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 the Company’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 the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

Overview

APA is an independent energy company that owns consolidated subsidiaries that explore for, develop, and produce 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 appraisal operations ongoing in Suriname, as well as interests in the Dominican Republic, and other international locations that may, over time, result in reportable discoveries and development opportunities. As a holding company, APA Corporation’s primary assets are its ownership interests in its subsidiaries. Prior to the BCP Business Combination (as defined in the Notes to the Company’s Consolidated Financial Statements set forth in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q), the Company’s midstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus).

APA believes energy underpins global progress, and the Company wants to be a part of the conversation and solution as society works to meet growing global demand for reliable and affordable energy. APA strives to meet those challenges while creating value for all its stakeholders.

The global economy and the energy industry continue to be impacted by the effects of ongoing international conflicts and the coronavirus disease 2019 (COVID-19) pandemic. Uncertainties in the global supply chain and financial markets, including the impact of inflation and rising interest rates, and actions taken by foreign oil and gas producing nations, including OPEC+, continue to impact oil supply and demand and contribute to commodity price volatility. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of 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 upstream exploration, appraisal, and development capital program that can be directed to debt reduction, share repurchases, and other return of capital to its shareholders. The Company continues to aggressively manage its cost structure regardless of the oil price environment and closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process.

APA’s diversified asset portfolio and operational flexibility provide it the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. The Company deferred drilling and completion activity at Alpine High in the second quarter of 2023 in response to weakness in Waha natural gas and NGL prices during the year but are accelerating completion of eight Permian Basin wells and adding a drilling rig in the Delaware Basin in the fourth quarter of 2023. The Company also suspended drilling activity in the North Sea during the second quarter of 2023, as increasing cost and tax burdens have impacted the competitiveness of these assets within the Company’s portfolio. The Company anticipates its full-year 2023 upstream capital investment will be approximately $2 billion. For additional detail on the Company’s forward capital investment outlook, refer to “Capital Resources and Liquidity” below.

In the third quarter of 2023, the Company reported net income attributable to common stock of $459 million, or $1.49 per diluted share, compared to net income of $422 million, or $1.28 per diluted share, in the third quarter of 2022. Results for the third quarter of 2022 were impacted by higher deferred income tax expense related to remeasurement of the Company’s deferred tax liability from increases in the U.K. energy profits levy.

In the first nine months of 2023, the Company reported net income attributable to common stock of $1.1 billion, or $3.50 per diluted share, compared to net income of $3.2 billion, or $9.51 per diluted share, in the first nine months of 2022. Net income for the first nine months of 2023 was impacted by lower revenues attributable to significantly lower realized commodity prices when compared to the first nine months of 2022. Results from the first nine months of 2022 included approximately $1.2 billion of transaction gains recognized for divesting certain non-core mineral rights in the Delaware Basin and completing the BCP Business Combination.

The Company generated $2.1 billion of cash from operating activities during the first nine months of 2023, 41 percent lower than the first nine months of 2022. APA’s lower operating cash flows for the first nine months of 2023 were driven by lower commodity prices and associated revenues and the timing of working capital items. The Company repurchased 5.5 million shares of its common stock for $208 million and paid $232 million in dividends to APA common stockholders during the first nine months of 2023.

The Company remains committed to its capital return framework established in 2021 for equity holders to participate more directly and materially in cash returns.

• The Company believes returning 60 percent of cash flow over capital investment creates a good balance for providing near-term cash returns to shareholders while still recognizing the importance of longer-term balance sheet strengthening.

• The Company’s quarterly dividend was increased in the third quarter of 2022 from $0.125 per share to $0.25 per share, representing a return to pre-COVID-19 dividend levels.

• Beginning in the fourth quarter of 2021 and through the end of the third quarter of 2023, the Company had repurchased 72.9 million shares of the Company’s common stock. The Company repurchased 0.4 million shares in October 2023, and as of October 31, 2023, the Company had remaining authorization to repurchase up to 46.7 million shares under the Company’s share repurchase programs.

Operational Highlights

Key operational highlights for the quarter include:

United States

*•*Daily boe production from the Company’s U.S. assets accounted for 55 percent of its total production during the third quarter of 2023. The Company averaged five drilling rigs in the U.S. during the quarter, including three rigs in the Southern Midland Basin and two rigs in the Delaware Basin, and drilled and brought online 15 operated wells in the quarter. The Company has contracted a sixth Permian Basin rig, with plans to commence drilling in the fourth quarter of 2023. The Company’s core Midland Basin development program and recently acquired properties in the Delaware Basin continue to represent key growth areas for the U.S. assets.

International

• In Egypt, the Company continued its drilling and workover activity with a heavier focus on oil prospects. The Company averaged 18 drilling rigs and drilled 26 new productive wells during the third quarter of 2023. Third quarter 2023 gross equivalent production in the Company’s Egypt assets increased 2 percent from the third quarter of 2022, and net production decreased 3 percent. The Company averaged 20 workover rigs during the quarter and expects to increase workover activity over the next two quarters.

• The Company suspended all new drilling activity in the North Sea during the second quarter of 2023. The Company’s investment program there is now directed toward safety, base production management, and asset maintenance and integrity.

• During the quarter, the Company and TotalEnergies announced the launch of development studies for a large oil project in Block 58, offshore Suriname. Successful appraisal of two key oil discoveries, with the drilling and testing of two wells at Sapakara South and three wells at Krabdagu, confirmed combined recoverable resources of an estimated 700 million barrels of oil for the two fields. These fields, located in water depths between 100 and 1,000 meters, are expected to be produced through a system of subsea wells connected to a floating production, storage and offloading unit located 150 kilometers off the Suriname coast, with an oil production capacity of 200,000 b/d. Detailed engineering studies are anticipated to start by year-end 2023, and a final investment decision is expected by year-end 2024 with a first production target in 2028. No additional drilling is anticipated on Block 58 through the end of 2024.

Results of Operations

Oil, Natural Gas, and Natural Gas Liquids Production Revenues

Revenue

The Company’s 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,
						2023												2022												2023												2022
						$ Value						% Contribution						$ Value						% Contribution						$ Value						% Contribution						$ Value						% Contribution
						($ in millions)
Oil Revenues:
United States						$	633					37		%				$	630					38		%				$	1,631					37		%				$	1,883					36		%
Egypt(1)						724						43		%				739						44		%				1,971						44		%				2,431						46		%
North Sea						348						20		%				303						18		%				865						19		%				938						18		%
Total(1)						$	1,705					100		%				$	1,672					100		%				$	4,467					100		%				$	5,252					100		%
Natural Gas Revenues:
United States						$	89					38		%				$	300					70		%				$	229					35		%				$	764					62		%
Egypt(1)						81						34		%				84						20		%				264						40		%				270						22		%
North Sea						66						28		%				44						10		%				165						25		%				207						16		%
Total(1)						$	236					100		%				$	428					100		%				$	658					100		%				$	1,241					100		%
NGL Revenues:
United States						$	133					96		%				$	197					98		%				$	356					95		%				$	615					94		%
Egypt(1)						—						—		%				—						—		%				—						—		%				6						1		%
North Sea						5						4		%				5						2		%				19						5		%				33						5		%
Total(1)						$	138					100		%				$	202					100		%				$	375					100		%				$	654					100		%
Oil and Gas Revenues:
United States						$	855					41		%				$	1,127					49		%				$	2,216					40		%				$	3,262					46		%
Egypt(1)						805						39		%				823						36		%				2,235						41		%				2,707						38		%
North Sea						419						20		%				352						15		%				1,049						19		%				1,178						16		%
Total(1)						$	2,079					100		%				$	2,302					100		%				$	5,500					100		%				$	7,147					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,
						2023						Increase (Decrease)						2022						2023						Increase (Decrease)						2022
Oil Volume (b/d)
United States						83,584						16%						72,351						77,198						12%						68,926
Egypt(1)(2)						88,521						9%						81,095						88,038						5%						83,857
North Sea						35,680						42%						25,160						36,070						17%						30,928
Total						207,785						16%						178,606						201,306						10%						183,711
Natural Gas Volume (Mcf/d)
United States						454,643						(7)%						489,107						448,838						(5)%						474,777
Egypt(1)(2)						300,326						(6)%						318,945						331,158						(5)%						350,400
North Sea						65,168						246%						18,822						47,665						43%						33,291
Total						820,137						(1)%						826,874						827,661						(4)%						858,468
NGL Volume (b/d)
United States						66,280						2%						64,958						61,418						(1)%						61,990
Egypt(1)(2)						—						NM						—						—						NM						261
North Sea						1,497						168%						558						1,209						12%						1,080
Total						67,777						3%						65,516						62,627						(1)%						63,331
BOE per day(3)
United States						225,639						3%						218,826						213,423						2%						210,045
Egypt(1)(2)						138,575						3%						134,253						143,231						1%						142,518
North Sea(4)						48,038						66%						28,855						45,222						20%						37,557
Total						412,252						8%						381,934						401,876						3%						390,120

(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,
						2023												2022						2023												2022
Oil (b/d)						144,528												133,607						141,995												136,476
Natural Gas (Mcf/d)						472,744												510,260						511,430												554,268
NGL (b/d)						—												—						—												397

(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,
						2023												2022						2023												2022
Oil (b/d)						29,514												27,082						29,369												27,971
Natural Gas (Mcf/d)						100,122												106,553						110,476												116,869
NGL (b/d)						—												—						—												87

(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 quarters of 2023 and 2022 were 55,283 boe/d and 36,467 boe/d, respectively, and 47,370 boe/d and 39,362 boe/d for the first nine months of 2023 and 2022, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.

NM — Not Meaningful

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,
						2023						Increase (Decrease)						2022						2023						Increase (Decrease)						2022
Average Oil Price – Per barrel
United States						$	82.33					(13)%						$	94.62					$	77.40					(23)%						$	100.06
Egypt						88.99						(10)%						99.04						82.04						(23)%						106.19
North Sea						87.70						(14)%						101.85						83.25						(21)%						105.59
Total						86.15						(12)%						97.81						80.50						(22)%						103.81
Average Natural Gas Price – Per Mcf
United States						$	2.12					(68)%						$	6.67					$	1.87					(68)%						$	5.89
Egypt						2.91						1%						2.87						2.92						4%						2.82
North Sea						10.98						(54)%						24.12						12.83						(48)%						24.59
Total						3.12						(44)%						5.62						2.91						(45)%						5.31
Average NGL Price – Per barrel
United States						$	21.87					(34)%						$	32.97					$	21.24					(42)%						$	36.36
Egypt						—						NM						—						—						NM						76.80
North Sea						42.78						(39)%						70.42						47.58						(35)%						72.86
Total						22.26						(33)%						33.39						21.85						(42)%						37.47

NM — Not Meaningful

Third-Quarter 2023 compared to Third-Quarter 2022

Crude Oil Crude oil revenues for the third quarter of 2023 totaled $1.7 billion, a $33 million increase from the comparative 2022 quarter. A 16 percent higher average daily production increased revenues by $233 million compared to the prior-year quarter, while 12 percent decrease in average realized prices decreased third-quarter 2023 oil revenues by $200 million. Crude oil revenues accounted for 82 percent of total oil and gas production revenues and 50 percent of worldwide production in the third quarter of 2023. Crude oil prices realized in the third quarter of 2023 averaged $86.15 per barrel, compared with $97.81 per barrel in the comparative prior-year quarter.

The Company’s worldwide oil production increased 29.2 Mb/d to 207.8 Mb/d during the third quarter of 2023 from the comparative prior-year period, primarily a result of increased drilling activity in the U.S. and Egypt, property acquisitions in the U.S., and prior year downtime for turnaround maintenance in the North Sea, partially offset by natural production decline across all assets.

Natural Gas Gas revenues for the third quarter of 2023 totaled $236 million, a $192 million decrease from the comparative 2022 quarter. A 44 percent decrease in average realized prices decreased third-quarter 2023 natural gas revenues by $191 million compared to the prior-year quarter, while 1 percent lower average daily production decreased revenues by $1 million. Natural gas revenues accounted for 11 percent of total oil and gas production revenues and 33 percent of worldwide production during the third quarter of 2023. The Company’s worldwide natural gas production decreased 6.8 MMcf/d to 820.1 MMcf/d during the third quarter of 2023 from the comparative prior-year period, primarily a result of natural production decline across all assets and the sale of non-core assets in the U.S., offset by increased drilling activity, recompletions, property acquisitions in the U.S., and prior year downtime for turnaround maintenance in the North Sea.

NGL NGL revenues for the third quarter of 2023 totaled $138 million, a $64 million decrease from the comparative 2022 quarter. A 33 percent decrease in average realized prices decreased third-quarter 2023 NGL revenues by $67 million compared to the prior-year quarter, while 3 percent higher average daily production increased revenues by $3 million. NGL revenues accounted for 7 percent of total oil and gas production revenues and 17 percent of worldwide production during the third quarter of 2023. The Company’s worldwide NGL production increased 2.3 Mb/d to 67.8 Mb/d during the third quarter of 2023 from the comparative prior-year period, primarily a result of increased drilling activity, recompletions, property acquisitions in the U.S., and prior year downtime for turnaround maintenance in the North Sea, partially offset by natural production decline.

Year-to-Date 2023 compared to Year-to-Date 2022

Crude Oil Crude oil revenues for the first nine months of 2023 totaled $4.5 billion, a $785 million decrease from the comparative 2022 period. A 22 percent decrease in average realized prices decreased oil revenues for the 2023 period by approximately $1.2 billion compared to the prior-year period, while 10 percent higher average daily production increased revenues by $394 million. Crude oil revenues accounted for 81 percent of total oil and gas production revenues and 50 percent of worldwide production for the first nine months of 2023. Crude oil prices realized during the first nine months of 2023 averaged $80.50 per barrel, compared to $103.81 per barrel in the comparative prior-year period.

The Company’s worldwide oil production increased 17.6 Mb/d to 201.3 Mb/d in the first nine months of 2023 compared to the prior-year period, primarily a result of property acquisitions in the U.S., increased drilling activity in the U.S. and Egypt, and less maintenance downtime in the North Sea, partially offset by natural production decline across all assets.

Natural Gas Gas revenues for the first nine months of 2023 totaled $658 million, a $583 million decrease from the comparative 2022 period. A 45 percent decrease in average realized prices decreased natural gas revenues for the 2023 period by $560 million compared to the prior-year period, while 4 percent lower average daily production decreased revenues by $23 million compared to the prior-year period. Natural gas revenues accounted for 12 percent of total oil and gas production revenues and 34 percent of worldwide production for the first nine months of 2023. The Company’s worldwide natural gas production decreased 30.8 MMcf/d to 827.7 MMcf/d in the first nine months of 2023 compared to the prior-year period, primarily a result of natural production decline across all assets and the sale of non-core assets in the U.S., partially offset by increased drilling activity, recompletions, property acquisitions in the U.S., and less maintenance downtime in the North Sea.

NGL NGL revenues for the first nine months of 2023 totaled $375 million, a $279 million decrease from the comparative 2022 period. A 42 percent decrease in average realized prices decreased NGL revenues for the 2023 period by $273 million compared to the prior-year period, while 1 percent lower average daily production decreased revenues by $6 million compared to the prior-year period. NGL revenues accounted for 7 percent of total oil and gas production revenues and 16 percent of worldwide production for the first nine months of 2023. The Company’s worldwide NGL production decreased 0.7 Mb/d to 63 Mb/d in the first nine months of 2023 compared to the prior-year period, primarily a result of natural production decline, partially offset by increased drilling activity, recompletions, property acquisitions in the U.S., and less maintenance downtime in the North Sea.

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 $229 million and $585 million during the third quarters of 2023 and 2022, respectively, and $612 million and $1.5 billion during the first nine months of 2023 and 2022, respectively. Purchased oil and gas sales were offset by associated purchase costs of $211 million and $573 million during the third quarters of 2023 and 2022, respectively, and $558 million and $1.5 billion during the first nine months of 2023 and 2022, respectively. Gross purchased oil and gas sales values were lower in the third quarter and the first nine months of 2023, primarily due to lower average natural gas prices during the 2023 periods.

Operating Expenses

The Company’s operating expenses were as follows:

						For the Quarter Ended September 30,												For the Nine Months Ended September 30,
						2023						2022						2023						2022
						(In millions)
Lease operating expenses						$	394					$	364					$	1,076					$	1,067
Gathering, processing, and transmission						89						99						245						274
Purchased oil and gas costs						211						573						558						1,452
Taxes other than income						61						82						163						230
Exploration						49						95						144						193
General and administrative						139						69						276						314
Transaction, reorganization, and separation						5						4						11						21
Depreciation, depletion, and amortization:
Oil and gas property and equipment						407						300						1,086						847
Gathering, processing, and transmission assets						2						4						5						10
Other assets						9						6						26						22
Asset retirement obligation accretion						29						29						86						87
Impairments						—						—						46						—
Financing costs, net						81						75						235						303
Total Operating Expenses						$	1,476					$	1,700					$	3,957					$	4,820

Lease Operating Expenses (LOE)

LOE increased $30 million and $9 million compared to the third quarter and the first nine months of 2022, respectively. On a per-unit basis, LOE remained essentially flat in the third quarter of 2023 when compared to the third quarter of 2022 and decreased 2 percent in the first nine months of 2023 when compared to the first nine months of 2022. Overall higher labor costs and other operating costs trending with global inflation drove an increase in absolute LOE, but these increases were primarily offset by decreased workover activity primarily in the North Sea and changes in foreign currency exchange rates against the US dollar.

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,
						2023						2022						2023						2022
						(In millions)
Third-party processing and transmission costs						$	63					$	71					$	164					$	205
Midstream service costs – ALTM						—						—						—						18
Midstream service costs – Kinetik						26						28						81						64
Upstream processing and transmission costs						89						99						245						287
Midstream operating expenses						—						—						—						5
Intersegment eliminations						—						—						—						(18)
Total Gathering, processing, and transmission						$	89					$	99					$	245					$	274

GPT costs decreased $10 million and $29 million in the third quarter and the first nine months of 2023, respectively, from the comparative prior-year period, primarily the result of lower upstream processing and transmission costs, partially offset by impacts of the BCP Business Combination. Upstream processing and transmission costs decreased $10 million and $42 million in the third quarter and the first nine months of 2023, respectively, from the comparative prior-year period, primarily driven by a decrease in natural gas production volumes when compared to the prior-year period. Costs for services provided by ALTM in 2022 prior to the BCP Business Combination totaling $18 million were eliminated in the Company’s consolidated financial statements and reflected as “Intersegment eliminations” in the table above. Subsequent to the BCP Business Combination and the Company’s deconsolidation of Altus on February 22, 2022, these midstream services continue to be provided by Kinetik Holdings Inc. (Kinetik) but are no longer eliminated.

Taxes Other Than Income

Taxes other than income decreased $21 million and $67 million from the third quarter and the first nine months of 2022, respectively, primarily from lower severance taxes driven by lower commodity prices as compared to the 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,
						2023						2022						2023						2022
						(In millions)
Unproved leasehold impairments						$	9					$	16					$	20					$	22
Dry hole expense						18						66						71						107
Geological and geophysical expense						1						1						3						19
Exploration overhead and other						21						12						50						45
Total Exploration						$	49					$	95					$	144					$	193

Exploration expenses decreased $46 million and $49 million from the third quarter and the first nine months of 2022, respectively, primarily the result of higher dry hole expense in Suriname and Egypt during 2022 coupled with lower geological and geophysical expenses. These decreases were partially offset by higher exploration overhead and other activities.

General and Administrative (G&A) Expenses

G&A expenses increased $70 million and decreased $38 million compared to the third quarter and the first nine months of 2022, respectively. The increase in expenses for the third quarter of 2023 compared to the third quarter of 2022 was primarily driven by higher cash-based stock compensation expense resulting from changes in the Company’s stock price and anticipated achievement of performance and financial objectives as defined in the stock award plans. G&A expenses for the first nine months of 2022 were higher than the first nine months of 2023, as impacts of anticipated achievement-based objectives and changes in the Company’s stock price on cash-based stock compensation were greater during the first nine months of 2022 than those in the first nine months of 2023.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs remained essentially flat in the third quarter of 2023 when compared to the third quarter of 2022 and decreased $10 million compared to the first nine months of 2022. Higher TRS costs during the first nine months of 2022 were primarily a result of transaction costs from the BCP Business Combination in the first quarter of 2022.

Depreciation, Depletion, and Amortization (DD&A)

Total DD&A expenses increased $108 million and $238 million from the third quarter and the first nine months of 2022, respectively, primarily driven by DD&A on the Company’s oil and gas properties. The Company’s DD&A rate on its oil and gas properties increased $2.17 per boe and $1.93 per boe from the third quarter and the first nine months of 2022, respectively, driven by general cost inflation. The increase on an absolute basis was also impacted by an increase in capital investment activity in Egypt and acquisitions in the U.S. over the past year.

Impairments

During the second quarter of 2023, the Company recorded $46 million of impairments in connection with valuations of drilling and operations equipment inventory upon the Company’s decision to suspend drilling operations in the North Sea.

Financing Costs, Net

The Company’s Financing costs were as follows:

						For the Quarter Ended September 30,												For the Nine Months Ended September 30,
						2023						2022						2023						2022
						(In millions)
Interest expense						$	89					$	80					$	266					$	249
Amortization of debt issuance costs						1						1						3						8
Capitalized interest						(7)						(5)						(18)						(13)
(Gain) loss on extinguishment of debt						—						—						(9)						67
Interest income						(2)						(1)						(7)						(8)
Total Financing costs, net						$	81					$	75					$	235					$	303

Net financing costs increased $6 million and decreased $68 million from the third quarter and the first nine months of 2022, respectively. The increase in costs during the third quarter of 2023 was primarily a result of interest expense on higher outstanding credit facility borrowings compared to the prior-year period. The decrease in costs during the first nine months of 2023 was primarily the result of losses incurred on the extinguishment of debt during the first nine months of 2022 and gains on extinguishment of debt in the first nine months of 2023, partially offset by interest expense on higher outstanding credit facility borrowings compared to the prior-year period.

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 2023, the Company’s effective income tax rate was primarily impacted by a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2023 year-to-date effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023 on January 10, 2023, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During the third quarter of 2022, the Company’s effective income tax rate was primarily impacted by a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of the Energy (Oil and Gas) Profits Levy Act of 2022 on July 14, 2022, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company’s 2022 year-to-date effective income tax rate was primarily impacted by the gain associated with deconsolidation of Altus, the gain on sale of certain non-core mineral rights in the Delaware Basin, a deferred tax expense related to the remeasurement of taxes in the U.K., and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.

On January 10, 2023, Finance Act 2023 was enacted, receiving Royal Assent, and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022, increasing the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, in the first quarter of 2023, the Company recorded a deferred tax expense of $174 million related to the remeasurement of the December 31, 2022 U.K. deferred tax liability.

On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (Corporate AMT) on applicable corporations with an average annual financial statement income that exceeds $1 billion for any three consecutive years preceding the tax year at issue. The Corporate AMT is effective for tax years beginning after December 31, 2022. The Company is continuing to evaluate the provisions of the IRA and awaits further guidance from the U.S. Treasury Department to properly assess the impact of these provisions on the Company. Under the existing guidance, the Company does not believe the IRA will have a material impact for 2023.

The Company has 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. However, given the Company’s current and anticipated future domestic earnings, the Company believes that there is a reasonable possibility that in the next 12 months sufficient positive evidence may become available to allow the Company to reach a conclusion that a significant portion of the U.S. valuation allowance will no longer be needed. A release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense, which could be material, for the period the release is recorded.

The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various states and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority.

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 sustained decreases 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 expects its full-year 2023 estimated upstream capital investment will be approximately $2 billion and remains committed to its capital return framework established in 2021 for equity holders to participate more directly and materially in cash returns through dividends and share repurchases.

The Company believes its available liquidity and capital resource alternatives, 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, share buy-back activity, 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 borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for other liquidity and capital resource needs, if required.

For additional information, refer to Part I, Items 1 and 2—Business and Properties, and Item 1A—Risk Factors, in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.

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,
						2023						2022
						(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities						$	2,099					$	3,530
Proceeds from revolving credit facilities, net						202						—
Proceeds from asset divestitures						29						778
Proceeds from sale of Kinetik shares						—						224
Total Sources of Cash and Cash Equivalents						2,330						4,532
Uses of Cash and Cash Equivalents:
Additions to upstream oil and gas property						$	1,747					$	1,168
Acquisition of Delaware Basin properties						24						563
Leasehold and property acquisitions						11						30
Payments on revolving credit facilities, net						—						22
Payments on Apache fixed-rate debt						65						1,370
Dividends paid to APA common stockholders						232						127
Distributions to noncontrolling interest – Egypt						154						237
Treasury stock activity, net						208						884
Deconsolidation of Altus cash and cash equivalents						—						143
Other, net						39						22
Total Uses of Cash and Cash Equivalents						2,480						4,566
Decrease in Cash and Cash Equivalents						$	(150)					$	(34)

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 during the first nine months of 2023 totaled $2.1 billion, down $1.4 billion from the first nine months of 2022, primarily the result of significantly lower commodity prices and associated revenues and timing of working capital items.

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 Revolving Credit Facilities, Net As of September 30, 2023, outstanding borrowings under the Company’s U.S. dollar denominated syndicated credit facility were $768 million, an increase of $202 million since December 31, 2022.

Proceeds from Asset Divestitures The Company received $29 million and $778 million in proceeds from the divestiture of certain non-core assets during the first nine months of 2023 and 2022, respectively. The Company also received $224 million of cash proceeds from the sale of four million of its shares in Kinetik during the first nine months of 2022. 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 $1.7 billion and $1.2 billion during the first nine months of 2023 and 2022, respectively. The increase in capital investment is reflective of the increase in the Company’s capital program that has gradually increased over the past year. The Company operated an average of approximately 24 drilling rigs during the first nine months of 2023, compared to an average of approximately 20 drilling rigs during the first nine months of 2022.

Acquisition of Delaware Basin Properties During the third quarter of 2022, the Company closed on the acquisition of oil and gas assets in the Delaware Basin for a total purchase price of $615 million after post-closing adjustments. Final cash settlements of $24 million were completed during the first nine months of 2023. Cash consideration paid during the first nine months of 2022 totaled $563 million.

Leasehold and Property Acquisitions During the first nine months of 2023 and 2022, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $11 million and $30 million, respectively.

Payments on Apache Fixed-Rate Debt During the nine months ended September 30, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the Company’s US dollar-denominated revolving credit facility.

During the nine months ended September 30, 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.

During the nine months ended September 30, 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of an aggregate $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.

On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility.

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

Dividends Paid to APA Common Stockholders The Company paid $232 million and $127 million during the first nine months of 2023 and 2022, respectively, for dividends on its common stock. During the third quarter of 2022, the Company’s Board of Directors approved an increase to its quarterly dividend from $0.125 to $0.25 per share.

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 $154 million and $237 million during the first nine months of 2023 and 2022, respectively, in cash distributions to Sinopec.

Treasury Stock Activity, net In the first nine months of 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share totaling $208 million, and as of September 30, 2023, the Company had remaining authorization to repurchase 47.1 million shares. In the first nine months of 2022, the Company repurchased 24.0 million shares at an average price of $36.78 per share totaling $884 million.

Liquidity

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

						September 30, 2023						December 31, 2022
						(In millions)
Cash and cash equivalents						$	95					$	245
Total debt – APA and Apache						5,584						5,453
Total equity						2,107						1,345
Available committed borrowing capacity under syndicated credit facilities						2,164						2,238

Cash and Cash Equivalents As of September 30, 2023, the Company had $95 million in cash and cash equivalents. 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, 2023, the Company had $5.6 billion in total debt outstanding, which consisted of notes and debentures of Apache, credit facility borrowings, and finance lease obligations. As of September 30, 2023, current debt included $2 million of finance lease obligations.

Committed Credit Facilities On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes that replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility).

• One agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). The Company may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

• The second agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to the Company’s two, one-year extension options.

In connection with the Company’s entry into the USD Agreement and the GBP Agreement (each, a New Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under the USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a New Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache may borrow under the USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.

As of September 30, 2023, there were $768 million of borrowings under the USD Agreement and an aggregate £572 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2023, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2022, there were $566 million of borrowings and a $20 million letter of credit outstanding under the USD Agreement, and an aggregate £652 million in letters of credit outstanding under the GBP Agreement. The 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.

Uncommitted Credit Facilities Each of the Company and 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, 2023 and December 31, 2022, there were no outstanding borrowings under these facilities. As of September 30, 2023 there were £185 million and $3 million in letters of credit outstanding under these facilities. As of December 31, 2022, there were £199 million and $17 million in letters of credit outstanding under these facilities.

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 that may not be recorded on the Company’s consolidated balance sheet. For more information regarding these and other contractual arrangements, please refer to “Contractual Obligations” in Part II, Item 7 of APA’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. 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. The Company has divested various leases, wells, and facilities located in the Gulf of Mexico (GOM) where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser of such GOM assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, APA’s subsidiaries could be required to perform such actions under applicable federal laws and regulations. In such event, such 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 trust agreement and one of the NPIs to consolidate the trusts into a single Trust (Trust A) funded by both remaining NPIs. Following the 2018 reorganization of Fieldwood, Apache held two bonds (Bonds) and five Letters of Credit securing 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 the operation of GOM Shelf and the decommissioning of Legacy GOM Assets.

By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders on the other Legacy GOM Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOM Assets that were not included in GOM Shelf’s notification letters. 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 of September 30, 2023, Apache has incurred $692 million in decommissioning costs related to several Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will not, reimburse Apache for these decommissioning costs. As a result, Apache has sought and will continue to seek reimbursement from its security for these costs, of which $288 million had been reimbursed from Trust A and $87 million has been reimbursed from the Letters of Credit as of September 30, 2023. If GOM Shelf does not reimburse Apache for further decommissioning costs incurred with respect to Legacy GOM Assets, then Apache will continue to seek reimbursement from Trust A, to the extent of available funds, and thereafter, will seek further reimbursement from the Bonds and the Letters of Credit until all such funds and securities are fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the Legacy GOM Assets.

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

As of September 30, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $695 million to $895 million on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has recorded a contingent liability of $695 million as of September 30, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on Legacy GOM Assets. Of the total liability recorded, $470 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $225 million is reflected under “Other current liabilities” in the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued.

As of September 30, 2023, the Company has also recorded a $411 million asset, which represents the remaining amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $38 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $373 million is reflected under “Other current assets.”

Critical Accounting Estimates

The Company prepares its financial statements and accompanying notes in conformity with accounting principles generally accepted in the U.S., which require management to make estimates and assumptions about future events that affect reported amounts in the financial statements and the accompanying notes. The Company identifies certain accounting policies involving estimation as critical accounting estimates based on, among other things, their impact on the portrayal of the Company’s financial condition, results of operations, or liquidity, as well as the degree of difficulty, subjectivity, and complexity in their deployment. Critical accounting estimates address accounting matters that are inherently uncertain due to unknown future resolution of such matters. Management routinely discusses the development, selection, and disclosure of each critical accounting estimate. For a discussion of the Company’s most critical accounting estimates, please see the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022. Some of the more significant estimates include reserve estimates, oil and gas exploration costs, offshore decommissioning contingency, long-lived asset impairments, asset retirement obligations, and income taxes.

New Accounting Pronouncements

There were no material changes in recently issued or adopted accounting standards from those disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022.