APA Corp

Previous wording

In the first quarter of 2025, the Company announced a significant cost reduction initiative. The Company’s primary objective is to drive sustainable cost savings for the long-term and is targeting over $350 million in annualized savings within 2026. This will include reducing the Company’s overhead costs, addressing the capital cost structure for its drilling, completions, and facility investments, and improving efficiencies of day-to-day field operating practices.

Current wording

In the first quarter of 2025, the Company announced a significant cost reduction initiative. The Company’s primary objective is to drive sustainable cost savings for the long-term and is targeting $350 million in annualized savings across G&A, LOE, and capital by the end of 2025 and an additional $50 million to $100 million by the end of 2026. This will include reducing the Company’s overhead costs, addressing the capital cost structure for its drilling, completions, and facility investments, and improving efficiencies of day-to-day field operating practices.

Previous wording

•Beginning in the fourth quarter of 2021 and through the end of the second quarter of 2025, the Company has repurchased 92.4 million shares of the Company’s common stock. Subsequent to the quarter ended June 30, 2025 through July 31, 2025, the Company repurchased 1.0 million shares, and as of July 31, 2025, the Company had remaining authorization to repurchase up to 26.7 million shares under the Company’s share repurchase programs.

Current wording

•Beginning in the fourth quarter of 2021 and through the end of the third quarter of 2025, the Company has repurchased 95.5 million shares of the Company’s common stock. Subsequent to the quarter ended September 30, 2025 through October 31, 2025, the Company repurchased 1.0 million shares, and as of October 31, 2025, the Company had remaining authorization to repurchase up to 23.6 million shares under the Company’s share repurchase programs.

Previous wording

In the first six months of 2025, the Company reported net income attributable to common stock of $950 million, or $2.62 per diluted share, compared to net income of $673 million, or $2.00 per diluted share, in the first six months of 2024. The increase in net income in the first six months of 2025 was primarily driven by increased production from drilling activity in the Permian Basin coupled with the Callon merger, as well as gains on extinguishment of debt and derivative instruments.

Current wording

In the third quarter of 2025, the Company reported net income attributable to common stock of $205 million, or $0.57 per diluted share, compared to a net loss of $223 million, or $0.60 per diluted share, in the third quarter of 2024. In the first nine months of 2025, the Company reported net income attributable to common stock of $1.2 billion, or $3.20 per diluted share, compared to net income of $450 million, or $1.29 per diluted share, in the first nine months of 2024. The increase in net income in the third quarter and the first nine months of 2025 compared to the same prior-year periods was primarily driven by $1.1 billion of impairments recorded in the prior-year period. Lower operating expenses in the third quarter and first nine months of 2025, resulting largely from focused cost-reduction efforts undertaken in 2025, further contributed to the increase in net income.

Previous wording

The Company generated $2.3 billion of cash from operating activities during the first six months of 2025, 83 percent higher than the first six months of 2024. APA’s higher operating cash flows for the first six months of 2025 were primarily driven by the timing of working capital items. The Company repurchased 7.1 million shares of its common stock for $150 million and paid $181 million in dividends to APA common stockholders during the first six months of 2025. The Company exited the quarter with approximately $4.6 billion of debt, a reduction of $1.5 billion from year-end 2024.

Current wording

The Company generated $3.7 billion of cash from operating activities during the first nine months of 2025, 45 percent higher than the first nine months of 2024. APA’s higher operating cash flows for the first nine months of 2025 were primarily driven by lower overall expenses, collection of outstanding receivables, and timing of other working capital items. The Company repurchased 10.2 million shares of its common stock for $215 million and paid $271 million in dividends to APA common stockholders during the first nine months of 2025. The Company exited the quarter with approximately $4.5 billion of debt, a reduction of $1.6 billion from year-end 2024.

Previous wording

•Daily boe production from the Company’s U.S. assets, which decreased 4 percent from the second quarter of 2024, accounted for 62 percent of the Company’s worldwide production during the second quarter of 2025. The Company averaged seven drilling rigs in the Permian Basin, including four rigs in the Southern Midland Basin and three rigs in the Delaware Basin in the second quarter of 2025. The Company brought online 36 operated wells during the quarter. The Company’s core Permian Basin development program continues to represent key growth areas for the U.S. assets.

Current wording

•Daily boe production from the Company’s U.S. assets, which decreased 7 percent from the third quarter of 2024, accounted for 61 percent of the Company’s worldwide production during the third quarter of 2025. The Company averaged six drilling rigs in the Permian Basin, including four rigs in the Southern Midland Basin and two rigs in the Delaware Basin in the third quarter of 2025. The Company brought online 42 operated wells during the quarter. The Company’s core Permian Basin development program continues to represent the key growth area for its U.S. assets.

Previous wording

•APA holds approximately 750 MMBtu/d of firm capacity on various pipelines. As of June 30, 2025, the Company had open basis swap contracts which purchased NYMEX Henry Hub/Waha and sold NYMEX Henry Hub/HSC on approximately two-thirds of its firm transport capacity for 2025, thereby locking in a significant portion of cash flows associated with its marketing activities for the remainder of the year. Refer to Note 4—Derivative Instruments and Hedging Activities for further discussion of these basis swap agreements.

Current wording

•APA holds approximately 750,000 MMBtu/d of firm capacity on various pipelines. As of September 30, 2025, the Company had open basis swap contracts which purchased NYMEX Henry Hub/Waha and sold NYMEX Henry Hub/HSC on approximately two-thirds of its firm transport capacity for 2025 and including swap contracts entered into subsequent to September 30, 2025, approximately one-third for 2026, thereby locking in a significant portion of cash flows associated with its marketing activities for the near term. Refer to Note 4—Derivative Instruments and Hedging Activities for further discussion of these basis swap agreements.

Previous wording

•In Egypt, the Company averaged 13 drilling rigs and drilled 20 new productive wells during the second quarter of 2025. During the same period, the Company averaged 19 workover rigs as it continues to align its drilling and workover activity with a goal of driving improved capital efficiency. Second quarter 2025 gross and net production from the Company’s Egypt assets decreased 4 percent and increased 8 percent, respectively, from the second quarter of 2024.

Current wording

•In Egypt, the Company averaged 12 drilling rigs and drilled 17 new productive wells during the third quarter of 2025. During the same period, the Company averaged 19 workover rigs as it continues to align its drilling and workover activity with a goal of driving improved capital efficiency. Third quarter 2025 gross and net production from the Company’s Egypt assets decreased 1 percent and increased 7 percent, respectively, from the third quarter of 2024.

Previous wording

•In Egypt, following the recent success of the gas program and the relative softening of oil prices, the Company now expects one-third of its activities to be gas-focused and anticipates continued strong performance for the rest of the year, with realized gas prices increasing through the period.

Current wording

•In Egypt, following the recent success of the gas program and the relative softening of oil prices, the Company expects one-third of its activities to be gas-focused and anticipates continued strong performance for the rest of the year, with realized gas prices increasing through the period.

Previous wording

•Subsequent to the end of the quarter, the Government of Egypt awarded the Company an additional 2 million net exploration acreage in the Western Desert for a period of five years. This new acreage expands on the Company’s existing position in the country. In addition to a signature bonus of $25 million, the Company has committed to a drilling program on the acreage that the Company believes it will be able to meet in the normal course of operations. The transaction is expected to close in the third-quarter of 2025.

Current wording

•The Government of Egypt awarded the Company an additional two million net exploration acreage in the Western Desert. This new acreage expands on the Company’s existing position in the country. In addition to a signature bonus of $25 million, the Company has committed to a drilling program on the acreage that the Company believes it will be able to meet in the normal course of operations. The Government also helped facilitate significant payments in the third quarter, nearly eliminating EGPC’s past due receivables.

Previous wording

(4) Average sales volumes from the North Sea for the second quarters of 2025 and 2024 were 28,015 boe/d and 37,491 boe/d, respectively, and 32,336 boe/d and 36,285 boe/d for the first six months of 2025 and 2024, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.

Current wording

(4) Average sales volumes from the North Sea for the third quarters of 2025 and 2024 were 32,832 boe/d and 19,374 boe/d, respectively, and 32,503 boe/d and 30,607 boe/d for the first nine months of 2025 and 2024, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.

Previous wording

Crude Oil Crude oil revenues for the second quarter of 2025 totaled $1.4 billion, a $526 million decrease from the comparative 2024 quarter. A 20 percent decrease in average realized prices decreased second-quarter 2025 oil revenues by $387 million compared to the second quarter of 2024, while a 7 percent lower average daily production decreased revenues by $139 million. Crude oil revenues accounted for 80 percent of total oil and gas production revenues and 51 percent of worldwide production in the second quarter of 2025. Crude oil prices realized in the second quarter of 2025 averaged $65.58 per barrel, compared with $82.28 per barrel in the comparative prior-year quarter.

Current wording

Crude Oil Crude oil revenues for the third quarter of 2025 totaled $1.5 billion, a $327 million decrease from the comparative 2024 quarter. A 14 percent decrease in average realized prices decreased third-quarter 2025 oil revenues by $245 million compared to the third quarter of 2024, while 9 percent lower average daily production decreased revenues by $82 million. Crude oil revenues accounted for 81 percent of total oil and gas production revenues and 51 percent of worldwide production in the third quarter of 2025. Crude oil prices realized in the third quarter of 2025 averaged $67.43 per barrel, compared with $78.06 per barrel in the comparative prior-year quarter.

Previous wording

The Company’s worldwide oil production decreased 18.4 Mb/d to 235.2 Mb/d during the second quarter of 2025 from the comparative prior-year period, primarily a result of natural production decline in the U.S. and the North Sea and the sale of non-core assets in the U.S. These decreases were offset by drilling activity in the Permian Basin and downtime recovery in the North Sea.

Current wording

The Company’s worldwide oil production decreased 22.1 Mb/d to 234.2 Mb/d during the third quarter of 2025 from the comparative prior-year period, primarily a result of the sale of non-core assets in the U.S. and natural production decline in the U.S. and the North Sea. These decreases were offset by drilling activity in the Permian Basin and downtime recovery in the North Sea.

Previous wording

Natural Gas Natural gas revenues for the second quarter of 2025 totaled $184 million, a $49 million increase from the comparative 2024 quarter. A 29 percent increase in average realized prices increased second-quarter 2025 natural gas revenues by $38 million compared to the second quarter of 2024, while a 7 percent higher average daily production increased revenues by $11 million. Natural gas revenues accounted for 11 percent of total oil and gas production revenues and 32 percent of worldwide production during the second quarter of 2025.

Current wording

Natural Gas Natural gas revenues for the third quarter of 2025 totaled $192 million, an $89 million increase from the comparative 2024 quarter. A 57 percent increase in average realized prices increased third-quarter 2025 natural gas revenues by $60 million compared to the third quarter of 2024, while 18 percent higher average daily production increased revenues by $29 million. Natural gas revenues accounted for 11 percent of total oil and gas production revenues and 33 percent of worldwide production during the third quarter of 2025.

Previous wording

The Company’s worldwide natural gas production increased 58.5 MMcf/d to 894.1 MMcf/d during the second quarter of 2025 from the comparative prior-year period, primarily a result of increased drilling activity in Egypt and the Permian Basin. Natural gas production was also higher as a result of lower volume curtailments at Alpine High compared with the 2024 period in response to extreme Waha basis differentials. These increases were partially offset by natural production decline in the U.S. and North Sea, the sale of non-core assets, and operational downtime in the U.S.

Current wording

The Company’s worldwide natural gas production increased 145.3 MMcf/d to 932.2 MMcf/d during the third quarter of 2025 from the comparative prior-year period, primarily a result of increased drilling activity in Egypt and downtime recovery in the North Sea. Natural gas production was also higher as a result of lower volume curtailments at Alpine High compared with the 2024 period in response to extreme Waha basis differentials. These increases were partially offset by the sale of non-core assets in the U.S. and natural production decline in the U.S. and North Sea.

Previous wording

NGL NGL revenues for the second quarter of 2025 totaled $153 million, a $6 million decrease from the comparative 2024 quarter. A 5 percent decrease in average realized prices decreased second-quarter 2025 NGL revenues by $9 million compared to the second quarter of 2024, partially offset by slightly higher average daily production, which increased revenues by $3 million. NGL revenues accounted for 9 percent of total oil and gas production revenues and 17 percent of worldwide production during the second quarter of 2025.

Current wording

NGL NGL revenues for the third quarter of 2025 totaled $142 million, a $16 million decrease from the comparative 2024 quarter. A 7 percent lower average daily production decreased third-quarter 2025 NGL revenues by $11 million compared to the third quarter of 2024, while a 3 percent decrease in average realized prices decreased revenues by $5 million. NGL revenues accounted for 8 percent of total oil and gas production revenues and 16 percent of worldwide production during the third quarter of 2025.

Previous wording

The Company’s worldwide NGL production increased 0.3 Mb/d to 80.8 Mb/d during the second quarter of 2025 from the comparative prior-year period, primarily a result of increased drilling activity in the Permian Basin and reduced volume curtailments at Alpine High compared with the 2024 period in response to extreme Waha basis differentials. These increases were offset by natural production decline in the U.S. and North Sea, the sale of non-core assets and operational downtime in the U.S.

Current wording

The Company’s worldwide NGL production decreased 5.8 Mb/d to 74.2 Mb/d during the third quarter of 2025 from the comparative prior-year period, primarily a result of the sale of non-core assets in the U.S. and natural production decline in the U.S. and the North Sea. These decreases were offset by drilling activity in the Permian Basin and downtime recovery in the North Sea.

Previous wording

Crude Oil Crude oil revenues for the first six months of 2025 totaled $3.0 billion, a $358 million decrease from the comparative 2024 period. A 15 percent decrease in average realized prices lowered oil revenues for the 2025 period by $485 million compared to the same prior-year period, while a 4 percent higher average daily production increased oil revenues by $127 million. Crude oil revenues accounted for 79 percent of total oil and gas production revenues and 51 percent of worldwide production for the first six months of 2025. Crude oil prices realized during the first six months of 2025 averaged $69.72 per barrel, compared to $81.57 per barrel in the comparative prior-year period.

Current wording

Crude Oil Crude oil revenues for the first nine months of 2025 totaled $4.5 billion, a $685 million decrease from the comparative 2024 period. A 14 percent decrease in average realized prices lowered oil revenues for the 2025 period by $726 million compared to the same prior-year period, while higher sales volumes, despite relatively flat average daily production, increased oil revenues by $41 million. Crude oil revenues accounted for 80 percent of total oil and gas production revenues and 50 percent of worldwide production for the first nine months of 2025. Crude oil prices realized during the first nine months of 2025 averaged $68.94 per barrel, compared to $80.31 per barrel in the comparative prior-year period.

Previous wording

The Company’s worldwide oil production increased 9.0 Mb/d to 235.9 Mb/d in the first six months of 2025 compared to the same prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition in the U.S. and downtime recovery in the North Sea. These increases were offset by natural production decline across all assets and the sale of non-core assets in the U.S.

Current wording

The Company’s worldwide oil production stayed relatively flat in the first nine months of 2025 compared to the same prior-year period, the result of the sale of non-core assets in the U.S. and natural production decline, mostly offset by drilling activity in the Permian Basin and downtime recovery in the North Sea.

Previous wording

Natural Gas Natural gas revenues for the first six months of 2025 totaled $417 million, a $106 million increase from the comparative 2024 period. A 21 percent increase in average realized prices increased natural gas revenues for the 2025 period by $63 million compared to the same prior-year period, while 12 percent higher average daily production increased revenues by $43 million. Natural gas revenues accounted for 11 percent of total oil and gas production revenues and 32 percent of worldwide production for the first six months of 2025.

Current wording

Natural Gas Natural gas revenues for the first nine months of 2025 totaled $609 million, a $195 million increase from the comparative 2024 period. A 30 percent increase in average realized prices increased natural gas revenues for the 2025 period by $123 million compared to the same prior-year period, while 14 percent higher average daily production increased revenues by $72 million. Natural gas revenues accounted for 11 percent of total oil and gas production revenues and 33 percent of worldwide production for the first nine months of 2025.

Previous wording

The Company’s worldwide natural gas production increased 97.6 MMcf/d to 909 MMcf/d in the first six months of 2025 compared to the same prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition in the U.S., and downtime recovery in the North Sea. Natural gas production was also higher as a result of reduced volume curtailments at Alpine High compared with the 2024 period in response to extreme Waha basis differentials. These increases were offset by natural production decline in the U.S. and North Sea, the sale of non-core assets, and operational downtime in the U.S.

Current wording

The Company’s worldwide natural gas production increased 113.7 MMcf/d to 917 MMcf/d in the first nine months of 2025 compared to the same prior-year period, primarily a result of increased drilling activity in Egypt and the Permian Basin coupled with the Callon acquisition in the U.S., and downtime recovery in the North Sea. Natural gas production was also higher as a result of reduced volume curtailments at Alpine High compared with the 2024 period in response to extreme Waha basis differentials. These increases were offset by the sale of non-core assets in the U.S., natural production decline in the U.S. and North Sea, and operational downtime in the U.S.

Previous wording

NGL NGL revenues for the first six months of 2025 totaled $359 million, a $60 million increase from the comparative 2024 period. A 15 percent higher average daily production increased NGL revenues for the 2025 period by $48 million compared to the same prior-year period, while a 4 percent increase in average realized prices increased revenues by $12 million. NGL revenues accounted for 10 percent of total oil and gas production revenues and 17 percent of worldwide production for the first six months of 2025.

Current wording

NGL NGL revenues for the first nine months of 2025 totaled $501 million, a $44 million increase from the comparative 2024 period. A 7 percent higher average daily production increased NGL revenues for the 2025 period by $33 million compared to the same prior-year period, while a 3 percent increase in average realized prices increased revenues by $11 million. NGL revenues accounted for 9 percent of total oil and gas production revenues and 17 percent of worldwide production for the first nine months of 2025.

Previous wording

The Company’s worldwide NGL production increased 10.5 Mb/d to 79.7 Mb/d in the first six months of 2025 compared to the same prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition in the U.S. NGL production was also higher as a result of reduced volume curtailments at Alpine High compared with the 2024 period in response to extreme Waha basis differentials. These increases were offset by natural production decline in the U.S. and North Sea, the sale of non-core assets in the U.S., and the cessation of new drilling in the North Sea.

Current wording

The Company’s worldwide NGL production increased 5.0 Mb/d to 77.8 Mb/d in the first nine months of 2025 compared to the same prior-year period, primarily a result of increased drilling activity in the Permian Basin coupled with the Callon acquisition in the U.S. and downtime recovery in the North Sea. NGL production was also higher as a result of reduced volume curtailments at Alpine High compared with the 2024 period in response to extreme Waha basis differentials. These increases were offset by the sale of non-core assets in the U.S., natural production decline in the U.S. and North Sea, and operational downtime in the U.S.

Previous wording

Purchased oil and gas sales represent volumes primarily attributable to 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 purchased volumes totaled $460 million and $342 million during the second quarters of 2025 and 2024, respectively, and $1.1 billion and $545 million during the first six months of 2025 and 2024, respectively. Purchased oil and gas sales were partially offset by associated purchase costs of $304 million and $210 million during the second quarters of 2025 and 2024, respectively, and $778 million and $373 million, respectively, during the first six months of 2025 and 2024, respectively. Gross purchased oil and gas sales values were higher in the second quarter and the first six months of 2025, primarily driven by higher natural gas volume sales and higher gas prices, as well as activity associated with the Callon acquisition.

Current wording

Purchased oil and gas sales represent volumes primarily attributable to 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 purchased volumes totaled $311 million and $473 million during the third quarters of 2025 and 2024, respectively, and $1.4 billion and $1.0 billion during the first nine months of 2025 and 2024, respectively. Purchased oil and gas sales were partially offset by associated purchase costs of $184 million and $292 million during the third quarters of 2025 and 2024, respectively, and $962 million and $665 million, respectively, during the first nine months of 2025 and 2024, respectively. Gross purchased oil and gas sales values were lower in the third quarter, primarily driven by lower oil volume sales and lower oil prices. Gross purchased oil and gas sales values were higher in the first nine months of 2025, primarily driven by higher natural gas prices and activity associated with the Callon acquisition.

Previous wording

LOE decreased $93 million and $24 million from the second quarter and the first six months of 2024, respectively. On a per-unit basis, LOE decreased 18 percent and 11 percent in the second quarter and the first six months of 2025, respectively, when compared to the second quarter and the first six months of 2024. The decrease in absolute costs was primarily driven by overall lower operating costs and lower workover activity coupled with the sale of non-core assets in the Permian Basin, compared to the same prior-year periods. The decrease in absolute costs for the first six months of 2025 was partially offset by activity related to the Callon transaction.

Current wording

LOE decreased $42 million and $66 million from the third quarter and the first nine months of 2024, respectively. On a per-unit basis, LOE decreased 11 percent in each of the third quarter and the first nine months of 2025, respectively, when compared to the third quarter and the first nine months of 2024. The decrease in absolute costs when compared to the same prior-year periods was primarily driven by lower workover activity, continued cost reduction efforts in all operating areas, and the sale of non-core assets in the Permian Basin. The decrease in absolute costs for the first nine months of 2025 was partially offset by a full year of operating cost activity related to the Callon transaction.

Previous wording

GPT costs decreased $17 million and increased $3 million from the second quarter and the first six months of 2024, respectively. The decrease in third-party costs for the second quarter of 2025 was primarily driven by decreased oil production volumes in the U.S. and decreased natural gas and NGL production volumes in the North Sea compared to the same prior-year period. The increase in third-party costs for the first six months of 2025 was driven by an increase in oil, natural gas, and NGL production volumes in the U.S. compared to the same prior-year period, primarily related to the Callon acquisition.

Current wording

GPT costs decreased $13 million and $10 million from the third quarter and the first nine months of 2024, respectively. The decrease in third-party costs for the third quarter of 2025 was primarily driven by decreased oil and NGL production volumes in the U.S. partially offset by production volumes resulting from downtime recovery in the North Sea compared to the same prior-year period. The decrease in third-party costs for the first nine months of 2025 was driven by decreases in average transportation rates compared to the same prior-year period.

Previous wording

Purchased oil and gas costs increased $94 million and $405 million from the second quarter and the first six months of 2024, respectively. The increase in the second quarter and the first six months of 2025 was primarily driven by increased oil volume purchases and gas volumes purchased at a higher rate coupled with activity associated with the Callon acquisition, compared to the same prior-year periods. 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 in the second quarter and first six months of 2025, as discussed above.

Current wording

Purchased oil and gas costs decreased $108 million and increased $297 million from the third quarter and the first nine months of 2024, respectively. The decrease in the third quarter of 2025 was primarily driven by decreased oil volume purchases, compared to the same prior-year periods. The increase in the first nine months of 2025 was primarily driven by increased oil volume purchases and gas volumes purchased at a higher rate coupled with 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 in the third quarter and first nine months of 2025, as discussed above.

Previous wording

Taxes other than income decreased $24 million and $7 million from the second quarter and the first six months of 2024, respectively, primarily from lower severance taxes driven by lower oil prices and lower ad valorem taxes.

Current wording

Taxes other than income decreased $19 million and $26 million from the third quarter and the first nine months of 2024, respectively, primarily from lower severance taxes driven by lower oil prices and lower ad valorem taxes.

Previous wording

Exploration expenses decreased $28 million and $146 million from the second quarter and the first six months of 2024, respectively. The decrease in expenses for the second quarter of 2025 was primarily driven by higher dry hole and seismic expenses in Alaska in the prior-year period. These decreases were partially offset by increased dry hole expenses in Egypt. The decrease in expenses for the first six months of 2025 was primarily driven by higher dry hole expenses in Alaska and Suriname in the prior-year period.

Current wording

Exploration expenses decreased $7 million and $153 million from the third quarter and the first nine months of 2024, respectively. The decrease in expenses for the third quarter of 2025 was primarily driven by higher dry hole and seismic expenses in Alaska in the prior-year period. The decrease in expenses for the first nine months of 2025 was primarily driven by higher dry hole expenses in Alaska and Suriname in the prior-year period.

Previous wording

G&A expenses decreased $19 million and $14 million from the second quarter and the first six months of 2024, respectively. The decreases in expenses compared with the comparative prior-year periods were primarily driven by the impacts of focused cost-reduction efforts on personnel and other overhead expenses. The decreases in expense for the first six months of 2025 were partially offset by higher cash-based stock compensation expense resulting from changes in expected payouts for the Company’s performance programs and the Company’s stock price.

Current wording

G&A expenses increased $3 million and decreased $11 million from the third quarter and the first nine months of 2024, respectively. The increase in expenses for the third quarter of 2025 compared to the same prior-year period was primarily driven by higher cash-based stock compensation expense resulting from changes in the Company’s stock price and expected payouts for the Company’s performance programs, which were largely offset by the impacts of focused cost-reduction efforts on personnel and other overhead expenses. The decrease in expenses for the first nine months of 2025 compared with the prior-year period was primarily the result of these focused cost-reduction efforts.

Previous wording

TRS costs decreased $104 million and $94 million from the second quarter and the first six months of 2024, respectively. TRS costs for 2025 were primarily associated with employee separations and other cost-saving initiatives, while TRS costs for 2024 comprised primarily expenses associated with the Callon merger.

Current wording

TRS costs increased $4 million and decreased $90 million from the third quarter and the first nine months of 2024, respectively. TRS costs for 2025 were primarily associated with employee separations and other cost-saving initiatives, while TRS costs for 2024 comprised primarily expenses associated with the Callon merger.

Previous wording

Total DD&A expenses decreased $58 million and increased $155 million from the second quarter and the first six months of 2024, respectively. The Company’s DD&A rate on its oil and gas properties decreased $1.05 per boe and increased $0.86 per boe from the second quarter and the first six months of 2024, respectively. The decrease in DD&A absolute expenses and on a per boe basis for the second quarter of 2025 was primarily driven by lower DD&A rates resulting from the sale of non-core assets in the Permian Basin. For the first six months of 2025, the Company’s higher DD&A rate on its oil and gas properties on a per boe basis was driven by year-end 2024 negative gas price-related reserve revisions in the U.S. Permian Basin coupled with higher DD&A rates resulting from the Callon acquisition. Higher absolute dollar amounts of DD&A for the first six months of 2025 was directly impacted by these higher rates.

Current wording

Total DD&A expenses decreased $30 million and increased $125 million from the third quarter and the first nine months of 2024, respectively. The Company’s DD&A rate on its oil and gas properties decreased $0.81 per boe and increased $0.29 per boe from the third quarter and the first nine months of 2024, respectively. The decrease in DD&A absolute expenses and on a per boe basis for the third quarter of 2025 was primarily driven by lower DD&A rates resulting from the sale of non-core assets in the Permian Basin. For the first nine months of 2025, the Company’s higher DD&A rate on its oil and gas properties on a per boe basis was driven by year-end 2024 negative gas price-related reserve revisions in the U.S. Permian Basin. Higher absolute dollar amounts of DD&A for the first nine months of 2025 were directly impacted by these higher rates.

Previous wording

Net financing costs decreased $34 million and $167 million from the second quarter and the first six months of 2024, respectively. The lower overall interest expense was primarily a result of lower outstanding credit facility borrowings compared to the prior-year periods. The decrease in total financing costs, net during the first six months of 2025 was further driven by gains on extinguishment of debt from the Company’s cash tender purchases during the first quarter of 2025.

Current wording

Net financing costs decreased $54 million and $221 million from the third quarter and the first nine months of 2024, respectively. The lower overall interest expense was primarily a result of lower outstanding credit facility borrowings compared to the prior-year periods. The decrease in net financing costs during the first nine months of 2025 was further driven by gains on extinguishment of debt from the Company’s cash tender purchases during the first quarter of 2025.

Previous wording

The Company’s effective income tax rate for the six months ended June 30, 2025 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations and a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2025 on March 20, 2025. The Company’s effective income tax rate for the six months ended June 30, 2024 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations.

Current wording

The Company’s effective income tax rate for the three and nine months ended September 30, 2025 differed from the U.S. federal statutory income tax rate of 21 percent due to taxes on foreign operations and a deferred tax expense related to the remeasurement of taxes in the U.K. as a result of the enactment of Finance Act 2025 on March 20, 2025. 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.

Previous wording

On March 20, 2025, Finance Act 2025 was enacted, receiving Royal Assent, and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022, increasing the levy from a 35 percent rate to a 38 percent rate, among other changes, effective for the period of November 1, 2024 through March 31, 2030. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, in the first quarter of 2025, the Company recorded a deferred tax expense of $76 million related to the remeasurement of the December 31, 2024 U.K. deferred tax liability.

Current wording

On March 20, 2025, Finance Act 2025 was enacted, receiving Royal Assent, and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022, increasing the levy from a 35 percent rate to a 38 percent rate, among other changes, effective for the period of November 1, 2024 through March 31, 2030. Under GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, in the first quarter of 2025, the Company recorded a deferred tax expense of $76 million related to the remeasurement of the December 31, 2024 U.K. deferred tax liability.

Previous wording

On July 4, 2025, the U.S. enacted the One Big Beautiful Bill Act of 2025 (OBBBA). Among other changes, the OBBBA expanded and made permanent 100 percent bonus depreciation for eligible assets acquired and placed in service after January 19, 2025, and aligned the treatment of intangible drilling costs for CAMT purposes with regular tax treatment starting in 2026. The Company does not expect the OBBBA to have a material impact on total tax expense for the year ended December 31, 2025. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, the Company will record the impact of OBBBA in the third quarter of 2025.

Current wording

On July 4, 2025, the U.S. enacted the One Big Beautiful Bill Act of 2025 (OBBBA). Among other changes, the OBBBA expanded and made permanent 100 percent bonus depreciation for eligible assets acquired and placed in service after January 19, 2025, and aligned the treatment of intangible drilling costs for CAMT purposes with regular tax treatment starting in 2026. The Company does not expect the OBBBA to have a material impact on total tax expense for the year ended December 31, 2025, as impacts to current tax expense are offset by impacts to deferred tax expense. In the third quarter of 2025, the Company has recorded a current tax benefit of $29 million fully offset by a deferred tax expense of the same amount.

Previous wording

The Company expects its full-year 2025 estimated upstream capital investment to be approximately $2.3 billion to $2.4 billion. During the second quarter of 2025, the Company initiated its plans to reduce Permian rig count from eight to six, reflecting a sustained step-change in drilling efficiencies. In Egypt, following the recent success of the gas program and the relative softening of oil prices, the Company now expects one-third of its activities to be gas-focused. This activity set equates to a combined development capital budget for the Permian Basin, Egypt, and North Sea of approximately $2.0 billion. In addition, the Company will invest approximately $275 million for Suriname development and $65 million for other exploration activities. APA remains committed to its capital return framework for equity holders to participate more directly and materially in cash returns through dividends and share repurchases.

Current wording

The Company expects its full-year 2025 estimated upstream capital investment to be approximately $2.3 billion to $2.4 billion. During the third quarter of 2025, continued efficiency gains allowed the Company to further reduce the Permian rig count to five, while increasing oil production outlook for fourth quarter. In Egypt, following the ongoing momentum of the Company’s gas program and the relative softening of oil prices, the Company expects one-third of its activities to be gas-focused. APA remains committed to its capital return framework for equity holders to participate more directly and materially in cash returns through dividends and share repurchases.

Previous wording

Net cash provided by operating activities during the first six months of 2025 totaled $2.3 billion, $1.1 billion higher from the first six months of 2024, primarily due to timing of working capital items.

Current wording

Net cash provided by operating activities during the first nine months of 2025 totaled $3.7 billion, $1.1 billion higher from the first nine months of 2024, primarily due to collection of outstanding receivables, lower overall expenses, and timing of other working capital items.

Previous wording

Fixed-Rate Debt Borrowings During the first six months of 2025, the Company issued new notes for proceeds of $846 million, after deducting discounts and loan costs, to fund in part APA’s purchase of Apache notes in APA’s cash tender offers.

Current wording

Fixed-Rate Debt Borrowings During the first nine months of 2025, the Company issued new notes for proceeds of $846 million, after deducting discounts and loan costs, to fund in part APA’s purchase of Apache notes in APA’s cash tender offers.

Previous wording

Proceeds from Asset Divestitures The Company received $571 million and $729 million in proceeds from the divestitures of certain non-core assets during the first six months of 2025 and 2024, 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.

Current wording

Proceeds from Asset Divestitures The Company received $590 million and $724 million in proceeds from the divestitures of certain non-core assets during the first nine months of 2025 and 2024, 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.

Previous wording

Additions to Oil & Gas Property During the first six months of 2025 and 2024, exploration and development cash expenditures were $1.4 billion and $1.2 billion, respectively. The increase in capital investment compared to the prior-year period is reflective of the properties acquired from the Callon acquisition, which increased the number of drilling rigs being operated in the Permian Basin, partially offset by the Company’s decision to eliminate drilling activity in the North Sea and the sale of certain non-core assets and leasehold in the Permian Basin. The Company operated an average of approximately 21 drilling rigs during the first six months of 2025, compared to an average of approximately 25 drilling rigs during the first six months of 2024.

Current wording

Additions to Oil & Gas Property During the first nine months of 2025 and 2024, exploration and development cash expenditures were $2.2 billion in each period. The capital investment is reflective of the Company’s plan to streamline capital deployment and the sale of certain non-core assets and leasehold in the Permian Basin. The Company operated an average of approximately 20 drilling rigs during the first nine months of 2025, compared to an average of approximately 23 drilling rigs during the first nine months of 2024.