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Item 7. Management’s Discussion and Analysis

2026-02-25 compared with 2025-02-20 · 511 added, 348 removed, 579 unchanged (60% of the section changed)

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• Overview of CF Holdings

• Market Conditions

• Market Conditions and Current Developments

• Financial Executive Summary

• Acquisition of Waggaman Ammonia Production Facility

• Items Affecting Comparability of Results

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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 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 underpin our strategy to leverage our unique capabilities to accelerate the world’s transition to clean energy.

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.

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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:

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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 19—Noncontrolling Interest for additional information on our strategic venture with CHS);

(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;

CF INDUSTRIES HOLDINGS, INC.

• a United Kingdom manufacturing facility located in Billingham;

• an extensive system of terminals and associated transportation equipment located primarily in the Midwestern United States;

CF INDUSTRIES HOLDINGS, INC.

• 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;

• 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.

At our core, CF Industries is a producer of ammonia.

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Our strategy is to leverage our unique capabilities to accelerate the world’s transition to clean energy.

We believe this strategy builds upon our leadership in ammonia production to capture emerging opportunities to produce ammonia with a lower carbon intensity (“low-carbon ammonia”) than that of ammonia produced through traditional processes.

These opportunities include traditional applications in agriculture to help reduce the carbon footprint of food production and the life cycle carbon intensity of ethanol production, enabling production of sustainable aviation fuel, among other purposes.

These opportunities also include new growth opportunities from energy-intensive industries, such as power generation and marine shipping, as ammonia represents an efficient mechanism to both ship and store hydrogen, as well as a clean energy fuel source in its own right as ammonia does not contain or emit carbon when combusted.

Our strategy also strengthens our existing business.

We execute our strategy across four dimensions:

• decarbonizing our existing network to accelerate the availability of low-carbon ammonia and upgraded nitrogen products for traditional agricultural and industrial applications;

• evaluating new low-carbon ammonia capacity growth to supply emerging opportunities from power generation and marine shipping, among others;

• forging partnerships to accelerate our timeline, reducing risks and bridging gaps in areas where we do not have expertise;

• collaborating to build understanding of ammonia’s clean energy capability, safety track record and regulatory environment.

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.

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

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.

Construction of the dehydration and compression unit at our Donaldsonville complex is in advanced stages, with an estimated total cost of approximately $200 million over the life of the project.

Construction of the dehydration and compression unit at our Yazoo City complex is expected to cost approximately $100 million over the life of the project.

For each facility we have contracted with ExxonMobil to transport and sequester the captured CO 2 in permanent geologic storage.

At Donaldsonville, CCS is expected to commence in 2025 and annually will sequester up to approximately 2 million metric tons of CO 2 that would otherwise have been emitted to the atmosphere.

At Yazoo City, CCS is expected to commence in 2028 and annually will sequester up to approximately 500,000 metric tons of CO 2 that would otherwise have been emitted to the atmosphere.

Each project is expected to qualify under Section 45Q of the Internal Revenue Code for tax credits per metric ton of sequestered CO 2 .

Decarbonization projects in our existing network also include our 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.

Upon identification and remediation of the issue, we expect to resume commissioning activities.

At full electrolyzer capacity, we will be able to produce approximately 20,000 tons of low-carbon ammonia per year.

Our decarbonization projects also include front-end engineering and design (FEED) studies to inform our evaluation of whether, and how best, to invest in export-oriented, low-carbon ammonia capacity at our Blue Point complex in Ascension Parish, Louisiana, to supply developing clean energy markets and traditional ammonia markets where demand for low-carbon product is emerging.

In the fourth quarter of 2024, we received results from a FEED study evaluating the use of autothermal reforming (ATR) ammonia production technology alongside CCS to enable the production of low-carbon ammonia.

ATR technology, when combined with CCS to capture and sequester process CO 2 emissions, is expected to reduce CO 2 emissions from the ammonia

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.

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.

CF INDUSTRIES HOLDINGS, INC.

production process by more than 90% compared to conventional ammonia plants.

The FEED study results estimate the costs of a project with these attributes to be approximately $4 billion for the approximately 1.4 million metric ton capacity greenfield ATR ammonia facility and CCS technologies.

Additionally, we estimate approximately $500 million would be required for the scalable common infrastructure for our Blue Point complex, such as ammonia storage and a vessel loading dock.

We have entered into joint development agreements (JDAs) with two potential partners, Mitsui & Co., Ltd.

and JERA Co., Inc.

for the development of the greenfield low-carbon ammonia capacity.

Our evaluation includes assessing whether the ammonia production technology under consideration will satisfy carbon intensity and other requirements for potential end users.

Should a positive final investment decision (FID) be reached to construct greenfield low-carbon ammonia capacity at our Blue Point complex, construction and commissioning is expected to take approximately four years from a positive FID.

In addition to discussions with existing customers who have interest in using low-carbon ammonia for traditional applications, we are engaged in discussions regarding the supply of low-carbon ammonia for new applications.

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.

CF INDUSTRIES HOLDINGS, INC.

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.

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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 reliability, customer service and product quality.

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.

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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 American nitrogen fertilizer producers more competitive.

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

CF INDUSTRIES HOLDINGS, INC.

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.

The North American nitrogen fertilizer market 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.

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.

CF INDUSTRIES HOLDINGS, INC.

Farmers’ Economics

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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

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.

CF INDUSTRIES HOLDINGS, INC.

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

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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 lower in 2024 than in 2023, as lower global energy costs reduced the global market clearing price required to meet global demand.

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 10% decrease in the average selling price for our products in 2024 compared to 2023 resulted in a year-over-year decrease in net sales of approximately $716 million.

Our total sales volume was 1% lower in 2024 than in 2023, due primarily to lower sales volume in our UAN, AN and Other segments, partially offset by higher sales volume in our Ammonia segment as a result of the Waggaman acquisition on December 1, 2023.

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.

In January 2024, a winter storm produced extremely cold temperatures that impacted our operations, including the temporary shut-down and lost production at certain of our plants.

Due to the impact of plant downtime resulting from the adverse weather and additional plant maintenance activity in the first quarter of 2024, we purchased and resold approximately 62,000 tons of ammonia and 48,000 tons of granular urea at near breakeven margins in order to fulfill sales commitments.

The plant downtime led to approximately $75 million of additional costs in the first quarter of 2024 for maintenance, repairs and certain unabsorbed fixed costs.

The acquisition of the Waggaman ammonia production facility closed on December 1, 2023, and therefore provided incremental net sales in the first eleven months of 2024.

As a result, the Waggaman acquisition increased our 2024 sales volume by 644,000 tons and increased our net sales by $249 million due to the incremental eleven months of ownership compared to 2023.

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.

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Natural gas is both a chemical feedstock and a fuel used to produce nitrogen products.

Natural gas is a significant cost component of our manufactured nitrogen products, representing approximately 28% and 40%, respectively, of our production costs in 2024 and 2023.

CF INDUSTRIES HOLDINGS, INC.

manufacturing facilities are located in the United States and Canada.

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.

In the first quarter of 2024, warmer-than-normal average temperatures in North America drove lower heating demand for natural gas, in spite of a short-lived period of extremely cold temperatures in January 2024 that affected most of North America.

North American natural gas supply remained strong through the quarter, with a decline in supply occurring near the end of the quarter as producers responded to a weaker price environment.

In addition, although the higher cost for natural gas outside of North America incentivized liquefaction facilities in the United States to export domestic natural gas during the first quarter of 2024, an outage at the Freeport liquefied natural gas facility limited total gas exports, supporting domestic supply.

During the second quarter of 2024, there was a decline in natural gas supply as producers responded to a weaker price environment, limiting the domestic supply available to be injected into storage during the quarter.

In addition, natural gas demand for power generation reached record levels in the second quarter of 2024 as higher-than-normal temperatures drove increased cooling demand.

In the third quarter of 2024, the decline in natural gas supply continued as producers curtailed production in response to low natural gas prices.

Natural gas demand from the power generation sector set records despite increased solar and wind generation, as low natural gas prices increased demand for gas-fired power.

Liquefied natural gas exports were steady through the quarter as delays on commissioning of new facilities and maintenance activities at existing plants held exports at levels reached during the second quarter of 2024.

Natural gas in storage remained above historical levels despite continued below-average injections into storage during the third quarter.

During the fourth quarter of 2024, natural gas supply increased as producers responded to higher prices by restarting previously curtailed production.

After a warm start to the quarter, December temperatures turned colder-than-normal, raising demand for heat and power generation.

Liquefied natural gas exports increased to the highest level of the year due to strong global demand for natural gas and the startup of a new liquefaction facility in the U.S.

The higher demand decreased the storage surplus compared to historical levels.

The average daily market price of natural gas at the Henry Hub, the most heavily-traded natural gas pricing point in North America, was $4.25 per MMBtu for the period from January 1, 2025 through February 14, 2025.

The following table presents the average daily market price of natural gas at the Henry Hub for the years ended December 31, 2024, 2023 and 2022:

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

CF INDUSTRIES HOLDINGS, INC.

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,

2025 2024 2023 2025 v.

Average daily market price of natural gas Henry Hub (Louisiana) $ 2.25 $ 2.53 $ 6.38 $ (0.28) (11) % $ (3.85) (60) %

The total cost of natural gas used for production at our manufacturing facilities, which includes the impact of realized natural gas derivatives, decreased 35% to $2.40 per MMBtu in 2024 from $3.67 per MMBtu in 2023.

The decrease in natural gas costs in 2024 as compared to 2023 resulted in an increase in gross margin of approximately $436 million, excluding the impact of the Waggaman acquisition.

Financial Executive Summary

We reported net earnings attributable to common stockholders of $1.22 billion in 2024 compared to $1.53 billion in 2023, a decrease in net earnings of 20%, or $307 million.

The decrease in net earnings primarily reflects a decrease in gross margin partially offset by a lower income tax provision and a decrease in net earnings attributable to the noncontrolling interest.

Gross margin decreased by $489 million, or 19%, to $2.06 billion for the year ended December 31, 2024 compared to $2.55 billion for the year ended December 31, 2023.

The decrease in gross margin was due primarily to a 10% decrease in average selling prices to $313 per ton in 2024 from $347 per ton in 2023, which decreased gross margin by $716 million, excluding the impact of the Waggaman acquisition, and a decrease in sales volume, which decreased gross margin by $123 million, excluding the impact of the Waggaman acquisition.

These factors that decreased gross margin were partially offset by (i) lower natural gas costs, which increased gross margin by $436 million, excluding the impact of the Waggaman acquisition, and (ii) the impact of the Waggaman acquisition completed on December 1, 2023, which increased our 2024 gross margin by $57 million due to the incremental eleven months of ownership compared to 2023.

Lower gross margin was partially offset by a decrease in the income tax provision of $125 million due primarily to lower pre-tax earnings in 2024 and a decrease of $54 million in net earnings attributable to the noncontrolling interest.

Average daily market price of natural gas Henry Hub (per MMBtu) $ 3.53 $ 2.25 $ 2.53 $ 1.28 57 % $ (0.28) (11) %

Cost of natural gas used for production in cost of sales (1) (per MMBtu)

$ 3.31 $ 2.40 $ 3.67 $ 0.91 38 % $ (1.27) (35) %

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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.

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.

CF INDUSTRIES HOLDINGS, INC.

Diluted net earnings per share attributable to common stockholders decreased $1.13 per share, to $6.74 per share in 2024 compared to $7.87 per share in 2023 due primarily to lower net earnings, partially offset by lower weighted-average common shares outstanding as a result of shares repurchased under our share repurchase programs.

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.

Acquisition of Waggaman Ammonia Production Facility

On December 1, 2023, we acquired an ammonia production facility located in Waggaman, Louisiana from Dyno Nobel Louisiana Ammonia, LLC (DNLA), a U.S.

subsidiary of Australia-based Incitec Pivot Limited (IPL), pursuant to an asset purchase agreement with DNLA and IPL.

The facility has a nameplate production capacity of 880,000 tons of ammonia annually.

Our acquisition of the Waggaman facility expanded our ammonia manufacturing and distribution capacity.

In connection with the acquisition, we entered into a long-term ammonia offtake agreement providing for us to supply up to 200,000 tons of ammonia per year to IPL’s Dyno Nobel, Inc.

Under the terms of the asset purchase agreement, $425 million of the purchase price of $1.675 billion, subject to adjustment, was allocated by the parties to the ammonia offtake agreement.

We funded the balance of the initial purchase price on the acquisition date with $1.223 billion of cash on hand.

The consideration transferred on the acquisition date reflected an estimated net working capital adjustment and other adjustments to the purchase price, which was subject to further adjustment pursuant to the terms of the asset purchase agreement.

The purchase price adjustments required under the asset purchase agreement were finalized in the second quarter of 2024, which resulted in a $2 million reduction in the purchase price with a corresponding reduction in goodwill.

As a result, the final purchase price was $1.221 billion.

In connection with recording the acquisition, we recognized, among other items, goodwill, intangible assets and a supply contract liability.

See Note 6—Acquisition of Waggaman Ammonia Production Facility for additional information.

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 the acquisition of the Waggaman ammonia production facility discussed above, certain items affected the comparability of our financial results during the years ended December 31, 2024 and 2023.

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.

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(in millions)

Unrealized net mark-to-market gain on natural gas derivatives (2)

Unrealized net mark-to-market loss (gain) on natural gas derivatives (2)

$ 5 $ 4 $ (35) $ (27)

Gain on foreign currency transactions (3)(4)

Asset impairment 76 58 — —

Loss on sale of Ince facility (5)

Blue Point joint venture construction costs (3)(4)

Loss on debt extinguishment 6 4 — —

Pension settlement loss (6)

Impact of employee benefit plan policy change (7)

— — (16) (13)

operations restructuring — — 10 8

Acquisition and integration costs 4 3 39 29

Impairment of equity method investment in PLNL (4)

Integration costs — — 4 3

Canada Revenue Agency Competent Authority Matter:

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______________________________________________________________________________

(1) The tax impact is calculated utilizing a marginal effective rate of 23.6% and 23.5% in 2024 and 2023, respectively, except for acquisition and integration costs related to the Waggaman acquisition, which reflects a 24.0% and 26.2% marginal effective rate in 2024 and 2023, respectively.

(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.

(4) Included in equity in earnings (loss) of operating affiliate in our consolidated statement of operations.

(8) Included in interest expense and interest income in our consolidated statement of operations.

CF INDUSTRIES HOLDINGS, INC.

Unrealized net mark-to-market gain on natural gas derivatives

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.

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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 2024 and 2023, we recognized unrealized net mark-to-market gains on natural gas derivatives of $35 million and $39 million, respectively.

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.

CF INDUSTRIES HOLDINGS, INC.

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 is included in both cost of sales and selling, general and administrative expenses in our consolidated statement of operations.

operations restructuring

In 2023, we recognized total charges of $10 million, consisting primarily of the recognition of an asset retirement obligation and post-employment benefits related to contractual and statutory obligations due to employees as a result of our approved plan to permanently close the ammonia plant at our Billingham complex.

Acquisition and integration costs

On December 1, 2023, we acquired an ammonia production facility located in Waggaman, Louisiana, as described above under “Acquisition of Waggaman Ammonia Production Facility.” In 2024, we incurred approximately $4 million of integration costs related to the Waggaman acquisition.

In 2023, we incurred $36 million of acquisition-related costs and $3 million of integration costs related to the Waggaman acquisition.

These costs are included in acquisition and integration costs in our consolidated statements of operations.

Impairment of equity method investment in PLNL

PLNL, our joint venture in Trinidad, 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 NGC Contract had an expiration date of September 2023.

In the third quarter of 2023, PLNL entered into a new gas sales contract with NGC (the New NGC Contract), which is effective October 2023 through December 2025.

In the third quarter of 2023 and due to the terms of the New NGC Contract, 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.

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 second half of 2022, as a result of the conclusion of arbitration proceedings and the settlement provisions between the United States and Canadian competent authorities related to tax years 2006 through 2011, we paid additional income taxes and related interest of $124 million and $100 million, respectively, to the Canada Revenue Agency (CRA) and Alberta Tax and Revenue Administration (Alberta TRA).

In the third quarter of 2024, we were informed that the CRA granted us discretionary interest relief for certain tax years from 2006 through 2011.

In the fourth quarter of 2024, we received the CRA portion of the interest relief consisting of interest refunds of $21 million and related interest of $2 million.

The interest relief from the Alberta TRA is estimated to be approximately $16 million, consisting of interest refunds of $15 million and related interest of $1 million, based on current estimates and foreign currency exchange rates as of December 31, 2024.

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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Selling, general and administrative expenses 364 320 289 44 14 % 31 11 %

long-lived and intangible asset impairment — — 239 — — % (239) (100) %

operations restructuring — 10 19 (10) (100) % (9) (47) %

Acquisition and integration costs 4 39 — (35) (90) % 39 N/M

Other operating—net (10) (31) 10 21 68 % (41) N/M

Asset impairment 76 — — 76 N/M — — %

operations restructuring 23 — 10 23 N/M (10) (100) %

Acquisition and integration costs — 4 39 (4) (100) % (35) (90) %

Other operating—net (25) (10) (31) (15) (150) % 21 68 %

Total other operating costs and expenses 438 314 307 124 39 % 7 2 %

Equity in earnings (loss) of operating affiliate 4 (8) 94 12 N/M (102) N/M

Equity in earnings (loss) of operating affiliate 14 4 (8) 10 250 % 12 N/M

Operating earnings 2,300 1,746 2,230 554 32 % (484) (22) %

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Interest income (81) (123) (158) 42 34 % 35 22 %

Loss on debt extinguishment — — 8 — — % (8) (100) %

Other non-operating—net (14) (10) 15 (4) (40) % (25) N/M

Loss on debt extinguishment 6 — — 6 N/M — — %

Other non-operating—net (19) (14) (10) (5) (36) % (4) (40) %

Earnings before income taxes 2,239 1,762 2,248 477 27 % (486) (22) %

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Net earnings 1,798 1,477 1,838 321 22 % (361) (20) %

Net earnings attributable to noncontrolling interest 259 313 591 (54) (17) % (278) (47) %

Net earnings attributable to noncontrolling interests 343 259 313 84 32 % (54) (17) %

Net earnings attributable to common stockholders $ 1,455 $ 1,218 $ 1,525 $ 237 19 % $ (307) (20) %

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Realized derivatives loss in COS (2)

0.12 0.41 0.02 (0.29) (71) % 0.39 N/M

0.01 0.12 0.41 (0.11) (92) % (0.29) (71) %

Cost of natural gas used for production in COS $ 3.31 $ 2.40 $ 3.67 $ 0.91 38 % $ (1.27) (35) %

Average daily market price of natural gas Henry Hub (Louisiana) $ 3.53 $ 2.25 $ 2.53 $ 1.28 57 % $ (0.28) (11) %

Unrealized net mark-to-market (gain) loss on natural gas derivatives $ (35) $ (39) $ 41 $ 4 10 % $ (80) N/M

Unrealized net mark-to-market loss (gain) on natural gas derivatives $ 5 $ (35) $ (39) $ 40 N/M $ 4 10 %

Depreciation and amortization $ 898 $ 925 $ 869 $ (27) (3) % $ 56 6 %

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AN 1,253 1,392 1,520 (139) (10) % (128) (8) %

CF INDUSTRIES HOLDINGS, INC.

______________________________________________________________________________

N/M—Not Meaningful

CF INDUSTRIES HOLDINGS, INC.

(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.

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Sales incentives are reported as a reduction in net sales.

Our total net sales decreased $695 million, or 10%, to $5.94 billion in 2024 compared to $6.63 billion in 2023.

The change in our net sales reflects (i) the impact of the Waggaman acquisition completed on December 1, 2023, which increased our net sales by $249 million, and (ii) a $944 million, or 14%, decline in our net sales excluding the impact of the Waggaman acquisition, due to a 10% decrease in average selling prices and a 4% decrease in sales volume.

Our average selling price was $313 per ton in 2024 compared to $347 per ton in 2023, a decrease of 10%, due to lower average selling prices across all of our segments, as lower global energy costs reduced the global market clearing price required to meet global demand.

The impact of lower average selling prices, excluding the impact of the Waggaman acquisition, was a decrease in net sales of approximately $716 million for 2024 compared to 2023.

Our total sales volume of 18.9 million product tons in 2024 was 1% lower compared to 19.1 million product tons in 2023, due primarily to lower sales volume in our UAN, AN and Other segments, partially offset by higher sales volume in our Ammonia segment driven by the impact of the Waggaman acquisition, which increased our 2024 sales volume by 644,000 tons due to the incremental eleven months of ownership compared to 2023.

Excluding the impact of the Waggaman acquisition, the impact of lower sales volume was a decrease in net sales of approximately $228 million.

Gross ammonia production for 2024 increased to approximately 9.8 million tons compared to 9.5 million tons in 2023.

We expect gross ammonia production for 2025 will be approximately 10 million tons.

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

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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.

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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 decreased $206 million, or 5%, to $3.88 billion in 2024 as compared to $4.09 billion in 2023.

The decrease in our cost of sales primarily reflects lower realized natural gas costs, including the impact of realized derivatives.

The impact of lower realized natural gas costs decreased cost of sales by $436 million, excluding the impact of the Waggaman acquisition.

The impact of lower realized natural gas costs was partially offset by higher costs for planned and unplanned maintenance and repair activities in 2024, including the impact of the adverse weather in January 2024, as discussed above under “Nitrogen Selling Prices and Sales Volume,” and the impact of the Waggaman acquisition, which increased our cost of sales by $192 million due to the incremental eleven months of ownership compared to 2023.

Cost of sales also includes the impact of a $35 million unrealized net mark-to-market gain on natural gas derivatives in 2024 compared to a $39 million gain in 2023.

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.

CF INDUSTRIES HOLDINGS, INC.

Cost of sales averaged $204 per ton in 2024, a 5% decrease from $214 per ton in 2023.

Our cost of natural gas, including the impact of realized derivatives, decreased 35% to $2.40 per MMBtu in 2024 from $3.67 per MMBtu in 2023.

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 certain taxes and insurance and other professional service fees, including those for corporate initiatives, and amortization of definite-lived intangible assets.

Selling, general and administrative expenses increased $31 million to $320 million in 2024 compared to $289 million in 2023.

The increase was due primarily to an increase of $21 million in amortization expense related to the customer relationships recognized in conjunction with the Waggaman acquisition on December 1, 2023, and an increase in costs related to certain corporate initiatives.

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.

Operations Restructuring

In 2023, related to our U.K.

operations, we recognized total charges of $10 million, consisting primarily of the recognition of an asset retirement obligation and post-employment benefits related to contractual and statutory obligations due to employees as a result of our approved plan to permanently close the ammonia plant at our Billingham complex.

See Note 7—United Kingdom Operations Restructuring and Impairment Charges for further discussion of the Billingham ammonia plant closure.

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

On December 1, 2023, we acquired an ammonia production facility located in Waggaman, Louisiana, as described above under “Acquisition of Waggaman Ammonia Production Facility.” In 2024, we incurred $4 million of integration costs related to the Waggaman acquisition.

In 2023, we incurred $36 million of acquisition-related costs and $3 million of 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 and FEED study costs related to our clean energy initiatives.

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.

In both 2024 and 2023, the income recognized consists primarily of gains on sales of emission credits, partially offset by FEED study costs for our clean energy initiatives.

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.

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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 (loss) of operating affiliate was $4 million of earnings in 2024 compared to an $8 million loss in 2023, which includes an impairment of our equity method investment in PLNL of $43 million recognized in the third quarter of 2023.

See “Items Affecting Comparability of Results—Impairment of equity method investment in PLNL,” above, for further discussion.

Lower equity in earnings of operating affiliate in 2024 compared to 2023, excluding the impact from the impairment charge, primarily reflects a decrease in the operating results of PLNL as a result of a plant turnaround in the second quarter of 2024 at the PLNL facility in Trinidad, lower ammonia selling prices, higher natural gas costs and lower operating rates at PLNL due to lower availability of natural gas.

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 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 $121 million in 2024 compared to $150 million in 2023.

The decrease of $29 million was due primarily to a reduction in interest on tax liabilities driven by a $36 million reduction in interest expense recognized in 2024 related to discretionary interest relief granted to us by Canadian taxing authorities that is further described above under “Items Affecting Comparability of Results—Canada Revenue Agency Competent Authority Matter.”

Capitalized interest relating to

CF INDUSTRIES HOLDINGS, INC.

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

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Interest income was $81 million in 2025 compared to $123 million in 2024.

The decrease of $35 million was due primarily to a $52 million decrease in interest income on short-term investments in 2024, partially offset by $3 million of interest income in 2024 related to discretionary interest relief that is further described above under “Items Affecting Comparability of Results—Canada Revenue Agency Competent Authority Matter.”

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.

Our effective tax rate is impacted by earnings attributable to the noncontrolling interest in CFN, as our consolidated income tax provision does not include a tax provision on the earnings attributable to the noncontrolling interest.

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 interest of $259 million.

Our effective tax rate for 2023 of 18.3%, which is based on pre-tax income of $2.25 billion, would be 2.9 percentage points higher, or 21.2%, if based on pre-tax income exclusive of the earnings attributable to the noncontrolling interest of $313 million.

Both 2024 and 2023 were impacted by additional discrete tax items.

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.

See Note 10—Income Taxes for additional information.

Net Earnings Attributable to Noncontrolling Interest

Net earnings attributable to noncontrolling interest includes the net earnings attributable to the approximately 11% CHS minority equity interest in CFN, a subsidiary of CF Holdings.

Net earnings attributable to noncontrolling interest decreased $54 million, or 17%, to $259 million in 2024 compared to $313 million in 2023 due to lower earnings of CFN driven by lower average selling prices as described above under “Net Sales,” partially offset by lower natural gas costs.

Diluted Net Earnings Per Share Attributable to Common Stockholders

Net earnings per share attributable to common stockholders decreased 14% to $6.74 per diluted share in 2024 from $7.87 per diluted share in 2023.

This decrease was due primarily to a decrease in gross margin, driven by lower average selling prices, partially offset by lower natural gas costs.

Lower gross margin was partially offset by a decrease in the income tax provision resulting from lower profitability and a decrease in net earnings attributable to the noncontrolling interest.

Additionally, diluted weighted-average common shares outstanding declined 7% from 193.8 million shares for 2023 to 180.7 million shares for 2024, due primarily to repurchases of common shares under our share repurchase programs.

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.

CF INDUSTRIES HOLDINGS, INC.

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 segment structure reflects how our chief operating decision maker, as defined in accounting principles generally accepted in the United States (U.S.

GAAP), assesses the performance of our reportable segments and makes decisions about resource allocation.

Our reportable segments consist of Ammonia, Granular Urea, UAN, AN and Other.

These segments are differentiated by products.

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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:

Granular Urea (2)

Ammonia Granular Urea (1)

(in millions)

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_______________________________________________________________________________

(1) The financial results of the Waggaman facility are included in the Ammonia segment from the Waggaman acquisition date of December 1, 2023.

See “Acquisition of Waggaman Ammonia Production Facility” for additional information.

(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.

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Year ended December 31,

2025 2024 2023 2025 v.

(in millions, except as noted)

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Depreciation and amortization $ 249 $ 239 $ 171 $ 10 4 % $ 68 40 %

Unrealized net mark-to-market (gain) loss on natural gas derivatives $ (13) $ (11) $ 13 $ (2) (18) % $ (24) N/M

Unrealized net mark-to-market loss (gain) on natural gas derivatives $ 2 $ (13) $ (11) $ 15 N/M $ (2) (18) %

_______________________________________________________________________________

N/M—Not Meaningful

(1) The financial results of the Waggaman facility are included in the Ammonia segment from the Waggaman acquisition date of December 1, 2023.

See “Acquisition of Waggaman Ammonia Production Facility” for additional information.

(1) Ammonia represents 82% nitrogen content.

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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 15% increase in sales volume, including the impact of the Waggaman acquisition completed on December 1, 2023, partially offset by a 10% decrease in average selling prices.

Average selling prices decreased to $425 per ton in 2024 compared to $473 per ton in 2023 as lower global energy costs reduced the global market clearing price required to meet global demand.

In January 2024, a winter storm produced extremely cold temperatures that impacted our operations, including the temporary shut-down of certain of our plants.

As a result of the adverse weather, we incurred additional maintenance costs in the first quarter of 2024.

Due to the impact of plant downtime resulting from the adverse weather and additional plant maintenance activity in the first quarter of 2024, we purchased and resold 62,000 tons of ammonia at near breakeven margins in order to fulfill sales commitments.

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 reflects both the impact of the Waggaman acquisition completed on December 1, 2023, which increased our ammonia sales volume in 2024 by 644,000 tons due to the incremental eleven months of ownership compared to 2023, and 62,000 tons of ammonia purchased and resold as described above, partially offset by lower demand due to lower spring ammonia applications in North America compared to the prior year as a result of unfavorable weather.

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 $304 per ton in 2024, a 5% decrease from $320 per ton in 2023.

The decrease was due primarily to lower realized natural gas costs, including the impact of realized derivatives, partially offset by higher costs for maintenance, repairs and certain unabsorbed fixed costs as a result of plant downtime, including the impact of the adverse weather in January 2024 as discussed above.

The impact of the Waggaman acquisition on our cost of sales per ton in our Ammonia segment was not material.

CF INDUSTRIES HOLDINGS, INC.

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 decreased by $48 million, or 9%, to $493 million in 2024 from $541 million in 2023, and our gross margin percentage was 28.4% in 2024 compared to 32.2% in 2023.

The decrease in gross margin was due primarily to a 10% decrease in average selling prices, which decreased gross margin by $160 million, a net increase in manufacturing, maintenance and other costs, which decreased gross margin by $121 million, and, excluding the impact of the Waggaman acquisition, a decrease in sales volume, which decreased gross margin by $8 million.

These factors that decreased gross margin were partially offset by the impact of a decrease in realized natural gas costs, including the impact of realized derivatives, which increased gross margin by $182 million, and the impact of the Waggaman acquisition, which increased gross margin by $57 million.

Gross margin also includes the impact of a $13 million unrealized net mark-to-market gain on natural gas derivatives in 2024 compared to an $11 million gain in 2023.

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.

CF INDUSTRIES HOLDINGS, INC.

Granular Urea Segment

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Depreciation and amortization $ 253 $ 284 $ 285 $ (31) (11) % $ (1) — %

Unrealized net mark-to-market (gain) loss on natural gas derivatives $ (9) $ (11) $ 13 $ 2 18 % $ (24) N/M

Unrealized net mark-to-market loss (gain) on natural gas derivatives $ 1 $ (9) $ (11) $ 10 N/M $ 2 18 %

______________________________________________________________________________

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Year Ended December 31, 2025 Compared to Year Ended December 31, 2024

Net sales in our Granular Urea segment decreased $223 million, or 12%, to $1.60 billion in 2024 compared to $1.82 billion in 2023 due primarily to an 11% decrease in average selling prices.

Average selling prices decreased to $354 per ton in 2024 compared to $399 per ton in 2023 as lower global energy costs reduced the global market clearing price required to meet global demand.

Sales volume in 2024 was 4.5 million tons, a decrease of 1% compared to 4.6 million tons in 2023.

Lower sales volume in the first quarter of 2024, which was due primarily to a reduction in ammonia available for upgrade and lower supply availability from the impact of severe weather that caused urea plant outages, was largely offset by higher sales volume in the second and third quarters of 2024 due primarily to a production mix that favored granular urea production.

Sales volume in 2024 includes the impact of 48,000 tons of granular urea purchased and resold in the first quarter of 2024 due to the impact of the severe weather described above.

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 $205 per ton in 2024, a 7% decrease from $221 per ton in 2023, due primarily to lower realized natural gas costs, including the impact of realized derivatives, partially offset by higher costs associated with maintenance activity in 2024.

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 decreased by $139 million, or 17%, to $674 million in 2024 from $813 million in 2023, and our gross margin percentage was 42.1% in 2024 compared to 44.6% in 2023.

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.

CF INDUSTRIES HOLDINGS, INC.

decrease in gross margin was driven by an 11% decrease in average selling prices, which decreased gross margin by approximately $185 million, a net increase in manufacturing, maintenance and other costs, which decreased gross margin by $37 million, and a 1% decrease in sales volume, which decreased gross margin by $21 million.

These factors that decreased gross margin were partially offset by lower realized natural gas costs, including the impact of realized derivatives, which increased gross margin by $106 million.

Gross margin also includes the impact of a $9 million unrealized net mark-to-market gain on natural gas derivatives in 2024 compared to an $11 million gain in 2023.

Our UAN segment produces urea ammonium nitrate solution (UAN).

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Depreciation and amortization $ 265 $ 268 $ 288 $ (3) (1) % $ (20) (7) %

Unrealized net mark-to-market (gain) loss on natural gas derivatives $ (10) $ (11) $ 14 $ 1 9 % $ (25) N/M

Unrealized net mark-to-market loss (gain) on natural gas derivatives $ 2 $ (10) $ (11) $ 12 N/M $ 1 9 %

______________________________________________________________________________

3 unchanged sentences

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024

Net sales in our UAN segment decreased $390 million, or 19%, to $1.68 billion in 2024 compared to $2.07 billion in 2023 due primarily to a 13% decrease in average selling prices and a 6% decrease in sales volume.

Average selling prices decreased to $248 per ton in 2024 compared to $286 per ton in 2023 due primarily to lower global energy costs reducing the global market clearing price required to meet global demand.

The decrease in sales volume was due primarily to lower supply availability resulting from lower beginning inventory entering 2024 and the impact of a production mix that favored granular urea production.

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 $158 per ton in 2024, a 9% decrease from $173 per ton in 2023, due primarily to the impact of lower realized natural gas costs, including the impact of realized derivatives.

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 decreased by $208 million, or 25%, to $609 million in 2024 from $817 million in 2023, and our gross margin percentage was 36.3% in 2024 compared to 39.5% in 2023.

The decrease in gross margin was due primarily to a 13% decrease in average selling prices, which decreased gross margin by $274 million, and a 6% decrease in sales volume, which decreased gross margin by $57 million.

These factors that decreased gross margin were partially offset by a decrease in realized natural gas costs, including the impact of realized derivatives, which increased gross margin by $113 million, and a net decrease in manufacturing, maintenance and other costs, which increased gross margin by $11 million.

Gross margin also includes the impact of a $10 million unrealized net mark-to-market gain on natural gas derivatives in 2024 compared to an $11 million gain in 2023.

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.

CF INDUSTRIES HOLDINGS, INC.

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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 in our AN segment decreased $78 million, or 16%, to $419 million in 2024 from $497 million in 2023 due primarily to a 9% decrease in average selling prices and a 7% decrease in sales volume.

Average selling prices decreased to $286 per ton in 2024 compared to $316 per ton in 2023 as lower global energy costs reduced the global market clearing price required to meet global demand.

Sales volume declined due primarily to lower supply availability resulting from lower production in 2024.

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 $232 per ton in 2024, a 2% increase from $228 per ton in 2023.

The increase was due primarily to higher costs for maintenance activity in North America, which was partially offset by the impact of lower realized natural gas costs, including the impact of realized derivatives, and, for our United Kingdom operations, a lower cost per ton for purchased ammonia used for upgrading into AN.

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 decreased by $59 million, or 43%, to $79 million in 2024 from $138 million in 2023, and our gross margin percentage was 18.9% in 2024 compared to 27.8% in 2023.

The decrease in gross margin was due primarily to a 9% decrease in average selling prices, which decreased gross margin by $65 million, and a 7% decrease in sales volume, which decreased gross margin by $14 million.

These factors that decreased gross margin were partially offset by a decrease in realized natural gas costs, including the impact of realized derivatives, which increased gross margin by $12 million, and a net decrease in manufacturing, maintenance and other costs, which increased gross margin by $9 million.

The net decrease in manufacturing, maintenance and other costs primarily reflects lower costs for purchased ammonia in the United Kingdom, partially offset by higher costs for maintenance activity in North America.

Gross margin also includes the impact of a $1 million unrealized net mark-to-market gain on natural gas derivatives in 2024 compared to a $2 million gain in 2023.

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.

CF INDUSTRIES HOLDINGS, INC.

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Depreciation and amortization $ 65 $ 61 $ 64 $ 4 7 % $ (3) (5) %

Unrealized net mark-to-market (gain) loss on natural gas derivatives $ (2) $ (4) $ 3 $ 2 50 % $ (7) N/M

Unrealized net mark-to-market gain on natural gas derivatives $ — $ (2) $ (4) $ 2 100 % $ 2 50 %

_______________________________________________________________________________

N/M—Not Meaningful

(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 in our Other segment decreased $61 million, or 11%, to $503 million in 2024 from $564 million in 2023 due to a 7% decrease in average selling prices and a 5% decrease in sales volume.

Average selling prices decreased to $239 per ton in 2024 compared to $256 per ton in 2023 as lower global energy costs reduced the global market clearing price required to meet global demand.

The decrease in sales volume was due primarily to lower DEF sales volume, partially offset by higher nitric acid sales volume.

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 $143 per ton in 2024, a 4% decrease from $149 per ton in 2023, due primarily to the impact of lower realized natural gas costs, including the impact of realized derivatives, partially offset by higher costs for maintenance activity.

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 decreased by $35 million, or 15%, to $201 million in 2024 from $236 million in 2023, and our gross margin percentage was 40.0% in 2024 compared to 41.8% in 2023.

The decrease in gross margin was due primarily to a 7% decrease in average selling prices, which decreased gross margin by $32 million, a 5% decrease in sales volume, which decreased gross margin by $23 million, and a net increase in manufacturing, maintenance and other costs, which decreased gross margin by $1 million.

These factors that decreased gross margin were partially offset by a decrease in realized natural gas costs, including the impact of realized derivatives, which increased gross margin by $23 million.

Gross margin includes the impact of a $2 million unrealized net mark-to-market gain on natural gas derivatives in 2024 compared to a $4 million gain in 2023.

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.

CF INDUSTRIES HOLDINGS, INC.

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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, raw material costs, freight costs and seasonal factors inherent in the business.

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.

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We may also from time to time access the capital markets or engage in borrowings under our revolving credit agreement.

As of December 31, 2024, our cash and cash equivalents balance was $1.61 billion, a decrease of $418 million from $2.03 billion at December 31, 2023.

At December 31, 2024, we were in compliance with all applicable covenant requirements under our revolving credit agreement and senior notes, and unused borrowing capacity under our revolving credit agreement was $750 million.

In each of the quarters of 2024, quarterly dividends of $0.50 per common share were declared and paid, representing a 25% increase from the quarterly dividends of $0.40 per common share that were declared and paid in each of the quarters of 2023.

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 $ 1,852 $ 1,614

Cash and cash equivalents held by—Blue Point Number One, LLC 130 —

Total cash and cash equivalents $ 1,982 $ 1,614

Cash Equivalents

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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.

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.

CF INDUSTRIES HOLDINGS, INC.

We estimate that the cost of the low-carbon ATR ammonia production facility with CCS technologies will be approximately $3.7 billion.

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.

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.

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 $518 million in 2024 compared to $499 million in 2023.

Capital expenditures in 2025 are estimated to be in the range of $500 million to $550 million.

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, performance of third parties, delays in the receipt of equipment, adverse weather, defects in materials and workmanship, labor or material shortages, transportation constraints, acceleration or delays in the timing of the work and other unforeseen difficulties.

Any of these changes in planned capital expenditures, individually or in the aggregate, could have a material impact on our results of operations and cash flows.

In addition, our decarbonization projects include FEED studies to inform our evaluation of whether, and how best, to invest in an export-oriented, low-carbon ammonia capacity at our Blue Point complex in Ascension Parish, Louisiana, to supply developing energy markets and traditional ammonia markets where demand for low-carbon product is emerging.

Our estimated capital expenditures for 2025, which are described above, exclude any amounts that would be required in connection with this project, and such amounts could be significant.

See “Overview of CF Holdings—Our Strategy,” above, for additional information on our clean energy initiatives.

Acquisition of Waggaman Ammonia Production Facility

On December 1, 2023, we acquired an ammonia production facility located in Waggaman, Louisiana from Dyno Nobel Louisiana Ammonia, LLC (DNLA), a U.S.

subsidiary of Australia-based Incitec Pivot Limited (IPL), pursuant to an asset purchase agreement with DNLA and IPL.

In connection with the acquisition, we entered into a long-term ammonia offtake agreement providing for us to supply up to 200,000 tons of ammonia per year to IPL’s Dyno Nobel, Inc.

Under the terms of the asset purchase agreement, $425 million of the purchase price of $1.675 billion, subject to adjustment, was allocated by the parties to the ammonia offtake agreement.

We funded the balance of the initial purchase price on the acquisition date with $1.223 billion of cash on hand.

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 $ 620 $ 507

Blue Point joint venture (1)

Blue Point complex scalable infrastructure 9 —

Capitalized interest 14 11

Total capital expenditures $ 950 $ 518

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(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

CF INDUSTRIES HOLDINGS, INC.

The purchase price adjustments required under the asset purchase agreement were finalized in the second quarter of 2024, which resulted in a $2 million reduction in the purchase price.

As a result, the final purchase price was $1.221 billion.

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

On November 3, 2021, our Board of Directors (the Board) authorized the repurchase of up to $1.5 billion of CF Holdings common stock through December 31, 2024 (the 2021 Share Repurchase Program).

The 2021 Share Repurchase Program was completed in the second quarter of 2023.

On November 2, 2022, the Board authorized the repurchase of up to $3 billion of CF Holdings common stock commencing upon completion of the 2021 Share Repurchase Program and effective through December 31, 2025 (the 2022 Share Repurchase Program).

Repurchases under our share repurchase programs may be made from time to time in the open market, through privately negotiated transactions, through block transactions, through accelerated share repurchase programs, or otherwise.

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.

The following table summarizes the share repurchases under the 2022 Share Repurchase Program.

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)

(in millions)

Shares repurchased in 2023 — $ — 5.6 $ 425

Second quarter 0.8 $ 50

Third quarter 1.9 150

Fourth quarter 2.9 225

Total shares repurchased in 2023 5.6 $ 425

Shares repurchased in 2024 — $ — 18.8 $ 1,513

Shares repurchased in 2025:

First quarter — $ — 5.4 $ 434

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3.4 $ 278 37.6 $ 3,000

(1) As defined in the 2022 Share Repurchase Program, amounts reflect the price paid for the shares of common stock repurchased, excluding commissions paid to brokers and excise taxes.

In 2024, we repurchased approximately 18.8 million shares under the 2022 Share Repurchase Program for approximately $1.51 billion, of which $10 million was accrued and unpaid as of December 31, 2024.

In 2024, we retired approximately 18.7 million shares of repurchased stock, and we held approximately 0.4 million shares of treasury stock as of December 31, 2024.

In 2023, we completed the 2021 Share Repurchase Program with the repurchase of approximately 2.3 million shares for $155 million, and we repurchased 5.6 million shares under the 2022 Share Repurchase Program for $425 million.

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(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

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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, changing political leadership, including the new U.S.

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 connection with the matter described above under “Items Affecting Comparability of Results—Canada Revenue Agency Competent Authority Matter,” in the third quarter of 2024, we were informed that the CRA granted us discretionary interest relief for certain tax years from 2006 through 2011.

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.

In addition, interest relief from the Alberta TRA is estimated to be approximately $16 million, consisting of interest refunds of $15 million and related interest of $1 million, based on current estimates and foreign currency exchange rates as of December 31, 2024.

We expect to receive the interest refunds from the Alberta TRA in the first half of 2025.

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.

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

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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.

As of December 31, 2024, we recorded a deferred tax liability of $14 million on the undistributed earnings of our Canadian subsidiaries for which the Company does not have an indefinite reinvestment assertion.

We have not provided for deferred taxes on the remainder of undistributed earnings from our foreign subsidiaries because such earnings would not give rise to additional tax liabilities upon repatriation.

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.

Revolving Credit Agreement

We have a senior unsecured revolving credit agreement (the Revolving Credit Agreement), which provides for a revolving credit facility of up to $750 million with a maturity of October 26, 2028 and includes a letter of credit sub-limit of $125 million.

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.

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Borrowings in U.S.

dollars bear interest at a per annum rate equal to, at our option, an applicable adjusted term Secured Overnight Financing Rate or base rate plus, in either case, a specified margin.

We are required to pay an undrawn commitment fee on the undrawn portion of the commitments under the Revolving Credit Agreement and customary letter of credit fees.

The specified margin and the amount of the commitment fee depend on CF Holdings’ credit rating at the time.

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 that the total net leverage ratio (as defined in the Revolving Credit Agreement) be not greater than 3.75:1.00 (the Maximum Total Net Leverage Ratio) as of the last day of each fiscal quarter, provided that, if any borrower or subsidiary consummates a material acquisition during any fiscal quarter, CF Industries may elect to increase the Maximum Total Net Leverage Ratio to 4.25:1.00 for the period of four consecutive fiscal quarters commencing with such fiscal quarter (and no further such election may be made unless and until the Maximum Total Net Leverage Ratio is less than or equal to 3.75:1.00 as of the end of two consecutive fiscal quarters after the end of such period).

As of December 31, 2024, we were in compliance with all covenants under the Revolving Credit Agreement.

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.

CF INDUSTRIES HOLDINGS, INC.

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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.

As of December 31, 2024 and 2023, and during the years then ended, there were no borrowings outstanding under the Revolving Credit Agreement.

Letters of Credit Under Bilateral Agreement

We are party to a bilateral agreement providing for the issuance of up to $425 million of letters of credit.

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.

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:

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5.150% due March 2034 5.293% $ 750 $ 743 $ 750 $ 742

5.300% due November 2035 5.444% 1,000 989 — —

4.950% due June 2043 5.040% 750 742 750 742

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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 are no longer secured, in accordance with the terms of the applicable indenture.

Public Senior Notes

(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.

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

CF INDUSTRIES HOLDINGS, INC.

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.

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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 insolvency, the applicable Public Senior Notes would become due and payable immediately, and, in the case of any other event of default (other than an event of default 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.

CF INDUSTRIES HOLDINGS, INC.

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.

Senior Secured Notes

Under the terms of the indenture governing the 4.500% senior secured notes due 2026 (the 2026 Notes), the 2026 Notes are guaranteed by CF Holdings.

Interest on the 2026 Notes is payable semiannually, and the 2026 Notes are redeemable at our option, in whole at any time or in part from time to time, at specified make-whole redemption prices.

Under the indenture governing the 2026 Notes, specified changes of control involving CF Holdings or CF Industries, when accompanied by a ratings downgrade, as defined with respect to the 2026 Notes, constitute change of control repurchase events.

Upon the occurrence of a change of control repurchase event with respect to the 2026 Notes, unless CF Industries has exercised its option to redeem such 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.

The indenture governing the 2026 Notes contains 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.

The indenture governing the 2026 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 of the 2026 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 2026 Notes to be enforceable;

and specified events of bankruptcy or insolvency.

Under the indenture governing the 2026 Notes, in the case of an event of default arising from one of the specified events of bankruptcy or insolvency, the 2026 Notes would become due and payable immediately, and, in the case of any other event of default (other than an event of default related to CF Industries’ and CF Holdings’ reporting obligations), the trustee or the holders of at least 25% in aggregate principal amount of the 2026 Notes then outstanding may declare all of such notes to be due and payable immediately.

Forward Sales and Customer Advances

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Natural gas is the principal raw material used to produce our nitrogen products.

We use natural gas both as a chemical feedstock and as a fuel to produce ammonia, granular urea, UAN, AN and other products.

Expenditures on natural gas are a significant portion of our production costs, representing approximately 28% of our total production costs in 2024.

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, decreased 35% to $2.40 per MMBtu in 2024 from $3.67 per MMBtu in 2023.

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, 2024, our natural gas purchase agreements have remaining terms that range from five months to five years and a total minimum commitment of approximately $2.64 billion, and our natural gas transportation agreements have terms that range from one to eight years and a total minimum commitment of approximately $62 million.

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.

Most of our nitrogen manufacturing facilities are located in the United States and Canada.

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.

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Volatility in reported quarterly earnings can result from the unrealized mark-to-market adjustments in the value of the derivatives.

In 2024 and 2023, we recognized unrealized net mark-to-market gains on natural gas derivatives of $35 million and $39 million, respectively, which is 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, 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.

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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, 2024 and 2023, the aggregate fair value of the derivative instruments with credit-risk-related contingent features in net liability positions was zero and $34 million, 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 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.

As of December 31, 2023, our open natural gas derivative contracts consisted of natural gas fixed price swaps, basis swaps and options for 49.0 million MMBtus.

At both December 31, 2025 and 2024, we had no cash collateral on deposit with counterparties for derivative contracts.

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Defined Benefit Pension Plans

We made cash contributions of $22 million to our pension plans in 2024.

We expect to contribute approximately $6 million in total to our U.S.

pension plans in 2025, and, as currently agreed with the plans’ trustees, approximately $13 million to our U.K.

pension plans in 2026.

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

CF INDUSTRIES HOLDINGS, INC.

Distributions to Noncontrolling Interest in CFN

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:

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Third quarter of 2023 Six months ended June 30, 2023 204

Net cash provided by operating activities in 2024 was $2.27 billion, a decrease of $486 million compared to $2.76 billion in 2023.

The decrease in cash flow from operations was due primarily to lower net earnings.

Net earnings in 2024 was $1.48 billion, a decrease of $361 million compared to $1.84 billion in 2023.

The decrease in net earnings was due primarily to a decrease in gross margin, driven by lower average selling prices, partially offset by lower natural gas costs, a lower income tax provision and a decrease in net earnings attributable to noncontrolling interest.

During 2024, net changes in working capital also impacted cash flow from operations by contributing $63 million more toward net cash from operations in 2024 than in 2023.

These changes primarily occurred in changes in accounts payable, accrued expenses and customer advances, partially offset by changes in inventories.

Net cash used in investing activities was $469 million in 2024 compared to $1.68 billion in 2023, or a decrease of $1.21 billion.

The decrease was due primarily to the consideration paid of $1.223 billion for the Waggaman acquisition in 2023.

See “Acquisition of Waggaman Ammonia Production Facility,” above for additional information.

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.

The increase was due primarily to an increase in share repurchases and dividends paid, partially offset by a decrease in distributions to the noncontrolling interest.

In 2024, we paid $1.51 billion for share repurchases compared to $580 million for share repurchases in 2023.

In 2024, dividends paid on common stock were $364 million compared to $311 million in 2023.

The increase in dividends paid on common stock reflects quarterly dividends of $0.50 per common share declared and paid in 2024, compared to quarterly dividends of $0.40 per common share that were declared and paid in 2023.

In 2024, distributions to the noncontrolling interest were $308 million compared to $459 million in 2023 due to lower earnings of CFN.

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 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.

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GAAP in order to assess recoverability.

Factors that we must estimate when performing impairment tests include production and sales volumes, selling 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.

Factors that we must estimate when performing impairment tests include production and sales volumes, selling

CF INDUSTRIES HOLDINGS, INC.

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

CF INDUSTRIES HOLDINGS, INC.

they are attributed.

Certain of the operating assumptions are particularly sensitive to the cyclical nature of the fertilizer industry.

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The impairment loss is measured as the amount by which the carrying value exceeds the fair value of the long-lived assets.

PLNL is our joint venture investment in Trinidad and operates an ammonia plant that relies on natural gas supplied, under a gas sales contract, by the National Gas Company of Trinidad and Tobago Limited (NGC).

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.

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.

The joint venture experienced past curtailments in the supply of natural gas from NGC, which reduced the ammonia production at PLNL.

The prior gas sales contract had an expiration date of September 2023.

In the third quarter of 2023, PLNL entered into a new gas sales contract with NGC (the New NGC Contract), which is effective October 2023 through December 2025.

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.

Any NGC commitment to supply gas beyond December 2025 will be based on new agreements.

If NGC does not make sufficient quantities of natural gas available to PLNL at prices that permit profitable operations, PLNL may cease operating its facility and we would write off the remaining investment in PLNL.

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.

CF INDUSTRIES HOLDINGS, INC.

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.

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retail price index (RPI).

The December 31, 2024 PBO was computed based on a weighted-average discount rate of 5.2% for our North America plans and 5.5% for our United Kingdom plans, which were 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, 2024.

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.

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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 North America qualified pension plans, our PBO was $278 million as of December 31, 2024, which was $21 million lower than pension plan assets.

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, 2024 PBO:

CF INDUSTRIES HOLDINGS, INC.

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

North America Plans United Kingdom Plans

Assumption +50 bps -50 bps +50 bps -50 bps

United Kingdom Plans

Assumption +50 bps -50 bps

(in millions)

Discount Rate $ (17) $ 18

RPI n/a n/a 9 (9)

_______________________________________________________________________________

n/a—not applicable

See Note 11—Pension and Other Postretirement Benefits for further discussion of our pension plans.

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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.

CF INDUSTRIES HOLDINGS, INC.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis