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, 2023.

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 has oil and gas 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 Uruguay 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.

APA believes energy underpins global progress, and the Company wants to be a part of the 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.

Uncertainties in the global supply chain and financial markets, including the impact of ongoing international conflicts, inflation, and actions taken by foreign oil and gas producing nations, including OPEC+, 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 invest for long-term returns in pursuit of moderate, sustainable production growth; (2) to strengthen the balance sheet to underpin the generation of 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; and (3) to responsibly manage its cost structure regardless of the oil price environment.

The Company closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process. APA's diversified asset portfolio and operational flexibility provide the Company the ability to timely respond to near-term price volatility and effectively manage its investment programs accordingly. For additional detail on the Company's forward capital investment outlook, refer to "Capital Resources and Liquidity" below.

The Company remains committed to its capital return framework 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 pays a quarterly dividend of $0.25 per share on its common stock.

•Beginning in the fourth quarter of 2021 and through the end of the third quarter of 2024, the Company has repurchased 80.7 million shares of the Company's common stock.

Financial and Operational Highlights

On April 1, 2024, APA completed its acquisition of Callon Petroleum Company (Callon) in an all-stock transaction valued at approximately $4.5 billion, inclusive of Callon's debt (the Callon acquisition). The acquired assets include approximately 120,000 net acres in the Delaware Basin and 25,000 net acres in the Midland Basin. The Company believes the acquisition of Callon provides opportunities to reduce costs, improve capital efficiencies, leverage economies of scale, and expand the development inventory that formed the basis of the transaction value.

Subject to the terms of the merger agreement (Merger Agreement), each share of Callon common stock was converted into the right to receive 1.0425 shares of APA common stock, with cash in lieu of fractional shares. As a result, APA issued approximately 70 million shares of APA common stock in connection with the transaction, and following the acquisition, Callon common stock is no longer listed for trading on the NYSE.

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On September 10, 2024, APA announced it entered into an agreement to sell non-core producing properties in the Permian Basin to an undisclosed buyer for $950 million, prior to customary closing adjustments. The properties are located in the Central Basin Platform, Texas and New Mexico Shelf, and Northwest Shelf and currently represent estimated net production of 21,000 barrels of oil equivalent per day, of which approximately 57 percent is oil. Proceeds from this sale are expected to be used primarily to reduce debt. The effective date of the transaction is July 1, 2024, and the transaction is expected to close during the fourth quarter of 2024.

In the third quarter of 2024, the Company reported a net loss attributable to common stock of $223 million, or $0.60 per diluted share, compared to net income of $459 million, or $1.49 per diluted share, in the third quarter of 2023. The decrease in net income in the third quarter of 2024 compared to the third quarter of 2023 was primarily driven by $1.1 billion of impairments, which included $793 million of oil and gas property impairments in the North Sea, a $315 million impairment of assets held for sale in the Permian Basin, and $3 million inventory impairments in the North Sea. These impacts to net loss were partially offset by lower income tax expense compared to the same prior-year period.

In the first nine months of 2024, the Company reported net income attributable to common stock of $450 million, or $1.29 per diluted share, compared to net income of $1.1 billion, or $3.50 per diluted share, in the first nine months of 2023. The decrease in net income in the first nine months of 2024 compared to the first nine months of 2023 was primarily driven by $1.1 billion of impairments recorded during the third quarter of 2024 and the related tax impacts. Net income was further impacted by higher depreciation expense, transaction and reorganization costs, and lease operating expenses, primarily a result of the Callon acquisition. These impacts to net income were partially offset by higher revenues as a result of increased drilling activity in the Permian Basin, production from the acquired Callon properties, gain from divestitures of non-core assets, and lower income tax expense compared to the same prior-year period.

The Company generated $2.6 billion of cash from operating activities during the first nine months of 2024, 23 percent higher than the first nine months of 2023. APA's higher operating cash flows for the first nine months of 2024 were primarily driven by higher revenues as a result of increased drilling activity in the Permian Basin, production from the acquired Callon properties, and timing of working capital items. The Company repurchased 4.6 million shares of its common stock for $146 million and paid $260 million in dividends to APA common stockholders during the first nine months of 2024.

Key operational highlights include:

United States

•Daily boe production from the Company's U.S. assets accounted for 64 percent of its total production during the third quarter of 2024 and increased 33 percent from the third quarter of 2023. Daily oil production from the Company's U.S. assets increased 71 percent from the third quarter of 2023. During the third quarter of 2024, the Company averaged nine drilling rigs in the Permian Basin, including five rigs in the Southern Midland Basin and four rigs in the Delaware Basin. The Company brought online 48 operated wells during the quarter, of which 21 wells were associated with the Callon assets. The Company's core Permian Basin development program continues to represent key growth areas for the U.S. assets. The Company expects to average 8 drilling rigs in the Permian Basin for the remainder of 2024 and into 2025.

International

•In Egypt, the Company continued its drilling and workover activity with a focus on oil production. The Company averaged 12 drilling rigs and drilled 15 new productive wells during the third quarter of 2024. During the same period, the Company averaged 20 workover rigs as it continues to align its drilling and workover activity with a goal of driving improved capital efficiency. Third quarter 2024 gross production from the Company's Egypt assets decreased 5 percent from the third quarter of 2023, and net production increased 2 percent.

•Subsequent to September 30, 2024, but prior to the date of this filing, the Company entered into a new pricing agreement for incremental gas volumes produced in Egypt, making gas exploration and development more economically competitive with oil development.

•The Company suspended all new drilling activity in the North Sea during the second quarter of 2023. During the third quarter of 2024, the Company continued its economic assessment of its North Sea assets in light of several new regulatory guidelines and obligations surrounding significant tax levies and modernization of aging infrastructure. The Company determined the expected returns do not economically support making investments required under the combined impact of the regulations, and it will cease production at its facilities in the North Sea prior to 2030. The Company's investment program in the North Sea is now directed toward asset safety and integrity.

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•In October 2024, the Company announced that its subsidiary reached a positive final investment decision for the first oil development, named GranMorgu, in Block 58 offshore Suriname. This development will include production from the Krabdagu and Sapakara oil discoveries. These fields, located in water depths between 100 and 1,000 meters, will be produced through a system of subsea wells connected to a floating production, storage and offloading (FPSO) unit located 150 km off the Suriname coast, with an oil production capacity of 220,000 barrels per day. The GranMorgu FPSO unit is designed to accommodate future tie-back opportunities that would extend its 4-year production plateau and will feature technology that minimizes greenhouse gas emissions. Total investment is estimated at $10.5 billion, with APA's share of the investment subject to the existing agreement with TotalEnergies to carry a portion of Apache's appraisal and development capital. First oil is anticipated in 2028.

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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,

2024202320242023

$ Value%Contribution$ Value%Contribution$ Value%Contribution$ Value%Contribution

($ in millions)

Oil Revenues:

United States$1,007 56 %$633 37 %$2,616 51 %$1,631 37 %

Egypt(1)

673 37 %724 43 %2,003 39 %1,971 44 %

North Sea117 7 %348 20 %517 10 %865 19 %

Total(1)

$1,797 100 %$1,705 100 %$5,136 100 %$4,467 100 %

Natural Gas Revenues:

United States$7 7 %$89 38 %$79 19 %$229 35 %

Egypt(1)

81 79 %81 34 %231 56 %264 40 %

North Sea15 14 %66 28 %104 25 %165 25 %

Total(1)

$103 100 %$236 100 %$414 100 %$658 100 %

NGL Revenues:

United States$153 97 %$133 96 %$436 95 %$356 95 %

North Sea5 3 %5 4 %21 5 %19 5 %

Total(1)

$158 100 %$138 100 %$457 100 %$375 100 %

Oil and Gas Revenues:

United States$1,167 56 %$855 41 %$3,131 52 %$2,216 40 %

Egypt(1)

754 37 %805 39 %2,234 37 %2,235 41 %

North Sea137 7 %419 20 %642 11 %1,049 19 %

Total(1)

$2,058 100 %$2,079 100 %$6,007 100 %$5,500 100 %

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

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Production

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

For the Quarter Ended

September 30,

For the Nine Months Ended

September 30,

2024Increase(Decrease)20232024Increase(Decrease)2023

Oil Volume (b/d)

United States143,299 71%83,584 122,138 58%77,198

Egypt(1)(2)

91,673 4%88,521 88,725 1%88,038

North Sea21,334 (40)%35,680 25,888 (28)%36,070

Total256,306 23%207,785 236,751 18%201,306

Natural Gas Volume (Mcf/d)

United States467,615 3%454,643 473,997 6%448,838

Egypt(1)(2)

300,418 0%300,326 287,953 (13)%331,158

North Sea18,911 (71)%65,168 41,042 (14)%47,665

Total786,944 (4)%820,137 802,992 (3)%827,661

NGL Volume (b/d)

United States79,474 20%66,280 71,690 17%61,418

North Sea543 (64)%1,497 1,164 (4)%1,209

Total80,017 18%67,777 72,854 16%62,627

BOE per day(3)

United States300,709 33%225,639 272,827 28%213,423

Egypt(1)(2)

141,742 2%138,575 136,718 (5)%143,231

North Sea(4)

25,029 (48)%48,038 33,892 (25)%45,222

Total467,480 13%412,252 443,437 10%401,876

(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,

2024202320242023

Oil (b/d)136,670 144,528 138,039 141,995

Natural Gas (Mcf/d)447,173 472,744 445,397 511,430

(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,

2024202320242023

Oil (b/d)30,579 29,514 29,596 29,369

Natural Gas (Mcf/d)100,210 100,122 96,054 110,476

(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 2024 and 2023 were 19,374 boe/d and 55,283 boe/d, respectively, and 30,607 boe/d and 47,370 boe/d for the first nine months of 2024 and 2023, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.

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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,

2024Increase(Decrease)20232024Increase(Decrease)2023

Average Oil Price - Per barrel

United States$76.34 (7)%$82.33 $78.16 1%$77.40

Egypt79.88 (10)%88.99 82.41 0%82.04

North Sea83.36 (5)%87.70 83.67 1%83.25

Total78.06 (9)%86.15 80.31 0%80.50

Average Natural Gas Price - Per Mcf

United States$0.16 (92)%$2.12 $0.61 (67)%$1.87

Egypt2.93 1%2.91 2.93 0%2.92

North Sea9.76 (11)%10.98 9.89 (23)%12.83

Total1.43 (54)%3.12 1.89 (35)%2.91

Average NGL Price - Per barrel

United States$20.91 (4)%$21.87 $22.20 5%$21.24

North Sea45.93 7%42.78 46.47 (2)%47.58

Total21.29 (4)%22.26 22.73 4%21.85

Third-Quarter 2024 compared to Third-Quarter 2023

Crude Oil Crude oil revenues for the third quarter of 2024 totaled $1.8 billion, a $92 million increase from the comparative 2023 quarter. A 23 percent higher average daily production increased third-quarter 2024 oil revenues by $251 million compared to the third quarter of 2023, while a 9 percent decrease in average realized prices decreased revenues by $159 million. Crude oil revenues accounted for 87 percent of total oil and gas production revenues and 55 percent of worldwide production in the third quarter of 2024. Crude oil prices realized in the third quarter of 2024 averaged $78.06 per barrel, compared with $86.15 per barrel in the comparative prior-year quarter.

The Company's worldwide oil production increased 48.5 Mb/d to 256.3 Mb/d during the third quarter of 2024 from the comparative prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition. These increases were offset by natural production decline, the sale of non-core assets in the U.S., and operational downtime due to maintenance activities in the North Sea.

Natural Gas Natural gas revenues for the third quarter of 2024 totaled $103 million, a $133 million decrease from the comparative 2023 quarter. A 54 percent decrease in average realized prices decreased third-quarter 2024 natural gas revenues by $128 million compared to the third quarter of 2023, while 4 percent lower average daily production decreased revenues by $5 million. Natural gas revenues accounted for 5 percent of total oil and gas production revenues and 28 percent of worldwide production during the third quarter of 2024.

The Company's worldwide natural gas production decreased 33.2 MMcf/d to 786.9 MMcf/d during the third quarter of 2024 from the comparative prior-year period, primarily a result of operational downtime due to maintenance activities in the North Sea, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, natural production decline, and the sale of non-core assets in the U.S. These decreases were offset by the Callon acquisition coupled with increased drilling activity and recompletions in the Permian Basin.

NGL NGL revenues for the third quarter of 2024 totaled $158 million, a $20 million increase from the comparative 2023 quarter. An 18 percent higher average daily production increased third-quarter 2024 NGL revenues by $26 million compared to the third quarter of 2023, while a 4 percent decrease in average realized prices decreased revenues by $6 million. NGL revenues accounted for 8 percent of total oil and gas production revenues and 17 percent of worldwide production during the third quarter of 2024.

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The Company's worldwide NGL production increased 12.2 Mb/d to 80 Mb/d during the third quarter of 2024 from the comparative prior-year period, primarily a result of the Callon acquisition coupled with increased drilling activity in the Permian Basin. These increases were offset by natural production decline, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S. These increases were further offset by operational downtime due to maintenance activities in the North Sea.

Year-to-Date 2024 compared to Year-to-Date 2023

Crude Oil Crude oil revenues for the first nine months of 2024 totaled $5.1 billion, a $669 million increase from the comparative 2023 period. An 18 percent higher average daily production increased oil revenues for the 2024 period by $680 million compared to the prior-year period, while a slight decrease in average realized prices lowered oil revenues by $11 million compared to the prior-year period. Crude oil revenues accounted for 85 percent of total oil and gas production revenues and 54 percent of worldwide production for the first nine months of 2024. Crude oil prices realized during the first nine months of 2024 averaged $80.31 per barrel, compared to $80.50 per barrel in the comparative prior-year period.

The Company's worldwide oil production increased 35.4 Mb/d to 236.8 Mb/d in the first nine months of 2024 compared to the prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition. These increases were offset by natural production decline across all assets, the sale of non-core assets in the U.S., and operational downtime due to maintenance activities in the North Sea.

Natural Gas Natural gas revenues for the first nine months of 2024 totaled $414 million, a $244 million decrease from the comparative 2023 period. A 35 percent decrease in average realized prices decreased natural gas revenues for the 2024 period by $232 million compared to the prior-year period, while 3 percent lower average daily production decreased revenues by $12 million compared to the prior-year period. Natural gas revenues accounted for 7 percent of total oil and gas production revenues and 30 percent of worldwide production for the first nine months of 2024.

The Company's worldwide natural gas production decreased 24.7 MMcf/d to 803 MMcf/d in the first nine months of 2024 compared to the prior-year period, primarily a result of operational downtime due to maintenance activities in the North Sea, reduced gas-focused activity in Egypt, natural production decline, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S. These decreases were partially offset by increased drilling activity in the Permian Basin coupled with the Callon acquisition.

NGL NGL revenues for the first nine months of 2024 totaled $457 million, a $82 million increase from the comparative 2023 period. A 16 percent higher average daily production increased NGL revenues for the 2024 period by $66 million compared to the prior-year period, while a 4 percent increase in average realized prices increased revenues by $16 million. NGL revenues accounted for 8 percent of total oil and gas production revenues and 16 percent of worldwide production for the first nine months of 2024.

The Company's worldwide NGL production increased 10.2 Mb/d to 72.9 Mb/d in the first nine months of 2024 compared to the prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition, offset by natural production decline, curtailment of volumes at Alpine High in response to extreme Waha basis differentials, and the sale of non-core assets in the U.S. These increases were further offset by operational downtime due to maintenance activities in the North Sea.

Purchased Oil and Gas Sales

Purchased oil and gas sales represent volumes primarily attributable to U.S. domestic oil and gas purchases that were sold by the Company to fulfill oil and natural gas takeaway obligations and delivery commitments. Sales related to these purchased volumes totaled $473 million and $229 million during the third quarters of 2024 and 2023, respectively, and $1.0 billion and $612 million during the first nine months of 2024 and 2023, respectively. Purchased oil and gas sales were offset by associated purchase costs of $292 million and $211 million during the third quarters of 2024 and 2023, respectively, and $665 million and $558 million during the first nine months of 2024 and 2023, respectively. Gross purchased oil and gas sales values were higher in the third quarter and the first nine months of 2024 as compared to the third quarter and the first nine months of 2023, primarily driven by activity associated with the Callon acquisition.

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Operating Expenses

The Company's operating expenses were as follows and include costs attributable to a noncontrolling interest in Egypt:

For the Quarter Ended

September 30,

For the Nine Months Ended

September 30,

2024202320242023

(In millions)

Lease operating expenses$418 $394 $1,216 $1,076

Gathering, processing, and transmission123 89 328 245

Purchased oil and gas costs292 211 665 558

Taxes other than income70 61 205 163

Exploration29 49 248 144

General and administrative92 139 270 276

Transaction, reorganization, and separation14 5 156 11

Depreciation, depletion, and amortization:

Oil and gas property and equipment588 407 1,589 1,086

Gathering, processing, and transmission assets2 2 5 5

Other assets5 9 19 26

Asset retirement obligation accretion36 29 112 86

Impairments1,111 - 1,111 46

Financing costs, net100 81 276 235

Total Operating Expenses$2,880 $1,476 $6,200 $3,957

Lease Operating Expenses (LOE)

LOE increased $24 million and $140 million compared to the third quarter and the first nine months of 2023, respectively. On a per-unit basis, LOE decreased 4 percent and increased 3 percent in the third quarter and the first nine months of 2024, respectively, when compared to the third quarter and the first nine months of 2023. The absolute dollar increase in the third quarter and the first nine months of 2024 compared to same prior year periods was driven by higher operating and labor costs coupled with higher workover activity, primarily from the Callon acquisition.

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,

2024202320242023

(In millions)

Third-party processing and transmission costs$123 $63 $305 $164

Midstream service costs - Kinetik- 26 23 81

Total Gathering, processing, and transmission

$123 $89 $328 $245

GPT costs increased $34 million and $83 million in the third quarter and the first nine months of 2024, respectively, when compared to the third quarter and the first nine months of 2023, primarily driven by an increase in natural gas and NGL production volumes in the U.S. when compared to the prior-year periods.

Purchased Oil and Gas Costs

Purchased oil and gas costs increased $81 million and $107 million in the third quarter and the first nine months of 2024, respectively, when compared to the third quarter and the first nine months of 2023. The increase in the third quarter and the first nine months of 2024 compared to same prior-year periods was primarily driven by oil purchases from activity associated with the Callon acquisition. With widening margins under third-party gas agreements, purchased oil and gas costs were more than offset by associated sales to fulfill oil and natural gas takeaway obligations and delivery commitments totaling $473 million and $1.0 billion in the third quarter and the first nine months of 2024, respectively, as discussed above.

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Taxes Other Than Income

Taxes other than income increased $9 million and $42 million from the third quarter and the first nine months of 2023, respectively, primarily from higher severance taxes driven by increased production volumes in the U.S. compared to the same prior-year periods.

Exploration Expenses

The Company's exploration expenses were as follows:

For the Quarter Ended

September 30,

For the Nine Months Ended

September 30,

2024202320242023

(In millions)

Unproved leasehold impairments$1 $9 $11 $20

Dry hole expense8 18 172 71

Geological and geophysical expense6 1 22 3

Exploration overhead and other14 21 43 50

Total Exploration$29 $49 $248 $144

Exploration expenses decreased $20 million and increased $104 million from the third quarter and the first nine months of 2023, respectively. The decrease in exploration expenses for the third quarter of 2024 compared to the third quarter of 2023 was primarily the result of higher dry hole expenses in the 2023 period coupled with lower unproved leasehold impairments and exploration overhead. The increase in exploration expenses for the first nine months of 2024 compared to the first nine months of 2023 was primarily the result of dry hole expense associated with the completion of an initial drilling campaign in Alaska where two wells were unable to reach target objectives in the allotted seasonal time window.

General and Administrative (G&A) Expenses

G&A expenses decreased $47 million and $6 million from the third quarter and the first nine months of 2023, respectively. The decrease in G&A expenses for the third quarter and first nine months of 2024 compared to the same prior-year periods was primarily driven by higher cash-based stock compensation expense in the 2023 period resulting from changes in the Company's stock price, partially offset by higher overall labor costs across the Company and the Callon acquisition.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs increased $9 million and $145 million from the third quarter and the first nine months of 2023, respectively. Higher TRS costs during the third quarter and the first nine months of 2024 were primarily a result of ongoing transaction costs related to the Callon acquisition coupled with separation costs in the North Sea. TRS costs incurred in the first nine months of 2024 comprised primarily $139 million associated with the Callon acquisition, including $71 million of separation costs and $68 million of transaction and integration costs.

Depreciation, Depletion, and Amortization (DD&A)

Total DD&A expenses increased $177 million and $496 million from the third quarter and the first nine months of 2023, 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 $3.30 per boe and $3.33 per boe from the third quarter and the first nine months of 2023, respectively. The increase in DD&A on a per boe basis was driven by negative gas price-related reserve revisions in prior periods and impacts resulting from the Callon acquisition in 2024. Higher absolute dollar amount of DD&A was driven primarily by higher capital expenditures incurred in the U.S. and Egypt.

Impairments

During the third quarter and the first nine months of 2024, the Company recorded $1.1 billion of impairments, which includes $793 million of oil and gas property impairments in the North Sea, $315 million impairment of assets held for sale in the Permian Basin, and $3 million of inventory impairments in the North Sea.

During the first nine months 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.

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Financing Costs, Net

The Company's Financing costs were as follows:

For the Quarter Ended

September 30,

For the Nine Months Ended

September 30,

2024202320242023

(In millions)

Interest expense$109 $89 $302 $266

Amortization of debt issuance costs1 1 4 3

Capitalized interest(8)(7)(22)(18)

Gain on extinguishment of debt

• • • (9)

Interest income(2)(2)(8)(7)

Total Financing costs, net$100 $81 $276 $235

Net financing costs increased $19 million and $41 million from the third quarter and the first nine months of 2023, respectively. The increase in costs during the third quarter and the first nine months of 2024 was primarily due to higher interest expense from higher average long-term debt balances compared to the third quarter and the first nine 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.

The Company's effective income tax rate for the three and nine months ended September 30, 2024 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations. During the third quarter of 2023, the Company's effective income tax rate differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations and a decrease in the amount of valuation allowance against its U.S. deferred tax assets. The Company's effective income tax rate for the nine months ended September 30, 2023 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations, a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2023, and a decrease in the amount of valuation allowance against its U.S. deferred tax assets.

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 (CAMT) on applicable corporations with an average annual adjusted financial statement income that exceeds $1.0 billion for any three consecutive years preceding the tax year at issue. The CAMT is effective for tax years beginning after December 31, 2022. The Company became an applicable corporation subject to CAMT beginning on January 1, 2024. On September 12, 2024, the U.S. Department of Treasury and the Internal Revenue Service released proposed regulations relating to the application and implementation of CAMT. The Company is continuing to evaluate the proposed regulations and their effect on the Company's consolidated financial statements.

In December 2021, the Organisation for Economic Co-operation and Development issued Pillar Two Model Rules introducing a new global minimum tax of 15 percent on a country-by-country basis, with certain aspects effective in certain jurisdictions on January 1, 2024. Although the Company continues to monitor enacted legislation to implement these rules in countries where the Company could be impacted, APA does not expect that the Pillar Two framework will have a material impact on its consolidated financial statements.

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.

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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.

During the nine months ended September 30, 2024, the Company recognized downward reserve revisions of approximately 26 percent of its year-end 2023 estimated proved reserves in the North Sea as a result of its economic assessment of its North Sea assets described in "Financial and Operational Highlights" above.

Following the completion of the Callon acquisition, the Company revised its full-year 2024 estimated upstream capital investment to approximately $2.8 billion and remains committed to its capital return framework 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 all other liquidity and capital resource needs.

For additional information, refer to Part I, Items 1 and 2-Business and Properties, and Item 1A-Risk Factors, in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2023.

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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,

20242023

(In millions)

Sources of Cash and Cash Equivalents:

Net cash provided by operating activities$2,584 $2,099

Proceeds from commercial paper and revolving credit facilities, net

190 202

Proceeds from term loan facility

1,500 -

Proceeds from asset divestitures724 29

Proceeds from sale of Kinetik Shares

428 -

Other20 -

Total Sources of Cash and Cash Equivalents5,446 2,330

Uses of Cash and Cash Equivalents:

Additions to upstream oil and gas property$2,153 $1,747

Leasehold and property acquisitions64 11

Payments on term loan facility

500 -

Payment on Callon Credit Agreement

472 -

Payments on fixed-rate debt

1,641 65

Dividends paid to APA common stockholders260 232

Distributions to noncontrolling interest

233 154

Treasury stock activity, net146 208

Other, net- 63

Total Uses of Cash and Cash Equivalents5,469 2,480

Decrease in Cash and Cash Equivalents

$(23)$(150)

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 accretion, and deferred income tax expense.

Net cash provided by operating activities during the first nine months of 2024 totaled $2.6 billion, $485 million higher from the first nine months of 2023, primarily due to higher revenues from increased oil and gas production 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 Commercial Paper and Revolving Credit Facilities, Net As of September 30, 2024, outstanding borrowings under the Company's commercial paper and U.S. dollar denominated syndicated credit facility were $562 million, an increase of $190 million since December 31, 2023. During the nine months ended September 30, 2023, the Company had net borrowings of $202 million under the Company's U.S. dollar denominated syndicated credit facility.

Proceeds from Term Loan Facility On April 1, 2024, the Company borrowed an aggregate $1.5 billion under a syndicated credit agreement. Loan proceeds were used to refinance certain indebtedness of Callon upon the closing of the Callon acquisition. For additional details of the credit agreement, see "Term Loan Credit Agreement" in the Liquidity section below. As of September 30, 2024, $1.0 billion remained outstanding under the term loan facility governed by the Term Loan Credit Agreement.

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Proceeds from Asset Divestitures The Company received $724 million and $29 million in proceeds from the divestiture of certain non-core assets during the first nine months of 2024 and 2023, respectively. For more information regarding the Company's acquisitions and divestitures, refer to Note 2-Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Proceeds from Sale of Kinetik Shares The Company received $428 million of cash proceeds from the sale of its remaining shares of Kinetik Class A Common Stock in March 2024. For more information regarding the Company's equity method interests, refer to Note 6-Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Uses of Cash and Cash Equivalents

Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $2.2 billion and $1.7 billion during the first nine months of 2024 and 2023, respectively. The increase in capital investment compared to the prior-year period is reflective of the Company's acquisition of Callon, which increased the number of drilling rigs being operated in the Permian Basin, partially offset by the Company's efforts to balance workover activity in Egypt and reduce drilling activity in the North Sea as it continually assesses inventory opportunities across its diverse portfolio. The Company operated an average of approximately 23 drilling rigs during the first nine months of 2024, compared to an average of approximately 24 drilling rigs during the first nine months of 2023.

Leasehold and Property Acquisitions During the first nine months of 2024 and 2023, in addition to the Callon acquisition, the Company completed other leasehold and property acquisitions, primarily in the Permian Basin, for total cash consideration of $64 million and $11 million, respectively.

Payments on Callon Credit Agreement During the first nine months of 2024, the Company financed Callon's repayment in full of the $472 million outstanding under the Callon Credit Agreement upon the Callon acquisition.

Payments on Term Loan Facility During the first nine months of 2024, the Company made a payment of $500 million on its syndicated credit agreement. For additional details of the credit agreement, see "Term Loan Credit Agreement" in the Liquidity section below. As of September 30, 2024, $1.0 billion remained outstanding under the term loan facility governed by the Term Loan Credit Agreement.

Payments on Fixed-Rate Debt During the first nine months of 2024, the Company financed Callon's repayment pursuant to Callon's cash tender offers for, and redemptions of all senior notes issued under Callon's indentures for an aggregate cash payment amount of $1.6 billion, reflecting principal amounts, premium to par, and associated fees.

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. The Company recognized a $9 million gain on these repurchases.

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 $260 million and $232 million during the first nine months of 2024 and 2023, respectively, for dividends on its common stock.

Distributions to Noncontrolling Interest 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 $233 million and $154 million during the first nine months of 2024 and 2023, respectively, in cash distributions to Sinopec.

Treasury Stock Activity, net In the first nine months of 2024, the Company repurchased 4.6 million shares at an average price of $31.72 per share and an aggregate purchase price of approximately $146 million, and as of September 30, 2024, the Company had remaining authorization to repurchase 39.3 million shares. In the first nine months of 2023, the Company repurchased 5.5 million shares at an average price of $37.91 per share and an aggregate purchase price of approximately $208 million.

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Liquidity

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

September 30,

2024

December 31,

2023

(In millions)

Cash and cash equivalents$64 $87

Total debt - APA and Apache6,372 5,188

Total equity6,160 3,691

Available committed borrowing capacity under syndicated credit facilities2,839 2,894

Cash and Cash Equivalents As of September 30, 2024, the Company had $64 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, 2024, the Company had $6.4 billion in total debt outstanding, which consisted of notes and debentures of Apache, credit facility and commercial paper borrowings, and finance lease obligations. As of September 30, 2024, current debt included $2 million of finance lease obligations.

Unsecured 2022 Committed Credit Facilities On April 29, 2022, the Company entered into two unsecured syndicated credit agreements for general corporate purposes.

•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.

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 of the USD Agreement and GBP Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache's existing indentures first is less than US$1.0 billion.

As of September 30, 2024, there were $232 million of borrowings under the USD Agreement and an aggregate £303 million in letters of credit outstanding under the GBP Agreement. As of September 30, 2024, there were no letters of credit outstanding under the USD Agreement. As of December 31, 2023, there were $372 million of borrowings under the USD Agreement and an aggregate £348 million in letters of credit outstanding under the GBP Agreement. As of December 31, 2023, there were no letters of credit outstanding under the USD Agreement.

Uncommitted Lines of Credit 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, 2024 and December 31, 2023, there were no outstanding borrowings under these facilities. As of September 30, 2024, there were £461 million and $11 million in letters of credit outstanding under these facilities. As of December 31, 2023, there were £416 million and $2 million in letters of credit outstanding under these facilities.

Commercial Paper Program In December 2023, the Company established a commercial paper program under which it from time to time may issue in private placements exempt from registration under the Securities Act short-term unsecured promissory notes (CP Notes) up to a maximum aggregate face amount of $1.8 billion outstanding at any time. The maturities of CP Notes may vary but may not exceed 397 days from the date of issuance. Outstanding CP Notes are supported by available borrowing capacity under the Company's committed $1.8 billion USD Agreement.

Payment of CP Notes has been unconditionally guaranteed on an unsecured basis by Apache, such guarantee effective until the first time that the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache's existing indentures is less than US$1.0 billion.

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As of September 30, 2024, there was $330 million in aggregate face amount of CP Notes outstanding, which is classified as long-term debt. As of December 31, 2023, there were no CP Notes outstanding.

Term Loan Credit Agreement On January 30, 2024, APA entered into a syndicated credit agreement under which the lenders committed an aggregate $2.0 billion for senior unsecured delayed-draw term loans to APA (Term Loan Credit Agreement), the proceeds of which could be used to refinance certain indebtedness of Callon only once upon the date of the closings under the Merger Agreement and Term Loan Credit Agreement; of such aggregate commitments, $1.5 billion was for term loans that would mature three years after the date of such closings (3-Year Tranche Loans) and $500 million was for term loans that would mature 364 days after the date of such closings (364-Day Tranche Loans). Apache has guaranteed obligations under the Term Loan Credit Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache's existing indentures first is less than $1.0 billion.

On April 1, 2024, APA closed the transactions under the Term Loan Credit Agreement, electing to borrow an aggregate $1.5 billion in 3-Year Tranche Loans maturing April 1, 2027, and to allow the lender commitments for the 364-Day Tranche Loans to expire. Loan proceeds were used to refinance certain indebtedness of Callon upon the substantially simultaneous closing of APA's acquisition of Callon pursuant to the Merger Agreement and to pay related fees and expenses. APA may at any time prepay loans under the Term Loan Credit Agreement. As of September 30, 2024, $1.0 billion in 3-Year Tranche Loans remained outstanding under the Term Loan Credit Agreement.

Indebtedness of Callon that APA could refinance by borrowing under the Term Loan Credit Agreement included indebtedness outstanding under (i) the Amended and Restated Credit Agreement, dated October 19, 2022, among Callon, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (Callon Credit Agreement), (ii) Callon's 6.375% Senior Notes due 2026 (Callon's 2026 Notes), (iii) Callon's 8.00% Senior Notes due 2028 (Callon's 2028 Notes), and (iv) Callon's 7.500% Senior Notes due 2030 (Callon's 2030 Notes).

On April 1, 2024, all indebtedness under the Callon Credit Agreement and Callon's 2026 Notes was repaid, and the aggregate principal balance remaining outstanding under Callon's 2028 Notes and Callon's 2030 Notes was reduced to $24 million. On May 6, 2024, all remaining indebtedness under Callon's 2028 Notes and Callon's 2030 Notes was repaid. Given these repayments, no guarantee by Callon of APA's obligations under the Term Loan Credit Agreement is required.

On April 1, 2024, the following Callon indebtedness was repaid by borrowings under the Term Loan Credit Agreement and the USD Agreement:

•Callon closed cash tender offers for Callon's 2028 Notes and Callon's 2030 Notes, accepting for purchase $1.2 billion aggregate principal amount of notes. Callon paid holders an aggregate $1.3 billion in cash, reflecting principal, premium to par, early tender consent fee, and accrued and unpaid interest.

•Callon redeemed the outstanding $321 million principal amount of Callon's 2026 Notes at a redemption price equal to 101.063% of their principal amount, plus accrued and unpaid interest to the redemption date.

•Callon repaid the aggregate $472 million owed under the Callon Credit Agreement, including principal, accrued and unpaid interest, and certain fees.

On May 6, 2024, Callon fully redeemed the remaining outstanding $8 million principal amount of Callon's 2028 Notes at a redemption price equal to 101.588% of their principal amount and $16 million principal amount of Callon's 2030 Notes at a redemption price equal to 102.803% of their principal amount, in each case, plus accrued and unpaid interest to the redemption date. The repayments were partially funded by borrowing under the USD Agreement.

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, 2023. There have been no material changes to the contractual obligations described therein.

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Potential Decommissioning Obligations on Sold Properties

In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). 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). On February 14, 2018, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection. On August 3, 2020, Fieldwood filed for (and subsequently emerged from) Chapter 11 bankruptcy protection for a second time. Upon emergence from this second bankruptcy, 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 are to be used to fund the operation of GOM Shelf and the decommissioning of Legacy GOM Assets. Pursuant to the terms of the original transaction, as amended in the first bankruptcy, the securing of the asset retirement obligations for the Legacy GOM Assets as and when Apache is required to perform or pay for any such decommissioning was accomplished through the posting of letters of credit in favor of Apache (Letters of Credit), the provision of two bonds (Bonds) in favor of Apache, and the establishment of a trust account of which Apache was a beneficiary and which was funded by net profits interests (NPIs) depending on future oil prices. In addition, after such sources have been exhausted, Apache agreed upon resolution of GOM Shelf's second bankruptcy to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning, with such standby loan secured by a first and prior lien on the Legacy GOM Assets.

By letter dated April 5, 2022 (replacing two earlier letters) 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 was 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 and demands from third parties to decommission certain of the Legacy GOM Assets included in GOM Shelf's notifications to BSEE. Apache expects to receive similar orders and demands 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.

On June 21, 2023, two sureties that issued Bonds directly to Apache and two sureties that issued bonds to the issuing bank on the Letters of Credit filed suit against Apache in a case styled Zurich American Insurance Company, HCC International Insurance Company PLC, Philadelphia Indemnity Insurance Company and Everest Reinsurance Company (Insurers) v. Apache Corporation, Cause No. 2023-38238 in the 281st Judicial District Court, Harris County Texas. The sureties sought to prevent Apache from drawing on the Bonds and Letters of Credit and further alleged that they are discharged from their reimbursement obligations related to decommissioning costs and are entitled to other relief. On July 20, 2023, the 281st Judicial District Court denied the Insurers' request for a temporary injunction. On July 26, 2023, Apache removed the suit to the United States Bankruptcy Court for the Southern District of Texas (Houston Division). Since the time the sureties filed their state court lawsuit, Apache has drawn down the entirety of the Letters of Credit. Apache has also sought to draw down on the Bonds; however, the sureties refuse to pay such Bond draws. On September 12, 2024, the bankruptcy court issued its opinion (1) finding that the sureties' state court lawsuit against Apache was void; (2) holding that Apache's claims against the sureties for unpaid amounts may proceed in bankruptcy court; and (3) holding the sureties in civil contempt and awarding attorneys' fees to Apache as a sanction in an amount to be determined in a future hearing. Apache is vigorously pursuing its claims against the sureties.

As of September 30, 2024, the Company has recorded a $188 million asset, which represents the remaining amount the Company expects to be reimbursed from security related to these decommissioning costs.

The Company has recorded contingent liabilities in the amounts of $853 million and $824 million as of September 30, 2024 and December 31, 2023, respectively, representing the estimated costs of decommissioning it may be required to perform on the Legacy GOM Assets. The Company recognized $83 million in the first nine months of 2024 of "Loss on previously sold Gulf of Mexico properties." Amounts recorded in the first nine months of 2024 included $50 million related to orders received from BSEE during the period to decommission properties previously sold to Cox Operating LLC and to decommission a property operated and produced by Fieldwood Energy Offshore and Dynamic Offshore Resources NS, LLC. The Company recognized no losses for decommissioning previously sold properties during the third quarter and the first nine months of 2023. There have been no other changes in estimates from December 31, 2023 that would have a material impact on the Company's financial position, results of operations, or liquidity.

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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, 2023. For the nine months ended September 30, 2024, the Company notes the following additional critical accounting estimate:

Long-Lived Asset Impairments

Long-lived assets used in operations, including proved oil and gas properties and GPT assets, are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. If there is an indication that the carrying amount of an asset group may not be recovered, the asset is assessed by management through an established process in which changes to significant assumptions such as prices, volumes, and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is assessed by management using the income approach.

Under the income approach, the fair value of each asset group is estimated based on the present value of expected future cash flows. The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, the success of future exploration for and development of unproved reserves, expected throughput volumes for GPT assets, discount rates, and other variables. Key assumptions used in developing a discounted cash flow model described above include estimated quantities of crude oil and natural gas reserves; estimates of market prices considering forward commodity price curves as of the measurement date; and estimates of operating, administrative, and capital costs adjusted for inflation. The Company discounts the resulting future cash flows using a discount rate believed to be consistent with those applied by market participants.

To assess the reasonableness of our fair value estimate, when available, management uses a market approach to compare the fair value to similar assets. This requires management to make certain judgments about the selection of comparable assets, recent comparable asset transactions, and transaction premiums.

Although the fair value estimate of each asset group is based on assumptions believed to be reasonable, those assumptions are inherently unpredictable and uncertain, and actual results could differ from the estimate. Negative revisions of estimated reserves quantities, increases in future cost estimates, divestiture of a significant component of the asset group, or sustained decreases in crude oil or natural gas prices could lead to a reduction in expected future cash flows and possibly an additional impairment of long-lived assets in future periods.

The Company has recorded material impairments of certain proved oil and gas properties and gathering, processing, and transmission facilities in the third quarter of 2024. For discussion of these impairments, see "Fair Value Measurements" of Note 1-Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements.

Purchase Price Allocation

Accounting for the acquisition of a business requires the allocation of the purchase price to the various assets and liabilities of the acquired business and recording deferred taxes for any differences between the allocated values and tax basis of assets and liabilities. Any excess of the purchase price over the amounts assigned to assets and liabilities would be recorded as goodwill.

The purchase price allocation is accomplished by recording each asset and liability at its estimated fair value. Estimated deferred taxes are based on available information concerning the tax basis of the acquired company's assets and liabilities and tax-related carryforwards at the merger date, although such estimates may change in the future as additional information becomes known. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed relative to the total acquisition cost.

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In estimating the fair values of assets acquired and liabilities assumed, the Company has made various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties, the Company prepared estimates of crude oil and natural gas reserves as described in the "Reserves Estimates" section of 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, 2023. Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future.

New Accounting Pronouncements

In November 2024, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2024-03, "Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40)," which expands disclosures around a public entity's costs and expenses of specific items (i.e. employee compensation, DD&A), requires the inclusion of amounts that are required to be disclosed under GAAP in the same disclosure as other disaggregation requirements, requires qualitative descriptions of amounts remaining in expense captions that are not separately disaggregated quantitatively, and requires disclosure of total selling expenses, and in annual periods, the definition of selling expenses. The amendment does not change or remove existing disclosure requirements. The amendment is effective for fiscal years beginning after December 15, 2026, and interim periods with fiscal years beginning after December 15, 2027. Early adoption is permitted, and the amendment can be adopted prospectively or retrospectively to any or all periods presented in the financial statements. The Company is currently assessing the impact of adopting this standard.