APA
Updated: 24/09/2026, 08:31:29
APA Corporation operates in the upstream segment of the oil and natural gas industry, utilizing its various subsidiaries to explore for, develop, and produce hydrocarbon assets. The company maintains significant operational presences in the United States, Egypt, and the United Kingdom, while also conducting exploration activities offshore Suriname. Furthermore, APA Corporation manages critical gathering, processing, and transmission infrastructure within West Texas and holds ownership interests in four major pipelines connecting the Permian Basin to the Gulf Coast. Established in 1954, the company is headquartered in Houston, Texas.
No summaries found.
Reported and calculated KPIs plus operational exposure disclosed in the FY 2025 filing.
Revenue
N/A
FY — · Reported
Net income
$1.4B
FY 2025 · Reported
Gross margin
N/A
FY — · Reported
Free cash flow
N/A
FY — · Reported
R&D intensity
N/A
FY — · Reported
Share repurchases
N/A
FY — · Reported
Map layer
Pins show disclosed operations. The heatmap colors the filing’s reported geographies; regional figures shade the region and are not estimates for each country.
Only locations and quantities explicitly supported by the filing are displayed. A country-level manufacturing percentage or product allocation is shown only when the source discloses it; materiality scores are never presented as production shares.
Company overview
Independent E&P: oil/gas/NGL operations in U.S., Egypt, North Sea; exploration in Suriname, Uruguay, Alaska
“APA is an independent energy company that owns subsidiaries that explore for, develop, and produce crude oil, natural gas, and natural gas liquids (NGLs).”
Oil revenue by country 2025/2024/2023
Oil: US $3,010M/Egypt $2,177M/North Sea $622M (2025); Gas: US $193M/Egypt $460M/North Sea $117M; NGL: US $616M/North Sea $34M (2025), with 2024 and 2023 comparisons
“Oil Revenues: United States$3,010 52 %$3,572 51 %$2,241 37 %”
International production ~38% of 2025 production; ~26% of proved reserves
Approximately 38% of 2025 production and ~26% of proved reserves (Dec 31, 2025) outside the U.S.; operations primarily in Egypt, U.K., and offshore Suriname
“approximately 38 percent of the Company’s 2025 production was outside the U.S., and approximately 26 percent of the Company’s estimated proved oil and gas reserves as of December 31, 2025, were located outside the U.S.”
Oil price sensitivity
$1.00/bbl oil price change = ~$87 million revenue impact (2025 avg daily production basis)
“a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the year by approximately $87 million”
Natural gas price sensitivity
$0.10/Mcf gas price change = ~$33 million revenue impact
“a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the year by approximately $33 million”
Open natural gas derivatives net liability
Open natural gas derivatives (non-hedge) in $77 million net liability position at Dec 31, 2025
“the Company had open natural gas derivatives not designated as cash flow hedges in a net liability position with a fair value of $77 million”
NGL price sensitivity
$1.00/bbl NGL price change = ~$28 million revenue impact
“a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the year by approximately $28 million”
British pound exposure - North Sea
North Sea production sold in USD while majority of costs paid in GBP; £120 million FX contracts post-year-end to hedge decommissioning-related exposure
“Subsequent to December 31, 2025, the Company entered into outstanding foreign exchange contracts with a total notional amount of £120 million to reduce its exposure to fluctuating foreign exchange rates for the British pound.”
Egypt currency profile
Egypt production sold under USD contracts; majority of costs denominated in USD
“The Company’s Egypt production is sold under U.S. dollar contracts, and the majority of costs incurred are denominated in U.S. dollars.”
Callon Petroleum acquisition
Callon Petroleum acquired April 1, 2024 for ~$4.5B all-stock incl. debt (~120,000 Delaware acres, 25,000 Midland acres)
“On April 1, 2024, APA completed its acquisition of Callon Petroleum Company (Callon) in an all-stock transaction valued at approximately $4.5 billion”
Egypt acreage award
Government of Egypt awarded 2 million net exploration acres in Western Desert; $25M signature bonus plus drilling commitment
“the Government of Egypt awarded the Company an additional two million net exploration acres in the Western Desert”
2025 sale of New Mexico Permian assets
Sold all New Mexico Permian assets in Q2 2025 for $571M cash (carrying value $282M)
“the Company completed the sale of all of its New Mexico Permian assets...exchanged for total cash consideration of $571 million, inclusive of post-closing adjustments.”
2024 Permian Basin non-core divestiture with impairment
Q3 2024 agreement to sell non-core Permian Basin properties; $315M impairment based on agreed proceeds less costs to sell (Level 1)
“the Company entered into an agreement to sell certain non-core U.S. oil and gas producing properties in the Permian Basin”
Fixed-rate debt outstanding
$4.5 billion net fixed-rate notes and debentures at 5.66% weighted average rate as of Dec 31, 2025
“the Company had $4.5 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 5.66 percent”
Debt and liquidity position at YE2025
Total debt $4.49B (-$1.6B YoY); cash $516M; $4.02B available committed borrowing capacity; $211M notes due within next year
“As of December 31, 2025, the Company had $4.5 billion in total debt outstanding”
Undrawn short-term credit facilities
No borrowings under term loan, commercial paper, or revolver as of Dec 31, 2025; ~$516 million cash, ~95% in money market funds/short-term investments
“there were no borrowings outstanding under the Company’s term loan facility, commercial paper program, and syndicated revolving credit facilities”
Credit facilities and Sinopec distributions
New $2.0B USD and £1.5B GBP five-year revolving facilities (Jan 2025, mature 2030); Sinopec holds one-third Egypt interest, paid $430M distributions in 2025
“Sinopec holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt.”
APA exchange/tender offers and new notes
Jan 2025: exchanged ~$2.7B APA notes for Apache notes; issued $850M new notes (6.10% 2035, 6.75% 2055); paid $869M cash for $1B Apache notes; $135M gain
“APA issued new notes and debentures under its indentures in aggregate principal amounts of (i) $2.5 billion in exchange for Apache notes”
Permian rig outlook and gas transport hedging
5 Permian rigs currently; 2026 oil production targeted flat vs 2025; ~750,000 MMBtu/d firm transport, ~1/3 hedged via Waha basis swaps for 2026
“The Company holds approximately 750,000 MMBtu/d of firm capacity on various pipelines.”
Alaska exploration discovery
Alaska exploratory well discovery confirmed Q1 2025; flow test averaged 2,700 b/d; APA holds 50% interest
“A successful flow test of the well was announced in April, with the well averaging 2,700 b/d during the final flow period. The Company holds a 50 percent ownership interest in the project.”
Office building impairment on anticipated sale
$18 million impairment in 2025 for anticipated sale of an office building
“the Company recorded an $18 million impairment for the anticipated sale of an office building.”
Commodity price volatility risk
Revenues and carrying value of oil and gas properties depend highly on crude oil, natural gas, and NGL prices; NYMEX prompt-month oil in 2025 ranged $55.44-$80.73/bbl and natural gas $2.65-$9.86/MMBtu
“The Company’s revenues, operating results, future rate of growth, and carrying value of its oil and gas properties depend highly upon the prices it receives for its sales of crude oil, natural gas, and NGL products.”
Commodity price volatility risk
Revenues, earnings, cash flow and growth highly dependent on volatile crude oil, natural gas, and NGL prices
“highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile”
OPEC+ and geopolitical influence on prices
Prices depend on factors beyond company control including OPEC/OPEC+ actions, political instability, alternative energy competitiveness, pipeline capacity, and climate regulations
“actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC) and non-OPEC members that participate in OPEC initiatives (OPEC+);”
North Sea production to cease before 2030 due to Energy Profits Levy economics
Company expects to cease North Sea production prior to 2030 because expected returns did not economically support investments required under regulations
“determined that expected returns did not economically support making investments required under the combined impact of the regulations and now expects to cease production at its facilities in the North Sea prior to 2030.”
Frontier exploration risk in Alaska, Suriname, Uruguay
Frontier exploration portfolio in Alaska and offshore Suriname and Uruguay involves heightened operational, regulatory, and execution risks
“The Company’s exploration and development portfolio includes higher‑risk frontier opportunities, including in Alaska and offshore Suriname and Uruguay”
Midstream/third-party transportation dependency
Ability to sell production and meet transportation volume commitments depends on pipeline/gathering capacity and financial health of midstream providers
“the financial distress or insolvency of midstream or transportation providers that could reduce available capacity or disrupt service.”
Energy transition and ESG demand risk
Energy transition could reduce demand for hydrocarbon-powered products and the prices received for crude oil, natural gas, and NGLs
“increased availability of, and demand for, energy sources other than oil and natural gas, including wind, solar, and hydroelectric power”
North Sea decommissioning regulatory uncertainty (OPRED OSPAR consultation)
OPRED opened consultation Sept 5, 2025 on draft guidance under OSPAR Decision 98/3 emphasizing 'clear seabed' policy; adoption could materially increase North Sea decommissioning obligations and costs
“The consultation materials emphasize a policy objective of achieving a “clear seabed,” a presumption in favor of removal, and an expectation of a reduction in derogations”
Produced water disposal regulation and seismicity restrictions
Regulators such as the Railroad Commission of Texas have limited disposal well activities and required seismic monitoring; disposal restrictions could raise water costs or limit operations
“Regulators in some states, such as the Railroad Commission of Texas, have taken actions to limit disposal well activities (including orders to temporarily shut down or to curtail water injection)”
Hedging may limit upside and create earnings volatility
Price risk management may prevent benefiting from price increases; no hedge accounting applied, causing earnings volatility
“because the Company does not apply hedge accounting to its derivative instruments, changes in the fair value of derivatives are recognized in current-period earnings”
Weather/climate impact on production
Severe weather (freezing, Gulf of America hurricanes, North Sea storms) has previously caused production loss and equipment damage
“severe weather, such as freezing temperatures, hurricanes in the Gulf of America, or major storms in the North Sea, each of which have previously caused and may cause a loss of production”
Decommissioning cost inflation and partner default risk
Inflation, supply constraints, and limited contractor/vessel availability have raised decommissioning costs; partners or third parties may fail to meet decommissioning funding obligations
“inflation, supply constraints, and limited contractor and vessel availability have raised decommissioning costs in recent periods”
Potential repeal of oil and gas tax incentives
Legislative proposals could repeal percentage depletion, eliminate IDC deductions, and extend G&G amortization periods
“the repeal of the percentage depletion allowance for oil and gas properties, the elimination of current deductions for intangible drilling and development costs”
Permian takeaway capacity could compress third-party gas gains
New Permian gas pipeline takeaway capacity may compress Permian–Gulf Coast price spreads, reducing gains on third-party purchases and sales
“As additional gas pipeline takeaway capacity in the Permian Basin comes online, the spread between Permian and Gulf Coast gas prices may compress, which would reduce the Company’s gain on third-party oil and gas purchases and sales.”
Oil price realizations directly drive revenue; $1.00/bbl change = ~$87 million annual revenue impact.
“revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs”
Company revenues, operating results, and carrying value of oil and gas properties depend highly on crude oil prices, which were volatile in 2025 ($55.44–$80.73/bbl NYMEX prompt month).
“The Company’s revenues, operating results, future rate of growth, and carrying value of its oil and gas properties depend highly upon the prices it receives for its sales of crude oil, natural gas, and NGL products.”
Revenue and capital program depend on oil prices; company may moderate 2026 Permian activity if oil prices decline and hedges Waha-Henry Hub basis on gas transport.
“Should oil prices decline, the Company may moderate activity in 2026 and further reduce capital spending.”
Future commodity prices are the largest driver of cash flow variability used in impairment testing and UOP depreciation.
“Future production volumes and estimated future commodity prices are the largest drivers in the variability of future cash flows.”
Natural gas prices (NYMEX prompt month 2025 range $2.65–$9.86/MMBtu) directly drive revenues and third-party purchase/sale gains.
“the NYMEX daily settlement price for the prompt month natural gas contract in 2025 ranged from a high of $9.86 per MMBtu to a low of $2.65 per MMBtu.”
Substantially all Egypt natural gas production is sold to EGPC under a new gas sales agreement effective January 2025; Egypt is ~37% of oil revenue.
“Effective January 2025, substantially all of the Company’s natural gas production was sold to EGPC under the terms of this agreement.”
38% of 2025 production and 26% of proved reserves outside the U.S. (primarily Egypt and U.K.) expose a significant portion of production to international political and economic risks including civil unrest, expropriation, exchange controls, and forced contract renegotiation.
“approximately 38 percent of the Company’s 2025 production was outside the U.S., and approximately 26 percent of the Company’s estimated proved oil and gas reserves as of December 31, 2025, were located outside the U.S.”
North Sea cessation-of-production decisions drove the $796M 2024 impairment and continued inventory and drilling-suspension charges.
“This change significantly altered the Company's remaining oil and gas reserves in the North Sea and triggered an impairment assessment”
International conflicts, inflation, tariffs, global trade disputes, and OPEC+ actions contribute to commodity price volatility affecting supply and demand.
“current and potential tariffs or other trade barriers, global trade policies and disputes, and actions taken by foreign oil and gas producing nations, including OPEC+”
Gas realizations drive revenue ($0.10/Mcf = ~$33 million) and open derivatives create a $77 million net liability sensitive to price moves.
“a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the year by approximately $33 million”
Receivables from EGPC represent a monitored collection risk that could affect cash flow and credit losses.
“the Company continues to closely monitor its exposure to EGPC, as payment patterns may vary over time.”
Significant exploration, appraisal, and development activities offshore Suriname involve long-cycle projects with heightened regulatory, execution, and host-government approval risks.
“significant exploration, appraisal, and development activities offshore Suriname, which involve long-cycle projects with significant capital requirements and are subject to host-government approvals”
UK operations exposed to Energy Profits Levy-type regulations driving North Sea exit before 2030, evolving decommissioning rules (OPRED/OSPAR), and GHG-related fees.
“determined that expected returns did not economically support making investments required under the combined impact of the regulations and now expects to cease production at its facilities in the North Sea prior to 2030.”
Ability to sell production, receive market prices, and meet volume commitments under transportation agreements depends on pipeline/gathering capacity and the financial health of midstream providers.
“the financial distress or insolvency of midstream or transportation providers that could reduce available capacity or disrupt service.”
Growth of alternative energy sources and lower-emission products could reduce demand and prices for the Company's crude oil, natural gas, and NGLs.
“Further developments could adversely impact the demand for products powered by or manufactured with hydrocarbons and the demand for, and in turn the prices the Company receives for, its crude oil, natural gas, and NGL products”
Global supply chain and financial market uncertainties impact oil supply and demand and contribute to commodity price volatility that drives revenue.
“Uncertainties in the global supply chain and financial markets impact oil supply and demand and contribute to commodity price volatility.”
Company subject to 15% Corporate AMT effective January 1, 2024; any resulting AMT liability could adversely affect earnings and cash flows.
“Effective January 1, 2024, the Company is subject to the Corporate AMT.”
Sinopec holds a one-third minority participation interest in Egypt oil and gas operations and received $430 million in cash distributions in 2025.
“Sinopec holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt.”
Asset retirement obligations, dismantlement, restoration and abandonment costs feed depreciation and liability estimates, with North Sea oil held in inventory pending sale.
“Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.”
Rising allowance for credit losses ($140M at end of 2025, up from $123M) reflects counterparty credit-quality and liquidity monitoring.
“The Company monitors the credit quality of its counterparties through review of collections, credit ratings, and other analyses.”
North Sea revenues in USD but costs (including decommissioning obligations) in GBP, creating FX mismatch hedged with £120 million forwards.
“The Company is subject to increased foreign currency risk associated with the effects of decommissioning obligations in the North Sea.”
Egypt is a production geography with USD-denominated production contracts and mostly USD costs, limiting direct FX exposure there.
“The Company’s Egypt production is sold under U.S. dollar contracts, and the majority of costs incurred are denominated in U.S. dollars.”
Capitalized interest is based on the Company's weighted-average borrowing cost on debt, linking rates to asset carrying values; a market-based WACC also discounts impairment cash flows.
“Capitalized interest is determined by multiplying the Company's weighted-average borrowing cost on debt by the average amount of qualifying costs incurred.”
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