre-tax Amounts Recognized in Accumulated Other Comprehensive Income (Loss)
Accumulated gain (loss)		$	(7	)		$	19			$	(13	)		$	10			$	(11	)		$	8
Weighted Average Assumptions used as of December 31
Discount rate		2.10		%		3.00		%		2.90		%		4.13		%		2.60		%		3.44		%
Salary increases		4.30		%		N/A				4.70		%		N/A				4.70		%		N/A
Expected return on assets		2.80		%		N/A				2.80		%		N/A				2.90		%		N/A
Healthcare cost trend
Initial		N/A				6.25		%		N/A				6.50		%		N/A				6.75		%
Ultimate in 2025		N/A				5.00		%		N/A				5.00		%		N/A				5.00		%

---

As of December 31, 2019, 2018, and 2017, the accumulated benefit obligation for the U.K. Pension Plan was $181 million, $167 million, and $193 million, respectively.

Apache’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:

 

		Target Allocation			Percentage of Plan Assets at Year-End
		2019			2019			2018
Asset Category
Equity securities:
Overseas quoted equities		22	%		23	%		22	%
Total equity securities		22	%		23	%		22	%
Debt securities:
U.K. Government bonds		62	%		62	%		62	%
U.K. corporate bonds		16	%		15	%		15	%
Total debt securities		78	%		77	%		77	%
Cash		—			—			1	%
Total		100	%		100	%		100	%

 

The plan’s assets do not include any direct ownership of equity or debt securities of Apache. The fair value of plan assets at December 31, 2019 and 2018 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, 2019 and December 31, 2018:

		December 31, 2019				December 31, 2018
		(In millions)
Equity securities:
Overseas quoted equities(1)		$	52			$	46
Total equity securities		52				46
Debt securities:
U.K. Government bonds(2)		140				129
U.K. corporate bonds(3)		35				32
Total debt securities		175				161
Cash		1				1
Fair value of plan assets		$	228			$	208

(1)

This category includes overseas equities, which comprises 20 percent passive global equities benchmarked against the MSCI World (NDR) Index, 25 percent passive global equities (hedged) benchmarked against the MSCI World (NDR) Hedged Index, 20 percent fundamental indexation global equities benchmarked against the FTSE RAFI Developed 1000 index, 25 percent fundamental indexation global equities (hedged) benchmarked against the FTSE RAFI Developed 1000 Hedge Index, and 10 percent emerging markets benchmarked against the MSCI Emerging Markets (NDR) Index, which has a performance target of 2 percent per annum over the benchmark over a rolling three-year period.

(2)	This category includes U.K. Government bonds, which comprises 61 percent index-linked gilts benchmarked against the FTSE Actuaries Government Securities Index-Linked Over 5 Years Index, 8 percent sterling nominal LDI bonds, and 31 percent sterling inflation linked LDI bonds, both benchmarked against ILIM Custom Benchmark index.

(3)	This category comprises U.K. corporate bonds benchmarked against the BofAML Sterling Corporate & Collaterlised (excluding Subordinated) Index.

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.

---

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, 2019, 2018, and 2017: 

		2019								2018								2017
		Pension Benefits				Postretirement Benefits				Pension Benefits				Postretirement Benefits				Pension Benefits				Postretirement Benefits
		(In millions)
Components of Net Periodic Benefit Cost
Service cost		$	3			$	2			$	4			$	2			$	4			$	2
Interest cost		5				1				5				1				6				1
Expected return on assets		(5		)		—				(7		)		—				(8		)		—
Amortization of actuarial (gain) loss		—				(1		)		—				—				—				(1		)
Settlement loss		—				—				1				—				—				—
Net periodic benefit cost		$	3			$	2			$	3			$	3			$	2			$	2
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31
Discount rate		2.90		%		4.13		%		2.60		%		3.44		%		2.70		%		3.76		%
Salary increases		4.70		%		N/A				4.70		%		N/A				4.80		%		N/A
Expected return on assets		2.80		%		N/A				2.90		%		N/A				3.40		%		N/A
Healthcare cost trend
Initial		N/A				6.50		%		N/A				6.75		%		N/A				7.00		%
Ultimate in 2025		N/A				5.00		%		N/A				5.00		%		N/A				5.00		%

Assumed health care cost trend rates affect amounts reported for postretirement benefits. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

 

		Postretirement Benefits
		1% Increase				1% Decrease
		(In millions)
Effect on service and interest cost components		$	1			$	(1	)
Effect on postretirement benefit obligation		2				(1		)

Apache expects to contribute approximately $6 million to its pension plan and $2 million to its postretirement benefit plan in 2020. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:

 

		Pension Benefits				Postretirement Benefits
		(In millions)
2020		$	5			$	2
2021		4				2
2022		5				2
2023		6				2
2024		6				2
Years 2025-2029		32				8

---

13.	REDEEMABLE NONCONTROLLING INTEREST - ALTUS

Preferred Units Issuance

On June 12, 2019, Altus Midstream LP issued and sold Series A Cumulative Redeemable Preferred Units (the 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 (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 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 $103 million. 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, imputed interest rate of Altus, the timing of periodic cash distributions, and dividend yields of the Preferred Units. See Note 4—Derivative Instruments and Hedging Activities for more detail.

---

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:

		June 12, 2019
		(In millions)
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners		$	517
Preferred Units embedded derivative		94
		$	611

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 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)(i) the carrying amount of the Preferred Units, plus (ii) the fair value of the embedded derivative liability or (b) the accreted value of the net transaction price.

Activity related to the Preferred Units for the year ended December 31, 2019 is as follows:

		Units Outstanding			Financial Position(2)
		(In millions, except unit data)
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners: beginning of period		—			$	—
Issuance of Preferred Units, net		625,000			517
Distribution of in-kind additional Preferred Units(1)		13,163			—
Allocation of Altus Midstream LP net income		N/A			38
Redeemable noncontrolling interest - Altus Preferred Unit Limited Partners: end of period		638,163			555
Preferred Units embedded derivative					103
					$	658

(1)

Subsequent to the balance sheet date, Altus Midstream LP provided notice to the Preferred Unit holders of record at December 31, 2019 of the amount of the distribution on the Preferred Units for the quarter ended December 31, 2019. The holders also were notified that Altus Midstream LP elected to pay the entire amount of the approximate $11 million distribution in-kind in additional Preferred Units (PIK Units) on February 14, 2020. In total, 11,168 PIK Units were issued in satisfaction of the required distribution.

(2)	As at December 31, 2019, the aggregate Redemption Price was $664 million, based on an internal rate of return of 11.5 percent.

N/A - not applicable.

---

Common Stock Outstanding

A summary of the shares issued and outstanding for the years ended December 31, 2019, 2018, and 2017 is presented in the table below.

		2019			2018			2017
Balance, beginning of year		374,696,222			380,954,864			379,439,676
Shares issued for stock-based compensation plans:
Treasury shares issued		31,701			2,454			1,411
Common shares issued		1,334,747			1,566,237			1,513,777
Treasury shares acquired		—			(7,827,333	)		—
Balance, end of year		376,062,670			374,696,222			380,954,864

Net Income (Loss) per Common Share

A reconciliation of the components of basic and diluted net income (loss) per common share for the years ended December 31, 2019, 2018, and 2017 is presented in the table below.

		2019											2018											2017
		Loss				Shares			Per Share				Income				Shares			Per Share				Income				Shares			Per Share
		(In millions, except per share amounts)
Basic:
Income (loss) attributable to common stock		$	(3,553	)		377			$	(9.43	)		$	40			382			$	0.11			$	1,304			381			$	3.42
Effect of Dilutive Securities:
Stock options and other		$	—			—			$	—			$	—			2			$	—			$	—			2			$	(0.01	)
Diluted:
Income (loss) attributable to common stock		$	(3,553	)		377			$	(9.43	)		$	40			384			$	0.11			$	1,304			383			$	3.41

The diluted EPS calculation excludes options and restricted shares that were anti-dilutive totaling 5.0 million, 5.6 million, and 7.3 million for the years ended December 31, 2019, 2018, and 2017, 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 were anti-dilutive for the year ended December 31, 2019.

Stock Repurchase Program

In 2013 and 2014, Apache’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. Shares may be purchased either in the open market or through privately held negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through December 31, 2019, had repurchased a total of 40 million shares at an average price of $79.18 per share. During the fourth quarter of 2018, the Company’s Board of Directors authorized the purchase of up to 40 million additional shares of the Company’s common stock. The Company is not obligated to acquire any specific number of shares and did not purchase any shares during 2019.

Common Stock Dividend

For each of the years ended December 31, 2019, 2018, and 2017, the Company paid common stock dividends of $1.00 per share.

---

Stock Compensation Plans

The Company has several stock-based compensation plans, which include stock options, restricted stock, and conditional restricted stock unit plans. On May 12, 2016, the Company’s shareholders approved the 2016 Omnibus Compensation Plan (the 2016 Plan), which is intended to provide eligible employees with equity-based incentives. The 2016 Plan provides for the granting of 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. A total of 14.4 million shares were authorized and available for grant under the 2016 Plan as of December 31, 2019. 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. A description of the Company’s stock-settled and cash-settled units compensation plans and related costs follows:

		For the Year Ended December 31,
		2019				2018				2017
		(In millions)
Stock-settled and cash-settled compensation expensed		$	110			$	157			$	142
Stock-settled and cash-settled compensation capitalized		28				37				41
Total stock-settled and cash-settled compensation costs		$	138			$	194			$	183

Stock Options

As of December 31, 2019, the Company had issued options to purchase shares of the Company’s common stock under the 2007 Omnibus Equity Compensation Plan, the 2011 Omnibus Equity Compensation Plan (2011 Plan), and the 2016 Plan (together, the Omnibus Plans). New shares of Company stock will be issued for employee stock option exercises. Under the Omnibus Plans, the exercise price of each option equals the closing price of Apache’s common stock on the date of grant. Options issued prior to 2016 generally become exercisable ratably over a four-year period and expire 10 years after granted. Options granted in or after 2016 become exercisable ratably over a three-year period and expire 10 years after granted. The Omnibus Plans were submitted to and approved by the Company’s shareholders.

 

A summary of stock options issued and outstanding under the Omnibus Plans is presented in the table below for the years ended December 31, 2019, 2018, and 2017 (shares in thousands):

		2019							2018							2017
		Shares Under Option			Weighted Average Exercise Price				Shares Under Option			Weighted Average Exercise Price				Shares Under Option			Weighted Average Exercise Price
Outstanding, beginning of year		4,872			$	75.95			4,593			$	83.36			5,113			$	84.89
Granted		—			—				812			45.93				490			63.25
Exercised		—			—				(29	)		41.79				(15	)		41.24
Forfeited		(80	)		34.58				(121	)		74.58				(691	)		84.65
Expired		(494	)		88.82				(383	)		104.21				(304	)		76.09
Outstanding, end of year(1)		4,298			75.24				4,872			75.95				4,593			83.36
Expected to vest(2)		495			49.11				1,274			48.74				947			51.83
Exercisable, end of year(3)		3,803			78.64				3,598			85.59				3,646			91.56

(1)	As of December 31, 2019, options outstanding had a weighted average remaining contractual life of 4.1 years and no intrinsic value.

(2)	As of December 31, 2019, options expected to vest had a weighted average remaining contractual life of 7.8 years and no intrinsic value.

(3)	As of December 31, 2019, options exercisable had a weighted average remaining contractual life of 3.6 years and no intrinsic value.

The fair value of each stock option award is estimated on the date of grant using the Black-Scholes option pricing model, a Level 2 fair value measurement. Assumptions used in the valuation are disclosed in the following table. Expected volatilities are based on historical volatility of the Company’s common stock and other factors. The expected dividend yield is based on historical yields on the date of grant. The expected term of stock options granted represents the period of time that the stock options are

---

expected to be outstanding and is derived from historical exercise behavior, current trends, and values derived from lattice-based models. The risk-free rate is based on the U.S. Treasury yield curve in effect at the time of grant.

		2019		2018				2017
Expected volatility		N/A		33.47		%		34.58		%
Expected dividend yields		N/A		2.16		%		1.58		%
Expected term (in years)		N/A		6				6
Risk-free rate		N/A		2.42		%		2.02		%
Weighted-average grant-date fair value		N/A		$	13.15			$	19.38

N/A - not applicable.

There were no options issued and no options exercised during 2019. The intrinsic values of options exercised during 2018 and 2017 were approximately $0.1 million and $0.2 million, respectively. As of December 31, 2019, the total compensation cost related to non-vested options not yet recognized was $2 million, which will be recognized over the remaining vesting period of the options.

Restricted Stock Units and Restricted Stock Phantom Units

The Company has restricted stock unit and restricted stock phantom unit (cash-settled) plans for eligible employees including officers. The programs created under the Omnibus Plans have been approved by Apache’s Board of Directors. The value of the stock-settled awards issued is established by the market price on the date of grant and is being recorded as compensation expense ratably over the vesting terms. The cash-settled awards compensation expense is recorded as a liability and remeasured at the end of each reporting period over the vesting terms. The restricted stock phantom units represent a hypothetical interest in either the Company’s stock or in ALTM’s common stock, as applicable, and, once vested, are settled in cash. The cash-settled awards compensation expense is recorded as a liability and remeasured at the end of each reporting period over the vesting terms. During 2019, 2018, and 2017, compensation-expense related to restricted stock units and cash-based units was $104 million, $101 million, and $108 million, respectively. In 2019, 2018, and 2017, $24 million, $29 million, and $35 million were capitalized, respectively.

The following table is a summary of stock-settled restricted stock unit activity for the years ended December 31, 2019, 2018, and 2017 (shares in thousands):

		2019							2018							2017
Stock-settled Restricted Stocks Units		Shares			Weighted- Average Grant- Date Fair Value				Shares			Weighted- Average Grant- Date Fair Value				Shares			Weighted- Average Grant- Date Fair Value
Non-vested, beginning of year		3,153			$	55.54			4,920			$	56.67			6,062			$	55.11
Granted		1,479			36.81				608			45.59				1,948			62.74
Vested(3)		(1,899	)		53.99				(2,023	)		55.10				(2,288	)		58.77
Forfeited		(285	)		45.06				(352	)		56.69				(802	)		55.54
Non-vested, end of year(1)(2)		2,448			46.65				3,153			55.54				4,920			56.67

(1)	As of December 31, 2019, there was $18 million of total unrecognized compensation cost related to 2,447,910 unvested stock-settled restricted stock units.

(2)	As of December 31, 2019, the weighted-average remaining life of unvested stock-settled restricted stock units is approximately 0.7 years.

(3)	The grant date fair values of the stock-settled awards vested during 2019, 2018, and 2017 were approximately $103 million, $111 million, and $135 million, respectively.

The following table is a summary of cash-settled restricted stock phantom unit activity for the years ended December 31, 2019 and 2018 (in thousands):

Cash-settled Restricted Stock Phantom Units(1)		2019			2018
Non-vested, beginning of year		1,818			59
Granted(2)		4,831			1,973
Vested		(616	)		(38	)
Forfeited		(649	)		(176	)
Non-vested, end of year(3)		5,384			1,818

(1)	The Company issued no cash-settled restricted stock phantom units in 2017.

---

(2)	The 2019 restricted stock phantom units included 3,401,477 awards based on the per-share market price of Apache’s common stock and 1,429,135 awards based on the per-share market price of ALTM’s common stock.

(3)	The outstanding liability for the unvested cash-settled restricted stock phantom units that has not been recognized as of December 31, 2019 was approximately $52 million.

In January 2020, the Company awarded 961,368 restricted stock units and 3,340,495 restricted stock phantom units based on Apache’s weighted-average per-share market price of $25.69 under the 2016 Plan to eligible employees. Total compensation cost for restricted stock units and restricted stock phantom units absent any forfeitures, is estimated to be $25 million and $86 million, respectively, and was calculated based on the 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.

Also during January 2020, the Company awarded 1,425,513 restricted stock phantom units based on ALTM’s weighted-average per-share market price of $2.70. 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 $4 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 Apache employees to deliver competitive returns to the Company’s stockholders, the Company has granted conditional restricted stock units to eligible employees. Apache 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 Apache 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, 2019, are as described below:

•	In January 2016, the Company’s Board of Directors approved the 2016 Performance Program, pursuant to the 2011 Plan. Eligible employees received initial stock-settled conditional restricted stock unit awards totaling 871,369. The results for the performance period ending December 31, 2018, yielded a payout of 100 percent of target. A total of 325,008 units were outstanding as of December 31, 2019.

•	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 455,499 units were outstanding as of December 31, 2019. 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. The actual amount of shares awarded will be between zero and 200 percent of target. A total of 796,829 phantom units were outstanding as of December 31, 2019, from which a minimum of zero to a maximum of 1,593,658 phantom units could be awarded.

•

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. The actual amount of shares awarded will be between zero and 200 percent of target. A total of 1,523,360 phantom units were outstanding as of December 31, 2019, from which a minimum of zero to a maximum of 3,046,720 phantom units could be awarded.

---

The fair value cost of the stock-settled awards was estimated on the date of grant and is being recorded as compensation expense ratably over the vesting terms. The fair value of the cash-settled awards are remeasured at the end of each reporting period over the vesting terms. During 2019, 2018, and 2017, $24 million, $38 million, and $23 million, respectively, were charged to expense. During 2019, 2018, and 2017, $3 million, $7 million, and $4 million were capitalized, respectively.

A summary of stock-settled conditional restricted stock unit activity for the year ended December 31, 2019, is presented below:

Stock-settled Conditional Restricted Stock Units		Shares			Weighted Average Grant- Date Fair Value(1)
		(In thousands)
Non-vested, beginning of year		1,347			$	49.58
Granted		345			32.75
Vested		(510	)		45.62
Forfeited		(71	)		53.96
Expired		(330	)		29.78
Non-vested, end of year(2)(3)		781			52.69

(1)

The fair value of each conditional restricted stock unit award is estimated as of the date of grant using a Monte Carlo simulation with the following assumptions used for all grants made under the plan: (i) a three-year continuous risk-free interest rate; (ii) a constant volatility assumption based on the historical realized stock price volatility of the Company and the designated peer group; and (iii) the historical stock prices and expected dividends of the common stock of the Company and its designated peer group.

(2)	As of December 31, 2019, there was $2 million of total unrecognized compensation cost related to 780,507 unvested stock-settled conditional restricted stock units.

(3)	As of December 31, 2019, the weighted-average remaining life of the unvested stock-settled conditional restricted stock units is approximately 0.3 years.

A summary of cash-settled conditional restricted stock unit activity for the year ended December 31, 2019, is presented below:

Cash-settled Conditional Restricted Stock Phantom Units		Phantom Units
		(In thousands)
Non-vested, beginning of year		890
Granted		1,680
Vested		(2	)
Forfeited		(248	)
Non-vested, end of year(1)		2,320

(1)	As of December 31, 2019, the outstanding liability for the unvested cash-settled conditional restricted stock units that has not been recognized was approximately $26 million.

---

Components of accumulated other comprehensive income (loss) include the following:

 

		As of December 31,
		2019				2018				2017
		(In millions)
Share of equity method interests other comprehensive loss		$	(1	)		$	—			$	—
Pension and postretirement benefit plan (Note 12)		17				4				4
Accumulated other comprehensive income		$	16			$	4			$	4

For the years ended 2019, 2018, and 2017, the customers, including their subsidiaries, that represented more than 10 percent of the Company’s worldwide oil and gas production revenues were as follows:

		For the Year Ended December 31,
		2019			2018			2017
BP plc(1)		10	%		17	%		12	%
China Petroleum & Chemical Corporation (Sinopec)(2)		11	%		15	%		16	%
Egyptian General Petroleum Corporation(3)		9	%		10	%		11	%

(1)	Sales to BP plc were reported as revenue in the Company’s U.S., Egypt, and North Sea upstream segments in the years ended 2019, 2018, and 2017.

(2)	Sales to Sinopec were reported as revenue in the Company’s Egypt upstream segment in the year ended 2019 and in the Company’s Egypt and North Sea upstream segments in the years ended 2018 and 2017.

(3)	Sales to EGPC were reported as revenue in the Company’s Egypt upstream segment in the years ended 2019, 2018, and 2017.

---

As of December 31, 2019, Apache is engaged in exploration and production (Upstream) activities across three operating segments: Egypt, North Sea, and the U.S. Apache also has exploration interests in Suriname and other international locations that may, over time, result in reportable discoveries and development opportunities. Apache’s Upstream business explores for, develops, and produces natural gas, crude oil and natural gas liquids. During 2018, Apache established a new reporting segment for its U.S. midstream business separate from its upstream oil and gas development activities. The midstream business is operated by Altus, which owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas, anchored by midstream service contracts to Apache’s production from its Alpine High resource play. Additionally, Altus owns equity interests in a total of four Permian Basin pipelines that will access various points along the Texas Gulf Coast, providing it with fully integrated, wellhead-to-water connectivity. Financial information for each segment is presented below:

		Egypt(1)				North Sea				U.S.				Altus Midstream				Intersegment Eliminations & Other				Total(2)
		Upstream
		(In millions)
2019
Oil revenues		$	1,969			$	1,163			$	2,098			$	—			$	—			$	5,230
Natural gas revenues		295				90				293				—				—				678
Natural gas liquids revenues		12				23				372				—				—				407
Oil and gas production revenues		2,276				1,276				2,763				—				—				6,315
Midstream service affiliate revenues		—				—				—				136				(136		)		—
Operating Expenses:
Lease operating expenses		484				320				645				—				(2		)		1,447
Gathering, processing, and transmission		40				45				299				56				(134		)		306
Taxes other than income		—				—				194				13				—				207
Exploration		100				2				688				—				15				805
Depreciation, depletion, and amortization		708				366				1,566				40				—				2,680
Asset retirement obligation accretion		—				76				29				2				—				107
Impairments		—				—				1,648				1,301				—				2,949
		1,332				809				5,069				1,412				(121		)		8,501
Operating Income (Loss)		$	944			$	467			$	(2,306	)		$	(1,276	)		$	(15	)		(2,186		)
Other Income (Expense):
Gain on divestitures, net																						43
Other(3)																						53
General and administrative																						(406		)
Transaction, reorganization, and separation																						(50		)
Financing costs, net																						(462		)
Loss Before Income Taxes																						$	(3,008	)
Net Property and Equipment		$	2,573			$	1,956			$	9,385			$	206			$	38			$	14,158
Total Assets(5)		$	3,700			$	2,473			$	10,388			$	1,479			$	67			$	18,107
Additions to Net Property and Equipment		$	454			$	183			$	1,696			$	308			$	93			$	2,734

---

		Egypt(1)				North Sea				U.S.				Altus Midstream				Intersegment Eliminations & Other				Total(2)
		Upstream
		(In millions)
2018
Oil revenues		$	2,396			$	1,179			$	2,271			$	—			$	—			$	5,846
Natural gas revenues		339				122				458				—				—				919
Natural gas liquids revenues		13				20				550				—				—				583
Oil and gas production revenues		2,748				1,321				3,279				—				—				7,348
Midstream service affiliate revenues		—				—				—				77				(77		)		—
Operating Expenses:
Lease operating expenses		428				341				670				—				—				1,439
Gathering, processing, and transmission		47				42				282				54				(77		)		348
Taxes other than income		—				—				207				8				—				215
Exploration		88				192				219				—				4				503
Depreciation, depletion, and amortization		745				375				1,266				19				—				2,405
Asset retirement obligation accretion		—				75				32				1				—				108
Impairments		63				10				438				—				—				511
		1,371				1,035				3,114				82				(73		)		5,529
Operating Income (Loss)		$	1,377			$	286			$	165			$	(5	)		$	(4	)		1,819
Other Income (Expense):
Gain on divestitures, net																						23
Other(3)																						53
General and administrative																						(431		)
Transaction, reorganization, and separation																						(28		)
Financing costs, net																						(478		)
Income Before Income Taxes																						$	958
Net Property and Equipment		$	2,856			$	2,148			$	12,145			$	1,227			$	45			$	18,421
Total Assets(5)		$	4,260			$	2,456			$	12,962			$	1,857			$	47			$	21,582
Additions to Net Property and Equipment		$	594			$	223			$	2,544			$	545			$	8			$	3,914

---

		Egypt				North Sea				Canada(4)				U.S.				Altus Midstream				Intersegment Eliminations & Other				Total(2)
		Upstream
		(In millions)
2017
Oil revenues		$	1,901			$	971			$	110			$	1,616			$	—			$	—			$	4,598
Natural gas revenues		395				92				104				368				—				—				959
Natural gas liquids revenues		11				15				17				287				—				—				330
Oil and gas production revenues		2,307				1,078				231				2,271				—				—				5,887
Midstream service affiliate revenues		—				—				—				—				15				(15		)		—
Operating Expenses:
Lease operating expenses		362				335				103				584				—				—				1,384
Gathering, processing, and transmission		44				30				34				86				16				(15		)		195
Taxes other than income		—				(14		)		12				153				—				—				151
Exploration		62				86				11				363				—				27				549
Depreciation, depletion, and amortization		758				446				76				994				6				—				2,280
Asset retirement obligation accretion		—				72				27				31				—				—				130
Impairments		—				8				—				—				—				—				8
		1,226				963				263				2,211				22				12				4,697
Operating Income (Loss)		$	1,081			$	115			$	(32	)		$	60			$	(7	)		$	(27	)		1,190
Other Income (Expense):
Gain on divestitures, net																										627
Other(3)																										(91		)
General and administrative																										(395		)
Transaction, reorganization, and separation																										(16		)
Financing costs, net																										(397		)
Income Before Income Taxes																										$	918
Net Property and Equipment		$	3,099			$	2,553			$	—			$	11,370			$	700			$	37			$	17,759
Total Assets(5)		$	4,658			$	2,977			$	—			$	13,522			$	706			$	59			$	21,922
Additions to Net Property and Equipment		$	517			$	374			$	—			$	1,847			$	550			$	14			$	3,302

(1)	Includes revenue from non-customers for the years ended 2019 and 2018 of:

		For the Year Ended December 31,
		2019				2018
		(In millions)
Oil		$	410			$	592
Natural gas		40				58
Natural gas liquids		1				2

(2)	Includes a noncontrolling interest in Egypt for years 2019, 2018, and 2017, and Altus for the years 2019 and 2018.

(3)	Included in Other are sales proceeds related to U.S. third-party purchased oil and gas volumes which are determined to be revenue from customers. Proceeds for these volumes totaled $176 million and $357 million for the years ended 2019 and 2018, respectively.

(4)	During 2017, Apache completed the sale of its Canadian operations. For more information regarding this divestiture, please refer to Note 2—Acquisitions and Divestitures.

(5)	Intercompany balances are excluded from total assets.

---

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. Apache has no long-term agreements to purchase oil or gas production from foreign governments or authorities.

		United States				Canada(3)				Egypt(4)				North Sea				Other International				Total(4)
		(In millions, except per boe)
2019
Oil and gas production revenues		$	2,763			$	—			$	2,276			$	1,276			$	—			$	6,315
Operating cost:
Depreciation, depletion, and amortization(1)		1,508				—				641				363				—				2,512
Asset retirement obligation accretion		29				—				—				76				—				105
Lease operating expenses		645				—				484				320				—				1,449
Gathering, processing, and transmission		299				—				40				45				—				384
Exploration expenses		688				—				100				2				15				805
Impairments related to oil and gas properties		1,633				—				—				—				—				1,633
Production taxes(2)		191				—				—				—				—				191
Income tax		(468		)		—				455				188				—				175
		4,525				—				1,720				994				15				7,254
Results of operations		$	(1,762	)		$	—			$	556			$	282			$	(15	)		$	(939	)
2018
Oil and gas production revenues		$	3,279			$	—			$	2,748			$	1,321			$	—			$	7,348
Operating cost:
Depreciation, depletion, and amortization(1)		1,206				—				688				371				—				2,265
Asset retirement obligation accretion		32				—				—				75				—				107
Lease operating expenses		670				—				428				341				—				1,439
Gathering, processing, and transmission		282				—				47				42				—				371
Exploration expenses		219				—				88				192				4				503
Impairments related to oil and gas properties		265				—				63				10				—				338
Production taxes(2)		203				—				—				—				—				203
Income tax		87				—				645				116				—				848
		2,964				—				1,959				1,147				4				6,074
Results of operations		$	315			$	—			$	789			$	174			$	(4	)		$	1,274
2017
Oil and gas production revenues		$	2,271			$	231			$	2,307			$	1,078			$	—			$	5,887
Operating cost:
Depreciation, depletion, and amortization(1)		924				72				707				433				—				2,136
Asset retirement obligation accretion		31				27				—				72				—				130
Lease operating expenses		584				103				362				335				—				1,384
Gathering, processing, and transmission		86				34				44				30				—				194
Exploration expenses		363				11				62				86				27				549
Production taxes(2)		153				11				—				(14		)		—				150
Income tax		45				(7		)		509				54				—				601
		2,186				251				1,684				996				27				5,144
Results of operations		$	85			$	(20	)		$	623			$	82			$	(27	)		$	743

(1)	This amount only 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.

(2)	Only reflects 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.

(3)	During the third quarter of 2017, Apache completed the sale of its Canadian operations. For more information regarding this divestiture, please refer to Note 2—Acquisitions and Divestitures

(4)	Includes noncontrolling interest in Egypt.

---

Costs Incurred in Oil and Gas Property Acquisitions, Exploration, and Development Activities

 

		United States				Canada				Egypt(2)				North Sea				Other International				Total(2)
		(In millions)
2019
Acquisitions:
Proved		$	3			$	—			$	5			$	—			$	—			$	8
Unproved		47				—				10				—				—				57
Exploration		162				—				139				62				105				468
Development		1,500				—				374				119				3				1,996
Costs incurred(1)		$	1,712			$	—			$	528			$	181			$	108			$	2,529
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest		$	23			$	—			$	—			$	5			$	4			$	32
Asset retirement costs		14				—				—				(111		)		—				(97		)
2018
Acquisitions:
Proved		$	—			$	—			$	6			$	—			$	—			$	6
Unproved		111				—				16				—				—				127
Exploration		640				—				175				113				12				940
Development		1,791				—				457				133				—				2,381
Costs incurred(1)		$	2,542			$	—			$	654			$	246			$	12			$	3,454
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest		$	23			$	—			$	—			$	11			$	2			$	36
Asset retirement costs		93				—				—				(62		)		—				31
2017
Acquisitions:
Proved		$	3			$	—			$	4			$	—			$	—			$	7
Unproved		136				5				40				—				—				181
Exploration		602				11				122				131				25				891
Development		1,118				52				387				250				—				1,807
Costs incurred(1)		$	1,859			$	68			$	553			$	381			$	25			$	2,886
(1) Includes capitalized interest and asset retirement costs as follows:
Capitalized interest		$	23			$	2			$	—			$	17			$	2			$	44
Asset retirement costs		15				—				—				55				—				70
(2) Includes a noncontrolling interest in Egypt.

---

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:

 

		United States				Egypt(1)				North Sea				Other International				Total(1)
		(In millions)
2019
Proved properties		$	20,291			$	11,614			$	8,635			$	—			$	40,540
Unproved properties		509				109				10				38				666
		20,800				11,723				8,645				38				41,206
Accumulated DD&A		(11,783		)		(9,377		)		(6,700		)		—				(27,860		)
		$	9,017			$	2,346			$	1,945			$	38			$	13,346
2018
Proved properties		$	22,699			$	11,184			$	8,462			$	—			$	42,345
Unproved properties		1,275				110				5				45				1,435
		23,974				11,294				8,467				45				43,780
Accumulated DD&A		(12,217		)		(8,736		)		(6,332		)		—				(27,285		)
		$	11,757			$	2,558			$	2,135			$	45			$	16,495
(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, Apache uses several different traditional methods that can be classified in three general categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy with similar properties. Apache will, at times, utilize additional technical analysis such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of the Company’s reserve estimates.

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.

 

---

		Crude Oil and Condensate
		(Thousands of barrels)
		United States			Canada			Egypt(1)			North Sea			Total(1)
Proved developed reserves:
December 31, 2016		300,900			51,508			138,771			91,138			582,317
December 31, 2017		304,279			—			124,568			92,598			521,445
December 31, 2018		300,484			—			110,014			104,491			514,989
December 31, 2019		278,145			—			103,573			101,712			483,430
Proved undeveloped reserves:
December 31, 2016		21,088			7,906			20,187			10,784			59,965
December 31, 2017		31,904			—			16,198			14,013			62,115
December 31, 2018		45,182			—			9,484			11,278			65,944
December 31, 2019		46,716			—			10,831			10,049			67,596
Total proved reserves:
Balance December 31, 2016		321,988			59,414			158,958			101,922			642,282
Extensions, discoveries and other additions		48,391			14,025			27,140			16,023			105,579
Purchases of minerals in-place		46			375			—			—			421
Revisions of previous estimates		825			1,829			(9,839	)		6,510			(675	)
Production		(33,394	)		(2,425	)		(35,493	)		(17,844	)		(89,156	)
Sales of minerals in-place		(1,673	)		(73,218	)		—			—			(74,891	)
Balance December 31, 2017		336,183			—			140,766			106,611			583,560
Extensions, discoveries and other additions		61,976			—			22,473			15,682			100,131
Purchases of minerals in-place		140			—			—			—			140
Revisions of previous estimates		(14,334	)		—			(9,556	)		10,613			(13,277	)
Production		(38,252	)		—			(34,185	)		(17,137	)		(89,574	)
Sales of minerals in-place		(47	)		—			—			—			(47	)
Balance December 31, 2018		345,666			—			119,498			115,769			580,933
Extensions, discoveries and other additions		52,297			—			21,039			9,017			82,353
Purchases of minerals in-place		—			—			—			—			—
Revisions of previous estimates		(16,446	)		—			4,752			5,132			(6,562	)
Production		(38,344	)		—			(30,885	)		(18,157	)		(87,386	)
Sales of minerals in-place		(18,312	)		—			—			—			(18,312	)
Balance December 31, 2019		324,861			—			114,404			111,761			551,026

(1)	2019, 2018, 2017, and 2016 includes proved reserves of 38 MMbbls, 40 MMbbls, 47 MMbbls, and 53 MMbbls, respectively, attributable to a noncontrolling interest in Egypt.

---

		Natural Gas Liquids
		(Thousands of barrels)
		United States			Canada			Egypt(1)			North Sea			Total(1)
Proved developed reserves:
December 31, 2016		155,124			13,866			1,266			1,627			171,883
December 31, 2017		171,005			—			685			2,025			173,715
December 31, 2018		197,574			—			502			1,938			200,014
December 31, 2019		158,794			—			667			2,317			161,778
Proved undeveloped reserves:
December 31, 2016		17,311			2,473			131			646			20,561
December 31, 2017		29,559			—			39			353			29,951
December 31, 2018		33,796			—			60			631			34,487
December 31, 2019		23,569			—			90			660			24,319
Total proved reserves:
Balance December 31, 2016		172,435			16,339			1,397			2,273			192,444
Extensions, discoveries and other additions		33,806			1,794			50			845			36,495
Purchases of minerals in-place		206			199			—			—			405
Revisions of previous estimates		12,982			(1,060	)		(425	)		(321	)		11,176
Production		(17,766	)		(1,032	)		(298	)		(419	)		(19,515	)
Sales of minerals in-place		(1,099	)		(16,240	)		—			—			(17,339	)
Balance December 31, 2017		200,564			—			724			2,378			203,666
Extensions, discoveries and other additions		60,990			—			144			1,444			62,578
Purchases of minerals in-place		40			—			—			—			40
Revisions of previous estimates		(9,250	)		—			31			(819	)		(10,038	)
Production		(20,969	)		—			(337	)		(434	)		(21,740	)
Sales of minerals in-place		(5	)		—			—			—			(5	)
Balance December 31, 2018		231,370			—			562			2,569			234,501
Extensions, discoveries and other additions		41,343			—			27			697			42,067
Purchases of minerals in-place		—			—			—			—			—
Revisions of previous estimates		(32,569	)		—			508			345			(31,716	)
Production		(24,959	)		—			(340	)		(634	)		(25,933	)
Sales of minerals in-place		(32,822	)		—			—			—			(32,822	)
Balance December 31, 2019		182,363			—			757			2,977			186,097

(1)    2019, 2018, 2017, and 2016 includes proved reserves of 252 Mbbls, 187 Mbbls, 241 Mbbls, and 466 Mbbls, respectively, attributable to a noncontrolling interest in Egypt.

 

---

		Natural Gas
		(Millions of cubic feet)
		United States			Canada			Egypt(1)			North Sea			Total(1)
Proved developed reserves:
December 31, 2016		1,200,379			553,724			675,559			86,948			2,516,610
December 31, 2017		1,347,009			—			540,667			83,342			1,971,018
December 31, 2018		1,626,403			—			476,132			95,347			2,197,882
December 31, 2019		945,938			—			433,382			106,329			1,485,649
Proved undeveloped reserves:
December 31, 2016		231,304			45,312			42,109			23,813			342,538
December 31, 2017		297,226			—			47,255			11,063			355,544
December 31, 2018		267,090			—			33,006			15,804			315,900
December 31, 2019		115,040			—			24,704			16,604			156,348
Total proved reserves:
Balance December 31, 2016		1,431,683			599,036			717,668			110,761			2,859,148
Extensions, discoveries and other additions		378,747			49,780			81,245			17,646			527,418
Purchases of minerals in-place		4,434			4,319			—			—			8,753
Revisions of previous estimates		(5,431	)		92,207			(70,030	)		(17,387	)		(641	)
Production		(143,943	)		(47,990	)		(140,961	)		(16,615	)		(349,509	)
Sales of minerals in-place		(21,255	)		(697,352	)		—			—			(718,607	)
Balance December 31, 2017		1,644,235			—			587,922			94,405			2,326,562
Extensions, discoveries and other additions		704,135			—			79,394			55,274			838,803
Purchases of minerals in-place		906			—			—			—			906
Revisions of previous estimates		(239,204	)		—			(38,892	)		(21,933	)		(300,029	)
Production		(216,538	)		—			(119,286	)		(16,595	)		(352,419	)
Sales of minerals in-place		(41	)		—			—			—			(41	)
Balance December 31, 2018		1,893,493			—			509,138			111,151			2,513,782
Extensions, discoveries and other additions		249,205			—			34,758			27,711			311,674
Purchases of minerals in-place		—			—			—			—			—
Revisions of previous estimates		(509,753	)		—			18,570			4,015			(487,168	)
Production		(233,447	)		—			(104,380	)		(19,944	)		(357,771	)
Sales of minerals in-place		(338,520	)		—			—			—			(338,520	)
Balance December 31, 2019		1,060,978			—			458,086			122,933			1,641,997

(1)   2019, 2018, 2017, and 2016 include proved reserves of 153 Bcf, 170 Bcf, 196 Bcf, and 239 Bcf, respectively, attributable to a noncontrolling interest in Egypt.

---

		Total Equivalent Reserves
		(Thousands barrels of oil equivalent)
		United States			Canada			Egypt(1)			North Sea			Total(1)
Proved developed reserves:
December 31, 2016		656,087			157,662			252,630			107,256			1,173,635
December 31, 2017		699,786			—			215,364			108,513			1,023,663
December 31, 2018		769,125			—			189,871			122,320			1,081,316
December 31, 2019		594,595			—			176,470			121,751			892,816
Proved undeveloped reserves:
December 31, 2016		76,950			17,931			27,336			15,399			137,616
December 31, 2017		111,001			—			24,112			16,210			151,323
December 31, 2018		123,493			—			15,045			14,543			153,081
December 31, 2019		89,458			—			15,038			13,476			117,972
Total proved reserves:
Balance December 31, 2016		733,037			175,593			279,966			122,655			1,311,251
Extensions, discoveries and other additions		145,322			24,115			40,731			19,809			229,977
Purchases of minerals in-place		991			1,294			—			—			2,285
Revisions of previous estimates		12,903			16,136			(21,936	)		3,291			10,394
Production		(75,151	)		(11,455	)		(59,285	)		(21,032	)		(166,923	)
Sales of minerals in-place		(6,315	)		(205,683	)		—			—			(211,998	)
Balance December 31, 2017		810,787			—			239,476			124,723			1,174,986
Extensions, discoveries and other additions		240,322			—			35,849			26,338			302,509
Purchases of minerals in-place		331			—			—			—			331
Revisions of previous estimates		(63,451	)		—			(16,007	)		6,139			(73,319	)
Production		(95,312	)		—			(54,402	)		(20,337	)		(170,051	)
Sales of minerals in-place		(59	)		—			—			—			(59	)
Balance December 31, 2018		892,618			—			204,916			136,863			1,234,397
Extensions, discoveries and other additions		135,174			—			26,859			14,333			176,366
Purchases of minerals in-place		—			—			—			—			—
Revisions of previous estimates		(133,974	)		—			8,355			6,146			(119,473	)
Production		(102,211	)		—			(48,622	)		(22,115	)		(172,948	)
Sales of minerals in-place		(107,554	)		—			—			—			(107,554	)
Balance December 31, 2019		684,053			—			191,508			135,227			1,010,788

(1)   2019, 2018, 2017, and 2016 include total proved reserves of 64 MMboe, 68 MMboe, 80MMboe, and 93 MMboe, respectively, attributable to a noncontrolling interest in Egypt.

During 2019, Apache added approximately 176 MMboe from extensions, discoveries, and other additions. The Company recorded 135 MMboe of exploration and development adds in the United States, 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 international regions contributed 41 MMboe of exploration and development adds during 2019, with Egypt contributing 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. Apache 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.

---

During 2018, Apache added approximately 303 MMboe from extensions, discoveries, and other additions. The Company recorded 240 MMboe of exploration and development adds in the United States, primarily associated with Woodford, Bone Springs, Yeso, Barnett, and Wolfcamp drilling programs in the Permian Basin (217 MMboe) and Woodford and Austin Chalk drilling activity in the Midcontinent region (20 MMboe). The international regions contributed 62 MMboe of exploration and development adds during 2018, with Egypt contributing 36 MMboe from onshore exploration and appraisal activity in the Khalda Extension 2, Khalda, Khalda Extension 3, Matruh, and West Kalabsha concessions. The North Sea contributed 26 MMboe from drilling success in the Beryl and Forties fields. Apache had combined downward revisions of previously estimated reserves of 73 MMboe. Downward revisions related to changes in product prices accounted for 24 MMboe, interest revisions accounted for 5 MMboe, and engineering and performance downward revisions accounted for 44 MMboe.

During 2017, Apache sold a combined 212 MMboe primarily through divestiture transactions in Canada. The Company added 2 MMboe of estimated proved reserves through purchases of minerals in-place and 230 MMboe from extensions, discoveries, and other additions. The Company recorded 169 MMboe of exploration and development adds in North America, primarily associated with Woodford, Bone Springs, Yeso, Barnett, and Wolfcamp drilling programs in the Permian Basin (128 MMboe), Montney and Duverney drilling in Canada (24 MMboe), and Woodford and Austin Chalk drilling activity in the Midcontinent region (17 MMboe). The international regions contributed 61 MMboe of exploration and development adds during 2017 with Egypt contributing 41 MMboe from onshore exploration and appraisal activity in the Khalda Extension 2, Khalda, Khalda Extension 3, Matruh, and West Kalabsha concessions. The North Sea offshore region contributed 20 MMboe from drilling success in the Beryl and Forties fields. Apache had combined upward revisions of previously estimated reserves of 10 MMboe. Changes in product prices accounted for 32 MMboe, offset by engineering and performance downward revisions totaling 22 MMboe.

Approximately 10 percent of Apache’s year-end 2019 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.”

---

Future Net Cash Flows

Future cash inflows as of December 31, 2019, 2018, and 2017 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.

 

		United States				Egypt(2)				North Sea				Total(2)
		(In millions)
2019
Cash inflows		$	21,694			$	8,306			$	7,454			$	37,454
Production costs		(10,642		)		(1,847		)		(2,730		)		(15,219		)
Development costs		(1,740		)		(707		)		(2,651		)		(5,098		)
Income tax expense		(27		)		(1,930		)		(784		)		(2,741		)
Net cash flows		9,285				3,822				1,289				14,396
10 percent discount rate		(4,003		)		(808		)		297				(4,514		)
Discounted future net cash flows(1)		$	5,282			$	3,014			$	1,586			$	9,882
2018
Cash inflows		$	29,906			$	9,866			$	9,206			$	48,978
Production costs		(13,699		)		(1,799		)		(2,588		)		(18,086		)
Development costs		(2,150		)		(792		)		(2,714		)		(5,656		)
Income tax expense		(19		)		(2,455		)		(1,352		)		(3,826		)
Net cash flows		14,038				4,820				2,552				21,410
10 percent discount rate		(6,516		)		(1,066		)		(107		)		(7,689		)
Discounted future net cash flows(1)		$	7,522			$	3,754			$	2,445			$	13,721
2017
Cash inflows		$	24,271			$	9,254			$	6,230			$	39,755
Production costs		(10,618		)		(1,749		)		(2,459		)		(14,826		)
Development costs		(1,659		)		(1,052		)		(2,795		)		(5,506		)
Income tax expense		(42		)		(2,078		)		(353		)		(2,473		)
Net cash flows		11,952				4,375				623				16,950
10 percent discount rate		(6,080		)		(1,034		)		247				(6,867		)
Discounted future net cash flows(1)		$	5,872			$	3,341			$	870			$	10,083

(1)	Estimated future net cash flows before income tax expense, discounted at 10 percent per annum, totaled approximately $12.4 billion, $16.9 billion, and $12.2 billion as of December 31, 2019, 2018, and 2017, respectively.

(2)	Includes discounted future net cash flows of approximately $1.0 billion, $1.3 billion, and $1.1 billion in 2019, 2018, and 2017, respectively, attributable to a noncontrolling interest in Egypt.

---

The following table sets forth the principal sources of change in the discounted future net cash flows:

		For the Year Ended December 31,
		2019				2018				2017
		(In millions)
Sales, net of production costs		$	(4,291	)		$	(5,335	)		$	(4,158	)
Net change in prices and production costs		(3,034		)		3,902				3,651
Discoveries and improved recovery, net of related costs		2,042				3,889				2,273
Change in future development costs		(75		)		47				(279		)
Previously estimated development costs incurred during the period		983				910				719
Revision of quantities		(741		)		(648		)		(344		)
Purchases of minerals in-place		—				6				9
Accretion of discount		1,693				1,216				952
Change in income taxes		720				(1,125		)		(617		)
Sales of minerals in-place		(817		)		(1		)		(809		)
Change in production rates and other		(319		)		777				626
		$	(3,839	)		$	3,638			$	2,023

The following table summarizes quarterly financial data for 2019 and 2018:

		First				Second				Third				Fourth
		(In millions, except per share amounts)
2019
Oil and gas production revenues		$	1,654			$	1,598			$	1,438			$	1,625
Operating income (loss)(1)		408				124				175				(2,893		)
Net income (loss) before income taxes		165				(152		)		14				(3,035		)
Net loss including noncontrolling interests		(2		)		(316		)		(117		)		(3,247		)
Net loss attributable to common stock		(47		)		(360		)		(170		)		(2,976		)
Net loss per common share(2):
Basic		$	(0.12	)		$	(0.96	)		$	(0.45	)		$	(7.89	)
Diluted		$	(0.12	)		$	(0.96	)		$	(0.45	)		$	(7.89	)
2018
Oil and gas production revenues		$	1,733			$	1,936			$	1,976			$	1,703
Operating income (loss)(1)		587				738				698				(204		)
Net income (loss) before income taxes		388				508				406				(344		)
Net income (loss) including noncontrolling interests		206				269				161				(350		)
Net income (loss) attributable to common stock		145				195				81				(381		)
Net income (loss) per common share(2):
Basic		$	0.38			$	0.51			$	0.21			$	(1.00	)
Diluted		$	0.38			$	0.51			$	0.21			$	(1.00	)

(1)

Operating expenses for 2019 include asset and leasehold impairments totaling $23 million, $279 million, $21 million, and $3.2 billion in the first, second, third, and fourth quarters of 2019, respectively. Operating expenses for 2018 include asset and leasehold impairments totaling $16 million, $21 million, $49 million, and $639 million in the first, second, third, and fourth quarters of 2018, respectively.

(2)	The sum of the individual quarterly net income (loss) per common share amounts may not agree with full-year net income (loss) per common share as each quarterly computation is based on the weighted-average number of common shares outstanding during that period.