ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
You should read the following discussion and analysis in conjunction with the consolidated financial statements and related notes included in Item 8. Financial Statements and Supplementary Data. All references to “CF Holdings,” “we,” “us,” “our” and “the Company” refer to CF Industries Holdings, Inc. and its subsidiaries, except where the context makes clear that the reference is to CF Industries Holdings, Inc. only and not its subsidiaries. All references to “CF Industries” refer to CF Industries, Inc., a 100% owned subsidiary of CF Industries Holdings, Inc. References to tons refer to short tons. Notes referenced in this discussion and analysis refer to the notes to consolidated financial statements that are found in Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements. For a discussion and analysis of the year ended December 31, 2024 compared to the year ended December 31, 2023, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2024 Annual Report on Form 10-K filed with the Securities and Exchange Commission (SEC) on February 20, 2025. The following is an outline of the discussion and analysis included herein:
• Overview of CF Holdings
• Market Conditions and Current Developments
• Financial Executive Summary
• Items Affecting Comparability of Results
• Consolidated Results of Operations
• Operating Results by Business Segment
• Liquidity and Capital Resources
• Critical Accounting Estimates
• Recent Accounting Pronouncements
Overview of CF Holdings
Our Company
Our mission is to provide clean energy to feed and fuel the world sustainably. With our employees focused on safe and reliable operations, environmental stewardship, and disciplined capital and corporate management, we are on a path to decarbonize our ammonia production network – the world’s largest – to enable low-carbon hydrogen and nitrogen products for energy, fertilizer, emissions abatement, and other industrial activities. Our value chain consists of manufacturing complexes in the United States, Canada and the United Kingdom, an extensive storage, transportation and distribution network in North America, and logistics capabilities enabling a global reach. In July 2025, we completed a significant decarbonization project at our Donaldsonville, Louisiana, complex to enable the production of low-carbon ammonia. Additionally, we are executing further decarbonization projects in our existing network and constructing a greenfield low-carbon ammonia plant at our Blue Point complex to drive our strategy to leverage our unique capabilities to accelerate the world’s transition to clean energy.
Our principal customers are cooperatives, retailers, independent fertilizer distributors, traders, wholesalers and industrial users. Our core product is anhydrous ammonia (ammonia), which contains 82% nitrogen and 18% hydrogen. Products derived from ammonia that are most often used as nitrogen fertilizers include granular urea, urea ammonium nitrate solution (UAN) and ammonium nitrate (AN). AN is also used extensively by the commercial explosives industry as a component of explosives. Products derived from ammonia that are sold primarily to industrial customers include diesel exhaust fluid (DEF), urea liquor, nitric acid and aqua ammonia. In addition, our low-carbon products are expected to be used for existing and new applications, such as power generation and steel production in Japan, and to help customers reduce the economic impact of European regulations on the price of carbon.
Our principal assets as of December 31, 2025 include:
• six U.S. manufacturing facilities, located in Donaldsonville, Louisiana (the largest ammonia production complex in the world); Sergeant Bluff, Iowa (our Port Neal complex); Yazoo City, Mississippi; Claremore, Oklahoma (our Verdigris complex); Woodward, Oklahoma; and Waggaman, Louisiana. The Waggaman facility is wholly owned by us, and the other five U.S. manufacturing facilities are wholly owned directly or indirectly by CF Industries Nitrogen, LLC (CFN), of which we own approximately 89% and CHS Inc. (CHS) owns the remainder (see Note 18—Noncontrolling Interests for additional information on our strategic venture with CHS);
• two Canadian manufacturing facilities, located in Medicine Hat, Alberta (the largest ammonia production complex in Canada) and Courtright, Ontario;
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• a United Kingdom manufacturing facility located in Billingham;
• an extensive system of terminals and associated transportation equipment located primarily in the Midwestern United States;
• a 50% interest in Point Lisas Nitrogen Limited (PLNL), an ammonia production joint venture located in Trinidad and Tobago (Trinidad) that we account for under the equity method; and
• a 40% interest in Blue Point Number One, LLC, a joint venture formed on April 8, 2025 (the Blue Point joint venture), to construct a manufacturing plant at our Blue Point complex located in Modeste, Louisiana. The joint venture entity is a variable interest entity (VIE) of which we are the primary beneficiary. As a result, we consolidate this entity in our consolidated financial statements, with the combined 60% equity interest owned by our joint venture partners recorded as noncontrolling interests. See “Our Strategy—Blue Point joint venture,” below, for additional information.
Our Strategy
At our core, CF Industries is a producer of ammonia. We use the Haber-Bosch process to fix atmospheric nitrogen with hydrogen from natural gas to produce anhydrous ammonia, whose chemical composition is NH 3 . We sell the ammonia itself or upgrade it to products such as granular urea, UAN and DEF. A majority of the ammonia and ammonia-derived products we manufacture are used as fertilizer, as the nitrogen content provides energy essential for crop growth. Other important uses of our products include emissions control.
Our strategy is to leverage our unique capabilities to accelerate the world’s transition to clean energy. Our unique capabilities include: advantaged production, unmatched distribution and logistics network, operational excellence and disciplined capital stewardship.
Our leadership in ammonia production enables us to drive continued operational excellence in our underlying business while investing in decarbonization technologies to produce ammonia with a lower carbon intensity than that of ammonia produced through traditional processes (“low-carbon ammonia”). These investments allow us to pursue demand for low-carbon ammonia and upgraded products for both traditional and new applications. Traditional applications include agriculture, where low-carbon nitrogen products can be used to reduce the carbon footprint of food production and the life cycle carbon intensity of ethanol production. New growth opportunities include power generation and marine shipping, which are hard-to-abate industries for which low-carbon ammonia offers a potential path to significantly lower carbon footprints as it does not contain or emit carbon when combusted.
Decarbonizing our existing network
At our Donaldsonville and Yazoo City complexes, our decarbonization projects are leveraging carbon capture and sequestration (CCS) to enable us to convert a portion of our existing ammonia production to low-carbon ammonia production. CCS requires the construction of carbon dioxide (CO 2 ) dehydration and compression units to enable process CO 2 captured from the ammonia production process to be transported and sequestered, which prevents approximately 60% of the CO 2 generated by ammonia production from being emitted to the atmosphere. For each facility we have contracted with ExxonMobil to transport and permanently store the captured CO 2 .
In July 2025, construction, commissioning and start-up of the dehydration and compression unit at our Donaldsonville complex was completed for a total cost of approximately $200 million. The dehydration and compression unit enables the transportation and permanent geological sequestration of up to 2 million metric tons of CO 2 annually, depending on gross ammonia production and consumption of CO 2 for upgraded products. This sequestered CO 2 would otherwise be emitted into the atmosphere. ExxonMobil, our CCS partner for this project, is transporting and permanently storing the CO 2 . The project qualifies for tax credits under Section 45Q of the Internal Revenue Code (45Q Tax Credits), which provide a tax credit per metric ton of CO 2 captured and disposed of in secure geological storage. As a result of the Donaldsonville CCS project, we have the capacity to produce up to approximately 1.9 million tons of low-carbon ammonia annually at our Donaldsonville complex.
On an interim basis, ExxonMobil is storing CO 2 from our Donaldsonville complex in permanent geologic sites through enhanced oil recovery. Upon receiving its Class VI permit, ExxonMobil plans to transition to dedicated permanent storage, starting with its Rose CCS project (Rose). Rose is one of many dedicated permanent storage sites ExxonMobil is developing along the Gulf Coast to expand its integrated CCS network. The U.S. Environmental Protection Agency issued the final Class VI permits for Rose in October 2025. Beginning of storage activities at Rose also requires authorization from the Railroad Commission of Texas.
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Construction of the dehydration and compression unit at our Yazoo City complex is expected to cost approximately $100 million. At Yazoo City, CCS is expected to commence in 2028, following construction, commissioning and start-up, and annually is expected to enable the transportation and sequestration of up to approximately 500,000 metric tons of CO 2 that would otherwise have been emitted into the atmosphere. The Yazoo City CCS project is expected to qualify for 45Q Tax Credits, which provide a tax credit per metric ton of CO 2 captured and disposed of in secure geological storage.
In the fourth quarter of 2025, we completed a nitric acid plant abatement project at our Verdigris complex. The abatement project is expected to significantly reduce nitrous oxide emissions from the plant, lowering CO 2 equivalent emissions by over 600,000 metric tons on an annual basis.
Blue Point joint venture
On April 8, 2025, we formed the Blue Point joint venture, with JERA Co., Inc. (JERA), Japan’s largest energy company, and Mitsui & Co., Ltd. (Mitsui), a leading global investment and trading company, to construct a low-carbon ammonia production facility at our Blue Point complex located in Modeste, Louisiana. We hold 40% ownership, JERA holds 35% ownership, and Mitsui holds 25% ownership in the Blue Point joint venture. Under the terms of the Blue Point joint venture’s limited liability company agreement, JERA had a conditional option that, if the specified condition were met, JERA could reduce its ownership percentage below 35% but not lower than 20%. We would have had the right and obligation to increase our ownership by the same amount had JERA opted to reduce its ownership. The option expired and is no longer exercisable.
The Blue Point joint venture is expected to construct an autothermal reforming (ATR) ammonia production facility with a CO 2 dehydration and compression unit to prepare captured CO 2 for transportation and sequestration. Engineering, equipment procurement and pre-construction activities at our Blue Point complex began in the second quarter of 2025. Construction of the ammonia production facility is expected to begin in 2026, with low-carbon ammonia production expected to begin in 2029. We are responsible for overseeing and managing the development, construction, operation and maintenance of the ammonia production facility under contracts with the Blue Point joint venture. We, JERA and Mitsui are required to purchase low-carbon ammonia produced by the Blue Point joint venture in accordance with our respective ownership percentages once production commences.
We estimate that the cost of the low-carbon ATR ammonia production facility with CCS technologies will be approximately $3.7 billion. We anticipate that approximately one-third of the estimated cost is related to materials that will be imported to the United States, with the majority of imported materials expected to arrive in Louisiana in 2028. Pursuant to periodic capital calls, the Blue Point joint venture members will fund the cost of the facility’s engineering, procurement and construction according to their respective ownership percentages. During the year ended December 31, 2025, we, JERA and Mitsui made capital contributions of $195 million, $170 million and $121 million, respectively, to the Blue Point joint venture. We funded $152 million of our contributions with cash and $43 million through a non-cash contribution of a license to use certain intellectual property.
The low-carbon ammonia production facility is designed with an annual nameplate capacity of approximately 1.4 million metric tons (approximately 1.5 million tons) and is expected to capture greater than 95% of the CO 2 generated from its production of ammonia. The facility is expected to capture, compress and dehydrate approximately 2.3 million metric tons of CO 2 annually. Pursuant to a long-term offtake agreement, a joint venture between a subsidiary of Occidental Petroleum Corporation and Enbridge Inc. would then transport the CO 2 and permanently sequester it in a Class VI well at its Pelican Sequestration Hub in Louisiana, which is currently under development. The ammonia production facility is expected to qualify for 45Q Tax Credits, which provide a tax credit per metric ton of CO 2 captured and disposed of in secure geological storage.
In June 2025, the Blue Point joint venture executed agreements, including a long-term supply agreement, with a subsidiary of Linde plc for them to design, construct, own, operate and maintain an air separation unit (ASU) at our Blue Point complex to supply oxygen and nitrogen to the low-carbon ATR ammonia production facility. Thus, our estimate of the cost of the low-carbon ATR ammonia production facility of approximately $3.7 billion, as noted above, excludes the costs to construct an ASU.
In addition, we plan to invest approximately $550 million to build scalable infrastructure at our Blue Point complex to supply the ammonia production facility with services, including product storage and vessel loading. We will own and operate this infrastructure, and the Blue Point joint venture will compensate us for these services.
We determined that the Blue Point joint venture is a VIE of which we are the primary beneficiary. As a result, we consolidate this VIE in our consolidated financial statements, with the combined 60% equity interest owned by JERA and Mitsui recorded as noncontrolling interests. See “Liquidity and Capital Resources—Blue Point Joint Venture,” below, and Note 14—Variable Interest Entity, for additional information on the Blue Point joint venture.
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Low-carbon ammonia demand
We believe that our decarbonization projects provide us with benefits: progress toward our long-term emissions reduction goals, a significant return profile, and a differentiated product offering to existing and new customers.
In 2025, we completed our first sales of low-carbon ammonia at a premium to traditional ammonia consumers in Europe and Africa as they began to establish a low-carbon ammonia supply chain. We expect continued demand growth for low-carbon ammonia and upgraded products into Europe as customers seek to reduce the additional costs imposed by the European Union’s regulations, including the carbon border adjustment mechanism in respect of GHG emissions associated with the production of imported ammonia and upgraded products.
In 2025, our expectation that there is developing demand for low-carbon ammonia for new applications of our products was confirmed through our joint venture partners, JERA and Mitsui. They have committed low-carbon ammonia volumes from the Blue Point joint venture for power generation and steel production, among other uses, which represent new applications for our products. In December 2025, both JERA and Mitsui were certified as a Supplier of Low-Carbon Hydrogen and its Derivatives by Japan’s Ministry of Economy, Trade and Industry. The certifications were granted under the “Support Focusing on the Price Gap” scheme established in accordance with the Hydrogen Society Promotion Act.
We continue to engage in discussions with existing and potential customers who have interest in using low-carbon ammonia for traditional applications as well as for the supply of low-carbon ammonia for new applications. We are evaluating and are in various stages of discussions with other companies for long-term offtake and/or potential joint investments related to new and traditional applications for low-carbon ammonia. These discussions continue to advance as we gain greater clarity regarding demand for low-carbon ammonia, including associated carbon intensity requirements, government incentives and regulatory developments.
Industry Factors
We operate in a highly competitive, global industry. Our operating results are influenced by a broad range of factors, including those outlined below.
Global Supply and Demand Factors
Our products are global commodities or derived from global commodities and are subject to price competition. The customers for our products make their purchasing decisions principally on the basis of delivered price and, to a lesser extent, on low-carbon attributes, reliability, customer service and product quality. The selling prices of our products fluctuate in response to global market conditions, changes in supply and demand and cost factors.
Historically, global fertilizer demand has been driven primarily by population growth, gross domestic product growth, changes in dietary habits, planted acreage, and application rates, among other things. We expect these key variables to continue to have major impacts on long-term fertilizer demand for the foreseeable future. Short-term fertilizer demand growth may depend on global economic conditions, farm sector income, weather patterns, the level of global grain stocks relative to consumption, fertilizer application rates, and governmental regulations, including fertilizer subsidies or requirements mandating increased use of bio-fuels or industrial nitrogen products, such as DEF. Geopolitical factors such as temporary disruptions in fertilizer trade related to government intervention, shipping delays and/or cost increases resulting from regional conflicts or changes in the buying/selling patterns of key exporting/consuming countries, including China, India, Russia and Brazil, among others, often play a major role in shaping near-term market fundamentals. The economics of nitrogen-based fertilizer manufacturing play a key role in decisions to increase or reduce production capacity. Supply of fertilizers is generally driven by available capacity and operating rates, raw material costs and availability, government policies and global trade. Raw materials are dependent on energy sources such as natural gas or coal; therefore, supply costs are affected by the supply of and demand for those commodities.
Global Trade in Fertilizer
Profitability of our products within a particular geographic region is determined not only by the relationship between global supply and demand, but also by the supply/demand balance within that region. Regional supply and demand can be influenced significantly by factors affecting trade within regions. Some of these factors include the relative cost to produce and deliver product, relative currency values, the availability of credit, agricultural supply and demand, industrial product demand and policies such as emissions abatement, government support for manufacturers or purchasers and governmental nitrogen product trade policies, including the imposition of duties, tariffs or quotas, that affect foreign trade or investment. Government energy or carbon policies may also affect regional nitrogen supply and demand. The development of additional natural gas reserves in North America has decreased natural gas costs in North America relative to the rest of the world, making North
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American nitrogen fertilizer producers more competitive. Changes in currency values may also alter our cost competitiveness relative to producers in other regions of the world.
North American nitrogen fertilizer demand for certain products is dependent on imports to balance supply and demand, and imports traditionally account for a significant portion of nitrogen fertilizer products consumed in North America. Producers of nitrogen-based fertilizers located in the Middle East, Trinidad, Africa and Russia have been major exporters to North America in recent years.
Farmers’ Economics
The demand for fertilizer is affected by the aggregate crop planting decisions and fertilizer application rate decisions of individual farmers. Individual farmers make planting decisions based largely on prospective profitability of a harvest, while the specific varieties and amounts of fertilizer they apply depend on factors like their current liquidity, soil conditions, weather patterns, crop and fertilizer prices, fertilizer products used and timing of applications, expected yields and the types of crops planted.
Market Conditions and Current Developments
Government Policies
Since January 20, 2025, the Trump administration has imposed, modified and proposed additional tariffs on a range of products from most countries around the world, including global tariffs and tariffs on imports from Canada pursuant to the International Emergency Economic Powers Act (IEEPA). The Trump administration has negotiated and is negotiating tariff and trade agreements that have resulted in, and will continue to result in, changes to existing tariffs and other trade policies in the United States and globally. From March 6, 2025, the United States excluded from IEEPA-based tariffs any products that entered the United States duty-free as a good of Canada pursuant to the United States-Mexico-Canada Agreement, such that U.S. tariffs on Canadian imports were not applicable to our Canadian production. Effective November 13, 2025, the Trump administration exempted most fertilizer products, including urea, UAN and AN, but not ammonia, from IEEPA global tariffs announced on April 5, 2025.
On February 20, 2026, the U.S. Supreme Court ruled that IEEPA does not authorize the president to impose tariffs, including IEEPA-based global tariffs and tariffs on imports from Canada. Invoking other legal authority, the president responded by imposing a 10% tariff on most products imported into the United States on or after February 24, 2026, which may run for up to 150 days absent further congressional extension. The proclamation imposing the 10% tariff continues the IEEPA tariff exemptions that were applicable to our Canadian production and to most fertilizer products, which are both described above. The Supreme Court decision did not modify non-IEEPA tariffs, including tariffs on imports of certain steel and aluminum products and their derivatives which may impact the cost of our capital equipment, including for development and construction at our Blue Point complex.
Trade agreements that were recently negotiated between the United States and the European Union (EU) and several other countries, may be continued or paused, or further negotiations regarding trade agreements may result in changes to the magnitude, timing or other aspects of tariffs between these countries. For example, the EU is seeking clarity from the Trump administration on tariffs to be imposed in response to the U.S. Supreme Court decision before fully implementing the United States-European Union Framework on an Agreement on Reciprocal, Fair, and Balanced Trade, in which the EU committed to eliminate its tariffs on U.S. imports of nitrogen fertilizer products.
There remains significant uncertainty regarding recent tariff developments. Proposed or enacted tariffs and changes to U.S. trading policies may be reinstituted, paused, removed or changed at any time and may also be subject to litigation. Retaliatory tariffs or other imposition of taxes and duties on U.S. exports to trading partners may also be significant and occur at any time. Changes in U.S. trade policy or changes in other countries’ trade policies has and may continue to lead to uncertainty in the global marketplace, impact the supply and demand balance in many regions, and increase the cost of capital equipment and other supplies, which could adversely affect our business, financial condition, results of operations and cash flows.
President Trump signed an Executive Order (EO) on December 6, 2025, on competitive activity in the food supply chain. The EO directs the Attorney General and the Federal Trade Commission to each establish a Food Supply Chain Security Task Force to investigate price-fixing and anti-competitive practices across the sector, including fertilizer, and take action as necessary, including bringing enforcement actions and proposing new regulatory approaches. The EO is particularly focused on “foreign entities” and “foreign control” within the food supply chain.
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U.S. Tax Legislation
On July 4, 2025, H.R.1 - One Big Beautiful Bill Act (the Act) was enacted into law. The Act makes permanent certain elements of the Tax Cuts and Jobs Act, including 100% bonus depreciation on qualified property, and modifies several international tax provisions, including the foreign-derived intangible income deduction. The legislation has multiple effective dates, with certain provisions becoming effective in fiscal year 2025 and the majority taking effect in future years. We began reflecting the impact of the Act in the third quarter of 2025, and it did not have a material impact on our income tax expense for the year ended December 31, 2025. In addition, we expect the Act will not have a material impact on our income tax expense in future periods. However, certain provisions of the Act affected the timing of cash tax payments in 2025 and are expected to affect the timing of cash tax payments in future periods.
Nitrogen Selling Prices and Sales Volume
Our nitrogen products are globally traded commodities with selling prices that fluctuate in response to global market conditions, changes in supply and demand, and other cost factors including domestic and local conditions. Intense global competition—reflected in import volumes and prices—strongly influences delivered prices for nitrogen fertilizers. In general, the prevailing global prices for nitrogen products must be at a level to incent the high-cost marginal producer to produce product at a breakeven or above price, or else they would cease production and leave a portion of global demand unsatisfied.
Average selling prices for all of our major products were higher in 2025 than in 2024 due primarily to strong global demand for all nitrogen products and supply disruptions due to geopolitical issues, including unexpected production outages in Egypt, Iran and Russia. Global demand was particularly strong in North America, India and Brazil. The average selling price for our products was $372 per ton in 2025 compared to $313 per ton in 2024. The 19% increase in the average selling price for our products in 2025 compared to 2024 resulted in a year-over-year increase in net sales of approximately $1.06 billion.
Our total sales volume was 1% higher in 2025 than in 2024, due primarily to higher sales volume in our Ammonia and UAN segments, partially offset by lower sales volume in our Granular Urea and AN segments. We shipped 19.1 million tons of product in 2025 compared to 18.9 million tons in 2024. This resulted in an increase in net sales of approximately $84 million for 2025 compared to 2024. The increase was due to higher supply availability as a result of increased production in 2025 compared to 2024, which was adversely impacted by production outages from a winter storm in the first quarter of 2024.
Sales volume for our products in 2025, 2024 and 2023 is shown in the table below.
Sales Volume (tons)
Net Sales
Sales Volume (tons)
Net Sales
Sales Volume (tons)
Net Sales
(tons in thousands; dollars in millions)
Ammonia
Granular Urea
UAN
Other (1)
Total
(1) Other segment products primarily include DEF, urea liquor, nitric acid and aqua ammonia.
Natural Gas
Natural gas is the principal raw material used to produce our nitrogen products. Natural gas is both a chemical feedstock and a fuel used to produce nitrogen products. Natural gas is the largest and most volatile component of the manufacturing cost for our nitrogen products, representing approximately 34% and 28%, respectively, of our production costs in 2025 and 2024. All of our ammonia manufacturing plants are located in the United States and Canada. As a result, the price of natural gas in North America directly impacts a substantial portion of our operating expenses.
During 2025, natural gas prices in North America generally traded in a range of $3.00 to $4.00 per MMBtu. Below normal temperatures combined with higher LNG exports led to an increase in prices in the first quarter of 2025. Natural gas storage inventories at the end of the first quarter of 2025 fell behind both 2024 and historical averages. Production increased through the second and third quarter of 2025, lowering prices during the summer period. Demand from power generation was lower throughout the summer as electricity generators utilized greater amounts of renewable and coal generation in lieu of
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natural gas to meet demand. Strong injections during the summer refill period led to above average levels to start the winter period, keeping a ceiling on prices. The cold start to winter and higher LNG exports led to the price increase experienced in the fourth quarter of 2025.
The following table presents the average daily market price of natural gas at the Henry Hub, the most heavily-traded natural gas pricing point in North America, and our cost of natural gas used for production, which includes the impact of realized natural gas derivatives:
Year ended December 31,
Average daily market price of natural gas Henry Hub (per MMBtu)
Cost of natural gas used for production in cost of sales (1) (per MMBtu)
(1) Includes the cost of natural gas used for production and related transportation that is included in cost of sales during the period under the first-in, first-out inventory cost method.
The total cost of natural gas used for production at our manufacturing facilities, which includes the impact of realized natural gas derivatives, increased 38% to $3.31 per MMBtu in 2025 from $2.40 per MMBtu in 2024. The increase in natural gas costs in 2025 as compared to 2024 resulted in a decrease in gross margin of approximately $316 million.
The average daily market price of natural gas at the Henry Hub from January 1, 2026 through February 20, 2026 was $6.32 per MMBtu.
Low-carbon Ammonia Production Section 45Q Tax Credits
In July 2025, construction, commissioning and start-up of the dehydration and compression unit at our Donaldsonville complex was completed. As a result, in 2025, we earned approximately $42 million of 45Q Tax Credits, which is recorded in other operating—net in our consolidated statement of operations for the year ended December 31, 2025. See “Overview of CF Holdings—Our Strategy—Decarbonizing our existing network,” above, for additional information.
Yazoo City Incident
In November 2025, we experienced an incident in the AN upgrade area at our Yazoo City complex. The facility’s ammonia plant and other upgrade units were not damaged by the incident. However, the incident required us to temporarily idle all production at the site. Management is conducting an investigation into the cause of the incident and determining the required equipment and installation timeline to rebuild. Management does not expect production to resume until the fourth quarter of 2026 at the earliest based on time required for fabrication and delivery of certain required equipment.
As a result of the damage incurred and based on estimates and assumptions of a preliminary review of the impact, we recorded an impairment of certain fixed assets within our North American AN asset group of $25 million, which primarily consisted of machinery and equipment and is included in the line titled “Asset impairment” in our consolidated statement of operations for the year ended December 31, 2025. In addition, we concluded that the incident necessitated evaluations of the long-lived assets within our North American AN asset group and the goodwill allocated to our North American AN reporting unit to determine if their fair value had declined to below their carrying value. The results of our long-lived asset impairment test indicated that there was no additional impairment as the undiscounted estimated future cash flows for the North American AN asset group exceeded its carrying value, and our goodwill impairment test concluded that the goodwill allocated to our North American reporting unit was not impaired.
Abandonment of Electrolyzer Project
Decarbonization projects in our existing network included an electrolyzer project at our Donaldsonville complex to produce ammonia with hydrogen sourced from an electrolysis process that produces no CO 2 emissions. Commissioning of the 20-megawatt alkaline water electrolysis plant to produce hydrogen was suspended due to an issue experienced in the fourth quarter of 2024. In December 2025, upon completion of a review of the incremental investment and operating costs necessary to complete and operate the project, we concluded such investment would not result in an acceptable return. As a result, we made the decision to not make the incremental investment to the electrolyzer project in favor of the higher return profile from low-carbon ammonia production with carbon capture and sequestration technologies. As a result, we recognized an impairment charge of $51 million, which is included in the line titled “Asset impairment” in our consolidated statement of operations for the year ended December 31, 2025.
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Financial Executive Summary
We reported net earnings attributable to common stockholders of $1.46 billion in 2025 compared to $1.22 billion in 2024, an increase in net earnings of $237 million, or 19%. The increase in net earnings attributable to common stockholders primarily reflects an increase in gross margin of $668 million partially offset by the following factors: (i) a higher income tax provision due to higher net earnings in 2025, (ii) higher net earnings attributable to noncontrolling interests, (iii) higher net interest expense, and (iv) asset impairment, as described under “Yazoo City Incident” and “Abandonment of Electrolyzer Project,” above.
Gross margin increased by $668 million, or 32%, to $2.72 billion for the year ended December 31, 2025 compared to $2.06 billion for the year ended December 31, 2024. The increase in gross margin was due primarily to a 19% increase in average selling prices to $372 per ton in 2025 from $313 per ton in 2024, which increased gross margin by $1.06 billion, partially offset by higher natural gas costs, including the impact of realized derivatives, which decreased gross margin by $316 million.
Diluted net earnings per share attributable to common stockholders increased $2.23 per share, to $8.97 per share in 2025 compared to $6.74 per share in 2024 due to higher net earnings and lower weighted-average common shares outstanding as a result of shares repurchased under our share repurchase programs. Diluted weighted-average common shares outstanding were 162.2 million shares for the year ended December 31, 2025, a decrease of 10% compared to diluted weighted-average common shares outstanding of 180.7 million shares for the year ended December 31, 2024.
Items Affecting Comparability of Results
During the years ended December 31, 2025 and 2024, we reported net earnings attributable to common stockholders of $1.46 billion and $1.22 billion, respectively. In addition to the impact of market conditions and current developments, including 45Q Tax Credits, discussed above, certain items affected the comparability of our financial results during the years ended December 31, 2025 and 2024. The following table and related discussion outline these items and their impact on the comparability of our financial results for these periods. The descriptions of items below that refer to amounts in the table refer to the pre-tax amounts unless otherwise noted.
Pre-Tax
After-Tax (1)
Pre-Tax
After-Tax (1)
(in millions)
Unrealized net mark-to-market loss (gain) on natural gas derivatives (2)
Gain on foreign currency transactions (3)(4)
Asset impairment
Loss on sale of Ince facility (5)
Blue Point joint venture construction costs (3)(4)
Loss on debt extinguishment
Pension settlement loss (6)
Impact of employee benefit plan policy change (7)
Integration costs
Canada Revenue Agency Competent Authority Matter:
Interest expense (income)—net (8)
(1) For 2025, the tax impact is calculated utilizing a marginal effective rate of approximately 23.5%, except for the loss on sale of Ince facility, which reflects the amount of income tax benefit recognized. For 2024, the tax impact is calculated utilizing a marginal effective rate of 23.6%.
(2) Included in cost of sales in our consolidated statements of operations.
(3) Included in other operating—net in our consolidated statements of operations.
(4) Includes results related to the Blue Point joint venture, of which we have a 40% equity interest. The after-tax impact for amounts related to the Blue Point joint venture does not include a tax provision on the 60% attributable to noncontrolling interests.
(5) Included in U.K. operations restructuring in our consolidated statement of operations.
(6) Included in other non-operating—net in our consolidated statement of operations.
(7) Included in cost of sales and selling, general and administrative expenses in our consolidated statement of operations.
(8) Included in interest expense and interest income in our consolidated statement of operations.
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Unrealized net mark-to-market loss (gain) on natural gas derivatives
Natural gas is the largest and most volatile single component of the manufacturing cost for our nitrogen-based products. At certain times, we have managed the risk of changes in natural gas prices through the use of derivative financial instruments. The derivatives that we use for this purpose are primarily natural gas fixed price swaps, basis swaps and options. We use natural gas derivatives as an economic hedge of natural gas price risk, but without the application of hedge accounting. This can result in volatility in reported earnings due to the unrealized mark-to-market adjustments that occur from changes in the value of the derivatives, which are reflected in cost of sales in our consolidated statements of operations. In 2025, we recognized an unrealized net mark-to-market loss of $5 million compared to a gain of $35 million in 2024.
Gain on foreign currency transactions
In 2025, we recognized a gain on foreign currency transactions of $5 million. (Gain) loss on foreign currency transactions consists of foreign currency exchange rate impacts on foreign currency denominated transactions, including cash held in a foreign currency.
Asset impairment
In 2025, we recognized total charges of $76 million, consisting of asset impairment related to property, plant and equipment at our Donaldsonville and Yazoo City facilities. See “Market Conditions and Current Developments—Yazoo City Incident” and “Market Conditions and Current Developments—Abandonment of Electrolyzer Project,” above, for additional information.
Loss on sale of Ince facility
In the second quarter of 2022, we approved and announced our proposed plan to restructure our U.K. operations, including the planned permanent closure of the Ince facility, which had been idled since September 2021. In the third quarter of 2022, the final restructuring plan was approved, and the facility was subsequently decommissioned. In the first quarter of 2025, we sold our Ince facility and recognized a loss of $23 million, which is reflected in U.K. operations restructuring in our consolidated statement of operations in 2025. See Note 6—Property, Plant and Equipment—Net for additional information on the sale of our Ince facility.
Blue Point joint venture construction costs
In 2025, the Blue Point joint venture incurred development costs that were not eligible for capitalization of approximately $10 million related to the construction of the low-carbon ammonia production facility at our Blue Point complex. See “Overview of CF Holdings—Our Strategy—Blue Point joint venture,” above, and Note 14—Variable Interest Entity, for additional information on the Blue Point joint venture.
Loss on debt extinguishment
On November 26, 2025, we issued $1 billion aggregate principal amount of 5.300% senior notes due 2035 (the 2035 Notes). The net proceeds, after deducting discounts and offering expenses, from the issuance and sale of the 2035 Notes were approximately $989 million.
On December 26, 2025, we used approximately $756 million of the net proceeds from the issuance of the 2035 Notes for the prepayment in full of the outstanding $750 million aggregate principal amount of the 4.500% senior secured notes due 2026 (the 2026 Notes). As a result, we recognized a loss on debt extinguishment of $6 million, consisting primarily of the premium paid on the redemption of the $750 million principal amount of the 2026 Notes prior to their scheduled maturity.
See “Liquidity and Capital Resources—Debt—Senior Notes,” below, for additional information.
Pension settlement loss
In the fourth quarter of 2025, we entered into an agreement with an insurance company to purchase group annuity contracts for both of our Canadian pension plans, including a buy-out annuity contract to transfer to the insurance company approximately $40 million of projected benefit obligation for one of the plans. The transactions closed on December 5, 2025 and were funded with proceeds from the sale of pension plan trust assets. As a result of the buy-out annuity contract purchased, in the fourth quarter of 2025, we recognized a non-cash pre-tax pension settlement loss of $1 million related to the settled obligations. See Note 11—Pension and Other Postretirement Benefits for additional information.
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Impact of employee benefit plan policy change
In 2024, we recognized income of $16 million pertaining to a policy change to an employee benefit plan that was included in both cost of sales and selling, general and administrative expenses in our consolidated statement of operations.
Integration costs
In 2024, we incurred integration costs of $4 million related to our acquisition of an ammonia production facility located in Waggaman, Louisiana on December 1, 2023. We did not incur integration costs in 2025.
Canada Revenue Agency Competent Authority Matter
In the third quarter of 2024, we were informed that the Canada Revenue Agency (CRA) granted one of our Canadian subsidiaries discretionary interest relief for certain tax years from 2006 through 2011, which were previously settled through arbitration proceedings between the United States and Canadian competent authorities. In the fourth quarter of 2024, we received the interest relief from the CRA consisting of interest refunds of $21 million and related interest of $2 million, and we were informed that the Alberta Tax and Revenue Administration (Alberta TRA) granted us discretionary interest relief in parallel with the CRA relief. The interest relief from the Alberta TRA was estimated to be approximately $16 million, consisting of interest refunds of $15 million and related interest of $1 million, based on estimates and foreign currency exchange rates as of December 31, 2024. As a result, in our consolidated statement of operations for the year ended December 31, 2024, we recognized $39 million of income consisting of a $36 million reduction in interest expense and $3 million of interest income.
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Consolidated Results of Operations
The following table presents our consolidated results of operations and certain supplemental data for the years ended December 31, 2025, 2024 and 2023:
Year ended December 31,
(in millions, except as noted)
Net sales
Cost of sales (COS)
Gross margin
Gross margin percentage
Selling, general and administrative expenses
Asset impairment
U.K. operations restructuring
Acquisition and integration costs
Other operating—net
Total other operating costs and expenses
Equity in earnings (loss) of operating affiliate
Operating earnings
Interest expense
Interest income
Loss on debt extinguishment
Other non-operating—net
Earnings before income taxes
Income tax provision
Net earnings
Less: Net earnings attributable to noncontrolling interests
Net earnings attributable to common stockholders
Diluted net earnings per share attributable to common stockholders
Diluted weighted-average common shares outstanding
Dividends declared per common share
Natural gas supplemental data (per MMBtu)
Natural gas costs in COS (1)
Realized derivatives loss in COS (2)
Cost of natural gas used for production in COS
Average daily market price of natural gas Henry Hub (Louisiana)
Unrealized net mark-to-market loss (gain) on natural gas derivatives
Depreciation and amortization
Capital expenditures
Sales volume by product tons (000s)
Production volume by product tons (000s):
Ammonia (3)
Granular urea
UAN (32%) (4)
N/M—Not Meaningful
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(1) Includes the cost of natural gas used for production and related transportation that is included in cost of sales during the period under the first-in, first-out inventory cost method.
(2) Includes realized gains and losses on natural gas derivatives settled during the period. Excludes unrealized mark-to-market gains and losses on natural gas derivatives.
(3) Gross ammonia production, including amounts subsequently upgraded on-site into granular urea, UAN, or AN.
(4) UAN product tons assume a 32% nitrogen content basis for production volume.
The following is a discussion and analysis of our consolidated results of operations for the year ended December 31, 2025, compared to the year ended December 31, 2024. For a discussion and analysis of our consolidated results of operations for the year ended December 31, 2024 compared to the year ended December 31, 2023, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2024 Annual Report on Form 10-K filed with the SEC on February 20, 2025.
Net Sales
Our net sales are derived primarily from the sale of nitrogen products and are determined by the quantities of nitrogen products we sell and the selling prices we realize. The volumes, mix and selling prices we realize are determined to a great extent by a combination of global and regional supply and demand factors. Net sales also include shipping and handling costs that are billed to our customers. Sales incentives are reported as a reduction in net sales.
Our total net sales increased $1.15 billion, or 19%, to $7.08 billion in 2025 compared to $5.94 billion in 2024 due primarily to higher average selling prices and, to a lesser extent, higher sales volume.
Our average selling price was $372 per ton in 2025 compared to $313 per ton in 2024, an increase of 19%. Average selling prices for all of our major products were higher in 2025 than 2024 due primarily to strong demand for all nitrogen products and supply disruptions due to geopolitical issues, including unexpected production outages in Egypt, Iran and Russia. Global demand was particularly strong in North America, India and Brazil. The impact of higher average selling prices resulted in an increase in net sales of approximately $1.06 billion for 2025 compared to 2024.
Our total sales volume of 19.1 million product tons in 2025 was 1% higher compared to 18.9 million product tons in 2024, as higher sales volume in our Ammonia and UAN segments was partially offset by lower sales volume in our Granular Urea and AN segments. The impact of higher sales volume was an increase in net sales of approximately $84 million.
Gross ammonia production for 2025 increased to approximately 10.1 million tons compared to 9.8 million tons in 2024, which was adversely impacted by production outages from a winter storm in the first quarter of 2024. We expect gross ammonia production for 2026 will be approximately 9.5 million tons reflecting a decrease from 2025 due in part to the outage at our Yazoo City complex. See “Market Conditions and Current Developments—Yazoo City Incident,” above, for additional information.
Cost of Sales
Our cost of sales includes manufacturing costs, purchased product costs, distribution and storage costs, and freight. Manufacturing costs, the most significant element of cost of sales, consist primarily of raw materials, realized and unrealized gains and losses on natural gas derivatives, maintenance, direct labor, depreciation and other plant overhead expenses. Natural gas is the principal raw material used in our production of nitrogen products. Purchased product costs primarily include the cost to purchase nitrogen fertilizers to augment or replace production at our facilities. Distribution costs consist of the cost of freight required to transport finished products from our manufacturing facilities to our distribution facilities, which are recognized in cost of sales when the product is sold to our customers. Storage costs consist of costs incurred prior to final shipment to customers. Freight consists of shipping and handling costs incurred by us to deliver the product to our customer’s intended destination.
Our total cost of sales increased $480 million, or 12%, to $4.36 billion in 2025 as compared to $3.88 billion in 2024. The increase in our cost of sales primarily reflects higher realized natural gas costs, including the impact of realized derivatives, which increased cost of sales by $316 million. Cost of sales also includes the impact of a $5 million unrealized net mark-to-market loss on natural gas derivatives in 2025 compared to a $35 million gain in 2024, which increased cost of sales by $40 million.
Cost of sales averaged $229 per ton in 2025, a 12% increase from $204 per ton in 2024. Our cost of natural gas, including the impact of realized derivatives, increased 38% to $3.31 per MMBtu in 2025 from $2.40 per MMBtu in 2024. See “Market Conditions and Current Developments—Natural Gas,” above, for additional information about the factors impacting natural gas prices.
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Selling, General and Administrative Expenses
Our selling, general and administrative expenses consist primarily of corporate office expenses such as salaries and other payroll-related costs for our executive, administrative, legal, financial, IT, and sales functions, as well as professional service fees, including those for corporate initiatives, amortization of definite-lived intangible assets, and certain taxes and insurance.
Selling, general and administrative expenses increased $44 million, or 14%, to $364 million in 2025 compared to $320 million in 2024. The increase reflects higher incentive compensation due primarily to strong operating performance and higher costs related to certain corporate initiatives, including our clean energy initiatives.
Asset Impairment
In 2025, we recognized total charges of $76 million, consisting of asset impairment related to property, plant and equipment at our Donaldsonville and Yazoo City facilities. See “Market Conditions and Current Developments—Yazoo City Incident” and “Market Conditions and Current Developments—Abandonment of Electrolyzer Project,” above, for additional information.
U.K. Operations Restructuring
In the second quarter of 2022, we approved and announced our proposed plan to restructure our U.K. operations, including the planned permanent closure of the Ince facility, which had been idled since September 2021. In the third quarter of 2022, the final restructuring plan was approved, and the facility was subsequently decommissioned. In the first quarter of 2025, we sold our Ince facility and recognized a loss of $23 million. See Note 6—Property, Plant and Equipment—Net for additional information on the sale of our Ince facility.
Acquisition and Integration Costs
In 2024, we incurred integration costs of $4 million related to our December 1, 2023 acquisition of an ammonia production facility located in Waggaman, Louisiana. We did not incur integration costs in 2025.
Other Operating—Net
Other operating—net includes administrative costs that do not relate directly to our central operations and can include foreign currency transaction gains and losses, unrealized gains and losses on foreign currency derivatives, litigation expenses, gains and losses on the disposal of fixed assets, costs related to our clean energy initiatives, such as front-end engineering and design (FEED) study costs and development costs for our Blue Point joint venture, and 45Q Tax Credits.
Other operating—net was $25 million of income in 2025 compared to $10 million of income in 2024. Higher income in 2025 was due primarily to approximately $42 million of 45Q Tax Credits earned as a result of CO 2 sequestered in the second half of 2025 and lower FEED study costs for our clean energy initiatives compared to 2024. These factors that increased income were partially offset by lower gains on sales of emission credits compared to 2024. See “Our Strategy,” above, for additional information related to our clean energy initiatives.
Equity in Earnings (Loss) of Operating Affiliate
Equity in earnings (loss) of operating affiliate consists of our 50% ownership interest in PLNL. We include our share of the net earnings from our equity method investment in PLNL as an element of earnings from operations because this investment provides additional production and is integrated with our other supply chain and sales activities.
Equity in earnings of operating affiliate was $14 million in 2025 compared to $4 million in 2024. Equity in earnings of operating affiliate in 2025 reflects an increase in the operating results of PLNL due primarily to higher ammonia selling prices and higher sales volume due to a plant turnaround at the PLNL facility that occurred in the second quarter of 2024 that did not recur in 2025, partially offset by higher natural gas costs.
See “Critical Accounting Estimates—Recoverability of Long-Lived Assets, Goodwill and Investment in Unconsolidated Affiliate,” below, for information on the status of PLNL’s gas supply contract with The National Gas Company of Trinidad and Tobago Limited, which was scheduled to expire on January 1, 2026.
Interest Expense
Interest expense includes interest on our long-term debt, amortization of the related fees required to execute financing agreements, annual fees pursuant to our revolving credit agreement and interest on tax liabilities. Capitalized interest relating to
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the construction of major capital projects reduces interest expense as the interest is capitalized and amortized over the estimated useful lives of the related assets.
Interest expense was $155 million in 2025 compared to $121 million in 2024. The increase of $34 million was due primarily to a $36 million reduction in interest expense recognized in 2024 that did not recur in 2025 related to discretionary interest relief on Canadian tax matters. This is further described above under “Items Affecting Comparability of Results—Canada Revenue Agency Competent Authority Matter.” In addition, higher interest expense in 2025 reflects the higher outstanding principal balance of senior notes outstanding for the one-month period between the issuance of the 2035 Notes in November 2025 and the redemption of the 2026 Notes in December 2025.
Interest Income
Interest income includes amounts earned on our cash, cash equivalents, and investments and any interest earned related to income tax refunds.
Interest income was $81 million in 2025 compared to $123 million in 2024. The decrease of $42 million was due primarily to a decrease in interest income on short-term investments and $3 million in interest income related to discretionary interest relief on Canadian tax matters that was granted in the third quarter of 2024 that did not recur in 2025. This is further described above under “Items Affecting Comparability of Results—Canada Revenue Agency Competent Authority Matter.”
Loss on debt extinguishment
Loss on debt extinguishment of $6 million in 2025 is described above under “Items Affecting Comparability of Results—Loss on debt extinguishment.”
Income Tax Provision
Our income tax provision for 2025 was $441 million on pre-tax income of $2.24 billion, or an effective tax rate of 19.7%, compared to an income tax provision of $285 million on pre-tax income of $1.76 billion, or an effective tax rate of 16.2%, in 2024. The higher effective tax rate in 2025 compared to 2024 was due primarily to increases in unrecognized tax benefits related to U.S. tax positions under the Internal Revenue Service audit in 2025. The increase also reflects discrete tax benefits recognized in 2024 that did not recur in 2025, including decreases in unrecognized tax benefits arising from transfer pricing matters, the release of a valuation allowance in the United Kingdom, and the remeasurement of state deferred taxes related to tax rate changes. These items that resulted in a higher effective tax rate in 2025 were partially offset by favorable state tax adjustments claimed on amended returns in 2025.
Our effective tax rate is impacted by earnings attributable to the noncontrolling interests as our consolidated income tax provision does not include a tax provision on the earnings attributable to the noncontrolling interests. Our effective tax rate for 2025 of 19.7%, which is based on pre-tax income of $2.24 billion, would be 3.5 percentage points higher, or 23.2%, if based on pre-tax income exclusive of the earnings attributable to the noncontrolling interests of $343 million. Our effective tax rate for 2024 of 16.2%, which is based on pre-tax income of $1.76 billion, would be 2.8 percentage points higher, or 19.0%, if based on pre-tax income exclusive of the earnings attributable to the noncontrolling interests of $259 million.
See Note 10—Income Taxes for additional information.
Net Earnings Attributable to Noncontrolling Interests
Net earnings attributable to noncontrolling interests includes the net earnings attributable to the approximately 11% CHS minority equity interest in CFN, a subsidiary of CF Holdings, and the combined 60% equity interest owned by our joint venture partners in Blue Point Number One, LLC, a joint venture formed on April 8, 2025, that is a VIE of which we are the primary beneficiary.
Net earnings attributable to noncontrolling interests increased $84 million, or 32%, to $343 million in 2025 compared to $259 million in 2024 due primarily to higher earnings of CFN driven by higher average selling prices and the impact of higher sales volume, partially offset by higher natural gas costs. In addition, the increase also reflects the earnings attributable to the noncontrolling interests in the Blue Point joint venture, which was formed in the second quarter of 2025. See “Overview of CF Holdings—Our Strategy—Blue Point joint venture,” above, Note 14—Variable Interest Entity and Note 18—Noncontrolling Interests for additional information on the Blue Point joint venture.
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Diluted Net Earnings Per Share Attributable to Common Stockholders
Net earnings per share attributable to common stockholders increased 33% to $8.97 per diluted share in 2025 from $6.74 per diluted share in 2024. This increase was due primarily to higher net earnings driven by an increase in gross margin and lower weighted-average common shares outstanding. Diluted weighted-average common shares outstanding declined 10% from 180.7 million shares for 2024 to 162.2 million shares for 2025, due primarily to repurchases of common shares under our share repurchase programs.
Operating Results by Business Segment
Our reportable segments consist of Ammonia, Granular Urea, UAN, AN and Other. These segments are differentiated by products. Our management uses gross margin to evaluate segment performance and allocate resources. Total other operating costs and expenses (consisting primarily of selling, general and administrative expenses and other operating—net) and non-operating expenses (consisting primarily of interest and income taxes), are centrally managed and are not included in the measurement of segment profitability reviewed by management. See Note 21—Segment Disclosures for additional information.
The following table presents summary operating results by business segment:
Ammonia
Granular Urea (1)
UAN (1)
Other (1)
Consolidated
(in millions)
Year ended December 31, 2025
Net sales
Cost of sales
Gross margin
Gross margin percentage
Year ended December 31, 2024
Net sales
Cost of sales
Gross margin
Gross margin percentage
Year ended December 31, 2023
Net sales
Cost of sales
Gross margin
Gross margin percentage
(1) The cost of ammonia and other products that are upgraded in the production of Granular Urea, UAN, AN and Other products is transferred at cost into the results of those products.
The following is a discussion and analysis of our operating results by business segment for the year ended December 31, 2025 compared to the year ended December 31, 2024. For a discussion and analysis of our operating results by business segment for the year ended December 31, 2024 compared to the year ended December 31, 2023, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2024 Annual Report on Form 10-K filed with the SEC on February 20, 2025.
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Ammonia Segment
Our Ammonia segment produces anhydrous ammonia (ammonia), which is the base product that we manufacture, containing 82% nitrogen and 18% hydrogen. The results of our Ammonia segment consist of sales of ammonia to external customers for its nitrogen content as a fertilizer, in emissions control and in other industrial applications. In addition, we upgrade ammonia into other nitrogen products such as granular urea, UAN and AN.
The following table presents summary operating data for our Ammonia segment:
Year ended December 31,
(in millions, except as noted)
Net sales
Cost of sales
Gross margin
Gross margin percentage
Sales volume by product tons (000s)
Sales volume by nutrient tons (000s) (1)
Average selling price per product ton
Average selling price per nutrient ton (1)
Gross margin per product ton
Gross margin per nutrient ton (1)
Depreciation and amortization
Unrealized net mark-to-market loss (gain) on natural gas derivatives
N/M—Not Meaningful
(1) Ammonia represents 82% nitrogen content. Nutrient tons represent the tons of nitrogen within the product tons.
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Net Sales. Net sales in our Ammonia segment increased by $440 million, or 25%, to $2.18 billion in 2025 from $1.74 billion in 2024. The increase in our net sales reflects a 13% increase in sales volume, and an 11% increase in average selling prices. Ammonia sales volume in 2025 was 4.6 million tons, an increase of 13% compared to 4.1 million tons in 2024. The increase in sales volume was due primarily to higher supply availability as a result of increased production in the first quarter of 2025 compared to the first quarter of 2024, which was adversely impacted by production outages from a winter storm.
Average selling prices increased to $473 per ton in 2025 compared to $425 per ton in 2024 due primarily to strong global nitrogen demand and supply disruptions due to geopolitical issues, including unexpected production outages in Egypt, Iran and Russia.
Cost of Sales. Cost of sales in our Ammonia segment averaged $325 per ton in 2025, a 7% increase from $304 per ton in 2024. The increase was due primarily to higher realized natural gas costs, including the impact of realized derivatives, partially offset by lower costs for maintenance activity in 2025 compared to 2024, which included higher costs for maintenance, repairs and certain unabsorbed fixed costs as a result of plant downtime, including the impact of the adverse weather in the first quarter of 2024 as discussed above.
Gross Margin . Gross margin in our Ammonia segment increased by $189 million, or 38%, to $682 million in 2025 from $493 million in 2024, and our gross margin percentage was 31.3% in 2025 compared to 28.4% in 2024. The increase in gross margin was due primarily to an 11% increase in average selling prices, which increased gross margin by $246 million, and an increase in sales volume, which increased gross margin by $118 million. These factors that increased gross margin were partially offset by the impact of higher realized natural gas costs, including the impact of realized derivatives, which decreased gross margin by $111 million, and a net increase in manufacturing, maintenance and other costs, which decreased gross margin by $49 million. Gross margin also includes the impact of a $2 million unrealized net mark-to-market loss on natural gas derivatives in 2025 compared to a $13 million gain in 2024.
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Granular Urea Segment
Our Granular Urea segment produces granular urea, which contains 46% nitrogen. Produced from ammonia and carbon dioxide, it has the highest nitrogen content of any of our solid nitrogen fertilizers. Granular urea is produced at our Donaldsonville, Port Neal and Medicine Hat complexes.
The following table presents summary operating data for our Granular Urea segment:
Year ended December 31,
(in millions, except as noted)
Net sales
Cost of sales
Gross margin
Gross margin percentage
Sales volume by product tons (000s)
Sales volume by nutrient tons (000s) (1)
Average selling price per product ton
Average selling price per nutrient ton (1)
Gross margin per product ton
Gross margin per nutrient ton (1)
Depreciation and amortization
Unrealized net mark-to-market loss (gain) on natural gas derivatives
N/M—Not Meaningful
(1) Granular urea represents 46% nitrogen content. Nutrient tons represent the tons of nitrogen within the product tons.
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Net Sales. Net sales in our Granular Urea segment increased $181 million, or 11%, to $1.78 billion in 2025 compared to $1.60 billion in 2024 due primarily to a 22% increase in average selling prices, partially offset by a 9% decrease in sales volume. Average selling prices increased to $433 per ton in 2025 compared to $354 per ton in 2024 due primarily to strong global nitrogen demand and supply disruptions due to geopolitical issues, including unexpected production outages in Egypt, Iran and Russia. Sales volume in 2025 was 4.1 million tons, a decrease of 9% compared to 4.5 million tons in 2024 due primarily to decreased supply availability as a result of lower production due to management’s decision to favor UAN production over granular urea and lower beginning inventory entering 2025.
Cost of Sales. Cost of sales in our Granular Urea segment averaged $229 per ton in 2025, a 12% increase from $205 per ton in 2024, due primarily to higher realized natural gas costs, including the impact of realized derivatives.
Gross Margin . Gross margin in our Granular Urea segment increased by $163 million, or 24%, to $837 million in 2025 from $674 million in 2024, and our gross margin percentage was 47.0% in 2025 compared to 42.1% in 2024. The increase in gross margin was due primarily to a 22% increase in average selling prices, which increased gross margin by $315 million. This increase in gross margin was partially offset by higher realized natural gas costs, including the impact of realized derivatives, which decreased gross margin by $79 million, a 9% decrease in sales volume, which decreased gross margin by $60 million, and a net increase in manufacturing, maintenance and other costs, which decreased gross margin by $3 million. Gross margin also includes the impact of a $1 million unrealized net mark-to-market loss on natural gas derivatives in 2025 compared to a $9 million gain in 2024.
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UAN Segment
Our UAN segment produces urea ammonium nitrate solution (UAN). UAN, a liquid fertilizer product with a nitrogen content that typically ranges from 28% to 32%, is produced by combining urea and ammonium nitrate. UAN is produced at our Courtright, Donaldsonville, Port Neal, Verdigris, Woodward, and Yazoo City complexes.
The following table presents summary operating data for our UAN segment:
Year ended December 31,
(in millions, except as noted)
Net sales
Cost of sales
Gross margin
Gross margin percentage
Sales volume by product tons (000s)
Sales volume by nutrient tons (000s) (1)
Average selling price per product ton
Average selling price per nutrient ton (1)
Gross margin per product ton
Gross margin per nutrient ton (1)
Depreciation and amortization
Unrealized net mark-to-market loss (gain) on natural gas derivatives
N/M—Not Meaningful
(1) UAN represents between 28% and 32% of nitrogen content, depending on the concentration specified by the customer. Nutrient tons represent the tons of nitrogen within the product tons.
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Net Sales. Net sales in our UAN segment increased $483 million, or 29%, to $2.16 billion in 2025 compared to $1.68 billion in 2024 due primarily to a 25% increase in average selling prices and a 3% increase in sales volume. Average selling prices increased to $311 per ton in 2025 compared to $248 per ton in 2024 due primarily to strong global nitrogen demand and supply disruptions due to geopolitical issues, including unexpected production outages in Egypt, Iran and Russia. The increase in sales volume was due primarily to higher supply availability as a result of higher production in 2025 compared to 2024 and inventory drawdown to meet strong domestic and international demand in the second quarter of 2025.
Cost of Sales. Cost of sales in our UAN segment averaged $178 per ton in 2025, a 13% increase from $158 per ton in 2024, due primarily to higher realized natural gas costs, including the impact of realized derivatives.
Gross Margin. Gross margin in our UAN segment increased by $312 million, or 51%, to $921 million in 2025 from $609 million in 2024, and our gross margin percentage was 42.6% in 2025 compared to 36.3% in 2024. The increase in gross margin was due primarily to a 25% increase in average selling prices, which increased gross margin by $424 million, and a 3% increase in sales volume, which increased gross margin by $33 million. These factors that increased gross margin were partially offset by higher realized natural gas costs, including the impact of realized derivatives, which decreased gross margin by $99 million, and a net increase in manufacturing, maintenance and other costs, which decreased gross margin by $34 million. Gross margin also includes the impact of a $2 million unrealized net mark-to-market loss on natural gas derivatives in 2025 compared to a $10 million gain in 2024.
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AN Segment
Our AN segment produces ammonium nitrate (AN). AN, which has a nitrogen content between 29% and 35%, is produced by combining anhydrous ammonia and nitric acid. AN is used as nitrogen fertilizer and is also used extensively by the commercial explosives industry as a component of explosives. AN is produced at our Yazoo City and Billingham complexes.
The following table presents summary operating data for our AN segment:
Year ended December 31,
(in millions, except as noted)
Net sales
Cost of sales
Gross margin
Gross margin percentage
Sales volume by product tons (000s)
Sales volume by nutrient tons (000s) (1)
Average selling price per product ton
Average selling price per nutrient ton (1)
Gross margin per product ton
Gross margin per nutrient ton (1)
Depreciation and amortization
Unrealized net mark-to-market gain on natural gas derivatives
(1) AN represents between 29% and 35% of nitrogen content. Nutrient tons represent the tons of nitrogen within the product tons.
Yazoo City Incident
In November 2025, we experienced an incident in the AN upgrade area at our Yazoo City complex. The facility’s ammonia plant and other upgrade units were not damaged by the incident. However, the incident required us to temporarily idle all production at the site. Management is conducting an investigation into the cause of the incident and determining the required equipment and installation timeline to rebuild. Management does not expect production to resume until the fourth quarter of 2026 at the earliest based on time required for fabrication and delivery of certain required equipment. See “Market Conditions and Current Developments—Yazoo City Incident,” above, for additional information. The Yazoo City incident does not impact AN production at our Billingham complex.
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Net Sales. Net sales in our AN segment increased $2 million to $421 million in 2025 from $419 million in 2024 due primarily to an 11% increase in average selling prices, partially offset by a 9% decrease in sales volume. Average selling prices increased to $317 per ton in 2025 compared to $286 per ton in 2024 due primarily to strong global nitrogen demand and supply disruptions due to geopolitical issues, including unexpected production outages in Egypt, Iran and Russia. Sales volume decreased due primarily to lower supply availability due to lower production in 2025 as a result of the incident at our Yazoo City complex described above.
Cost of Sales. Cost of sales in our AN segment averaged $257 per ton in 2025, an 11% increase from $232 per ton in 2024. The increase was due primarily to (i) costs incurred due to the idling of the Yazoo City plant, (ii) a higher proportion of AN sales in the United Kingdom compared to the prior year, which include higher costs per ton due to purchasing ammonia for upgrade to AN compared to the cost of natural gas used to produce ammonia, and (iii) higher realized natural gas costs, including the impact of realized derivatives, for our North American operations.
Gross Margin . Gross margin in our AN segment was $79 million in both 2025 and 2024, and our gross margin percentage was 18.8% in 2025 compared to 18.9% in 2024. An 11% increase in average selling prices increased gross margin by $35 million. This increase in gross margin was offset by a 9% decrease in sales volume, which decreased gross margin by $16 million, higher realized natural gas costs, including the impact of realized derivatives, which decreased gross margin by $11 million, a net increase in manufacturing, maintenance and other costs, which decreased gross margin by $7 million, and the impact of a $1 million unrealized net mark-to-market gain on natural gas derivatives in 2024 that did not recur in 2025.
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Other Segment
Our Other segment primarily includes the following products:
• diesel exhaust fluid (DEF), an aqueous urea solution typically made with 32.5% or 50% high-purity urea and the remainder deionized water;
• urea liquor, a liquid product that we sell in concentrations of 40%, 50% and 70% high-purity urea as a chemical intermediate; and
• nitric acid, a nitrogen-based mineral acid that is used in the production of nitrate-based fertilizers, nylon precursors and other specialty chemicals.
The following table presents summary operating data for our Other segment:
Year ended December 31,
(in millions, except as noted)
Net sales
Cost of sales
Gross margin
Gross margin percentage
Sales volume by product tons (000s)
Sales volume by nutrient tons (000s) (1)
Average selling price per product ton
Average selling price per nutrient ton (1)
Gross margin per product ton
Gross margin per nutrient ton (1)
Depreciation and amortization
Unrealized net mark-to-market gain on natural gas derivatives
(1) Nutrient tons represent the tons of nitrogen within the product tons.
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Net Sales. Net sales in our Other segment increased $42 million, or 8%, to $545 million in 2025 from $503 million in 2024 due primarily to a 10% increase in average selling prices. Average selling prices increased to $262 per ton in 2025 compared to $239 per ton in 2024 due primarily to strong global nitrogen demand and supply disruptions due to geopolitical issues, including unexpected production outages in Egypt, Iran and Russia.
Cost of Sales. Cost of sales in our Other segment averaged $163 per ton in 2025, a 14% increase from $143 per ton in 2024, due primarily to the impact of higher realized natural gas costs, including the impact of realized derivatives, and costs incurred due to the idling of the Yazoo City plant. See “AN Segment—Yazoo City Incident,” above, for additional information.
Gross Margin . Gross margin in our Other segment increased by $4 million, or 2%, to $205 million in 2025 from $201 million in 2024, and our gross margin percentage was 37.6% in 2025 compared to 40.0% in 2024. The increase in gross margin was due primarily to a 10% increase in average selling prices, which increased gross margin by $44 million. This increase in gross margin was partially offset by a net increase in manufacturing, maintenance and other costs, which decreased gross margin by $22 million, and higher realized natural gas costs, including the impact of realized derivatives, which decreased gross margin by $16 million. Gross margin also includes the impact of a $2 million unrealized net mark-to-market gain on natural gas derivatives in 2024 that did not recur in 2025.
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Liquidity and Capital Resources
Our primary uses of cash are generally for operating costs, working capital, capital expenditures, debt service, investments, taxes, share repurchases, dividends, and our clean energy initiatives. Our working capital requirements are affected by several factors, including demand for our products, selling prices, the level of customer advances, raw material costs, freight costs and seasonal factors inherent in the business. We may also utilize our cash to fund acquisitions. In addition, we may from time to time seek to retire or purchase our outstanding debt through cash purchases, in open market or privately negotiated transactions or otherwise. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Generally, our primary source of cash is cash from operations, which includes cash generated by customer advances. We may also from time to time access the capital markets or engage in borrowings under our revolving credit agreement.
On September 4, 2025, CF Holdings and CF Industries entered into the First Amended and Restated Revolving Credit Agreement (the Revolving Credit Agreement), which amended and restated our senior unsecured revolving credit facility that was scheduled to mature October 26, 2028 (the Prior Credit Agreement). The Revolving Credit Agreement provides for revolving credit facility commitments of up to $750 million with a maturity of September 4, 2030. See “Debt—Revolving Credit Agreement,” below, for additional information.
On November 26, 2025, CF Industries issued $1 billion aggregate principal amount of the 2035 Notes. The net proceeds, after deducting discounts and offering expenses, from the issuance and sale of the 2035 Notes were approximately $989 million. On December 26, 2025, in accordance with the optional redemption provisions in the indenture governing the 2026 Notes, we used approximately $756 million of the net proceeds for the prepayment (including payment of a make-whole amount of $4 million and accrued interest of $2 million) in full of the outstanding $750 million aggregate principal amount of the 2026 Notes. See “Debt—Senior Notes,” below, for additional information.
At December 31, 2025, we were in compliance with all applicable covenant requirements under the Revolving Credit Agreement and senior notes, and unused borrowing capacity under the Revolving Credit Agreement was $750 million.
As of December 31, 2025, our cash and cash equivalents balance was $1.98 billion, an increase of $368 million from $1.61 billion at December 31, 2024, and consisted of the following:
December 31, 2025
December 31, 2024
(in millions)
Cash and cash equivalents, excluding amounts related to Blue Point Number One, LLC
Cash and cash equivalents held by—Blue Point Number One, LLC
Total cash and cash equivalents
Cash Equivalents
Cash equivalents include highly liquid investments that are readily convertible to known amounts of cash with original maturities of three months or less. Under our short-term investment policy, we may invest our cash balances, either directly or through mutual funds, in several types of investment-grade securities, including notes and bonds issued by governmental entities or corporations. Securities issued by governmental entities include those issued directly by the U.S. and Canadian federal governments; those issued by state, local or other governmental entities; and those guaranteed by entities affiliated with governmental entities.
Blue Point Joint Venture
On April 8, 2025, we formed the Blue Point joint venture with JERA and Mitsui to construct a low-carbon ammonia production facility at our Blue Point complex located in Modeste, Louisiana. We hold 40% ownership, JERA holds 35% ownership, and Mitsui holds 25% ownership in the Blue Point joint venture. Under the terms of the Blue Point joint venture’s limited liability company agreement, JERA had a conditional option that, if the specified condition were met, JERA could reduce its ownership percentage below 35% but not lower than 20%. We would have had the right and obligation to increase our ownership by the same amount had JERA opted to reduce its ownership. The option expired and is no longer exercisable.
The Blue Point joint venture is expected to construct an ATR ammonia production facility with a CO 2 dehydration and compression unit to prepare captured CO 2 for transportation and sequestration. Engineering, equipment procurement and pre-construction activities at our Blue Point complex began in the second quarter of 2025. Construction of the ammonia production facility is expected to begin in 2026, with low-carbon ammonia production expected to begin in 2029.
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We estimate that the cost of the low-carbon ATR ammonia production facility with CCS technologies will be approximately $3.7 billion. We anticipate that approximately one-third of the estimated cost is related to materials that will be imported to the United States, with the majority of imported materials expected to arrive in Louisiana in 2028. Pursuant to periodic capital calls, the Blue Point joint venture members will fund the cost of the facility’s engineering, procurement and construction according to their respective ownership percentages. During 2025, we, JERA and Mitsui made capital contributions of $195 million, $170 million and $121 million, respectively, to the Blue Point joint venture. We funded $152 million of our contributions with cash and $43 million through a non-cash contribution of a license to use certain intellectual property.
In June 2025, the Blue Point joint venture executed agreements, including a long-term supply agreement, with a subsidiary of Linde plc for them to design, construct, own, operate and maintain an air separation unit (ASU) at our Blue Point complex to supply oxygen and nitrogen to the low-carbon ATR ammonia production facility. Thus, our estimate of the cost of the low-carbon ATR ammonia production facility of $3.7 billion, as noted above, excludes the costs to construct an ASU.
In addition, we plan to invest approximately $550 million to build scalable infrastructure at our Blue Point complex to supply the ammonia production facility with services, including product storage and vessel loading. This infrastructure will be constructed with a similar timeline as the ammonia production facility noted above.
See “Overview of CF Holdings—Our Strategy—Blue Point joint venture,” above, and Note 14—Variable Interest Entity, for additional information on the Blue Point joint venture.
Capital Spending
We make capital expenditures to sustain our asset base, increase our capacity or capabilities, improve plant efficiency, comply with various environmental, health and safety requirements, and invest in our clean energy strategy. Capital expenditures totaled $950 million in 2025 compared to $518 million in 2024, and consisted of the following:
December 31, 2025
December 31, 2024
(in millions)
Existing operations
Blue Point joint venture (1)
Blue Point complex scalable infrastructure
Capitalized interest
Total capital expenditures
(1) Amounts represent 100% of the Blue Point joint venture capital spending, of which 60% is funded by our joint venture partners through capital contributions to the joint venture. See “Overview of CF Holdings—Our Strategy—Blue Point joint venture,” above, and Note 14—Variable Interest Entity, for additional information on the Blue Point joint venture.
The Blue Point joint venture is consolidated in our financial statements, including our statements of cash flows. We currently anticipate that our consolidated capital expenditures for 2026 to be approximately $1.3 billion, consisting of approximately $550 million for our existing operations and approximately $600 million representing the Blue Point joint venture’s planned capital expenditures related to construction of the low-carbon ATR ammonia production facility at our Blue Point complex. Also, we anticipate our 2026 capital spending will include approximately $150 million related to our construction of the Blue Point complex scalable infrastructure.
Of the Blue Point joint venture’s $600 million of planned 2026 capital expenditures, approximately $240 million will be funded by us, representing our 40% equity interest in the Blue Point joint venture, and approximately $360 million will be funded by our partners in the joint venture, representing their combined 60% equity interest in the Blue Point joint venture.
For 2026, we anticipate that our capital expenditures will be funded primarily from available cash, including cash from operations, in addition to contributions received from our Blue Point joint venture partners pursuant to periodic capital calls as discussed under “Blue Point Joint Venture, ” above.
Planned capital expenditures are generally subject to change due to delays in regulatory approvals or permitting, unanticipated increases in cost, changes in scope and completion time, engineering and construction change orders, performance of third parties, delays in the receipt of equipment, adverse weather, defects in materials and workmanship, labor or material shortages, impact of tariffs, retaliatory measures or other changes in trade policy, transportation constraints, acceleration or delays in the timing of the work and other unforeseen difficulties. Any of these changes in planned capital
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expenditures, individually or in the aggregate, could have a material impact on our results of operations and cash flows. See “—Forward-Looking Statements” for additional risks related to our planned capital expenditures.
Share Repurchase Programs
Our Board of Directors (the Board) has authorized certain programs to repurchase shares of our common stock. These programs have generally permitted repurchases to be made from time to time in the open market, through privately-negotiated transactions, through block transactions, through accelerated share repurchase programs or otherwise. The manner, timing and amount of repurchases will be determined by our management based on the evaluation of market conditions, stock price and other factors.
On November 2, 2022, the Board authorized the repurchase of up to $3 billion of CF Holdings common stock, which commenced in the second quarter of 2023 upon completion of our previous share repurchase program and was effective through December 31, 2025 (the 2022 Share Repurchase Program). On May 6, 2025, the Board authorized the repurchase of up to $2 billion of CF Holdings common stock commencing upon the completion of the 2022 Share Repurchase Program and effective through December 31, 2029 (the 2025 Share Repurchase Program). In October 2025, we completed the 2022 Share Repurchase Program and commenced repurchases under the 2025 Share Repurchase Program.
The following table summarizes the share repurchases under the 2025 Share Repurchase Program and the 2022 Share Repurchase Program.
2025 Share Repurchase Program
2022 Share Repurchase Program
Shares
Amounts (1)
Shares
Amounts (1)
(in millions)
Shares repurchased in 2023
Shares repurchased in 2024
Shares repurchased in 2025:
First quarter
Second quarter
Third quarter
Fourth quarter
Total shares repurchased in 2025
Shares repurchased as of December 31, 2025
(1) As defined in the share repurchase programs, amounts reflect the price paid for the shares of common stock repurchased, excluding commissions paid to brokers and excise taxes.
In 2025, we completed the 2022 Share Repurchase Program with the repurchase of 13.2 million shares for $1.06 billion, and we repurchased 3.4 million shares under the 2025 Share Repurchase Program for $278 million. In 2025, we retired 17.1 million shares of repurchased stock, including shares repurchased under the 2022 Share Repurchase Program and the 2025 Share Repurchase Program. In 2024, we retired 18.7 million shares of repurchased stock. As of December 31, 2025 and 2024, we held zero shares and 0.4 million shares, of treasury stock, respectively.
Government Policies
The policies or laws of governments around the world can result in the imposition of taxes, duties, tariffs or other restrictions or regulatory requirements on imports and exports of raw materials, finished goods or services from a particular country or region of the world. The policies and laws of governments can also impact the subsidization of natural gas prices, and subsidies or quotas applied to domestic producers or farmers. Due to the critical role that fertilizers play in food production, the construction and operation of fertilizer plants often are influenced by economic, political and social objectives. Additionally, the import or export of fertilizer can be subject to local taxes imposed by governments which can have the effect of either encouraging or discouraging import and export activity. The impact of changes in governmental policies or laws or the political or social objectives of a country could have a material impact on fertilizer demand and selling prices and therefore could impact our liquidity. In addition, political leadership, including the current U.S. presidential administration and regulatory leadership, have proposed, and may propose further, policy, regulatory, and enforcement changes, which are and may continue to be subject to administrative and judicial challenges, that create additional uncertainty for our business.
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Canada Revenue Agency Competent Authority Matter
In the third quarter of 2024, we were informed that the CRA granted one of our Canadian subsidiaries discretionary interest relief for certain tax years from 2006 through 2011, which were previously settled through arbitration proceedings between the United States and Canadian competent authorities. In the fourth quarter of 2024, we received interest relief from the CRA consisting of interest refunds of $21 million and related interest of $2 million, and we were informed that the Alberta TRA granted us discretionary interest relief in parallel with the CRA relief. The interest relief from the Alberta TRA was estimated to be approximately $16 million, consisting of interest refunds of $15 million and related interest of $1 million, based on estimates and foreign currency exchange rates as of December 31, 2024. During the fourth quarter of 2025, the Alberta TRA finalized interest relief owed to the Company, which was applied as credits to our account and is available to offset future income tax owed to the Alberta TRA.
Repatriation of Foreign Earnings and Income Taxes
We have operations in Canada, the United Kingdom and a 50% interest in a joint venture in Trinidad. Historically, the estimated additional U.S. and foreign income taxes due upon repatriation of the earnings of these foreign operations to the United States were recognized in our consolidated financial statements as the earnings were recognized, unless the earnings were considered to be permanently reinvested based upon our then current plans. However, the cash payment of the income tax liabilities associated with repatriation of earnings from foreign operations occurred at the time of the repatriation. As a result, the recognition of income tax expense related to foreign earnings, as applicable, and the payment of taxes resulting from repatriation of those earnings could occur in different periods.
In light of changes made by the Tax Cuts and Jobs Act, commencing with the 2018 tax year, the United States no longer taxes earnings of foreign subsidiaries even when such earnings are earned or repatriated to the United States, unless such earnings are subject to U.S. rules on passive income or certain anti-abuse provisions. Foreign subsidiary earnings may still be subject to withholding taxes when repatriated to the United States.
Cash balances held by our joint venture are maintained at sufficient levels to fund local operations as accumulated earnings are repatriated from the joint venture on a periodic basis.
As of December 31, 2025, approximately $555 million of our consolidated cash and cash equivalents balance of $1.98 billion was held by our Canadian and United Kingdom subsidiaries. The Company does not have an indefinite reinvestment assertion in any of our foreign subsidiaries. As of December 31, 2025, we recorded a deferred tax liability of $21 million on the undistributed earnings of our Canadian subsidiaries.
Debt
Revolving Credit Agreement
On September 4, 2025, CF Holdings and CF Industries entered into the First Amended and Restated Revolving Credit Agreement (the Revolving Credit Agreement), which amended and restated the Prior Credit Agreement. The Revolving Credit Agreement provides for revolving credit facility commitments of up to $750 million with a maturity of September 4, 2030, and has a letter of credit sub-limit of $125 million and a swingline loan sub-limit of $75 million. Borrowings under the Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions, share repurchases and other general corporate purposes. CF Industries is the lead borrower, and CF Holdings is the sole guarantor, under the Revolving Credit Agreement. CF Industries may designate as borrowers one or more wholly-owned subsidiaries that are organized in the United States or any state thereof, the District of Columbia, England and Wales or any other jurisdiction as mutually agreed to by all of the lenders party to the Revolving Credit Agreement and the administrative agent.
Borrowings under the Revolving Credit Agreement can be denominated in U.S. dollars, Canadian dollars, euros and British pounds. Borrowings in U.S. dollars bear interest at an annual rate equal to, at our option, an applicable adjusted term secured overnight financing rate (or a similar benchmark rate for non-U.S. dollar borrowings) plus a specified margin, or base rate plus a specified margin. We are required to pay a commitment fee on the undrawn portion of the commitments under the Revolving Credit Agreement and customary letter of credit fees. The specified margins and the amount of the commitment fee will depend on CF Holdings’ credit rating at the time.
The Revolving Credit Agreement contains representations and warranties and affirmative and negative covenants, including one financial covenant. The financial covenant requires the total net leverage ratio (as defined in the Revolving Credit Agreement) to be no greater than 3.75:1.00 (or 4.25:1.00 for a period of four fiscal quarters after certain material acquisitions) as of the last day of each fiscal quarter.
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The Revolving Credit Agreement contains events of default (with notice requirements and cure periods, as applicable) customary for a financing of this type, including, but not limited to, non-payment of principal, interest or fees; inaccuracy of representations and warranties in any material respect; and failure to comply with specified covenants. Upon the occurrence and during the continuance of an event of default under the Revolving Credit Agreement and after any applicable cure period, subject to specified exceptions, the administrative agent may, and at the request of the requisite lenders is required to, accelerate the loans under the Revolving Credit Agreement or terminate the lenders’ commitments under the Revolving Credit Agreement.
As of December 31, 2025, we were in compliance with all covenants under the Revolving Credit Agreement.
As of December 31, 2025, we had unused borrowing capacity under the Revolving Credit Agreement of $750 million and no outstanding letters of credit under the Revolving Credit Agreement. In addition, there were no borrowings outstanding under the Prior Credit Agreement as of December 31, 2024, or during the years ended December 31, 2025 or 2024.
Letters of Credit Under Reimbursement Agreement
We are party to a reimbursement agreement providing for the issuance of up to $425 million of letters of credit. As of December 31, 2025, approximately $339 million of letters of credit were outstanding under this agreement. The primary purpose of the letters of credit outstanding is to provide credit support to Canadian taxing authorities for amounts related to certain tax years that were reassessed and objected to, and which have been accepted for consideration under the bilateral settlement provisions of the U.S.-Canada tax treaty by the United States and Canadian competent authorities.
Senior Notes
Long-term debt presented on our consolidated balance sheets as of December 31, 2025 and 2024 consisted of the following debt securities issued by CF Industries:
Effective Interest Rate
December 31, 2025
December 31, 2024
Principal Outstanding
Carrying Amount (1)
Principal Outstanding
Carrying Amount (1)
(in millions)
Public Senior Notes:
5.150% due March 2034
5.300% due November 2035
4.950% due June 2043
5.375% due March 2044
Senior Secured Notes:
4.500% due December 2026 (2)
Total long-term debt
(1) Carrying amount is net of unamortized debt discount and deferred debt issuance costs. Total unamortized debt discount was $5 million and $6 million as of December 31, 2025 and 2024, respectively, and total deferred debt issuance costs were $30 million and $23 million as of December 31, 2025 and 2024, respectively.
(2) Effective August 23, 2021, these notes were no longer secured, in accordance with the terms of the applicable indenture.
On November 26, 2025, CF Industries issued $1 billion aggregate principal amount of the 2035 Notes, which are fully and unconditionally guaranteed by CF Holdings. The net proceeds, after deducting discounts and offering expenses, from the issuance and sale of the 2035 Notes were approximately $989 million. On December 26, 2025, we used approximately $756 million of the net proceeds to redeem in full the outstanding $750 million aggregate principal amount of the 2026 Notes. As a result, we recognized a loss on debt extinguishment of $6 million, consisting primarily of the premium paid on the redemption of the $750 million principal amount of the 2026 Notes prior to their scheduled maturity. We intend that the remainder of the net proceeds will be used for general corporate purposes.
Pursuant to Rule 3-10 of Regulation S-X and Rule 12h-5 of the Exchange Act, subsidiary issuers of obligations guaranteed by their parent company are not required to provide separate financial statements, provided that the subsidiary obligor is consolidated into such parent company’s consolidated financial statements, such related guarantee is “full and unconditional” and, subject to certain exceptions as set forth below, the alternative disclosure required by Rule 13-01 is provided, which includes narrative disclosure and summarized financial information. CF Holdings owns substantially all of its assets and conducts substantially all of its operations through CF Industries, and CF Industries is consolidated into CF Holdings’ financial statements. Our Public Senior Notes either meet the conditions of this requirement or are otherwise not
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required to be presented. Accordingly, separate consolidated financial statements of CF Industries have not been presented.
Furthermore, as permitted under Rule 13-01(a)(4)(vi) of Regulation S-X, summarized financial information for CF Industries has been excluded because the assets, liabilities and results of operations of CF Industries are not materially different than the corresponding amounts in CF Holdings’ consolidated financial statements incorporated by reference herein, and because management believes such summarized financial information would not be material for investors.
Under the indentures (including the applicable supplemental indentures) governing our senior notes due 2034, 2035, 2043 and 2044 identified in the table above (the Public Senior Notes), each series of Public Senior Notes is guaranteed by CF Holdings. Interest on the Public Senior Notes is payable semiannually, and the Public Senior Notes are redeemable at our option, in whole at any time or in part from time to time, at specified make-whole redemption prices.
The indentures governing the Public Senior Notes contain covenants that limit, among other things, the ability of CF Holdings and its subsidiaries, including CF Industries, to incur liens on certain assets to secure debt, to engage in sale and leaseback transactions, to merge or consolidate with other entities and to sell, lease or transfer all or substantially all of the assets of CF Holdings and its subsidiaries to another entity. Each of the indentures governing the Public Senior Notes provides for customary events of default, which include (subject in certain cases to customary grace and cure periods), among others, nonpayment of principal or interest on the applicable Public Senior Notes; failure to comply with other covenants or agreements under the indenture; certain defaults on other indebtedness; the failure of CF Holdings’ guarantee of the applicable Public Senior Notes to be enforceable; and specified events of bankruptcy or insolvency. Under each indenture governing the Public Senior Notes, in the case of an event of default arising from one of the specified events of bankruptcy or , the applicable Public Senior Notes would become due and payable immediately, and, in the case of any other event of (other than an event of related to CF Industries’ and CF Holdings’ reporting obligations), the trustee or the holders of at least 25% in aggregate principal amount of the applicable Public Senior Notes then outstanding may declare all of such Public Senior Notes to be due and payable immediately.
Under each of the indentures governing the Public Senior Notes, specified changes of control involving CF Holdings or CF Industries, when accompanied by a ratings downgrade, as defined with respect to the applicable series of Public Senior Notes, constitute change of control repurchase events. Upon the occurrence of a change of control repurchase event with respect to a series of Public Senior Notes, unless CF Industries has exercised its option to redeem such Public Senior Notes, CF Industries will be required to offer to repurchase them at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but not including, the date of repurchase.
Forward Sales and Customer Advances
We offer our customers the opportunity to purchase products from us on a forward basis at prices and on delivery dates we propose. Therefore, our reported fertilizer selling prices and margins may differ from market spot prices and margins available at the time of shipment.
Customer advances, which typically represent a portion of the contract’s value, are received shortly after the contract is executed, with any remaining unpaid amount generally being collected by the time control transfers to the customer, thereby reducing or eliminating the accounts receivable related to such sales. Any cash payments received in advance from customers in connection with forward sales contracts are reflected on our consolidated balance sheets as a current liability until control transfers and revenue is recognized. As of December 31, 2025 and 2024, we had $77 million and $118 million, respectively, in customer advances on our consolidated balance sheets.
While customer advances are generally a significant source of liquidity, the level of forward sales contracts is affected by many factors, including current market conditions, our customers’ outlook of future market fundamentals and seasonality. During periods of declining prices, customers tend to delay purchasing fertilizer in anticipation that prices in the future will be lower than the current prices. If the level of sales under our forward sales programs were to decrease in the future, our cash received from customer advances would likely decrease and our accounts receivable balances would likely increase. Additionally, borrowing under the Revolving Credit Agreement could become necessary. Due to the volatility inherent in our business and changing customer expectations, we cannot estimate the amount of future forward sales activity.
Under our forward sales programs, a customer may delay delivery of an order due to weather conditions or other factors. These delays generally subject the customer to potential charges for storage or may be grounds for termination of the contract by us. Such a delay in scheduled shipment or termination of a forward sales contract due to a customer’s inability or unwillingness to perform may negatively impact our reported sales.
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Natural Gas
Natural gas is the principal raw material used to produce our nitrogen products. Natural gas is both a chemical feedstock and a fuel used to produce nitrogen products. Natural gas is the largest and most volatile component of the manufacturing cost for our nitrogen products, representing approximately 34% of our total production costs in 2025. As a result of these factors, natural gas prices have a significant impact on our operating expenses and can thus affect our liquidity. Natural gas costs in our cost of sales, including the impact of realized natural gas derivatives, increased 38% to $3.31 per MMBtu in 2025 from $2.40 per MMBtu in 2024.
We enter into agreements for a portion of our future natural gas supply and related transportation. As of December 31, 2025, our natural gas purchase agreements have terms that range from five months to five years and a total minimum commitment of approximately $2.87 billion, and our natural gas transportation agreements have terms that range from one to five years and a total minimum commitment of approximately $254 million. Our minimum commitments to purchase and transport natural gas are based on prevailing market-based forward prices excluding reductions for plant maintenance and turnaround activities.
All of our ammonia manufacturing plants are located in the United States and Canada. As a result, the price of natural gas in North America directly impacts a substantial portion of our operating expenses. During the three-year period ended December 31, 2025, the daily closing price at the Henry Hub, the most heavily-traded natural gas pricing point in North America, reached a low of $1.23 per MMBtu on four consecutive days in November 2024 and a high of $12.97 per MMBtu on four consecutive days in January 2024.
Derivative Financial Instruments
We use derivative financial instruments to reduce our exposure to changes in prices for natural gas that will be purchased in the future. Natural gas is the largest and most volatile component of our manufacturing cost for nitrogen-based products. From time to time, we may also use derivative financial instruments to reduce our exposure to changes in foreign currency exchange rates. Volatility in reported quarterly earnings can result from the unrealized mark-to-market adjustments in the value of the derivatives. In 2025, we recognized an unrealized net mark-to-market loss of $5 million compared to a gain of $35 million in 2024, which is reflected in cost of sales in our consolidated statements of operations.
Derivatives expose us to counterparties and the risks associated with their ability to meet the terms of the contracts. For derivatives that are in net asset positions, we are exposed to credit loss from nonperformance by the counterparties. We control our credit risk through the use of multiple counterparties that are multinational commercial banks, other major financial institutions or large energy companies, and the use of International Swaps and Derivatives Association (ISDA) master netting arrangements. The ISDA agreements are master netting arrangements commonly used for over-the-counter derivatives that mitigate exposure to counterparty credit risk, in part, by creating contractual rights of netting and setoff, the specifics of which vary from agreement to agreement.
The ISDA agreements for most of our derivative instruments contain credit-risk-related contingent features, such as cross default provisions. In the event of certain defaults or termination events, our counterparties may request early termination and net settlement of certain derivative trades or may require us to collateralize derivatives in a net liability position. As of December 31, 2025 and 2024, the aggregate fair value of the derivative instruments with credit-risk-related contingent features in net liability positions was $4 million and zero, respectively, which also approximates the fair value of the assets that may be needed to settle the obligations if the credit-risk-related contingent features were triggered at the reporting dates.
As of December 31, 2025, our open natural gas derivative contracts consisted of natural gas basis swaps for 13.5 million MMBtus. As of December 31, 2024, our open natural gas derivative contracts consisted of natural gas fixed price swaps and basis swaps for 16.0 million MMBtus. At both December 31, 2025 and 2024, we had no cash collateral on deposit with counterparties for derivative contracts. The credit support documents executed in connection with certain of our ISDA agreements generally provide us and our counterparties the right to set off collateral against amounts owing under the ISDA agreements upon the occurrence of a default or a specified termination event.
Defined Benefit Pension Plans
In the fourth quarter of 2025, pursuant to the implementation of our retirement plan strategy for our Canadian and U.K. pension plans, we entered into agreements with insurance companies to purchase non-participating group buy-in annuity contracts (buy-in contracts), and for one of our Canadian plans, a non-participating group buy-out annuity contract that transferred the majority of the plan’s projected benefit obligation to the insurance company. While the buy-in contracts did not transfer the projected benefit obligations to the insurance companies, they were structured to align with the projected benefits
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for each of the plans and are held as pension trust assets. As a result of these transactions, we do not expect to have significant required contributions for our Canadian or U.K. pension plans.
As a result of the planned windup of our U.S. pension plan with an effective termination date of December 31, 2025, we expect to contribute approximately $9 million to this plan in 2026, representing the estimated plan termination liability.
We contributed $2 million to our pension plans in 2025. See Note 11—Pension and Other Postretirement Benefits for additional information.
Distributions to Noncontrolling Interests in CFN
The CFN Board of Managers approved semi-annual distribution payments for the years ended December 31, 2025, 2024 and 2023, in accordance with CFN’s limited liability company agreement, as follows:
Approved and paid
Distribution Period
Distribution Amount
(in millions)
First quarter of 2026
Six months ended December 31, 2025
Third quarter of 2025
Six months ended June 30, 2025
First quarter of 2025
Six months ended December 31, 2024
Third quarter of 2024
Six months ended June 30, 2024
First quarter of 2024
Six months ended December 31, 2023
Third quarter of 2023
Six months ended June 30, 2023
Cash Flows
Net cash provided by operating activities in 2025 was $2.75 billion, an increase of $481 million compared to $2.27 billion in 2024. The increase in cash flow from operations was due primarily to an increase in gross margin, driven by increased average selling prices and higher sales volume, partially offset by higher natural gas costs. During 2025, net changes in working capital also impacted cash flow from operations by contributing $200 million less toward net cash from operations in 2025 than in 2024. These changes primarily occurred in changes in accounts receivable and inventories.
Net cash used in investing activities was $933 million in 2025 compared to $469 million in 2024, or an increase of $464 million. During 2025, capital expenditures totaled $950 million compared to $518 million in 2024. Our capital expenditures for 2025 included $307 million related to the Blue Point joint venture.
Net cash used in financing activities was $1.48 billion in 2025 compared to $2.21 billion in 2024. In 2025, we received proceeds of approximately $999 million, net of discounts, from the issuance of the 2035 Notes, which were used to fund the prepayment of the $750 million of 2026 Notes and the related make-whole payment of $4 million. In addition, the decrease in net cash used in financing activities was due primarily to contributions from noncontrolling interests in 2025 of $291 million, a decrease in share repurchases in 2025 compared to 2024, and a decrease in dividends paid on common stock in 2025 compared to 2024 due to lower shares outstanding as a result of common shares repurchased under our share repurchase programs. In 2025, we paid $1.37 billion for share repurchases compared to $1.51 billion for share repurchases in 2024. In 2025, dividends paid on common stock were $326 million in 2025 compared to $364 million in 2024.
Critical Accounting Estimates
Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP). U.S. GAAP requires that we select policies and make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates. We base our estimates on historical experience, technological assessment, opinions of appropriate outside experts, and the most recent information available to us. Actual results may differ from these estimates. Changes in estimates that may have a material impact on our results are discussed in the context of the underlying financial statements to which they relate. The following discussion presents information about our most critical accounting estimates.
Recoverability of Long-Lived Assets, Goodwill and Investment in Unconsolidated Affiliate
We review the carrying values of our property, plant and equipment and other long-lived assets, including our finite-lived intangible assets, goodwill and our investment in an unconsolidated affiliate in accordance with U.S. GAAP in order to assess recoverability. Factors that we must estimate when performing impairment tests include production and sales volumes, selling
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prices, raw material costs, operating rates, operating expenses, inflation, discount rates, exchange rates, tax rates, capital spending and the impact that future market dynamics and geopolitical events could have on these factors. Judgment is involved in estimating each of these factors, which include inherent uncertainties. The factors we use are consistent with those used in our internal planning process. The recoverability of the values associated with our goodwill, long-lived assets and our investment in an unconsolidated affiliate is dependent upon future operating performance of the specific businesses to which they are attributed. Certain of the operating assumptions are particularly sensitive to the cyclical nature of the fertilizer industry. Adverse changes in demand for our products, increases in supply and the availability and costs of key raw materials could significantly affect the results of our review.
The recoverability and impairment tests of long-lived assets are required only when conditions exist that indicate the carrying value may not be recoverable. For goodwill, impairment tests are required at least annually, or more frequently whenever events or circumstances indicate that the carrying value may not be recoverable. Our investment in an unconsolidated affiliate is reviewed for impairment whenever events or circumstances indicate that its carrying value may not be recoverable. When circumstances indicate that the fair value of our investment is less than its carrying value, and the reduction in value is other than temporary, the reduction in value would be recognized immediately in earnings.
We evaluate goodwill for impairment in the fourth quarter at the reporting unit level. Our evaluation generally begins with a qualitative assessment of the factors that could impact the significant inputs used to estimate fair value. If after performing the qualitative assessment, we determine that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, then no further analysis is necessary. However, if it is unclear based on the results of the qualitative test, we perform a quantitative test, which involves comparing the fair value of a reporting unit with its carrying amount, including goodwill. We use an income-based valuation method, determining the present value of future cash flows, to estimate the fair value of a reporting unit. If the fair value of a reporting unit exceeds its carrying amount, no further testing is necessary. If the fair value of the reporting unit is less than its carrying amount, goodwill impairment would be recognized equal to the amount of the carrying value in excess of the reporting unit’s fair value, limited to the total amount of goodwill allocated to the reporting unit.
We review property, plant and equipment and other long-lived assets at the asset group level in order to assess recoverability based on expected future undiscounted cash flows. If the sum of the expected future net undiscounted cash flows is less than the carrying value, an impairment loss would be recognized. The impairment loss is measured as the amount by which the carrying value exceeds the fair value of the long-lived assets.
In November 2025, we experienced an incident in the AN upgrade area at our Yazoo City complex that required us to temporarily idle all production at the site. As a result of the damage incurred and based on estimates and assumptions of a preliminary review of the impact, we recorded an impairment of certain fixed assets within our North American AN asset group of $25 million. We concluded that the incident necessitated evaluations of the long-lived assets within our North American AN asset group and the goodwill allocated to our North American AN reporting unit to determine if their fair value had declined to below their carrying value. The results of our long-lived asset impairment test indicated that there was no additional impairment, and the results of our goodwill impairment test concluded that the goodwill allocated to our North American AN reporting unit was not impaired. See Note 6—Property, Plant and Equipment—Net and Note 7—Goodwill and Other Intangible Assets for additional information.
PLNL is our joint venture investment in Trinidad and operates an ammonia plant that relies on natural gas supplied, under a gas sales contract (the NGC Contract), by The National Gas Company of Trinidad and Tobago Limited (NGC). The joint venture is accounted for under the equity method. From time to time, the PLNL joint venture has experienced curtailments in the supply of natural gas from NGC, which has reduced the ammonia production at PLNL.
In the third quarter of 2023, PLNL entered into the NGC Contract, which replaced the previous gas sales contract that PLNL had with NGC. Due to the terms of the NGC Contract, in the third quarter of 2023, we assessed our investment in PLNL for impairment and determined that the carrying value of our equity method investment in PLNL exceeded its fair value. As a result, we recorded an impairment of our equity method investment in PLNL of $43 million, which is reflected in equity in earnings (loss) of operating affiliate in our consolidated statement of operations for the year ended December 31, 2023.
The NGC Contract was scheduled to expire on January 1, 2026. NGC and PLNL have entered into short-term extension letter agreements that provide for the continued supply of gas while the parties seek to negotiate terms and conditions for a new gas sales contract for 2026. Any NGC commitment to supply gas is dependent on mutual agreement of such terms and conditions between NGC and PLNL. Furthermore, any NGC commitment to supply gas beyond 2026 would require further negotiations between NGC and PLNL.
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If NGC does not make sufficient quantities of natural gas available to PLNL at prices and terms that permit profitable operations, PLNL may cease operating its facility, which would trigger an impairment assessment of our remaining investment in PLNL. The carrying value of our equity method investment in PLNL at December 31, 2025 was $32 million.
Projected Benefit Obligations
The projected benefit obligations (PBOs) for our defined benefit pension plans are affected by plan design, actuarial estimates and discount rates. Key assumptions that affect our PBO are discount rates and, in addition for our United Kingdom plans, inflation rates, including an adjusted U.K. retail price index (RPI).
Given the derisking activities resulting from a revision to our retirement plan strategy, including the plan terminations of two of the North American pension plans effective December 31, 2025, and the purchase of a buy-out annuity contract in the fourth quarter of 2025 that transferred approximately 94% of the other North American pension plan’s liability to an insurance company, the key assumptions used to value the PBO of our North American plans as of December 31, 2025, were not considered critical accounting estimates.
For our United Kingdom plans, the December 31, 2025 PBO was computed based on a weighted-average discount rate of 5.5% for our United Kingdom plans, which was based on yields for high-quality (AA rated or better) fixed income debt securities that match the timing and amounts of expected benefit payments as of the measurement date of December 31, 2025. Declines in comparable bond yields would increase our PBO. For our United Kingdom plans, the 2.8% RPI used to calculate our PBO is developed using a U.K. government gilt prices only retail price inflation curve, which is based on the difference between yields on fixed interest government bonds and index-linked government bonds.
For our United Kingdom pension plans, our PBO was $335 million as of December 31, 2025, which was $22 million lower than pension plan assets. The table below estimates the impact of a 50 basis point increase or decrease in the key assumptions on our December 31, 2025 PBO for our United Kingdom pension plans:
Increase/(Decrease) in December 31, 2025 PBO
United Kingdom Plans
Assumption
+50 bps
-50 bps
(in millions)
Discount Rate
RPI
See Note 11—Pension and Other Postretirement Benefits for further discussion of our pension plans.
Income Taxes
We are subject to the income tax laws of the many jurisdictions in which we operate, and we recognize expense, assets and liabilities based on estimates of amounts that ultimately will be determined to be taxable or deductible in tax returns filed in various jurisdictions. These tax laws are complex, and how they apply to our facts is sometimes open to interpretation. We recognize the effect of income tax positions only if sustaining those positions is more likely than not. Tax positions that meet the more likely than not recognition threshold but are not highly certain are measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement with the taxing authority. Differences in interpretation of the tax laws and regulations, including negotiations with taxing authorities in various jurisdictions and resolution of disputes arising from federal, state and international tax audits, can result in differences in taxes paid, which may be higher or lower than our estimates. The judgments made at a point in time may change from previous conclusions based on the outcome of tax audits, as well as changes to, or further interpretations of, tax laws and regulations, and these changes could significantly impact the provision for income taxes, the amount of taxes payable and the deferred tax asset and liability balances. We adjust our income tax provision in the period in which these changes occur. As of December 31, 2025, we have recorded a reserve for unrecognized tax benefits, including and interest, of $357 million.
We also engage in a significant amount of cross-border transactions. The taxability of cross-border transactions has received an increasing level of scrutiny among regulators across the globe, including the jurisdictions in which we operate. The tax rules and regulations of the various jurisdictions in which we operate are complex, and in many cases, there is not symmetry between the rules of the various jurisdictions. As a result, there are instances where regulators within the jurisdictions involved in a cross-border transaction may reach different conclusions regarding the taxability of the transaction in their respective jurisdictions based on the same set of facts and circumstances. We work closely with regulators to reach a common understanding and conclusion regarding the taxability of cross-border transactions.
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Recent Accounting Pronouncements
See Note 3—New Accounting Standards for a discussion of recent accounting pronouncements.
