Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together with the Company’s Consolidated Financial Statements and accompanying notes included in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q, as well as related information set forth in Apache Corporation’s Consolidated Financial Statements, accompanying Notes to Consolidated Financial Statements, and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

On January 4, 2021, Apache Corporation announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, Apache Corporation became a direct, wholly-owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares were automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache Corporation pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache Corporation as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the Company’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have subsidiaries operating around the globe.

Overview

APA is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids (NGLs). The Company’s upstream business currently has exploration and production operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). APA also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. The Company’s midstream business is operated by Altus Midstream Company (Nasdaq: ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas.

The Company’s mission is to grow in an innovative, safe, environmentally responsible, and profitable manner for the long-term benefit of its stakeholders. The Company is focused on rigorous portfolio management, disciplined financial structure, and optimization of returns.

The global economy and the energy industry have been deeply impacted by the effects of the coronavirus disease 2019 (COVID-19) pandemic and related governmental actions. Uncertainty in the commodity and financial markets during 2020 and 2021 continue to impact oil supply and demand. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of ongoing exploration and appraisal activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its capital program that can be directed on a priority basis to debt reduction. The Company continues to aggressively manage its cost structure regardless of the oil price environment and closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process.

In the third quarter of 2021, the Company reported a net loss of $113 million, or $0.30 per diluted common share, compared to a net loss of $4 million, or $0.01 per diluted common share, in the third quarter of 2020. The increase in net loss compared to the prior-year period is primarily the result of a non-cash $446 million loss on previously sold Gulf of Mexico properties, which represents the Company’s estimate of decommissioning Apache may be required to perform or pay for on assets sold to Fieldwood in 2013 in excess of securities available to the Company to recover costs incurred with respect to such decommissioning. For additional details of this loss, please refer to Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q. Absent this charge, the quarter benefited from significantly improved commodity prices that had collapsed in the prior year when the COVID-19 pandemic negatively affected economic activity and the oil markets. In response to lower commodity prices, the Company materially reduced its upstream capital investment budget and drilling activity during 2020. Daily production decreased 13 percent from an average of 445 Mboe/d in the third quarter of 2020 to an average of 389 Mboe/d in the third quarter of 2021.

The Company generated $2.4 billion of cash from operating activities during the first nine months of 2021, a 171 percent increase from the first nine months of 2020, driven by higher commodity prices and associated revenues. Since year-end 2020, the Company reduced its outstanding debt by $1.4 billion, and it had $377 million of cash at the end of the third quarter of 2021.

Following this progress and considering the ongoing constructive price environment, the Company has adjusted its cash allocation approach, as follows:

• The capital investment program will be increased to a level intended to sustain or slightly grow global production volumes. This will be primarily accomplished through a gradual ramp in activity over the next few quarters, primarily in Egypt, but also in the U.S. Onshore.

• The Company currently plans to return a minimum of 60 percent of its free cash flow to shareholders through dividends, share buybacks, or a combination thereof. In the third quarter of 2021, the Company announced a quarterly dividend increase from $0.025 per share to $0.0625 per share and, in the fourth quarter, announced a further increase to $0.125 per share. During the fourth quarter of 2021, the Company’s Board of Directors authorized the purchase of up to 40 million shares of the Company’s common stock. The Company repurchased 14.7 million shares in October 2021, and as of October 31, 2021, the Company had remaining authorization to repurchase up to 65.3 million shares under Company’s share repurchase programs. The optimal balance of cash return through dividends and share repurchases will be reviewed on a regular basis.

Operational Highlights

Key operational highlights for the quarter include:

United States

• Equivalent production from the Company’s U.S. assets accounted for 61 percent of its total production during the third quarter of 2021. After halting all drilling and completion activity for most of 2020, in early 2021 the Company re-activated one rig in the Permian Basin and one rig in the Austin Chalk. A second rig was added in the Permian Basin in late June 2021. The Company was also active in completing its backlog of Permian wells previously drilled but not completed. During the third quarter, the Company placed nine wells online in the Permian Basin. One additional well was drilled in the Austin Chalk, where the results are continuing to be evaluated, and a drilling rig was recently added to advance the characterization of the Company’s acreage position in the play.

• On October 11, 2021, the Company announced that it has ended routine flaring in its U.S. onshore operations, achieving one of its announced 2021 environmental, social and governance (ESG) goals, three months ahead of schedule.

• On October 21, 2021, ALTM announced that it will combine with privately-owned BCP Raptor Holdco LP (BCP) in an all-stock transaction. As consideration for the transaction, ALTM will issue 50 million Class C common shares (and its subsidiary, Altus Midstream LP, will issue corresponding common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. Upon closing of the transaction, APA will own approximately 20 percent of the issued and outstanding common stock of the combined entity. The transaction is expected to close during the first quarter of 2022 following completion of customary closing conditions, including ALTM shareholder approval and regulatory reviews.

International

• In May 2021, the Company reached an agreement in principle with the Egyptian Ministry of Petroleum and the Egyptian General Petroleum Corporation (EGPC) to modernize the terms of the majority of the production-sharing contracts. The changes simplify the contractual relationship with EGPC and include provisions to create a single cost recovery pool, adjust cost oil and gas and profit oil and gas participation, facilitate recovery of prior investment, update day-to-day operational governance, and refresh the term length of both exploration and development leases. The Apache entity that will become the sole contractor is owned two-thirds by Apache and one-third by Sinopec. The final draft of this agreement has been completed and is scheduled to move to the Egyptian Parliament and President in the fall for approvals to complete the process.

• In Egypt, the Company averaged 8 drilling rigs and completed 12 wells during the third quarter of 2021. Third-quarter gross equivalent production in the Company’s Egypt assets decreased 15 percent from the third quarter of 2020, given reduced drilling activity over the preceding year. The Company continues to build and enhance its drilling inventory in Egypt, supplemented with recent seismic acquisitions and new play concept evaluations on both new and existing acreage. Upon ratification of the new agreement referenced above, the Company expects to further increase drilling and workover activity.

• The Company averaged two rigs in the North Sea during the third quarter of 2021. Production was significantly impacted by compressor downtime, extended platform turnaround work, and third-party pipeline outages during the first nine months of the year.

• In late 2020, the Company commenced drilling a fourth exploration well at the Keskesi prospect in Block 58 offshore Suriname. In January 2021, the Company and its partner TotalEnergies (formerly Total S.A.) announced a discovery that confirmed oil in the eastern portion of the block. The Company has subsequently transferred operatorship of Block 58 to TotalEnergies, with ongoing exploration and appraisal activities continuing to progress. APA holds a 50 percent working interest in Block 58, with TotalEnergies, the operator, holding a 50 percent working interest.

• TotalEnergies is currently running two rigs. One is conducting a flow test at the Sapakara South appraisal well, and the other is drilling the Bonboni exploration well in the northern portion of Block 58.

Results of Operations

Oil and Gas Production Revenues

Revenue

The Company’s oil and gas production revenues and respective contribution to total revenues by country were as follows:

						For the Quarter Ended September 30,																								For the Nine Months Ended September 30,
						2021												2020												2021												2020
						$ Value						% Contribution						$ Value						% Contribution						$ Value						% Contribution						$ Value						% Contribution
						($ in millions)
Oil Revenues:
United States						$	484					41		%				$	303					39		%				$	1,325					40		%				$	929					40		%
Egypt(1)						465						39		%				303						38		%				1,299						39		%				823						35		%
North Sea						233						20		%				179						23		%				690						21		%				578						25		%
Total(1)						$	1,182					100		%				$	785					100		%				$	3,314					100		%				$	2,330					100		%
Natural Gas Revenues:
United States						$	188					64		%				$	77					47		%				$	533					64		%				$	169					41		%
Egypt(1)						63						22		%				74						45		%				198						24		%				209						50		%
North Sea						42						14		%				13						8		%				100						12		%				39						9		%
Total(1)						$	293					100		%				$	164					100		%				$	831					100		%				$	417					100		%
NGL Revenues:
United States						$	202					96		%				$	90					93		%				$	463					95		%				$	211					91		%
Egypt(1)						2						1		%				2						2		%				6						1		%				6						3		%
North Sea						6						3		%				5						5		%				16						4		%				15						6		%
Total(1)						$	210					100		%				$	97					100		%				$	485					100		%				$	232					100		%
Oil and Gas Revenues:
United States						$	874					52		%				$	470					45		%				$	2,321					50		%				$	1,309					44		%
Egypt(1)						530						31		%				379						36		%				1,503						33		%				1,038						35		%
North Sea						281						17		%				197						19		%				806						17		%				632						21		%
Total(1)						$	1,685					100		%				$	1,046					100		%				$	4,630					100		%				$	2,979					100		%

(1) Includes revenues attributable to a noncontrolling interest in Egypt.

Production

The Company’s production volumes by country were as follows:

						For the Quarter Ended September 30,																		For the Nine Months Ended, September 30,
						2021						Increase (Decrease)						2020						2021						Increase (Decrease)						2020
Oil Volume (b/d)
United States						75,526						(9)%						83,178						75,384						(19)%						93,051
Egypt(1)(2)						69,830						(12)%						79,194						71,052						(8)%						77,410
North Sea						33,783						(31)%						48,755						36,398						(28)%						50,339
Total						179,139						(15)%						211,127						182,834						(17)%						220,800
Natural Gas Volume (Mcf/d)
United States						546,058						(9)%						597,686						531,695						(7)%						571,325
Egypt(1)(2)						243,294						(15)%						286,744						259,108						(5)%						273,676
North Sea						33,752						(36)%						53,137						40,061						(31)%						57,659
Total						823,104						(12)%						937,567						830,864						(8)%						902,660
NGL Volume (b/d)
United States						70,962						(6)%						75,266						65,805						(13)%						75,468
Egypt(1)(2)						496						(19)%						611						544						(33)%						812
North Sea						1,200						(39)%						1,976						1,220						(37)%						1,948
Total						72,658						(7)%						77,853						67,569						(14)%						78,228
BOE per day(3)
United States						237,498						(8)%						258,058						229,805						(13)%						263,740
Egypt(1)(2)						110,875						(13)%						127,595						114,780						(7)%						123,834
North Sea(4)						40,608						(32)%						59,588						44,295						(28)%						61,897
Total						388,981						(13)%						445,241						388,880						(13)%						449,471

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

						For the Quarter Ended September 30,																		For the Nine Months Ended September 30,
						2021												2020						2021												2020
Oil (b/d)						134,128												159,941						134,976												171,778
Natural Gas (Mcf/d)						564,354												649,566						581,859												648,995
NGL (b/d)						776												1,175						846												1,534

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

						For the Quarter Ended September 30,																		For the Nine Months Ended September 30,
						2021												2020						2021												2020
Oil (b/d)						23,309												26,459						23,716												25,891
Natural Gas (Mcf/d)						81,309												95,776						86,564												91,374
NGL (b/d)						165												204						181												271

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

(4) Average sales volumes from the North Sea for the third quarter of 2021 and 2020 were 40,581 boe/d and 57,099 boe/d, respectively, and 45,637 boe/d and 61,771 boe/d for the first nine months of 2021 and 2020, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

Pricing

The Company’s average selling prices by country were as follows:

						For the Quarter Ended September 30,																		For the Nine Months Ended, September 30,
						2021						Increase (Decrease)						2020						2021						Increase (Decrease)						2020
Average Oil Price - Per barrel
United States						$	69.69					76%						$	39.60					$	64.38					77%						$	36.45
Egypt						72.37						74%						41.51						66.97						73%						38.79
North Sea						74.94						78%						42.10						66.93						59%						41.99
Total						71.72						75%						40.88						65.90						71%						38.53
Average Natural Gas Price - Per Mcf
United States						$	3.75					168%						$	1.40					$	3.67					240%						$	1.08
Egypt						2.82						—%						2.82						2.80						—%						2.79
North Sea						13.40						419%						2.58						9.13						271%						2.46
Total						3.87						104%						1.90						3.66						117%						1.69
Average NGL Price - Per barrel
United States						$	30.85					136%						$	13.06					$	25.75					152%						$	10.20
Egypt						52.02						101%						25.88						44.73						70%						26.24
North Sea						56.64						109%						27.08						48.32						69%						28.54
Total						31.42						133%						13.51						26.32						143%						10.83

Third-Quarter 2021 compared to Third-Quarter 2020

Crude Oil Crude oil revenues for the third quarter of 2021 totaled $1.2 billion, a $397 million increase from the comparative 2020 quarter. A 75 percent increase in average realized prices increased third-quarter 2021 oil revenues by $592 million compared to the prior-year quarter, while 15 percent lower average daily production decreased revenues by $195 million. Crude oil revenues accounted for 70 percent of total oil and gas production revenues and 46 percent of worldwide production in the third quarter of 2021. The Company’s worldwide oil production decreased 32.0 Mb/d to 179.1 Mb/d during the third quarter of 2021 from the comparative prior-year period, primarily a result of natural production decline across all countries and extended operational downtime and platform turnaround work in the North Sea.

Natural Gas Gas revenues for the third quarter of 2021 totaled $293 million, a $129 million increase from the comparative 2020 quarter. A 104 percent increase in average realized prices increased third-quarter 2021 natural gas revenues by $170 million compared to the prior-year quarter, while 12 percent lower average daily production decreased revenues by $41 million. Natural gas revenues accounted for 17 percent of total oil and gas production revenues and 35 percent of worldwide production during the third quarter of 2021. The Company’s worldwide natural gas production decreased 114.5 MMcf/d to 823 MMcf/d during the third quarter of 2021 from the comparative prior-year period, primarily a result of production decline across all countries and extended operational downtime in the North Sea, offset by increased completion activity in the U.S.

NGL NGL revenues for the third quarter of 2021 totaled $210 million, a $113 million increase from the comparative 2020 quarter. A 133 percent increase in average realized prices increased third-quarter 2021 NGL revenues by $128 million compared to the prior-year quarter, while 7 percent lower average daily production decreased revenues by $15 million. NGL revenues accounted for 13 percent of total oil and gas production revenues and 19 percent of worldwide production during the third quarter of 2021. The Company’s worldwide NGL production decreased 5.2 Mb/d to 72.7 Mb/d during the third quarter of 2021 from the comparative prior-year period, primarily a result of production decline across all countries.

Year-to-Date 2021 compared to Year-to-Date 2020

Crude Oil Crude oil revenues for the first nine months of 2021 totaled $3.3 billion, a $1.0 billion increase from the comparative 2020 period. A 71 percent increase in average realized prices increased oil revenues for the 2021 period by $1.7 billion compared to the prior-year period, while 17 percent lower average daily production decreased revenues by $671 million compared to the prior-year period. Crude oil revenues accounted for 72 percent of total oil and gas production revenues and 47 percent of worldwide production for the first nine months of 2021. Crude oil prices realized during the first nine months of 2021 averaged $65.90 per barrel, compared to $38.53 per barrel in the comparative prior-year period. The Company’s worldwide oil production decreased 38.0 Mb/d to 182.8 Mb/d in the first nine months of 2021 compared to the prior-year period, primarily a result of production decline across all countries, and extended operational downtime and platform turnaround work in the North Sea.

Natural Gas Gas revenues for the first nine months of 2021 totaled $831 million, a $414 million increase from the comparative 2020 period. A 117 percent increase in average realized prices increased natural gas revenues for the 2021 period by $489 million compared to the prior-year period, while 8 percent lower average daily production decreased revenues by $75 million compared to the prior-year period. Natural gas revenues accounted for 18 percent of total oil and gas production revenues and 36 percent of worldwide production for the first nine months of 2021. Natural gas prices realized during the first nine months of 2021 averaged $3.66 per Mcf, compared to $1.69 per Mcf in the comparative prior-year period. Gas prices for the U.S. during the first nine months of 2021 also reflect the extreme price volatility during the month of February due to the Texas freeze event. The Company’s worldwide natural gas production decreased 72 MMcf/d to 831 MMcf/d in the first nine months of 2021 compared to the prior-year period, primarily a result of production decline across all countries, impacts of winter storms in the U.S., and extended operational downtime and platform turnaround work in the North Sea.

NGL NGL revenues for the first nine months of 2021 totaled $485 million, a $253 million increase from the comparative 2020 period. A 143 percent increase in average realized prices increased NGL revenues for the 2021 period by $332 million compared to the prior-year period, while 14 percent lower average daily production decreased revenues by $79 million compared to the prior-year period. NGL revenues accounted for 10 percent of total oil and gas production revenues and 17 percent of worldwide production for the first nine months of 2021. NGL prices realized during the first nine months of 2021 averaged $26.32 per barrel, compared to $10.83 per barrel in the comparative prior-year period. The Company’s worldwide NGL production decreased 10.7 Mb/d to 67.6 Mb/d in the first nine months of 2021 compared to the prior-year period, primarily a result of production decline across all countries and the impacts of winter storms in the U.S.

Altus Midstream Revenues

Altus Midstream services revenues generated through its fee-based contractual arrangements with the Company totaled $35 million and $39 million during the third quarters of 2021 and 2020, respectively, and $99 million and $111 million during the first nine months of 2021 and 2020, respectively. These affiliated revenues are eliminated upon consolidation. Changes in revenue compared to the prior periods were primarily driven by lower natural gas throughput volumes processed by Altus for the Company’s Alpine High production.

Purchased Oil and Gas Sales

Purchased oil and gas sales represent volumes primarily attributable to transport, fuel, and physical in-basin gas purchases that were sold by the Company to fulfill natural gas takeaway obligations. Sales related to these purchased volumes totaled $374 million and $74 million during the third quarters of 2021 and 2020, respectively, and $1.1 billion and $237 million during the first nine months of 2021 and 2020, respectively. Purchased oil and gas sales were offset by associated purchase costs of $396 million and $75 million during the third quarters of 2021 and 2020, respectively, and $1.2 billion and $207 million during the first nine months of 2021 and 2020, respectively. When compared to the prior-year periods, gross purchased oil and gas sales values and the associated net losses in the third quarter and first nine months of 2021 increased as a result of production shortfalls following reduced capital investment and drilling activity in 2020. The year-to-date net loss was exacerbated by extreme price volatility during the month of February due to Winter Storm Uri in Texas.

Operating Expenses

The Company’s operating expenses were as follows:

						For the Quarter Ended September 30,												For the Nine Months Ended September 30,
						2021						2020						2021						2020
						(In millions)
Lease operating expenses						$	316					$	259					$	891					$	858
Gathering, processing, and transmission						68						63						187						206
Purchased oil and gas costs						396						75						1,152						207
Taxes other than income						54						34						149						90
Exploration						34						58						109						187
General and administrative						70						52						239						214
Transaction, reorganization, and separation						4						7						8						44
Depreciation, depletion, and amortization:
Oil and gas property and equipment						306						366						940						1,284
Gathering, processing, and transmission assets						18						19						56						58
Other assets						11						13						32						40
Asset retirement obligation accretion						29						27						85						81
Impairments						18						—						18						4,492
Financing costs, net						205						99						422						168
Total Operating Expenses						$	1,529					$	1,072					$	4,288					$	7,929

Lease Operating Expenses (LOE)

LOE increased $57 million and $33 million in the third quarter and the first nine months of 2021, respectively, from the comparative prior-year periods. On a per-unit basis, LOE increased 39 percent and 20 percent in the third quarter and the first nine months of 2021, respectively, from the comparative prior-year periods. The increase was driven by higher turnaround and maintenance costs in the North Sea, strengthening foreign exchange rates against the U.S. dollar, increased workover activity in the U.S. in the third quarter of 2021, and per-unit operating costs trending with higher oil and gas prices.

Gathering, Processing, and Transmission (GPT)

The Company’s GPT expenses were as follows:

						For the Quarter Ended September 30,												For the Nine Months Ended, September 30,
						2021						2020						2021						2020
						(In millions)
Third-party processing and transmission costs						$	59					$	54					$	163					$	177
Midstream service affiliate costs						35						38						98						110
Upstream processing and transmission costs						94						92						261						287
Midstream operating expenses						9						9						24						29
Intersegment eliminations						(35)						(38)						(98)						(110)
Total Gathering, processing, and transmission						$	68					$	63					$	187					$	206

GPT costs increased $5 million and decreased $19 million in the third quarter and the first nine months 2021, respectively, from the comparative prior-year periods. Third-party processing and transmission costs increased $5 million and decreased $14 million in the third quarter and the first nine months of 2021, respectively, from the comparative prior-year periods. The increase in third-party costs for the third quarter of 2021 was primarily driven by an increase in average transportation rates during the quarter. The overall decrease in third-party costs for the first nine months of 2021 was primarily driven by a decrease in contracted pricing and lower processed volumes. Midstream service affiliate costs decreased $3 million and $12 million in the third quarter and the first nine months of 2021, respectively, from the comparative prior-year periods. The overall decrease in the first nine months of 2021 was primarily driven by lower throughput of rich natural gas volumes at Alpine High. Midstream operating expenses, primarily incurred by Altus Midstream, remained flat in the third quarter of 2021 and decreased $5 million in the first nine months of 2021, compared to the respective prior-year periods, driven by increased operational efficiency and continued cost cutting efforts.

Purchased Oil and Gas Costs

Purchased oil and gas costs totaled $396 million and $1.2 billion during the third quarter and the first nine months of 2021, respectively, compared to $75 million and $207 million during the third quarter and the first nine months of 2020, respectively. Purchased oil and gas costs were offset by associated purchase sales of $374 million and $1.1 billion during the third quarter and the first nine months of 2021, respectively, compared to $74 million and $237 million during the third quarter and the first nine months of 2020, respectively, as further discussed above.

Taxes Other Than Income

Taxes other than income increased $20 million and $59 million from the third quarter and the first nine months of 2020, respectively, primarily from higher severance taxes driven by higher commodity prices as compared to the same prior-year periods.

Exploration Expenses

The Company’s exploration expenses were as follows:

						For the Quarter Ended September 30,												For the Nine Months Ended, September 30,
						2021						2020						2021						2020
						(In millions)
Unproved leasehold impairments						$	5					$	36					$	26					$	86
Dry hole expense						16						5						41						52
Geological and geophysical expense						4						7						14						14
Exploration overhead and other						9						10						28						35
Total Exploration						$	34					$	58					$	109					$	187

Exploration expenses decreased $24 million and $78 million from the third quarter and the first nine months of 2020, respectively, primarily the result of higher unproved leasehold impairments during the prior-year periods, due to lower oil and gas prices in the comparative periods. For the first nine months of 2021, the Company also had lower overhead and dry hole expenses resulting from decreased exploration activities compared to the prior year.

General and Administrative (G&A) Expenses

G&A expenses increased $18 million and $25 million in the third quarter and the first nine months of 2021, respectively, from the comparative prior-year periods, primarily driven by higher cash-based stock compensation expense resulting from an increase in the Company’s stock price, partially offset by lower overhead driven by organizational redesign efforts during 2019 and 2020.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs decreased $3 million and $36 million from the third quarter and the first nine months of 2020, respectively, driven by costs associated with the Company’s reorganization efforts incurred primarily in the prior year.

In recent years, the Company has streamlined its portfolio through strategic divestitures and centralized certain operational activities in an effort to capture greater efficiencies and cost savings through shared services. During the second half of 2019, management initiated a comprehensive redesign of the Company’s organizational structure and operations that it believes will better position the Company to be competitive for the long-term and further reduce recurring costs. Reorganization efforts were substantially completed during 2020.

Depreciation, Depletion, and Amortization (DD&A)

DD&A expenses on the Company’s oil and gas properties decreased $60 million and $344 million from the third quarter and the first nine months of 2020, respectively. The Company’s DD&A rate on its oil and gas properties decreased $0.45 per boe and $1.61 per boe from the third quarter and the first nine months of 2020, respectively. The decrease on an absolute basis was driven by lower production volumes and lower asset property balances associated with proved property impairments recorded during the first quarter of 2020. DD&A expense on the Company’s GPT assets remained essentially flat compared to the third quarter and the first nine months of 2020.

Impairments

During the third quarter and first nine months of 2021, the Company recorded $18 million of asset impairments in connection with inventory valuations and expected equipment dispositions in the North Sea.

The Company recognized $4.5 billion in asset impairments in connection with fair value assessments during the first nine months of 2020. During the first half of 2020, the Company recognized impairments totaling $4.3 billion related to proved oil and gas properties in the U.S., Egypt, and the North Sea, $68 million related to GPT facilities in Egypt, $87 million related to goodwill valuations in Egypt, and $18 million related to inventory and other miscellaneous assets, including charges for the early termination of drilling rig leases.

Financing Costs, Net

The Company’s Financing costs were as follows:

						For the Quarter Ended September 30,												For the Nine Months Ended, September 30,
						2021						2020						2021						2020
						(In millions)
Interest expense						$	102					$	113					$	324					$	327
Amortization of debt issuance costs						1						2						6						6
Capitalized interest						(2)						(3)						(6)						(9)
Loss (gain) on extinguishment of debt						105						(12)						104						(152)
Interest income						(1)						(1)						(6)						(4)
Total Financing costs, net						$	205					$	99					$	422					$	168

Net financing costs increased $106 million and $254 million from the third quarter and the first nine months of 2020, respectively, primarily driven by a $105 million loss on extinguishment of debt recognized in the third quarter of 2021, and a $152 million gain on extinguishment of debt during the first nine months of 2020.

Provision for Income Taxes

The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments on the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.

During the third quarter of 2021, the Company’s effective income tax rate was primarily impacted by a loss on offshore decommissioning contingency and an increase in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2020, the Company’s effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2021 year-to-date effective income tax rate was primarily impacted by a loss contingency in connection with decommissioning of previously sold Gulf of Mexico properties and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2020 year-to-date effective income tax rate was primarily impacted by oil and gas asset impairments, a goodwill impairment, and an increase in the amount of valuation allowance against its U.S. deferred tax assets.

The Company recorded a full valuation allowance against its U.S. net deferred tax assets. The Company will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance.

The Company is subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is currently under audit by the Internal Revenue Service for the 2014-2017 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.

Capital Resources and Liquidity

Operating cash flows are the Company’s primary source of liquidity. The Company’s short-term and long-term operating cash flows are impacted by highly volatile commodity prices, as well as production costs and sales volumes. Significant changes in commodity prices impact the Company’s revenues, earnings, and cash flows. These changes potentially impact the Company’s liquidity if costs do not trend with related changes in commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.

The Company’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of the Company’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves.

The Company’s capital investment for the third quarter of 2021 was below its planned budget announced earlier in the year, but the Company remains on-track for its full-year guidance and estimated upstream capital program of $1.1 billion. The program consists of approximately $900 million for development activities across its portfolio and approximately $200 million for exploration activities, predominantly in Suriname.

The Company believes the liquidity and capital resource alternatives available to the Company, combined with proactive measures to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including the Company’s capital development program, repayment of debt maturities, payment of dividends, and amounts that may ultimately be paid in connection with commitments and contingencies.

The Company may also elect to utilize available cash on hand, committed subsidiary borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for all other liquidity and capital resource needs.

For additional information, refer to Part I, Items 1 and 2—Business and Properties, and Item 1A—Risk Factors, in Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

Sources and Uses of Cash

The following table presents the sources and uses of the Company’s cash and cash equivalents for the periods presented.

						For the Nine Months Ended September 30,
						2021						2020
						(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities						$	2,411					$	890
Proceeds from Apache credit facility, net						290						87
Proceeds from Altus credit facility, net						33						184
Proceeds from asset divestitures						239						132
Fixed-rate debt borrowings						—						1,238
Other						27						—
Total Sources of Cash and Cash Equivalents						3,000						2,531
Uses of Cash and Cash Equivalents:
Additions to upstream oil and gas property(1)						$	(790)					$	(1,075)
Additions to Altus gathering, processing, and transmission facilities(1)						(2)						(27)
Leasehold and property acquisitions						(6)						(3)
Contributions to Altus equity method interests						(27)						(286)
Payments on fixed-rate debt						(1,795)						(980)
Dividends paid to APA common stockholders						(28)						(113)
Distributions to noncontrolling interest - Egypt						(203)						(61)
Distributions to Altus Preferred Unit limited partners						(34)						(11)
Other						—						(60)
Total Uses of Cash and Cash Equivalents						(2,885)						(2,616)
Increase (decrease) in cash and cash equivalents						$	115					$	(85)

(1) The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this Quarterly Report on Form 10-Q, which include accruals.

Sources of Cash and Cash Equivalents

Net Cash Provided by Operating Activities Operating cash flows are the Company’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile commodity prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense.

Net cash provided by operating activities increased $1.5 billion from the first nine months of 2020, primarily due to higher commodity prices.

For a detailed discussion of commodity prices, production, and operating expenses, refer to “Results of Operations” in this Item 2. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, refer to the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part I, Item 1, Financial Statements of this Quarterly Report on Form 10-Q.

Proceeds from Apache Credit Facility, Net During the first nine months of 2021 and 2020, Apache borrowed $290 million and $87 million, respectively, under its revolving credit facility.

Proceeds from Altus Credit Facility, Net The construction of Altus’ gathering and processing assets and the associated equity method pipelines has historically required capital expenditures in excess of Altus’ cash on hand and operational cash flows. During the first nine months of 2021 and 2020, Altus Midstream LP borrowed $33 million and $184 million, respectively, under its revolving credit facility to meet this short fall. With the midstream infrastructure complete and all of the equity method interest pipelines now in service, the Company anticipates that Altus’ existing capital resources will be sufficient to fund its continuing obligations and dividend program during 2021.

Proceeds from Asset Divestitures The Company received $239 million and $132 million of proceeds from the divestiture of certain non-core assets during the first nine months of 2021 and 2020, respectively. For more information regarding the Company’s acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Uses of Cash and Cash Equivalents

Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $790 million and $1.1 billion during the first nine months of 2021 and 2020, respectively. The decrease in capital investment is reflective of the Company’s reduced capital program to align with anticipated operating cash flows following the collapse of commodity prices stemming from the COVID-19 pandemic. The Company operated an average of 14 drilling rigs during the third quarter of 2021, compared to an average of eight drilling rigs during the third quarter of 2020.

Additions to Altus Gathering, Processing, and Transmission (GPT) Facilities The Company’s cash expenditures for GPT facilities totaled $2 million and $27 million during the first nine months of 2021 and 2020, respectively, nearly all comprising midstream infrastructure expenditures incurred by Altus, which were substantially completed as of December 31, 2019. Altus management believes its existing GPT infrastructure capacity is capable of fulfilling its midstream contracts to service the Company’s production from Alpine High and any third-party customers. As such, Altus expects capital requirements for its existing infrastructure assets for the remainder of 2021 to be minimal.

Leasehold and Property Acquisitions The Company completed leasehold and property acquisitions for total cash consideration of $6 million and $3 million during the first nine months of 2021 and 2020.

Contributions to Altus Equity Method Interests Altus contributed $27 million and $286 million in cash during the first nine months of 2021 and 2020, respectively, for equity interests in the equity method interest pipelines. For more information regarding the Company’s equity method interests, refer to Note 6—Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Payments on Fixed-Rate Debt In August 2021, Apache closed cash tender offers for certain outstanding notes and accepted for purchase $1.7 billion aggregate principal amount of certain notes. Apache paid holders an aggregate $1.8 billion, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $105 million loss on extinguishment of debt, including $98 million of unamortized debt discount and issuance costs, in connection with the note purchases.

During the first nine months of 2021, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $22 million for an aggregate purchase price of $20 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $2 million. The Company recognized a $1 million net loss on extinguishment of debt as part of these transactions.

On August 18, 2020, the Company closed cash tender offers for certain outstanding notes. Apache accepted for purchase $644 million aggregate principal amount of certain notes covered by the tender offers. Apache paid holders an aggregate $644 million, reflecting principal, aggregate discount to par of $38 million, early tender premium of $32 million, and accrued and unpaid interest of $6 million. The Company recorded a net gain of $2 million on extinguishment of debt, including an acceleration of unamortized debt discount and issuance costs, in connection with the note purchases.

During the quarter ended September 30, 2020, the Company purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $89 million for an aggregate purchase price of $79 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $11 million. These repurchases resulted in a $10 million net gain on extinguishment of debt. The net gain includes an acceleration of related discount and debt issuance costs. The repurchases were financed by borrowings under the Company’s revolving credit facility.

During the quarter ended June 30, 2020, the Company purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $410 million for an aggregate purchase price of $267 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $147 million. These repurchases resulted in a $140 million net gain on extinguishment of debt. The net gain includes an acceleration of related discount and debt issuance costs. The repurchases were financed by borrowings under the Company’s revolving credit facility.

The Company expects that Apache intends to reduce debt outstanding under its indentures from time to time.

Dividends The Company paid $28 million and $113 million during the first nine months of 2021 and 2020, respectively, for dividends on its common stock. In the first quarter of 2020, the Company’s Board of Directors approved a reduction in the Company’s quarterly dividend per share from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020. During the third quarter of 2021, the Company’s Board of Directors approved an increase in its quarterly dividend per share from $0.025 to $0.0625.

Distributions to Noncontrolling Interest - Egypt Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company paid $203 million and $61 million during the first nine months of 2021 and 2020, respectively, in cash distributions to Sinopec.

Distributions to Altus Preferred Units limited partners Altus Midstream LP paid $34 million and $11 million in cash distributions to its limited partners holding Preferred Units during the first nine months of 2021 and 2020, respectively. For more information regarding the Preferred Units, refer to Note 12—Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Liquidity

The following table presents a summary of the Company’s key financial indicators:

						September 30, 2021						December 31, 2020
						(In millions)
Cash and cash equivalents						$	377					$	262
Total debt - Apache						6,751						8,148
Total debt - Altus						657						624
Total deficit						(150)						(645)
Available committed borrowing capacity - Apache						2,896						2,944
Available committed borrowing capacity - Altus						141						176

Cash and Cash Equivalents As of September 30, 2021, the Company had $377 million in cash and cash equivalents, of which approximately $109 million was held by Altus. The majority of the Company’s cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.

Debt As of September 30, 2021, the Company had $7.4 billion in total debt outstanding, which consisted of notes, debentures, credit facility borrowings, and finance lease obligations. As of September 30, 2021, current debt included $213 million, net of discount, of 3.625% senior notes due April 15, 2022 and $2 million of finance lease obligations.

Committed Credit Facilities In March 2018, Apache entered into a revolving credit facility with commitments totaling $4.0 billion. In March 2019, the term of this facility was extended by one year to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise of an extension option. Apache can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of September 30, 2021. The facility is for general corporate purposes. Letters of credit are available for security needs, including in respect of North Sea decommissioning obligations. The facility has no collateral requirements, is not subject to borrowing base redetermination, and has no drawdown restrictions or prepayment obligations in the event of a decline in credit ratings.

As of September 30, 2021, there were $440 million of borrowings and aggregate £478 million and $20 million in letters of credit outstanding under this facility. As of December 31, 2020, there were $150 million of borrowings and an aggregate £633 million and $40 million in letters of credit outstanding under this facility. The outstanding letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020.

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 September 30, 2021, there were $657 million of borrowings and a $2 million letter of credit outstanding under this facility. As of December 31, 2020, there were $624 million of borrowings and no letters of credit outstanding under this facility. The Altus Midstream LP credit facility is unsecured and is not guaranteed by APA or any of its subsidiaries, including Apache.

Apache and Altus Midstream LP were in compliance with the terms of their respective credit facilities as of September 30, 2021.

Uncommitted Credit Facilities Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of September 30, 2021, there were no borrowings and £118 million and $17 million in letters of credit outstanding under these facilities, respectively. As of December 31, 2020, there were no borrowings and £34 million and $17 million in letters of credit outstanding under these facilities, respectively.

Commercial Paper Program Apache did not use its commercial paper program during the first six months of 2021 and terminated the program during the third quarter of 2021. As of December 31, 2020, no commercial paper was outstanding.

Off-Balance Sheet Arrangements The Company enters into customary agreements in the oil and gas industry for drilling rig commitments, firm transportation agreements, and other obligations as described in “Contractual Obligations” in Part II, Item 7 of Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020. There have been no material changes to the contractual obligations described therein.

Potential Decommissioning Obligations on Sold Properties

The Company’s subsidiaries have potential exposure to future obligations related to divested properties. Apache has divested various leases, wells, and facilities located in the Gulf of Mexico (GOM) where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of a severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser of such GOM assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, APA’s subsidiaries could be required to perform such actions under applicable federal laws and regulations. In such event, APA’s subsidiaries may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.

In 2013, Apache sold its GOM Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a beneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Currently, Apache holds two bonds (Bonds) and five Letters of Credit to secure Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset over the remaining life of the Legacy GOM Assets.

On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets will be used to fund decommissioning of Legacy GOM Assets.

In September 2021, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund its decommissioning obligations on certain of the Legacy GOM Assets that GOM Shelf is currently required to perform. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notification to BSEE. Apache expects to receive such orders on the other Legacy GOM Properties included in GOM Shelf’s notification letter. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the future and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.

As and when Apache incurs costs to decommission any Legacy GOM Asset and GOM Shelf does not reimburse Apache, Apache will obtain reimbursement from Trust A, the Bonds, and the Letters of Credit until such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets.

If the combination of GOM Shelf’s net cash flows from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit, are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be ordered by BSEE to perform or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, Apache may be forced to effectively use its available cash to fund the deficit.

As of September 30, 2021, Apache estimates that its potential liability to fund decommissioning of GOM Legacy Assets it may be ordered to perform ranges from $1.2 billion to $1.4 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, in the third quarter of 2021, the Company recorded a contingent liability of $1.2 billion, representing the estimated costs of decommissioning it may be required to perform on GOM Legacy Assets under the caption “Decommissioning contingency for sold Gulf of Mexico Properties” in the Company’s consolidated balance sheet. The Company also recorded a $740 million asset, which represents the amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on GOM Legacy Assets under the caption “Decommissioning security for sold Gulf of Mexico properties.” A “Loss on previously sold Gulf of Mexico properties” in the amount of $446 million was recognized in the third quarter of 2021 to reflect the net impact to the Company’s statement of consolidated operations. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. In addition, significant changes in the market price of oil, gas, and natural gas liquids could further impact Apache’s estimate of its contingent liability to decommission GOM Legacy Assets.

Critical Accounting Estimates

The Company prepares its financial statements and accompanying notes in conformity with accounting principles generally accepted in the United States of America, which require management to make estimates and assumptions about future events that affect reported amounts. Estimations are considered critical accounting estimates based on, among other things, its impact on the portrayal of the Company’s financial condition, results of operations, or liquidity, as well as the degree of difficulty, subjectivity, and complexity in its deployment. Critical accounting estimates address accounting matters that are inherently uncertain due to unknown future resolution of such matters. Management routinely discusses the development, selection, and disclosure of each critical accounting estimates. With the exception of the critical accounting estimate listed below, there have been no significant changes to the Company’s estimates and assumptions during the nine months ended September 30, 2021 and 2020.

Offshore Decommissioning Contingency

The Company has potential exposure to future obligations related to divested properties. For information regarding a potential obligation to decommission sold properties estimated and recorded in the third quarter of 2021, please refer to “Potential Obligation to Decommission Sold Properties” above and in Note 11—Commitments and Contingencies in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q. Changes in significant assumptions impacting the Company’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued. In addition, significant changes in the market price of oil, gas, and natural gas liquids could further impact Apache’s estimate of its contingent liability to decommission GOM Legacy Assets.