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 the conflict in Ukraine 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. For additional detail on the Company’s forward capital investment outlook, refer to “Capital Resources and Liquidity” below.

In the second quarter of 2023, the Company reported net income attributable to common stock of $381 million, or $1.23 per diluted share, compared to net income of $926 million, or $2.71 per diluted share, in the second quarter of 2022. Net income for the second quarter of 2023 was impacted by lower revenues attributable to significantly lower realized commodity prices when compared to the prior-year period.

The Company generated $1.3 billion of cash from operating activities during the first six months of 2023, 45 percent lower than the first six months of 2022. APA’s lower operating cash flows for the first six months of 2023 were driven by lower commodity prices and associated revenues and the timing of working capital items. The Company repurchased 5 million shares of its common stock for $188 million and paid $155 million in dividends to APA common stockholders during the first six 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 second quarter of 2023, the Company has repurchased 72.4 million shares of the Company’s common stock. As of June 30, 2023, the Company had remaining authorization to repurchase up to 48 million shares under the Company’s share repurchase programs.

APA’s diverse asset portfolio and operational flexibility provide it the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. In response to prevailing weakness in Waha natural gas and NGL prices, the Company is deferring additional drilling and completion activity at Alpine High until prices can support sustainable returns that are competitive within APA’s global portfolio. The Company also announced the suspension of drilling activity in the North Sea with increasing cost and tax burdens impacting the competitiveness of these assets within the Company’s portfolio. Accordingly, the Company has reduced planned full-year upstream capital investment to approximately $1.9 billion.

Operational Highlights

Key operational highlights for the quarter include:

United States

*•*Daily boe production from the Company’s U.S. assets accounted for 53 percent of its total production during the second quarter of 2023. The Company averaged five drilling rigs in the U.S. during the quarter, including two rigs in the Southern Midland Basin and three rigs in the Delaware Basin, and drilled and brought online 21 operated wells in the quarter. Two-thirds of those wells came online in June, so the full impact will be realized in the third quarter. The Company’s core Midland Basin development program and recently acquired properties in the Texas Delaware Basin continue to represent key growth areas for the U.S. assets.

International

• In Egypt, the Company averaged 17 drilling rigs and drilled 19 new productive wells during the second quarter of 2023. Second quarter 2023 gross equivalent production in the Company’s Egypt assets decreased 3 percent from the second quarter of 2022, and net production remained relatively flat. The Company has increased drilling and workover activity with a heavier focus on oil prospects and anticipates increases in gross oil production volumes throughout the remainder of the year as it maintains a steady operational cadence.

• The Company suspended all new drilling activity in the North Sea during the second quarter of 2023. The Company will manage its base production and maximize economic recovery of its oil and gas wells through well intervention activities.

• Suriname activity is focused on completing the Krabdagu appraisal program and scoping an oil hub project to develop the combined Sapakara and Krabdagu resource in Block 58. Testing has been completed at the Krabdagu-2 appraisal well, and data collection is ongoing at the Krabdagu-3 appraisal well. The semi-submersible rig currently on location will be released upon completion of operations, as the Company believes no additional appraisal or exploratory drilling is necessary in the Krabdagu area at this time.

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 June 30,																								For the Six Months Ended June 30,
						2023												2022												2023												2022
						$ Value						% Contribution						$ Value						% Contribution						$ Value						% Contribution						$ Value						% Contribution
						($ in millions)
Oil Revenues:
United States						$	512					38		%				$	654					35		%				$	998					36		%				$	1,253					35		%
Egypt(1)						618						45		%				902						48		%				1,247						45		%				1,692						47		%
North Sea						235						17		%				307						17		%				517						19		%				635						18		%
Total(1)						$	1,365					100		%				$	1,863					100		%				$	2,762					100		%				$	3,580					100		%
Natural Gas Revenues:
United States						$	51					28		%				$	281					65		%				$	140					33		%				$	464					57		%
Egypt(1)						90						50		%				88						20		%				183						43		%				186						23		%
North Sea						39						22		%				64						15		%				99						24		%				163						20		%
Total(1)						$	180					100		%				$	433					100		%				$	422					100		%				$	813					100		%
NGL Revenues:
United States						$	103					96		%				$	214					93		%				$	223					94		%				$	418					92		%
Egypt(1)						—						0		%				3						1		%				—						0		%				6						2		%
North Sea						4						4		%				12						6		%				14						6		%				28						6		%
Total(1)						$	107					100		%				$	229					100		%				$	237					100		%				$	452					100		%
Oil and Gas Revenues:
United States						$	666					40		%				$	1,149					46		%				$	1,361					40		%				$	2,135					44		%
Egypt(1)						708						43		%				993						39		%				1,430						42		%				1,884						39		%
North Sea						278						17		%				383						15		%				630						18		%				826						17		%
Total(1)						$	1,652					100		%				$	2,525					100		%				$	3,421					100		%				$	4,845					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 June 30,																		For the Six Months Ended June 30,
						2023						Increase (Decrease)						2022						2023						Increase (Decrease)						2022
Oil Volume (b/d)
United States						75,993						17%						64,759						73,952						10%						67,184
Egypt(1)(2)						87,790						3%						85,502						87,792						3%						85,261
North Sea						35,048						8%						32,493						36,268						7%						33,860
Total						198,831						9%						182,754						198,012						6%						186,305
Natural Gas Volume (Mcf/d)
United States						450,200						(2)%						457,459						445,887						(5)%						467,493
Egypt(1)(2)						337,413						(3)%						346,424						346,829						(5)%						366,390
North Sea						37,194						(13)%						42,802						38,769						(5)%						40,645
Total						824,807						(3)%						846,685						831,485						(5)%						874,528
NGL Volume (b/d)
United States						61,760						4%						59,267						58,947						(3)%						60,482
Egypt(1)(2)						—						NM						297						—						NM						394
North Sea						872						(27)%						1,195						1,062						(21)%						1,345
Total						62,632						3%						60,759						60,009						(4)%						62,221
BOE per day(3)
United States						212,786						6%						200,269						207,213						1%						205,582
Egypt(1)(2)						144,026						0%						143,536						145,597						(1)%						146,720
North Sea(4)						42,118						3%						40,822						43,792						4%						41,979
Total						398,930						4%						384,627						396,602						1%						394,281

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

						For the Quarter Ended June 30,																		For the Six Months Ended June 30,
						2023												2022						2023												2022
Oil (b/d)						140,652												141,432						140,708												137,934
Natural Gas (Mcf/d)						517,291												555,694						531,093												576,637
NGL (b/d)						—												464						—												599

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

						For the Quarter Ended June 30,																		For the Six Months Ended June 30,
						2023												2022						2023												2022
Oil (b/d)						29,298												28,516						29,296												28,423
Natural Gas (Mcf/d)						112,609												115,534						115,738												122,112
NGL (b/d)						—												99						—												131

(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 second quarters of 2023 and 2022 were 40,099 boe/d and 38,029 boe/d, respectively, and 43,347 boe/d and 40,833 boe/d for the first six 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 June 30,																		For the Six Months Ended June 30,
						2023						Increase (Decrease)						2022						2023						Increase (Decrease)						2022
Average Oil Price – Per barrel
United States						$	73.99					(33)%						$	110.98					$	74.56					(28)%						$	103.05
Egypt						77.39						(33)%						115.97						78.48						(28)%						109.65
North Sea						79.27						(30)%						113.77						80.51						(25)%						107.47
Total						76.38						(33)%						113.79						77.37						(28)%						106.87
Average Natural Gas Price – Per Mcf
United States						$	1.24					(82)%						$	6.75					$	1.73					(68)%						$	5.48
Egypt						2.95						6%						2.78						2.92						4%						2.80
North Sea						11.29						(38)%						18.15						14.47						(41)%						24.72
Total						2.39						(58)%						5.65						2.81						(46)%						5.16
Average NGL Price – Per barrel
United States						$	18.26					(54)%						$	39.79					$	20.88					(45)%						$	38.20
Egypt						—						NM						75.14						—						NM						76.80
North Sea						39.24						(45)%						71.71						49.52						(32)%						73.29
Total						18.69						(54)%						40.97						21.62						(45)%						39.63

NM — Not Meaningful

Second-Quarter 2023 compared to Second-Quarter 2022

Crude Oil Crude oil revenues for the second quarter of 2023 totaled $1.4 billion, a $498 million decrease from the comparative 2022 quarter. A 33 percent decrease in average realized prices decreased second-quarter 2023 oil revenues by $613 million compared to the prior-year quarter, while 9 percent higher average daily production increased revenues by $115 million. Crude oil revenues accounted for 83 percent of total oil and gas production revenues and 50 percent of worldwide production in the second quarter of 2023. Crude oil prices realized in the second quarter of 2023 averaged $76.38 per barrel, compared with $113.79 per barrel in the comparative prior-year quarter.

The Company’s worldwide oil production increased 16.1 Mb/d to 198.8 Mb/d during the second quarter of 2023 from the comparative prior-year period, primarily a result of property acquisitions in the U.S., increased drilling activity, and recompletions, partially offset by natural production decline across all assets.

Natural Gas Gas revenues for the second quarter of 2023 totaled $180 million, a $253 million decrease from the comparative 2022 quarter. A 58 percent decrease in average realized prices decreased second-quarter 2023 natural gas revenues by $249 million compared to the prior-year quarter, while 3 percent lower average daily production decreased revenues by $4 million. Natural gas revenues accounted for 11 percent of total oil and gas production revenues and 34 percent of worldwide production during the second quarter of 2023. The Company’s worldwide natural gas production decreased 21.9 MMcf/d to 824.8 MMcf/d during the second quarter of 2023 from the comparative prior-year period, primarily a result of natural production decline across all assets and sale of non-core assets in the U.S., partially offset by increased drilling activity, recompletions, and property acquisitions in the U.S.

NGL NGL revenues for the second quarter of 2023 totaled $107 million, a $122 million decrease from the comparative 2022 quarter. A 54 percent decrease in average realized prices decreased second-quarter 2023 NGL revenues by $125 million compared to the prior-year quarter, while 3 percent higher average daily production increased revenues by $3 million. NGL revenues accounted for 6 percent of total oil and gas production revenues and 16 percent of worldwide production during the second quarter of 2023. The Company’s worldwide NGL production increased 1.9 Mb/d to 62.6 Mb/d during the second quarter of 2023 from the comparative prior-year period, primarily a result of increased drilling activity, recompletions, and property acquisitions in the U.S., partially offset by natural production decline.

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

Crude Oil Crude oil revenues for the first six months of 2023 totaled $2.8 billion, an $818 million decrease from the comparative 2022 period. A 28 percent decrease in average realized prices decreased oil revenues for the 2023 period by $988 million compared to the prior-year period, while 6 percent higher average daily production increased revenues by $170 million. Crude oil revenues accounted for 81 percent of total oil and gas production revenues and 50 percent of worldwide production for the first six months of 2023. Crude oil prices realized during the first six months of 2023 averaged $77.37 per barrel, compared to $106.87 per barrel in the comparative prior-year period.

The Company’s worldwide oil production increased 11.7 Mb/d to 198.0 Mb/d in the first six months of 2023 compared to the prior-year period, primarily a result of property acquisitions in the U.S., increased drilling activity, and recompletions, partially offset by natural production decline across all assets.

Natural Gas Gas revenues for the first six months of 2023 totaled $422 million, a $391 million decrease from the comparative 2022 period. A 46 percent decrease in average realized prices decreased natural gas revenues for the 2023 period by $371 million compared to the prior-year period, while 5 percent lower average daily production decreased revenues by $20 million compared to the prior-year period. Natural gas revenues accounted for 12 percent of total oil and gas production revenues and 35 percent of worldwide production for the first six months of 2023. The Company’s worldwide natural gas production decreased 43.0 MMcf/d to 831.5 MMcf/d in the first six months of 2023 compared to the prior-year period, primarily a result of natural production decline across all assets and sale of non-core assets in the U.S., partially offset by increased drilling activity, recompletions, and property acquisitions in the U.S.

NGL NGL revenues for the first six months of 2023 totaled $237 million, a $215 million decrease from the comparative 2022 period. A 45 percent decrease in average realized prices decreased NGL revenues for the 2023 period by $205 million compared to the prior-year period, while 4 percent lower average daily production decreased revenues by $10 million compared to the prior-year period. NGL revenues accounted for 7 percent of total oil and gas production revenues and 15 percent of worldwide production for the first six months of 2023. The Company’s worldwide NGL production decreased 2.2 Mb/d to 60 Mb/d in the first six months of 2023 compared to the prior-year period, primarily a result of natural production decline, partially offset by increased drilling activity, recompletions, and property acquisitions in the U.S.

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 $144 million and $522 million during the second quarters of 2023 and 2022, respectively, and $383 million and $871 million during the first six months of 2023 and 2022, respectively. Purchased oil and gas sales were offset by associated purchase costs of $131 million and $528 million during the second quarters of 2023 and 2022, respectively, and $347 million and $879 million during the first six months of 2023 and 2022, respectively. Gross purchased oil and gas sales values were lower in the second quarter and the first six 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 June 30,												For the Six Months Ended June 30,
						2023						2022						2023						2022
						(In millions)
Lease operating expenses						$	361					$	359					$	682					$	703
Gathering, processing, and transmission						78						94						156						175
Purchased oil and gas costs						131						528						347						879
Taxes other than income						50						78						102						148
Exploration						43						56						95						98
General and administrative						72						89						137						245
Transaction, reorganization, and separation						2						3						6						17
Depreciation, depletion, and amortization:
Oil and gas property and equipment						354						269						679						547
Gathering, processing, and transmission assets						1						1						3						6
Other assets						12						8						17						16
Asset retirement obligation accretion						29						29						57						58
Impairments						46						—						46						—
Financing costs, net						82						76						154						228
Total Operating Expenses						$	1,261					$	1,590					$	2,481					$	3,120

Lease Operating Expenses (LOE)

LOE remained essentially flat in the second quarter of 2023 when compared to the second quarter of 2022 and decreased $21 million in the first six months of 2023 when compared to the first six months of 2022. On a per-unit basis, LOE decreased 3 percent and 4 percent in the second quarter and the first six months of 2023, respectively, from the comparative prior-year period. The decrease was primarily driven by the impact from changes in foreign currency exchange rates against the US dollar, decreased workover activity, primarily in the North Sea, and mark-to-market adjustments for cash-based stock compensation expense resulting from changes in the Company’s stock price. These decreases were offset by overall higher labor costs and chemical and other operating costs trending with global inflation.

Gathering, Processing, and Transmission (GPT)

The Company’s GPT expenses were as follows:

						For the Quarter Ended June 30,												For the Six Months Ended June 30,
						2023						2022						2023						2022
						(In millions)
Third-party processing and transmission costs						$	49					$	68					$	101					$	134
Midstream service costs – ALTM						—						—						—						18
Midstream service costs – Kinetik						29						26						55						36
Upstream processing and transmission costs						78						94						156						188
Midstream operating expenses						—						—						—						5
Intersegment eliminations						—						—						—						(18)
Total Gathering, processing, and transmission						$	78					$	94					$	156					$	175

GPT costs decreased $16 million and $19 million in the second quarter and the first six 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 $16 million and $32 million in the second quarter and the first six 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 the first six months of 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 $28 million and $46 million from the second quarter and the first six 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 June 30,												For the Six Months Ended June 30,
						2023						2022						2023						2022
						(In millions)
Unproved leasehold impairments						$	6					$	2					$	11					$	6
Dry hole expense						23						36						53						41
Geological and geophysical expense						1						3						2						18
Exploration overhead and other						13						15						29						33
Total Exploration						$	43					$	56					$	95					$	98

Exploration expenses decreased $13 million from the second quarter of 2022, primarily the result of higher dry hole expense in Suriname during the second quarter of 2022. Exploration expenses decreased $3 million from the first six months of 2022, primarily the result of lower geological and geophysical expense and exploration overhead during the second quarter of 2023, partially offset by higher dry hole expense from increased Egypt exploration activity during 2023.

General and Administrative (G&A) Expenses

G&A expenses decreased $17 million and $108 million compared to the second quarter and the first six months of 2022, respectively. The decrease in expenses for the second quarter and the first six months of 2023 compared to the prior-year period was primarily driven by lower cash-based stock compensation expense resulting from changes in the Company’s stock price.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs remained essentially flat compared to the second quarter of 2022 and decreased $11 million compared to the first six months of 2022. The decrease in costs during the first six months of 2023 compared to the prior-year period was primarily a result of transaction costs from the BCP Business Combination in the first quarter of 2022.

Depreciation, Depletion, and Amortization (DD&A)

DD&A expenses on the Company’s oil and gas properties increased $85 million and $132 million from the second quarter and the first six months of 2022, respectively. The Company’s DD&A rate on its oil and gas properties increased $2.09 per boe and $1.79 per boe from the second quarter and the first six 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 three and six months ended June 30, 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 June 30,												For the Six Months Ended June 30,
						2023						2022						2023						2022
						(In millions)
Interest expense						$	89					$	79					$	177					$	169
Amortization of debt issuance costs						1						5						2						7
Capitalized interest						(5)						(5)						(11)						(8)
(Gain) loss on extinguishment of debt						—						—						(9)						67
Interest income						(3)						(3)						(5)						(7)
Total Financing costs, net						$	82					$	76					$	154					$	228

Net financing costs increased $6 million and decreased $74 million from the second quarter and the first six months of 2022, respectively. The increase in costs during the second 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 six months of 2023 was primarily the result of losses incurred on the extinguishment of debt during the first six months of 2022 and gains on extinguishment of debt in the first six months of 2023.

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 second 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 second quarter of 2022, 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 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, 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 within 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 to be approximately $1.9 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 Six Months Ended June 30,
						2023						2022
						(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by operating activities						$	1,335					$	2,426
Proceeds from revolving credit facilities, net						196						—
Proceeds from asset divestitures						28						751
Proceeds from sale of Kinetik shares						—						224
Total Sources of Cash and Cash Equivalents						1,559						3,401
Uses of Cash and Cash Equivalents:
Additions to upstream oil and gas property						$	1,119					$	741
Leasehold and property acquisitions						10						26
Payments on revolving credit facilities, net						—						267
Payments on Apache fixed-rate debt						65						1,370
Dividends paid to APA common stockholders						155						86
Distributions to noncontrolling interest – Egypt						100						159
Treasury stock activity, net						188						552
Deconsolidation of Altus cash and cash equivalents						—						143
Other, net						25						77
Total Uses of Cash and Cash Equivalents						1,662						3,421
Decrease in Cash and Cash Equivalents						$	(103)					$	(20)

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 six months of 2023 totaled $1.3 billion, down $1.1 billion from the first six 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 June 30, 2023, outstanding borrowings under the Company’s U.S. dollar denominated syndicated credit facility were $762 million, an increase of $196 million since December 31, 2022.

Proceeds from Asset Divestitures The Company received $28 million and $751 million in proceeds from the divestiture of certain non-core assets during the first six 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 six 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 $1.1 billion and $741 million during the first six 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 six months of 2023, compared to an average of approximately 19 drilling rigs during the first six months of 2022.

Leasehold and Property Acquisitions During the first six months of 2023 and 2022, the Company completed leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $10 million and $26 million, respectively.

Payments on Apache Fixed-Rate Debt During the six months ended June 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 six months ended June 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 six months ended June 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 $155 million and $86 million during the first six 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 $100 million and $159 million during the first six months of 2023 and 2022, respectively, in cash distributions to Sinopec.

Treasury Stock Activity, net In the first six months of 2023, the Company repurchased 5 million shares at an average price of $37.53 per share totaling $188 million, and as of June 30, 2023, the Company had remaining authorization to repurchase 48 million shares. In the first six months of 2022, the Company repurchased 14.2 million shares at an average price of $38.79 per share totaling $552 million.

Liquidity

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

						June 30, 2023						December 31, 2022
						(In millions)
Cash and cash equivalents						$	142					$	245
Total debt – APA and Apache						5,576						5,453
Total equity						1,696						1,345
Available committed borrowing capacity under syndicated credit facilities						2,194						2,238

Cash and Cash Equivalents As of June 30, 2023, the Company had $142 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 June 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 June 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 June 30, 2023, there were $762 million of borrowings under the USD Agreement and an aggregate £590 million in letters of credit outstanding under the GBP Agreement. As of June 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 Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of June 30, 2023 and December 31, 2022, there were no outstanding borrowings under these facilities. As of June 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. 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.

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 June 30, 2023, Apache has incurred $464 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 $276 million had been reimbursed from Trust A as of June 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 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 June 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 $922 million to $1.1 billion 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 $922 million as of June 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, $472 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $450 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 June 30, 2023, the Company has also recorded a $507 million asset, which represents the amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the Letters of Credit for decommissioning it may be required to perform on Legacy GOM Assets. Of the total asset recorded, $57 million is reflected under the caption “Decommissioning security for sold Gulf of Mexico properties,” and $450 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.