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Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549

FORM | 10-K

(Mark One) |  |  |
☒ |  | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025

OR
☐ |  | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission file number 001-32597
CF INDUSTRIES HOLDINGS, INC.
(Exact name of registrant as specified in its charter)

Delaware |  |  |  |  | 20-2697511
(State or other jurisdiction of incorporation or organization) |  |  |  |  | (I.R.S. Employer Identification No.)
2375 Waterview Drive |  |  |  |  | 60062
Northbrook, Illinois |  |  |  |  | (Zip Code)
(Address of principal executive offices) |  |  |  |  |

Registrant’s telephone number, including area code: (847) 405-2400
Securities registered pursuant to Section 12(b) of the Act:

Title of each class |  | Trading symbol(s) |  | Name of each exchange on which registered
common stock, par value $0.01 per share |  | CF |  | New York Stock Exchange

Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer | ☒ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | Smaller reporting company | ☐ | Emerging growth company | ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to § 240.10D-1(b)☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The aggregate market value of the registrant’s common stock held by non-affiliates as of June 30, 2025 (the last business day of the registrant’s most recently completed second fiscal quarter), computed by reference to the closing sale price of the registrant’s common stock, was $14,796,888,341.
153,668,821 shares of the registrant’s common stock, par value $0.01 per share, were outstanding as of January 30, 2026.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for its 2026 annual meeting of shareholders (Proxy Statement) are incorporated by reference into Part III of this Annual Report on Form 10-K. The Proxy Statement will be filed with the Securities and Exchange Commission, pursuant to Regulation 14A, not later than 120 days after the end of the 2025 fiscal year, or, if the registrant does not file the Proxy Statement within such 120-day period, the registrant will amend this Annual Report on Form 10-K to include the information required under Part III of Form 10-K not later than the end of such 120-day period.

CF INDUSTRIES HOLDINGS, INC.
TABLE OF CONTENTS

PART I |  |  |
| Item 1. | Business | 1
| Item 1A. | Risk Factors | 14
| Item 1B. | Unresolved Staff Comments | 30
| Item 1C. | Cybersecurity | 30
| Item 2. | Properties | 31
| Item 3. | Legal Proceedings | 31
| Item 4. | Mine Safety Disclosures | 31
PART II |  |  |
| Item 5. | Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 32
| Item 6. | [Reserved] | 32
| Item 7. | Management's Discussion and Analysis of Financial Condition and Results of Operations | 33
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | 63
| Item 8. | Financial Statements and Supplementary Data | 64
|  | Report of Independent Registered Public Accounting Firm | 64
|  | Consolidated Statements of Operations | 66
|  | Consolidated Statements of Comprehensive Income | 67
|  | Consolidated Balance Sheets | 68
|  | Consolidated Statements of Equity | 69
|  | Consolidated Statements of Cash Flows | 70
|  | Notes to Consolidated Financial Statements | 71
| Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | 114
| Item 9A. | Controls and Procedures | 114
| Item 9B. | Other Information | 116
| Item 9C. | Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 116
PART III |  |  |
| Item 10. | Directors, Executive Officers and Corporate Governance | 116
| Item 11. | Executive Compensation | 116
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 117
| Item 13. | Certain Relationships and Related Transactions, and Director Independence | 117
| Item 14. | Principal Accountant Fees and Services | 117
PART IV |  |  |
| Item 15. | Exhibits and Financial Statement Schedules | 118
| Item 16. | Form 10-K Summary | 118

Table of Contents
CF INDUSTRIES HOLDINGS, INC.
PART I
ITEM 1. BUSINESS.
Our Company
All references to “CF Holdings,” “we,” “us,” “our” and “the Company,” refer to CF Industries Holdings, Inc. and its subsidiaries, except where the context makes clear that the reference is to CF Industries Holdings, Inc. only and not its subsidiaries. All references to “CF Industries” refer to CF Industries, Inc., a 100% owned subsidiary of CF Industries Holdings, Inc. References to tons refer to short tons. Notes referenced throughout this document refer to consolidated financial statement note disclosures that are found in Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements.
Our mission is to provide clean energy to feed and fuel the world sustainably. With our employees focused on safe and reliable operations, environmental stewardship, and disciplined capital and corporate management, we are on a path to decarbonize our ammonia production network – the world’s largest – to enable low-carbon hydrogen and nitrogen products for energy, fertilizer, emissions abatement and other industrial activities. Our value chain consists of manufacturing complexes in the United States, Canada and the United Kingdom, an extensive storage, transportation and distribution network in North America, and logistics capabilities enabling a global reach. In July 2025, we completed a significant decarbonization project at our Donaldsonville, Louisiana, complex to enable the production of low-carbon ammonia. Additionally, we are executing further decarbonization projects in our existing network and constructing a greenfield low-carbon ammonia plant at our Blue Point complex to drive our strategy to leverage our unique capabilities to accelerate the world’s transition to clean energy.
Our principal customers are cooperatives, retailers, independent fertilizer distributors, traders, wholesalers and industrial users. Our core product is anhydrous ammonia (ammonia), which contains 82% nitrogen and 18% hydrogen. Products derived from ammonia that are most often used as nitrogen fertilizers include granular urea, urea ammonium nitrate solution (UAN) and ammonium nitrate (AN). AN is also used extensively by the commercial explosives industry as a component of explosives. Products derived from ammonia that are sold primarily to industrial customers include diesel exhaust fluid (DEF), urea liquor, nitric acid and aqua ammonia. In addition, our low-carbon products are expected to be used for existing and new applications, such as power generation and steel production in Japan, and to help customers reduce the economic impact of European regulations on the price of carbon.
Our principal assets as of December 31, 2025 include:
•six U.S. manufacturing facilities, located in Donaldsonville, Louisiana (the largest ammonia production complex in the world); Sergeant Bluff, Iowa (our Port Neal complex); Yazoo City, Mississippi; Claremore, Oklahoma (our Verdigris complex); Woodward, Oklahoma; and Waggaman, Louisiana. The Waggaman facility is wholly owned by us, and the other five U.S. manufacturing facilities are wholly owned directly or indirectly by CF Industries Nitrogen, LLC (CFN), of which we own approximately 89% and CHS Inc. (CHS) owns the remainder;
•two Canadian manufacturing facilities, located in Medicine Hat, Alberta (the largest ammonia production complex in Canada) and Courtright, Ontario;
•a United Kingdom manufacturing facility located in Billingham;
•an extensive system of terminals and associated transportation equipment located primarily in the Midwestern United States;
•a 50% interest in Point Lisas Nitrogen Limited (PLNL), an ammonia production joint venture located in Trinidad and Tobago (Trinidad) that we account for under the equity method; and
•a 40% interest in Blue Point Number One, LLC, a joint venture formed on April 8, 2025 (the Blue Point joint venture), to construct a manufacturing plant at our Blue Point complex located in Modeste, Louisiana. The joint venture entity is a variable interest entity (VIE) of which we are the primary beneficiary. As a result, we consolidate this entity in our consolidated financial statements, with the combined 60% equity interest owned by our joint venture partners recorded as noncontrolling interests. See “Our Strategy—Blue Point joint venture,” below, for additional information.
We have a strategic venture with CHS under which CHS owns an equity interest in CFN, a subsidiary of CF Holdings, which represents approximately 11% of the membership interests of CFN. We own the remaining membership interests. CHS also receives deliveries pursuant to a supply agreement under which CHS has the right to purchase annually from CFN up to approximately 1.1 million tons of granular urea and 580,000 tons of UAN at market prices. As a result of its minority equity
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CF INDUSTRIES HOLDINGS, INC.
interest in CFN, CHS is entitled to semi-annual cash distributions from CFN. We are also entitled to semi-annual cash distributions from CFN. See Note 18—Noncontrolling Interests for additional information on our strategic venture with CHS.
For the years ended December 31, 2025, 2024 and 2023, we sold 19.1 million, 18.9 million and 19.1 million product tons generating net sales of $7.08 billion, $5.94 billion and $6.63 billion, respectively.
Our principal executive offices are located outside of Chicago, Illinois, at 2375 Waterview Drive, Northbrook, Illinois 60062, and our telephone number is 847-405-2400. Our Internet website address is www.cfindustries.com. Information made available on our website does not constitute part of this Annual Report on Form 10-K.
We make available free of charge on or through our Internet website, www.cfindustries.com, all of our reports on Forms 10-K, 10-Q and 8-K and all amendments to those reports as soon as reasonably practicable after such material is filed electronically with, or furnished to, the Securities and Exchange Commission (SEC). Copies of our Corporate Governance Guidelines, Code of Corporate Conduct and charters for the Audit Committee, Compensation and Management Development Committee, Corporate Governance and Nominating Committee, and Environmental Sustainability and Community Committee of our Board of Directors (the Board) are also available on our Internet website. We will provide electronic or paper copies of these documents free of charge upon request. The SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements and other information that we file electronically with the SEC.
Our Strategy
At our core, CF Industries is a producer of ammonia. We use the Haber-Bosch process to fix atmospheric nitrogen with hydrogen from natural gas to produce anhydrous ammonia, whose chemical composition is NH 3. We sell the ammonia itself or upgrade it to products such as granular urea, UAN and DEF. A majority of the ammonia and ammonia-derived products we manufacture are used as fertilizer, as the nitrogen content provides energy essential for crop growth. Other important uses of our products include emissions control.
Our strategy is to leverage our unique capabilities to accelerate the world’s transition to clean energy. Our unique capabilities include: advantaged production, unmatched distribution and logistics network, operational excellence and disciplined capital stewardship.
Our leadership in ammonia production enables us to drive continued operational excellence in our underlying business while investing in decarbonization technologies to produce ammonia with a lower carbon intensity than that of ammonia produced through traditional processes (“low-carbon ammonia”). These investments allow us to pursue demand for low-carbon ammonia and upgraded products for both traditional and new applications. Traditional applications include agriculture, where low-carbon nitrogen products can be used to reduce the carbon footprint of food production and the life cycle carbon intensity of ethanol production. New growth opportunities include power generation and marine shipping, which are hard-to-abate industries for which low-carbon ammonia offers a potential path to significantly lower carbon footprints as it does not contain or emit carbon when combusted.
Decarbonizing our existing network
At our Donaldsonville and Yazoo City complexes, our decarbonization projects are leveraging carbon capture and sequestration (CCS) to enable us to convert a portion of our existing ammonia production to low-carbon ammonia production. CCS requires the construction of carbon dioxide (CO 2) dehydration and compression units to enable process CO 2 captured from the ammonia production process to be transported and sequestered, which prevents approximately 60% of the CO 2 generated by ammonia production from being emitted to the atmosphere. For each facility we have contracted with ExxonMobil to transport and permanently store the captured CO 2.
In July 2025, construction, commissioning and start-up of the dehydration and compression unit at our Donaldsonville complex was completed for a total cost of approximately $200 million. The dehydration and compression unit enables the transportation and permanent geological sequestration of up to 2 million metric tons of CO 2 annually, depending on gross ammonia production and consumption of CO 2 for upgraded products. This sequestered CO 2 would otherwise be emitted into the atmosphere. ExxonMobil, our CCS partner for this project, is transporting and permanently storing the CO 2. The project qualifies for tax credits under Section 45Q of the Internal Revenue Code (45Q Tax Credits), which provide a tax credit per metric ton of CO 2 captured and disposed of in secure geological storage. As a result of the Donaldsonville CCS project, we have the capacity to produce up to approximately 1.9 million tons of low-carbon ammonia annually at our Donaldsonville complex.
On an interim basis, ExxonMobil is storing CO 2 from our Donaldsonville complex in permanent geologic sites through enhanced oil recovery. Upon receiving its Class VI permit, ExxonMobil plans to transition to dedicated permanent storage,
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CF INDUSTRIES HOLDINGS, INC.
starting with its Rose CCS project (Rose). Rose is one of many dedicated permanent storage sites ExxonMobil is developing along the Gulf Coast to expand its integrated CCS network. The U.S. Environmental Protection Agency issued the final Class VI permits for Rose in October 2025. Beginning of storage activities at Rose also requires authorization from the Railroad Commission of Texas.
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 (CO 2 e) 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.
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CF INDUSTRIES HOLDINGS, INC.
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 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Blue Point Joint Venture, and Note 14—Variable Interest Entity, for additional information on the Blue Point joint venture.
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 new applications. We are evaluating and are in various stages of discussions with other companies for long-term offtake and/or potential joint investments related to new and traditional applications for low-carbon ammonia. These discussions continue to advance as we gain greater clarity regarding demand for low-carbon ammonia, including associated carbon intensity requirements, government incentives and regulatory developments.
Company History
We were founded in 1946 as Central Farmers Fertilizer Company and were owned by a group of regional agriculture cooperatives for the first 59 years of our existence. Central Farmers Fertilizer Company became CF Industries in 1970.
Originally established as a fertilizer brokerage company, we expanded owning and operating fertilizer manufacturing and distribution facilities in the early 1950s with a principal objective of assured supply for our owners. At various times in our history, we manufactured and/or distributed nitrogen, phosphate and potash fertilizers.
We operated as a traditional manufacturing and supply cooperative until 2002, when we adopted a new business model that established financial performance as our principal objective, rather than assured supply for our owners. A critical aspect of the new business model was to establish a more economically driven approach to the marketplace.
In August 2005, we completed the initial public offering (IPO) of our common stock, which is listed on the New York Stock Exchange. In connection with the IPO, we consummated a reorganization transaction whereby we ceased to be a cooperative and our pre-IPO owners’ equity interests in CF Industries were cancelled in exchange for the proceeds of the offering and shares of our common stock. At the time of the IPO, our assets consisted of one wholly owned nitrogen manufacturing facility in Louisiana, United States; a joint venture nitrogen manufacturing facility in Alberta, Canada, of which we owned 66%; a phosphate mining and manufacturing operation in Florida, United States; and distribution facilities throughout North America.
In April 2010, we acquired Terra Industries Inc. (Terra), a leading North American producer and marketer of nitrogen fertilizer products for a purchase price of $4.6 billion, which was paid in cash and shares of our common stock. As a result of the Terra acquisition, we acquired five nitrogen fertilizer manufacturing facilities; an approximately 75.3% interest in Terra Nitrogen Company, L.P. (TNCLP), a publicly traded limited partnership; and certain joint venture interests.
Prior to April 30, 2013, we owned 66% of Canadian Fertilizers Limited (CFL), a joint venture nitrogen manufacturing facility in Alberta, Canada. On April 30, 2013, CF Industries acquired the outstanding interests in CFL that it did not already own and CFL became our wholly owned subsidiary.
In March 2014, we exited our phosphate mining and manufacturing business, which was located in Florida, through a sale to The Mosaic Company. As a result, we became focused solely on nitrogen manufacturing and distribution.
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In July 2015, we acquired the remaining 50% equity interest in CF Fertilisers UK Group Limited (formerly known as GrowHow UK Group Limited) (CF Fertilisers UK) not previously owned by us, and CF Fertilisers UK became wholly owned by us. This transaction added CF Fertilisers UK’s nitrogen manufacturing complexes in Ince, United Kingdom and Billingham, United Kingdom to our consolidated manufacturing capacity. Due to the substantial increase in the cost of natural gas in the United Kingdom, in 2022, we closed the Ince facility, and in 2023, we ceased operations of the ammonia plant at the Billingham facility, which was idled in September 2022. Since that time, we have imported ammonia for upgrade into AN and other nitrogen products at the Billingham facility.
In February 2016, our strategic venture with CHS commenced, at which time CHS made a capital contribution of $2.8 billion to CFN in exchange for membership interests in CFN, which represented approximately 11% of the total membership interests of CFN.
In late 2015 and 2016, we completed capacity expansion projects at our Donaldsonville complex in Louisiana and our Port Neal complex in Iowa. These projects, originally announced in 2012, included the construction of new ammonia, urea, and UAN plants at our Donaldsonville complex and new ammonia and urea plants at our Port Neal complex. These plants increased our overall production capacity by approximately 25%, improved our product mix flexibility at Donaldsonville, and improved our ability to serve upper-Midwest urea customers from our Port Neal complex. The total capital cost of the capacity expansion projects was $5.2 billion.
Prior to April 2, 2018, Terra Nitrogen, Limited Partnership, which owns and operates our Verdigris nitrogen manufacturing facility in Oklahoma, was a subsidiary of TNCLP. On April 2, 2018, Terra Nitrogen GP Inc., the sole general partner of TNCLP and an indirect wholly owned subsidiary of CF Holdings, completed its purchase of all the publicly traded common units of TNCLP (the Purchase). Upon completion of the Purchase, CF Holdings owned, through its subsidiaries, 100% of the general and limited partnership interests of TNCLP.
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 capacity of 880,000 tons of ammonia annually. In connection with the closing of the acquisition on December 1, 2023, 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. subsidiary. Under the terms of the asset purchase agreement, $425 million of the $1.675 billion purchase price, subject to adjustment, was allocated by the parties to the ammonia offtake agreement. We funded the balance of the final purchase price, after adjustment, with $1.221 billion of cash on hand.
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. We hold 40% ownership, JERA holds 35% ownership, and Mitsui holds 25% ownership in the Blue Point joint venture. See “Our Strategy—Blue Point joint venture,” above, for additional information on the Blue Point joint venture.
Product Tons and Nutrient Tons
Unless otherwise stated, we measure our production and sales volume in this Annual Report on Form 10-K in product tons, which represents the weight of the product measured in short tons (one short ton is equal to 2,000 pounds). References to UAN product tons assume a 32% nitrogen content basis for production volume.
We also provide certain supplementary volume information measured in nutrient tons. Nutrient tons represent the weight of the product’s nitrogen content, which varies by product. Ammonia represents 82% nitrogen content, granular urea represents 46% nitrogen content, UAN represents between 28% and 32% nitrogen content and AN represents between 29% and 35% nitrogen content.
Reportable Segments
Our reportable segments consist of the following segments: Ammonia, Granular Urea, UAN, AN and Other. These segments are differentiated by products. We use gross margin to evaluate segment performance and allocate resources. Total other operating costs and expenses (consisting primarily of selling, general and administrative expenses and other operating—net) and non-operating expenses (consisting primarily of interest and income taxes), are centrally managed and are not included in the measurement of segment profitability reviewed by management. See Note 21—Segment Disclosures for additional information.
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Our Products
Our primary products are ammonia, granular urea, UAN and AN. Our historical sales by segment are shown in the following table. Net sales do not reflect amounts used internally, such as ammonia, in the manufacture of other products.

| 2025 |  | 2024 |  | 2023
| Sales Volume (tons) |  | Net Sales |  | Sales Volume (tons) |  | Net Sales |  | Sales Volume (tons) |  | Net Sales
| (tons in thousands; dollars in millions)
Ammonia | 4,597 |  |  | $ | 2,176 |  |  | 4,085 |  |  | $ | 1,736 |  |  | 3,546 |  |  | $ | 1,679 |
Granular Urea | 4,109 |  |  | 1,781 |  |  | 4,522 |  |  | 1,600 |  |  | 4,570 |  |  | 1,823 |
UAN | 6,947 |  |  | 2,161 |  |  | 6,771 |  |  | 1,678 |  |  | 7,237 |  |  | 2,068 |
AN | 1,327 |  |  | 421 |  |  | 1,464 |  |  | 419 |  |  | 1,571 |  |  | 497 |
Other(1) | 2,077 |  |  | 545 |  |  | 2,101 |  |  | 503 |  |  | 2,206 |  |  | 564 |
Total | 19,057 |  |  | $ | 7,084 |  |  | 18,943 |  |  | $ | 5,936 |  |  | 19,130 |  |  | $ | 6,631 |

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(1)Other segment products primarily include DEF, urea liquor, nitric acid and aqua ammonia.
Gross margin was $2.72 billion, $2.06 billion and $2.55 billion for the years ended December 31, 2025, 2024 and 2023, respectively.
We own and operate eight manufacturing facilities in North America, consisting of six manufacturing facilities in the United States, and two in Canada. As of December 31, 2025, the combined production capacity of these eight facilities represented approximately 40%, 41%, 44% and 19% of North American ammonia, granular urea, UAN and AN production capacity, respectively. Each of our manufacturing facilities in North America has on-site storage to provide flexibility to manage the flow of outbound shipments without impacting production. Our United Kingdom manufacturing facility produces AN and primarily serves the agricultural and industrial markets in the United Kingdom.
The following table shows the production capacities as of December 31, 2025 at each of our manufacturing facilities:

| Average Annual Capacity(1)
| Gross Ammonia(2) |  | Net Ammonia(2) |  | UAN(3) |  | Urea(4) |  | AN(5) |  | Other(6)
| (tons in thousands)
Donaldsonville (Louisiana)(7)(8) | 4,335 |  |  | 1,390 |  |  | 3,255 |  |  | 2,635 |  |  | — |  |  | 445 |
Medicine Hat (Alberta) | 1,230 |  |  | 770 |  |  | — |  |  | 810 |  |  | — |  |  | — |
Port Neal (Iowa) | 1,280 |  |  | 65 |  |  | 800 |  |  | 1,440 |  |  | — |  |  | 290 |
Verdigris (Oklahoma)(8) | 1,210 |  |  | 430 |  |  | 1,955 |  |  | — |  |  | — |  |  | — |
Waggaman (Louisiana) | 880 |  |  | 880 |  |  | — |  |  | — |  |  | — |  |  | — |
Woodward (Oklahoma) | 480 |  |  | 130 |  |  | 810 |  |  | — |  |  | — |  |  | 115 |
Yazoo City (Mississippi)(8)(9)(10) | 570 |  |  | — |  |  | 160 |  |  | — |  |  | 1,035 |  |  | 125 |
Courtright (Ontario)(8)(11) | 500 |  |  | 265 |  |  | 345 |  |  | — |  |  | — |  |  | 400 |
Billingham (U.K.)(8) | — |  |  | — |  |  | — |  |  | — |  |  | 595 |  |  | 410 |
| 10,485 |  |  | 3,930 |  |  | 7,325 |  |  | 4,885 |  |  | 1,630 |  |  | 1,785 |
Unconsolidated Affiliate |  |  |  |  |  |  |  |  |  |  |
PLNL (Trinidad)(12) | 360 |  |  | 360 |  |  | — |  |  | — |  |  | — |  |  | — |
Total | 10,845 |  |  | 4,290 |  |  | 7,325 |  |  | 4,885 |  |  | 1,630 |  |  | 1,785 |

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(1)Average annual capacity includes allowance for normal outages and planned maintenance shutdowns.
(2)Gross ammonia capacity includes ammonia used to produce upgraded products. Net ammonia capacity is gross ammonia capacity less ammonia used to produce upgraded products based on the product mix shown in the table.
(3)Measured in tons of UAN containing 32% nitrogen by weight.
(4)Reflects granular urea capacity from the Donaldsonville, Medicine Hat, and Port Neal facilities. Urea liquor and DEF production capacities are included in Other.
(5)AN includes prilled products (Amtrate and industrial-grade AN, or IGAN) and AN solution produced for sale.
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(6)Includes product tons of: urea liquor and DEF from the Donaldsonville, Port Neal, Woodward, Yazoo City, and Courtright facilities; and nitric acid from the Billingham facility. Production of DEF can be increased by reducing urea and/or UAN production.
(7)The Donaldsonville facility capacities present an estimated production mix. This facility is capable of producing between 2.4 million and 3.3 million tons of granular urea and between 1.2 million and 4.3 million tons of UAN annually. The facility is also capable of producing up to 1.2 million product tons of 32.5% DEF.
(8)Reduction of UAN or AN production at the Yazoo City, Courtright, Verdigris, Donaldsonville and Billingham facilities can allow more merchant nitric acid to be made available for sale.
(9)The Yazoo City facility’s production capacity depends on product mix. With the facility maximizing the production of AN products, 160,000 tons of UAN can be produced. UAN production can be increased to 450,000 tons by reducing the production of AN to 900,000 tons.
(10)As of the date of this filing, production is temporarily idled at the Yazoo City facility. See “Manufacturing Facilities—Yazoo City, Mississippi,” below, and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Market Conditions and Current Developments—Yazoo City Incident.”
(11)Production of urea liquor and DEF at the Courtright facility can be increased by reducing UAN production.
(12)Represents our 50% interest in the capacity of PLNL.
The following table summarizes our production volume for the last three years:

| December 31,
| 2025 |  | 2024 |  | 2023
| (tons in thousands)
Ammonia(1) | 10,120 |  |  | 9,800 |  |  | 9,496 |
Granular urea | 4,262 |  |  | 4,404 |  |  | 4,544 |
UAN (32%) | 6,934 |  |  | 6,753 |  |  | 6,852 |
AN | 1,253 |  |  | 1,392 |  |  | 1,520 |

_______________________________________________________________________________
(1)Gross ammonia production, including amounts subsequently upgraded on-site into granular urea, UAN or AN.
Manufacturing Facilities
Donaldsonville, Louisiana
The Donaldsonville facility is the world’s largest and most flexible ammonia production complex. It has six ammonia plants, five urea plants, four nitric acid plants, three UAN plants, and one DEF plant. The complex, which is located on the Mississippi River, includes deep-water docking facilities, access to an ammonia pipeline, and truck and railroad loading capabilities. The complex has on-site storage for 139,000 tons of ammonia, 202,000 tons of UAN (measured on a 32% nitrogen content basis) and 130,000 tons of granular urea.
Medicine Hat, Alberta, Canada
The Medicine Hat facility, located in southeast Alberta, is the largest ammonia production complex in Canada. It has two ammonia plants and one urea plant. The complex has on-site storage for 55,000 tons of ammonia and 55,000 tons of granular urea.
Sergeant Bluff, Iowa (Port Neal)
The Port Neal facility is located approximately 12 miles south of Sioux City, Iowa, on the Missouri River in Sergeant Bluff, Iowa. The facility consists of two ammonia plants, three urea plants, two nitric acid plants and one UAN plant. The location has on-site storage for 82,000 tons of ammonia, 130,000 tons of granular urea, and 100,000 tons of 32% UAN.
Claremore, Oklahoma (Verdigris)
The Verdigris facility is located northeast of Tulsa, Oklahoma, near the Verdigris River, in Claremore, Oklahoma. It is the second largest UAN production facility in North America. The facility consists of two ammonia plants, two nitric acid plants, two UAN plants and a port terminal. We lease the port terminal from the Tulsa-Rogers County Port Authority. The complex has on-site storage for 57,000 tons of ammonia and 102,000 tons of 32% UAN.
Waggaman, Louisiana
The Waggaman facility is located near New Orleans, Louisiana on the Mississippi River approximately 60 miles southeast of the Donaldsonville facility. The facility consists of one ammonia plant, has access to an ammonia pipeline, and has on-site storage for approximately 39,000 tons of ammonia.
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Woodward, Oklahoma
The Woodward facility is located in rural northwest Oklahoma and consists of one ammonia plant, two nitric acid plants, two urea plants and two UAN plants. The complex has on-site storage for 34,000 tons of ammonia and 84,000 tons of 32% UAN.
Yazoo City, Mississippi
The Yazoo City facility is located in central Mississippi and includes one ammonia plant, four nitric acid plants, one AN plant, two urea plants, one UAN plant and a dinitrogen tetroxide production and storage facility. The complex has on-site storage for 48,000 tons of ammonia, 47,000 tons of 32% UAN and 10,000 tons of AN and related products.
In November 2025, we experienced an incident in the AN upgrade area at the 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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Market Conditions and Current Developments—Yazoo City Incident.”
Courtright, Ontario, Canada
The Courtright facility is located south of Sarnia, Ontario near the St. Clair River. The facility consists of an ammonia plant, a UAN plant, a nitric acid plant and a urea plant. The complex has on-site storage for 61,000 tons of ammonia and 16,000 tons of 32% UAN.
Billingham, United Kingdom
The Billingham facility, located in the Teesside chemical area in northeastern England, is geographically split among three primary locations: the main site, which contains three nitric acid plants; the Portrack site, approximately two miles away, which contains one AN fertilizer plant; and the North Tees site, approximately seven miles away, which contains an ammonia storage area. These locations collectively have on-site storage for 37,000 tons of ammonia and 138,000 tons of AN. In addition, we previously operated an ammonia plant at the main site of the Billingham facility. However, in September 2022, we idled ammonia production at the facility. Since that time, we have imported ammonia for upgrade at the facility into AN and other nitrogen products. In the third quarter of 2023, we approved our plan to permanently close the ammonia plant at the Billingham facility.
Point Lisas, Trinidad
The Point Lisas facility in Trinidad is owned jointly through a 50/50 venture with Koch Fertilizer LLC. This facility has the capacity to produce 720,000 tons of ammonia annually from natural gas supplied under a contract with The National Gas Company of Trinidad and Tobago Limited (NGC). 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. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates—Recoverability of Long-Lived Assets, Goodwill and Investment in Unconsolidated Affiliate,” for information on the status of PLNL’s gas supply contract with NGC, which was scheduled to expire on January 1, 2026.
Nitrogen Product Raw Materials
Natural gas is the principal raw material and primary fuel source used in the ammonia production process at our nitrogen manufacturing facilities. In 2025, natural gas accounted for approximately 34% of our total production costs. Our manufacturing facilities have access to abundant, competitively-priced natural gas through a reliable network of pipelines that are connected to major natural gas trading hubs. Our facilities utilize the following natural gas hubs: Henry Hub in Louisiana, SONAT and TETCO ELA in Mississippi; ONEOK in Oklahoma; AECO in Alberta; Ventura in Iowa; Demarcation in Kansas; Welcome in Minnesota; Dawn in Ontario; and the National Balancing Point in the United Kingdom.
In 2025, our manufacturing facilities consumed, in the aggregate, approximately 350 million MMBtus of natural gas. We employ a combination of daily spot and term purchases from a variety of quality suppliers to maintain a reliable, competitively-priced supply of natural gas. We also use certain financial instruments to hedge natural gas prices. See Note 16—Derivative Financial Instruments for additional information about our natural gas hedging activities.
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Nitrogen Product Distribution
The safe, efficient and economical distribution of nitrogen products is critical for successful operations. Our production facilities have access to multiple transportation modes by which we ship products to terminals, warehouses and customers. Each of our production facilities has a unique distribution pattern based on its production capacity and location.
Our North American production facilities can ship products via truck and rail to customers and to our storage facilities in the United States and Canada, with access to our leased railcar fleet of approximately 5,000 tank and hopper cars, as well as railcars provided by rail carriers. Our United Kingdom production facility mainly ships products via truck.
The North American waterway system is also used extensively to ship products from our Donaldsonville, Verdigris, Waggaman and Yazoo City facilities. To ship ammonia and UAN, we employ a fleet of up to thirteen tow boats and forty-two river barges, which are primarily leased. We also utilize contract marine services to move granular urea and AN. We can also export nitrogen products via seagoing vessels from our Donaldsonville and Billingham manufacturing facilities.
The Donaldsonville and Waggaman facilities are connected to the 2,000-mile long Sunoco ammonia pipeline through which we have the ability to transport ammonia to ten Company-owned terminals and additional shipping points in the Midwestern U.S. corn belt.
Storage Facilities and Other Properties
As of December 31, 2025, we owned or leased space at 39 in-market storage terminals and warehouses located in a 17-state region of the United States, Canada and the United Kingdom. Including storage at our production facilities, we have an aggregate storage capacity for approximately 2.8 million tons of product. Our storage capabilities are summarized in the following table:

| Ammonia |  | Granular Urea |  | UAN(1) |  | AN
| Number of Facilities |  | Capacity (000 Tons) |  | Number of Facilities |  | Capacity (000 Tons) |  | Number of Facilities |  | Capacity (000 Tons) |  | Number of Facilities |  | Capacity (000 Tons)
Plants | 9 |  |  | 535 |  |  | 4 |  |  | 394 |  |  | 6 |  |  | 522 |  |  | 2 |  |  | 148 |
Terminal and Warehouse Locations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Owned(2) | 21 |  |  | 735 |  |  | — |  |  | — |  |  | 9 |  |  | 236 |  |  | — |  |  | — |
Leased(3) | 4 |  |  | 60 |  |  | 3 |  |  | 23 |  |  | 11 |  |  | 186 |  |  | — |  |  | — |
Total In-Market | 25 |  |  | 795 |  |  | 3 |  |  | 23 |  |  | 20 |  |  | 422 |  |  | — |  |  | — |
Total Storage Capacity |  |  | 1,330 |  |  |  |  | 417 |  |  |  |  | 944 |  |  |  |  | 148 |

_______________________________________________________________________________
(1)Capacity is expressed as the equivalent volume of UAN measured on a 32% nitrogen content basis.
(2)The owned facilities that store UAN also can store ammonia.
(3)Our lease agreements are typically for periods of one to four years and commonly contain provisions for automatic renewal that can extend the lease term unless cancelled by either party.
Customers
The principal customers for our nitrogen products are cooperatives, retailers, independent fertilizer distributors, traders, wholesalers and industrial users. Sales are generated by our internal marketing and sales force. CHS was our largest customer in 2025 and accounted for approximately 13% of our consolidated net sales. We have a strategic venture with CHS under which CHS has a minority equity interest in CFN. See Note 18—Noncontrolling Interests for additional information on our strategic venture with CHS.
Competition
Our markets are global and intensely competitive, based primarily on delivered price and, to a lesser extent, on low-carbon attributes, reliability, customer service and product quality. During the peak demand periods, product availability and delivery time also play a role in the buying decisions of customers.
Our primary competitors with North American operations include Nutrien Ltd., Koch Fertilizer LLC, LSB Industries, CVR Partners, LP and Yara International. There is also significant competition from products sourced from other regions of the world, including some with lower natural gas or other feedstock costs, which may include the benefit of government subsidies. Because ammonia, urea and UAN are widely-traded fertilizer products and there are limited barriers to entry, we experience
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competition from foreign-sourced products continuously. Producers of nitrogen-based fertilizers located in the Middle East, Trinidad, Africa and Russia have been major exporters to North America in recent years.
Our primary United Kingdom competition comes from imported products supplied by companies including Yara International, Origin Fertilisers, Ameropa and Thomas Bell & Sons Ltd. Urea and UAN are not produced in the United Kingdom, but along with AN are widely-traded fertilizer products with limited barriers to entry.
Seasonality
The fertilizer business is seasonal. The degree of seasonality of our business can change significantly from year to year due to weather conditions in the agricultural industry and other factors. The strongest demand for our products in North America occurs during the spring planting season, with a second period of strong demand following the fall harvest. However, we and other fertilizer producers generally manufacture and distribute products throughout the year. As a result, we and/or our customers generally build inventories during the low demand periods of the year to ensure timely product availability during the peak sales seasons. Seasonality is greatest for ammonia due to the short application season and the limited ability of our customers and their customers to store significant quantities of this product. The seasonality of fertilizer demand generally results in our sales volumes and net sales being the highest during the spring and our working capital requirements being the highest just prior to the start of the spring planting season. Our quarterly financial results can vary significantly from one year to the next due to weather-related shifts in planting and application schedules and purchasing patterns as well as import timing, import and distribution costs and logistical limitations, such as river conditions.
Environmental, Health and Safety
We are subject to numerous environmental, health and safety laws and regulations in the United States, Canada, the United Kingdom, Trinidad and other locations, including laws and regulations relating to the generation, handling and disposal of hazardous substances and wastes; the cleanup of hazardous substance releases; the discharge of regulated substances to air or water; and the demolition of existing plant sites upon permanent closure. In the United States, these laws include the Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery Act (RCRA), the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), the Toxic Substances Control Act (TSCA), the Occupational Safety and Health Act (OSHA) and various other federal, state and local statutes. Violations of environmental, health and safety laws can result in substantial penalties, court orders to install pollution-control equipment, civil and criminal sanctions, permit revocations and facility shutdowns. In addition, environmental, health and safety laws and regulations may impose joint and several liability, without regard to fault, for cleanup costs on potentially responsible parties who have released or disposed of hazardous substances into the environment or who own or operate property where hazardous substances have been released or disposed of by other parties. We may be subject to more stringent enforcement of existing or new environmental, health and safety laws in the future. In addition, we are also subject to certain environmental, health and safety laws of jurisdictions where we introduce products, chemicals, or substances into a market.
Environmental, Health and Safety Expenditures
Our environmental, health and safety capital expenditures in 2025 totaled approximately $37 million. We estimate that we will have approximately $46 million of environmental, health and safety capital expenditures in 2026. In addition, to support safe and reliable operations at our continuous process manufacturing facilities, we conduct scheduled inspections, replacements and overhauls of our plant machinery and equipment, which are referred to as turnarounds or outages. A further description of turnaround activities is included in Note 6—Property, Plant and Equipment—Net in the notes to consolidated financial statements included in Item 8 of this report. Environmental, health and safety laws and regulations are complex and change frequently. We expect that continued government and public emphasis on environmental issues will result in increased future expenditures for environmental controls at our manufacturing and distribution facilities. Such expenditures could have a material adverse effect on our business, financial condition, results of operations and cash flows. Additionally, future environmental, health and safety laws and regulations or reinterpretation of current laws and regulations may require us to make substantial expenditures. Our costs to comply with, or any liabilities under, these laws and regulations could have a material adverse effect on our business, financial condition, results of operations and cash flows.
CERCLA/Remediation Matters
From time to time, we receive notices from governmental agencies or third parties alleging that we are a potentially responsible party at certain cleanup sites under CERCLA or other environmental cleanup laws. In 2011, we received a notice from the Idaho Department of Environmental Quality (IDEQ) that alleged that we were a potentially responsible party for the cleanup of a former phosphate mine site we owned in the late 1950s and early 1960s located in Georgetown Canyon, Idaho. The current owner of the property and a former mining contractor received similar notices for the site. In 2014, we and the
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current property owner entered into a Consent Order with IDEQ and the U.S. Forest Service to conduct a remedial investigation and feasibility study of the site. The remedial investigation was submitted to the agencies in 2021. In 2025, we and the current property owner received IDEQ approval of a risk assessment required under the Consent Order. The next steps will be a feasibility study, and then a decision on remediation at the site. In 2015, we and several other parties received a notice that the U.S. Department of the Interior and other trustees intended to undertake a natural resource damage assessment for 18 former phosphate mines and three former processing facilities in southeast Idaho. The Georgetown Canyon former mine and processing facility was included in the group of former mines and processing facilities identified by the trustees. In June 2021, we received another notice from the U.S. Department of the Interior that the natural resource damage trustees were commencing a ‘subsequent’ phase of the natural resource damage assessment, but no further details were provided with respect to said assessment. Because the former Georgetown Canyon mine site is still in the risk assessment and feasibility study stage, we are not able to estimate at this time our potential liability, if any, with respect to the cleanup of the site or a possible claim for natural resource damages. However, based on the results of the site investigation and risk assessment conducted to date, we do not expect the remedial or financial obligations to which we may be subject involving this or other cleanup sites will have a material adverse effect on our consolidated financial position, results of operations or cash flows.
Regulation of Greenhouse Gases
Our production facilities emit greenhouse gases (GHGs), such as CO 2 and nitrous oxide. Natural gas, a fossil fuel, is a primary raw material used in our nitrogen production process. We are subject to GHG regulations in Canada, the United States and the United Kingdom. Beginning on January 1, 2026, importers of nitrogen fertilizer products into the European Union (EU) became subject to the EU’s carbon border adjustment mechanism (CBAM) costs based on the product’s production GHGs, subject to certain thresholds, with certain EU member state officials currently advocating for a suspension of CBAM’s application to fertilizers. The United Kingdom is in the process of adopting its own carbon border adjustment mechanism, currently expected to apply from January 1, 2027.
In Canada, we are required to conduct an annual review of our operations with respect to compliance with Environment Canada’s National Pollutant Release Inventory, Ontario’s Mandatory Monitoring and Reporting Regulation, and the GHG Reporting Regulation. In addition, our manufacturing plants in Alberta and Ontario are subject to provincial or federal laws that impose a price on excess GHG emissions. Each of these laws establishes CO 2 e emissions standards applicable to our facilities in terms of emissions per unit of production, with the provincial laws and the federal law using different formulas for establishing the intensity-based limits and the reductions in these limits over time. The federal law is the Greenhouse Gas Pollution Pricing Act, which came into effect in 2018 and is intended to function only as a backstop to the provincial programs if such programs do not meet minimum federal criteria. In 2022, the federal government found that both the Alberta and Ontario programs for 2023-2030 met such minimum criteria, and therefore, the provincial laws apply. Effective January 1, 2023, these provincial regulations increased in stringency from 2022 levels, and we expect that the regulations will continue to increase in stringency going forward as Canada continues to work toward its stated goal of net zero GHG emissions by 2050. If a facility’s CO 2 e emissions exceed the applicable limit, the excess emissions must be offset, either through obtaining qualifying emission credits or by making a payment for each ton of excess emissions. For calendar year 2026, the excess emissions fee under the federal, Alberta and Ontario regulatory programs is CAD $110 per metric ton, which fee will increase by CAD $15 per metric ton per year, reaching CAD $170 per metric ton by 2030. Canada is in the process of reviewing and updating its federal and provincial carbon systems and some changes may be expected.
In the United States, GHG regulation continues to evolve at state, regional and federal levels. In February 2026, the United States Environmental Protection Agency (EPA) finalized its rule, which was first proposed in July 2025, rescinding the 2009 endangerment finding related to GHGs under the Clean Air Act, which previously formed the legal basis for GHG regulation at the federal level in the United States, including the issuance of the social cost of carbon, stationary and mobile GHG regulations. The EPA has also proposed eliminating the GHG reporting rule for most source categories, pursuant to which all of our U.S. manufacturing facilities, which are considered large emitters of GHGs, have been required to monitor GHG emissions and report the previous year’s emissions annually. The EPA is expected to finalize the proposed rule on this program in 2026. Legal challenges are expected, which will continue to lead to significant uncertainty with respect to how existing federal GHG regulations will be implemented and enforced, and climate policy and GHG regulation will develop, at the federal level, in the United States in the coming years.
In addition, if we seek to modify or expand any of our major facilities, such modifications or expansions may require air permit reviews that result in those facilities becoming subject to new or more stringent pollution control requirements applicable to GHGs in addition to requirements applicable to conventional air pollutants. Such requirements may result in increased costs or delays in completing such projects and operating those facilities going forward. Other than the states’ implementation of the federally delegated air permitting requirements, none of the states where our U.S. production facilities
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are located – Iowa, Louisiana, Mississippi and Oklahoma – has proposed control regulations limiting GHG emissions from our facilities as of the date of this filing.
Our U.K. manufacturing plant is required to report GHG emissions annually to the United Kingdom Environment Agency pursuant to its site Environmental Permits and Climate Change Agreement, which specifies energy efficiency targets. Failure to meet efficiency targets may require our plant to purchase CO 2 emissions allowances. Our U.K. manufacturing plant is subject to the UK Emissions Trading Scheme, which generally requires us to hold or purchase emission allowances to offset GHG emissions from those aspects of our operations that are subject to regulation under this framework.
Increasing concern over the impacts of climate change is driving many countries to establish even more ambitious GHG reduction targets. Approximately 200 countries, including Canada, the United Kingdom and the members of the EU have joined the Paris Agreement, an international agreement intended to provide a framework pursuant to which the parties to the agreement will attempt to hold the increase in global average temperatures to below 2°C above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5°C above pre-industrial levels. Each signatory is required to develop its own national plan to attain this objective. Canada updated its emissions reduction target under the Paris Agreement to 45-50% below 2005 levels by 2035, up from 30%. In early 2025, the United Kingdom updated its target to reduce GHG emissions by at least 81% by 2035 from the baseline year of 1990. Similarly, in early December 2025, the European Parliament and member states reached a political agreement to amend the EU Climate Law to include a target to reduce GHG emissions by 90% by 2040 from the baseline year of 1990, which the EU Parliament approved in January 2026 and the EU Council is reviewing. Following its issuance of detailed rules to implement the CBAM in December 2025, the EU began implementation of its CBAM regulation in 2026 that will require importers of nitrogen fertilizer products to purchase certificates reflecting the direct and indirect carbon emissions embedded in covered imports that enter the EU on or after January 1, 2026 to incentivize emissions reductions. The United Kingdom is in the process of adopting its own carbon border adjustment mechanism, currently expected to apply from January 1, 2027, which will similarly impose additional costs on importers of nitrogen fertilizer products, based on the GHG emissions associated with the production of such products. While some EU member state officials, including from France and Italy, are advocating that the EU Commission temporarily suspend the application of the CBAM to fertilizers, or for fertilizers to be wholly excluded from the CBAM, the EU has only recently begun the process to establish, but has not yet adopted, an exemption process, and it remains unclear whether such efforts will be successful. While the United States has previously been a party to the Paris Agreement and as recently as April 2021 increased its goal to reduce GHG emissions to 50-52% below 2005 levels by 2030, the Trump administration announced its withdrawal from the Paris Agreement in January 2025, which became effective in January 2026, and has issued executive orders and taken subsequent actions to revoke prior climate-focused executive orders and other actions. Moreover, in early January 2026, the Trump administration announced the withdrawal of the United States from the UN Framework Convention on Climate Change and the Intergovernmental Panel on Climate Change.
More stringent GHG regulations, if they are enacted, may have a significant impact on us, because our production facilities emit GHGs such as CO 2 and nitrous oxide and because natural gas, a fossil fuel that releases methane when extracted from the earth and when transported, is a primary raw material used in our nitrogen production process. Regulation of GHGs may require us to make changes in our operating activities that could increase our operating costs, reduce our efficiency, limit our output, require us to make capital improvements to our facilities, increase our costs for, or limit the availability of, energy, raw materials or transportation, or otherwise materially adversely affect our business, financial condition, results of operations and cash flows. In addition, to the extent that GHG restrictions are not imposed in countries where our competitors operate or are less stringent than regulations that are or may be imposed in the United States, Canada or the United Kingdom, our competitors may have cost or other competitive advantages over us.
Regulatory Permits and Approvals
We hold numerous environmental and other governmental permits and approvals authorizing operations at each of our facilities. A decision by a government agency to deny or delay issuing a new or renewed regulatory material permit or approval, or to revoke or substantially modify an existing material permit or approval, could have a material adverse effect on our ability to continue operations at the affected facility. Any future expansion of our existing operations, including the Blue Point joint venture, is also predicated upon securing the necessary environmental or other permits or approvals. More stringent environmental standards may impact our ability to obtain such permits.
Human Capital Resources
Our long-term success depends on our people. We are dedicated to creating a workplace where employees are proud to work and grow and where everyone feels empowered to do their best work. We do this by investing in extensive recruitment, training and professional development opportunities for our employees and fostering a culture of inclusion and engagement.
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Employee Population. We employed approximately 2,900 employees as of December 31, 2025, of which 80% were located in the United States, 14% in Canada, and 6% in the United Kingdom. As of December 31, 2025, approximately 8% of our employees have worked for the Company more than 20 years, 27% of our employees have worked for the Company between 11 and 20 years, 21% of our employees have worked for the Company between 6 and 10 years, and 44% of our employees have worked at the Company for less than 6 years. Full-time employees represented nearly 100% of our workforce as of December 31, 2025, and approximately 5% were covered by collective bargaining agreements. We supplement our workforce with contractors with specialized skill sets during periods of peak activity, such as during turnarounds and maintenance events.
Workforce Health and Safety. Operating in a safe and responsible manner is a core value and an integral part of what sets the Company apart. We believe that focusing on leading indicators — such as the behavioral and process safety practices we have incorporated into our annual incentive plan — to drive and measure activities that prevent safety incidents, results in our industry-leading safety record. As of December 31, 2025, our employee 12-month rolling recordable incident rate (RIR) was 0.26 incidents per 200,000 work hours, and during the year ended December 31, 2025, our total recordable injury/illness count was eight. For the year ended December 31, 2025, our days away, restricted or transferred (DART) incident rate was 0.13 injuries per 200,000 work hours, and our lost time incident rate was 0.03 injuries per 200,000 work hours.
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ITEM 1A. RISK FACTORS.
In addition to the other information contained in this Annual Report on Form 10-K, you should carefully consider the factors discussed below in evaluating the Company and before deciding to invest in any of our securities. These risks and uncertainties, individually or in combination, could materially and adversely affect our business, financial condition, results of operations and cash flows. Additional risks and uncertainties not presently known to us or that we currently do not believe to be material could also adversely affect our business, financial condition, results of operations and cash flows.
Market Risks
Our industry is cyclical, and our operating results are highly dependent upon and fluctuate based upon changes in supply and demand of nitrogen products, and our business, financial condition, results of operations and cash flows tend to be negatively affected in periods of industry oversupply.
Selling prices for our products, which are global commodities or derived from global commodities, have fluctuated in response to periodic changes in supply and demand conditions. Supply of nitrogen products is affected primarily by available production capacity and operating rates, raw material costs and availability, energy prices, government policies and global trade. Demand for nitrogen products is affected by planted acreage, crop selection and fertilizer application rates, driven by population changes, economic growth, changes in dietary habits and non-food use of crops, such as production of ethanol and other biofuels. Demand also includes industrial uses of nitrogen, for example, chemical manufacturing and emissions reductants such as diesel exhaust fluid (DEF). Many factors affecting supply and demand of global nitrogen products are out of our control and could significantly impact our business, financial condition, results of operations and cash flows.
Periods, or anticipated periods, of strong demand, high-capacity utilization or increasing operating margins tend to stimulate global investment in production capacity. During such periods, nitrogen manufacturers, including the Company, have built new production capacity or expanded capacity of existing production assets, or have announced plans to do so. Construction of new production capacity in the industry, and improvements to increase output from existing production assets, increase nitrogen supply availability and place downward pressure on nitrogen selling prices, particularly when supply growth outpaces demand growth. For example, in the two-year period ended December 31, 2017, additional production capacity came online, and the average selling price for our products declined 34%, from $314 per ton in 2015 to $207 per ton in 2017.
Additional nitrogen production capacity has come online in the past 12 months and is expected to continue to do so globally over the next 12 months. In addition, we and other companies have announced plans to build new facilities for low-carbon ammonia, such as our ongoing development of a low-carbon ammonia production facility at our Blue Point complex in Louisiana. We cannot predict the impact of this additional capacity on nitrogen selling prices. Additionally, global or local economic, political and financial conditions or changes in such conditions, or other factors, may cause acceleration of announced and/or ongoing projects, which could further impact nitrogen selling prices. Similarly, lower energy prices can spur increases in production, which would result in increased supply and pressure on selling prices. Additionally, if imports increase into an oversupplied region, that region could experience lower prices.
During periods of industry oversupply, our financial condition, results of operations and cash flows tend to be affected negatively due to a decline in the price at which we sell our products. As a result, we may experience reduced profit margins, write-downs in the value of our inventory and temporary or permanent curtailments of production. Due to the cyclical nature of our industry, we have experienced periods of industry oversupply, which impacted our financial performance, credit ratings and the trading price for our common stock. We cannot predict the timing or duration of such periods of industry oversupply or the degree to which oversupply conditions would impact our business, financial condition, results of operations and cash flows.
Nitrogen products are global commodities, and we face intense global competition from other producers.
We are subject to intense price competition from other producers. The nitrogen products that we produce are global commodities or are derived from global commodities, with little or no product differentiation. Customers tend to make their purchasing decisions of these products principally on the basis of delivered price and, to a lesser extent, low-carbon attributes, reliability, customer service and product quality. As a consequence, conditions in the global market, including pricing competition, for nitrogen products significantly influence our operating results.
We compete with many producers, including state-owned and government-subsidized entities. Some of our competitors have greater total resources and are less dependent on earnings from nitrogen product sales, which make them less vulnerable to fertilizer and other nitrogen product industry downturns and better positioned to pursue new expansion and development opportunities. In addition, some of these entities may have access to lower cost natural gas supplies, financing, transportation and government-subsidies and tax incentives, which could place us at a competitive disadvantage. Furthermore, state-owned competitors may be willing to accept lower prices and profitability on their products, or may have their production inputs or
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consumption subsidized in order to support domestic employment or to foster other political or social goals. We may not be able to be competitive with these entities, including if we are not able to expand our own resources to a similar extent, either through investments in new or existing operations or through acquisitions or joint ventures.
China, the world’s largest producer and consumer of nitrogen fertilizers, currently has a government policy to limit exports of nitrogen fertilizers through a variety of measures. However, a number of factors could encourage China to expand exports of nitrogen fertilizers, including changes in Chinese government policy, higher utilization of production capacity, devaluation of the Chinese renminbi, the relaxation of Chinese environmental standards or decreases in Chinese producers’ underlying costs such as the price of Chinese coal. Any increase in production or export volume could adversely affect the balance between global supply and demand and put downward pressure on global fertilizer prices, which could materially adversely affect our business, financial condition, results of operations and cash flows.
We also face competition from other fertilizer producers in the Middle East, Europe, Africa, and the Western Hemisphere, including Canada and Trinidad and Tobago (Trinidad). These producers, depending on market conditions, fluctuating input prices, geographic location and freight economics, may take actions at times with respect to price or selling volumes that adversely affect our business, financial condition, results of operations and cash flows. Some of these producers also benefit from non-market or government-set rates for natural gas pricing, which has resulted in significant volumes of exports to the United States. For example, the 2016 revocations of U.S. antidumping measures on solid urea and fertilizer grade ammonium nitrate from Russia allowed for increased imports from that country into the United States in recent years. In addition, in recent years, high volumes of urea ammonium nitrate solution (UAN) imports from Russia have negatively affected U.S. producers’ UAN profitability. Government policies in these regions may also stimulate future ammonia or hydrogen investments. Recently, many proposed low-carbon ammonia projects have been announced or considered, and future hydrogen, energy, environmental or carbon policies may support development of additional nitrogen production in locations outside North America, including Europe, Australia, India, and the Middle East.
Global competition for nitrogen products is also influenced by other factors, including currency exchange rates, including the relative value of the U.S. dollar and its impact on the cost of importing nitrogen products into the United States, foreign agricultural policies, the existence of, or changes in, import or foreign currency exchange barriers in certain foreign jurisdictions and the laws and policies of the regions in which we operate, including the imposition of new duties, tariffs or quotas, that affect foreign trade and investment. For example, the imposition of duties, tariffs or quotas in a region, such as the European Union’s imposition of additional and increasing tariffs on nitrogen fertilizers from Russia that began in July 2025, can directly impact product pricing in that region, which can lead to changes in global trade flows and impact the global supply and demand balance and pricing. Market participants customarily move product between regions of the world, or adjust trade flows, in response to these factors. North America, where we manufacture and sell most of our products, is one of the largest and most accessible nitrogen trading regions in the world. As a result, other manufacturers, traders and other market participants have historically moved nitrogen products to North America when there is uncertainty associated with the supply and demand balance in other regions or when duties, tariffs or quotas impact prices or trade flows in other regions. Changes to tariffs on imports into the United States, retaliatory tariffs on U.S. exports, and potential renegotiation of trade deals may also impact prices or trade flows. Any such duties, tariffs and quotas can lead to uncertainty in the global marketplace and impact the supply and demand balance in many regions, which could adversely affect our business, financial condition, results of operations and cash flows. For example, the European Commission recently extended through January 6, 2031, definitive anti-dumping duties on imports to the European Union (EU) of UAN manufactured in Russia, Trinidad and the United States.
A decline in agricultural production, limitations on the use of our products for agricultural purposes or developments in crop technology could materially adversely affect the demand for our products.
Conditions in the United States, Europe, India, Brazil, China and other countries and regions of global significance in agricultural production significantly impact our operating results. Agricultural planted areas and production can be affected by a number of factors, including weather patterns and field conditions, current and projected grain inventories and prices, crop disease and/or livestock disease, demand for agricultural products and governmental policies regarding production of or trade in agricultural products. These factors are outside of our control.
Governmental policies and changes thereto, including farm and biofuel subsidies, commodity support programs and tariffs, environmental and greenhouse gas (GHG) policies, as well as the prices of fertilizer products, may also directly or indirectly influence the number of acres planted, the mix of crops planted and the use of fertilizers for particular agricultural applications. For example, ethanol production in the United States contributes significantly to corn demand, representing approximately 35% of total U.S. corn demand, and is impacted by federal legislation mandating renewable fuels use. Mandated ethanol production increases have increased the amount of corn grown in the United States and related fertilizer usage. Other U.S. policies have had similar impacts on other crops including grains and soybeans. Conversely, while the current Renewable
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Fuel Standard encourages continued high levels of corn-based ethanol production, various interested parties have called to eliminate or reduce the renewable fuel mandate, or to eliminate or reduce corn-based ethanol as part of such mandate. Additionally, other factors that drive the ethanol market include the prices of ethanol, gasoline and corn. Lower gasoline prices and fewer aggregate miles, driven by increased automobile fuel efficiency and the expansion of electric vehicle use, may put pressure on ethanol prices that could result in reduced profitability and lower production for the ethanol industry. This could have an adverse effect on corn-based ethanol production, planted corn acreage and fertilizer demand. Additionally, government incentives and other policies and recent increased investment in renewable biodiesel and associated soybean crush capacity may drive higher soybean oil prices, resulting in more planted acres allocated to soybeans and other oil crops and displacing some acreage traditionally planted to more nitrogen intensive crops such as grains and cotton.
Developments in crop technology, such as nitrogen fixation, the conversion of atmospheric nitrogen into compounds that plants can assimilate, or nitrogen-efficient varieties, or developments in alternatives to traditional animal feed or alternative proteins, could also reduce the use of nitrogen fertilizers and adversely affect the demand for our products. Widespread adoption of emerging application technologies or alternative farming techniques could disrupt traditional application practices, affecting the volume or types of fertilizer products used and timing of applications. In addition, from time to time various foreign governments and U.S. state legislatures have considered limitations on the use and application of nitrogen fertilizers due to concerns about the negative impact that the application of these products can have on the environment. For example, the United Kingdom implemented an assurance scheme in 2024 to limit the use of unprotected or uninhibited urea products between January and March of every year. While CF Fertilisers UK Limited does not sell solid urea fertilizer in the United Kingdom, limitations on fertilizer use have been and may be considered by other jurisdictions. In addition, Canada has announced a target of reducing emissions from fertilizers by 30% below 2020 levels by 2030 and is supporting implementation through improved nitrogen management and optimizing fertilizer use. These or other more stringent limitations on GHG emissions applicable to farmers, the end-users of our nitrogen fertilizers, could reduce the demand for our fertilizer products to the extent their use of our products increases farm-level emissions. Any reduction in the demand for our nitrogen fertilizer products, including as a result of technological developments or limitations on the use and application of nitrogen fertilizers, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our business is dependent on natural gas, the prices of which are subject to volatility.
Nitrogen from the atmosphere and hydrogen from natural gas, coal and other carbon energy feedstocks, or from the electrolysis of water, are the fundamental building blocks of nitrogen products. Energy feedstock costs comprise a significant portion of the total production cost of nitrogen products and, relative to the industry’s marginal producers that set the global price of nitrogen, generally determine profitability for nitrogen producers. Our manufacturing processes utilize natural gas as the principal raw material used in our production of nitrogen products. We use natural gas both as a chemical feedstock and as a fuel to produce ammonia, granular urea, UAN, AN and other nitrogen products.
Most of our nitrogen manufacturing facilities are located in the United States and Canada. As a result, North American natural gas comprises a significant portion of the total production cost of our products. The price of natural gas in North America has historically been volatile. The price has declined on average due in part to the development of significant natural gas reserves, including shale gas, and the rapid improvement in shale gas extraction techniques, such as hydraulic fracturing and horizontal drilling. However, shifts in the supply of and demand for natural gas due to market and regulatory changes can lead to extended periods of higher natural gas prices.
In recent years, the cost of North American natural gas for the production of nitrogen fertilizers has been significantly lower than the cost of natural gas in other parts of the world where the industry’s marginal nitrogen producers are located. Any increases in the volume of liquefied natural gas (LNG) exported from the United States to other regions or increases in natural gas development outside the United States, particularly in regions where nitrogen products are produced, could increase our natural gas costs and/or lower natural gas costs for our competitors. In recent years, U.S. LNG export capabilities have expanded, and U.S. LNG exports have increased, resulting in the United States becoming a leading exporter of LNG globally, with further expanded capabilities and export increases expected following the resumption of U.S. export permitting in 2025. If natural gas prices outside of North America were to decrease or North American natural gas prices were to increase, our favorable energy cost differentials relative to the industry’s marginal nitrogen producers could significantly erode, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Certain of our operating facilities are located near natural gas hubs that have experienced increased natural gas development and have favorable price differences as compared to other North American hubs. Favorable price differences in certain regions may dissipate over time due to increases in natural gas pipeline or storage capacity in those regions. Additionally, price differentials may become materially unfavorable due to a lack of inbound gas pipeline or storage capacity in other regions during periods of unusually high demand. Increased demand for natural gas, particularly in the Gulf Coast
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Region, due to increased industrial demand and increased natural gas exports, could result in increased natural gas prices. If reduced production, increased demand or changes in price were to occur, or if other developments adversely impact the supply and demand balance for natural gas in North America or elsewhere, natural gas prices could rise, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Adverse weather conditions may decrease demand for our fertilizer products, increase the cost of natural gas or materially disrupt our operations. Adverse weather conditions could become more frequent and/or more severe as a result of climate change.
Adverse weather conditions, which may be impacted by climate change, have in the past and may in the future have various negative impacts on our business, financial condition, results of operations and cash flows. Weather conditions that delay or disrupt field work during the planting, growing, harvesting or application periods may cause agricultural customers to use different forms of nitrogen fertilizer, which may adversely affect demand for the forms that we sell or may impede farmers from applying our fertilizers until the following application period, resulting in lower seasonal demand for our products.
Adverse weather conditions during or following harvest may delay or eliminate opportunities to apply fertilizer in the fall. Weather can also have an adverse effect on crop yields, which could lower the income of growers and impair their ability to purchase fertilizer from our customers. Adverse weather conditions could also impact transportation of fertilizer, which could disrupt our ability to deliver our products to customers on a timely basis. Our quarterly financial results can vary significantly from one year to the next due to weather-related shifts in fertilizer applications, planting schedules and purchasing patterns. Over the longer term, changes in weather patterns may shift the periods of demand for products and even the regions to which our products are distributed, which could require us to evolve our distribution system.
In addition, we use the North American waterway system extensively to ship products from some of our manufacturing facilities to our distribution facilities and our customers. We also export nitrogen fertilizer products via seagoing vessels from deep-water docking facilities at certain of our manufacturing sites on the U.S. river system near the U.S. Gulf. Therefore, persistent significant changes in river or ocean water levels (either up or down, such as a result of flooding, drought or climate change, for example) may require changes to our operating and distribution activities and/or significant capital improvements to our facilities. For example, recent low water levels on the U.S. river system and in the Panama Canal have delayed shipping in these locations, resulting in an increase in shipping costs.
Weather conditions or, in certain cases, weather forecasts, can also disrupt our operations and can affect the price of natural gas, the principal raw material used to make our nitrogen products. Colder and/or longer than normal winters and warmer than normal summers increase the demand for natural gas for residential and industrial use and for power generation, which can increase the cost and/or decrease the availability of natural gas. In addition, adverse weather events, such as extreme cold temperatures, storms, hurricanes, tornadoes, or floods, not only can cause loss of power or other impacts to our facilities or damage to or delays in logistics capabilities disrupting our operations, but also can impact the supply of natural gas and utilities and cause prices to rise.
All of the adverse weather conditions described above, including those impacting our customers and our operations, such as the physical risk from storms, hurricanes, tornadoes, or floods could become more frequent and/or more severe as a result of climate change. Our Donaldsonville and Waggaman complexes are located in an area of the United States that experiences a relatively high level of hurricane or high wind activity and several of our complexes are located in areas that experience extreme weather events for which insurance may be insufficient or unavailable. In the last several years, there has been an increase in the frequency and severity of adverse weather conditions, including in the geographic areas where we have operations. Any significant adverse weather event or combination of adverse weather events could decrease demand for our fertilizer products, increase the cost of natural gas or materially disrupt our operations—any of which could have a material adverse impact on our business, financial condition, results of operations and cash flows.
Our operating results fluctuate due to seasonality. Our inability to predict future seasonal fertilizer demand accurately could result in our having excess inventory, potentially at costs in excess of market value.
The fertilizer business is seasonal. The degree of seasonality of our business can change significantly from year to year due to conditions in the agricultural industry and other factors. The strongest demand for our products in North America occurs during the spring planting season, with a second period of strong demand following the fall harvest. In contrast, we and other fertilizer producers generally manufacture and distribute products throughout the year. As a result, we and/or our customers generally build inventories during the low demand periods of the year to facilitate timely product availability during the peak demand periods. Seasonality is greatest for ammonia due to the short application seasons and the limited ability of our customers and their customers to store significant quantities of this product. The seasonality of fertilizer demand generally
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results in our sales volumes and net sales being the highest during the spring and our working capital requirements to build inventory being the highest just prior to the start of the spring planting season.
If seasonal demand is less than we expect, we may be left with excess inventory that would need to be stored (in which case our results of operations would be negatively affected by any related increased storage costs) or liquidated (in which case the selling price could be below our production, procurement and storage costs). The risks associated with excess inventory and product shortages are exacerbated by the volatility of nitrogen fertilizer prices, the constraints of our storage capacity, and the relatively brief periods during which farmers can apply nitrogen fertilizers. If prices for our products rapidly decrease, we may be required to write-down the value of our inventory, adversely affecting our operating results.
A change in the volume of products that our customers purchase on a forward basis, or the percentage of our sales volume that is sold to our customers on a forward basis, could increase our exposure to fluctuations in our profit margins and working capital and materially adversely affect our business, financial condition, results of operations and cash flows.
We offer our customers the opportunity to purchase products from us on a forward basis at prices and delivery dates we propose. Under our forward sales programs, customers generally make an initial cash down payment at the time of order and pay the remaining portion of the contract sales value in advance of the shipment date. Our forward sales improve our liquidity by reducing our working capital needs due to the upfront cash payments received from customers and facilitate more efficient production planning and utilization of our manufacturing and distribution assets. Any cash payments received in advance from customers in connection with forward sales are reflected on our consolidated balance sheets as a current liability until the related orders are shipped, which can take up to several months.
We believe the ability to purchase products on a forward basis is more appealing to our customers during periods of generally increasing prices for nitrogen fertilizers. Our customers may be less willing or even unwilling to purchase products on a forward basis during periods of generally decreasing or stable prices or when there is an expectation of lower prices in the future. In addition, our customers may be unwilling to purchase products on a forward basis due to their limited capital resources. Fixing the selling prices of our products, often months in advance of their ultimate delivery to customers, typically causes our reported selling prices and margins to differ from spot market prices and margins available at the time of shipment. In periods of rising fertilizer prices, selling our nitrogen fertilizers on a forward basis may result in lower profit margins than if we had not sold fertilizer on a forward basis.
Operational Risks
Our operations are dependent upon raw materials and utilities provided by third parties, and any delay or interruption in the delivery of raw materials or utilities may adversely affect our business.
We use raw materials, primarily natural gas, and utilities, such as electricity, in the manufacture of our nitrogen products. We purchase raw materials and utilities from third party suppliers. Our natural gas is transported by pipeline to our facilities by third party transportation providers or through the use of facilities owned by third parties, and certain of our plants are reliant on only one natural gas pipeline. Delays or interruptions in the delivery of raw materials and utilities may be caused by, among other things, adverse weather conditions or natural disasters, unscheduled downtime, labor difficulties or shortages, insolvency of our suppliers or their inability to meet existing contractual arrangements, deliberate sabotage and terrorist incidents, unplanned maintenance or mechanical failures. In addition, the transport of natural gas by pipeline is subject to additional risks, including delays or interruptions caused by capacity constraints, leaks or ruptures. Any delay or interruption in the delivery of raw materials or utilities, even for a limited period, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our transportation and distribution activities, including those related to carbon dioxide (CO 2) sequestration, rely on third party providers and are subject to environmental, safety and regulatory oversight. This exposes us to risks and uncertainties beyond our control that may adversely affect our operations and exposes us to additional liability.
We rely on natural gas pipelines to transport natural gas, the principal raw material used in our production process, to our manufacturing facilities. In addition, we rely on railroad, barge, truck, vessel and pipeline companies to coordinate and deliver finished products to our distribution system and to ship finished products to our customers. We also lease rail cars in order to ship finished products. Further to our clean energy strategy, we recently launched low-carbon ammonia production at our Donaldsonville complex and have ongoing investments in our Yazoo City and Blue Point complexes. This production and these investments are dependent on our third-party providers, including their CO 2 pipelines and sequestration wells, for the transport and permanent sequestration of CO 2. These transportation operations, equipment and services are subject to various hazards and other sources of disruption, including adverse operating conditions on the inland waterway system or on the seas with respect to
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oceangoing vessels, adverse weather conditions, system failures, unscheduled downtime, labor difficulties or shortages, shutdowns, delays, accidents such as spills and derailments, vessel groundings and other accidents and operating hazards. The inability of our third-party providers to develop or operate CO 2 pipelines and sequestration wells would impact our ability to generate tax credits and recognize revenue for low-carbon ammonia sales. Additionally, due to the aging infrastructure of certain rail lines, bridges, roadways, pipelines, river locks, and equipment that our third-party service providers utilize, we may experience delays in both the receipt of raw materials or the shipment of finished product while repairs, maintenance or replacement activities are conducted. Also, certain third-party service providers, such as railroads, have from time to time experienced service delays or shutdowns due to capacity constraints in their systems, operational and maintenance difficulties, blockades, organized labor strikes, weather or safety-related embargoes and delays, and other events, which could impact the shipping of our products and cause disruption in our operations and supply chain.
These transportation operations, equipment and services, including those related to CO 2 sequestration, are also subject to environmental, safety, and regulatory oversight. These operations are currently subject to stringent regulatory requirements due to concerns related to accidents, discharges or other releases of hazardous substances, terrorism, or the potential use of fertilizers as explosives. Governmental entities could implement new or more stringent regulatory requirements affecting the transportation of raw materials or finished products or affecting the transportation or sequestration of CO 2.
If shipping of our products is delayed or we are unable to obtain raw materials as a result of these transportation companies’ failure to operate properly, if new and more stringent regulatory requirements were implemented affecting transportation operations or equipment, or if there were significant increases in the cost of these services or equipment, our revenues and cost of operations could be adversely affected. In addition, increases in our transportation costs, or changes in such costs relative to transportation costs incurred by our competitors, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In the United States and Canada, the railroad industry continues various efforts to limit its potential liability with respect to transportation of toxic inhalation hazard materials, such as the ammonia we transport to and from our manufacturing and distribution facilities. For example, various railroads shift liability to shippers by contract, purport to shift liability to shippers by tariff, or otherwise seek to require shippers to indemnify and defend the railroads from and against liabilities (including in negligence, strict liability, or statutory liability) that may arise from certain acts or omissions of the railroads, third parties that may have insufficient resources, or the Company or from unknown causes or acts of god. These initiatives could materially and adversely affect our operating expenses and potentially our ability to transport ammonia, including the impact of potential rail mergers, which if approved, would reduce the number of Class I railroads available to transport ammonia. Additionally, the railroad initiatives could increase our liability for releases of our ammonia while in the care, custody and control of the railroads, third parties or us, for which our insurance may be insufficient or unavailable. New or more stringent regulatory requirements also could be implemented affecting the equipment used to ship our raw materials or finished products. Restrictions on service, increases in transportation costs, or changes in such costs relative to transportation costs incurred by our competitors, and any railroad industry initiatives that may impact our ability to transport our products, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We are reliant on a limited number of key facilities.
Our nitrogen manufacturing facilities are located at nine separate nitrogen complexes, the largest of which is the Donaldsonville complex, which represented approximately 40% of our ammonia production capacity as of December 31, 2025. The suspension of operations at any of these complexes could adversely affect our ability to produce our products and fulfill our commitments and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Operational disruptions could occur for many reasons, including natural disasters, adverse weather conditions, unplanned maintenance and other manufacturing problems, such as mechanical failures, disease, strikes or other labor unrest or transportation interruptions. For example, our Donaldsonville and Waggaman complexes, and our under development Blue Point complex, are located in an area of the United States that experiences extreme weather events, including a relatively high level of hurricane or high wind activity, and several of our other complexes are also located in areas that experience extreme weather events. Extreme weather events, including temperature extremes, depending on their severity and location, have the potential not only to damage our facilities and disrupt our operations, but also to affect adversely the shipping and distribution of our products. Moreover, our facilities may be subject to failure of equipment that may be difficult to replace or have long delivery lead times, due in part to a limited number of suppliers, and could result in operational disruptions.
Failure, inadequacy, breach of, or unauthorized access to, our information technology systems or those of third-party service providers or customers could negatively affect our business and operations.
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We rely on internal and third-party information technology and computer control systems in many aspects of our business, including internal and external communications, the management of our accounting, financial and supply chain functions and plant operations, some of which are within our control and some of which are within the control of third parties, to accumulate, process, store, and transmit large amounts of confidential information. If we do not allocate and effectively manage the resources necessary to build, implement and sustain the proper technology infrastructure, we could be subject to transaction errors, inaccurate financial reporting, processing inefficiencies, the loss of customers, business disruptions, or the loss of or damage to our confidential business information due to a security breach. In addition, our information technology systems may be damaged, disrupted or shut down due to attacks by computer hackers, computer viruses, employee error or malfeasance, power outages, hardware failures, telecommunication or utility failures, catastrophes or other unforeseen events, and in any such circumstances our system redundancy and other disaster recovery planning may be ineffective or inadequate. Security breaches of our systems (or the systems of our customers, suppliers or other business partners) could result in misappropriation, destruction or unauthorized disclosure of confidential information or personal data belonging to us or to our employees, business partners, customers or suppliers, and may subject us to legal liability.
Our information technology systems (and those of our business partners and other third-parties) have in the past been, and in the future likely will be, subject to computer viruses, malicious codes, unauthorized access and other cyberattacks, and we expect the sophistication and frequency of such attacks to continue to increase. Any of the attacks, breaches or other disruptions or damage described above could: result in an operational interruption or failure at one or more sites; damage our operations; delay production and shipments; expose us to ransom payment, other demands, or paralyze our operations; result in the theft of our and our customers’ intellectual property and trade secrets; damage customer and business partner relationships and our reputation; result in legal claims and proceedings, liability and penalties under privacy or other laws, including for unauthorized disclosure of personally identifiable information, or increased costs for security and remediation; or raise concerns regarding our accounting for transactions. Each of these consequences could have an adverse effect on our business, reputation and our financial statements, some of which could be material. From time to time, we update, transition, acquire, or expand use of our and third-party information technology systems, which may result in additional vulnerability.
Our business involves the use, storage, and transmission of information about our employees, customers, and suppliers. The protection of such information, as well as our proprietary information, is critical to us, and we are subject to various laws and regulations globally regarding privacy and data protection, including laws and regulations relating to the collection, storage, handling, use, disclosure, transfer, and safekeeping of personal information. The regulatory environment surrounding information security and privacy is increasingly demanding, and the subject of significant attention by regulators and private parties globally, with frequent imposition of new requirements and changes to existing requirements. Breaches of our security measures or the accidental loss, inadvertent disclosure, or unapproved dissemination of proprietary information or sensitive or confidential data about us or our employees, customers or suppliers, including the potential loss or disclosure of such information or data as a result of fraud, trickery, or other forms of deception, could expose us or our employees, customers, suppliers or other individuals or entities affected to a risk of loss or misuse of this information, which could ultimately result in litigation and potential legal and financial liability. These events could damage our reputation or otherwise harm our business.
To date, we are not aware of any significant impact on our operations or financial results from such attempts; however, unauthorized access or other types of cyberattacks could disrupt our business operations, result in the loss of assets, and have a material adverse effect on our business, financial condition, or results of operations. Measures we implement in an effort to protect, detect, respond to, and minimize or prevent these risks may not be successful, and we may fail to detect or remediate system inadequacies, inadequate controls or procedures, operating failures, unauthorized access, service interruptions or failures, security breaches, malicious intrusions, theft, exfiltration, ransomware, cyberattacks, or other compromises of our systems. Any of these events could result in material financial, operational, legal, business, or reputational harm to our business.
Acts of terrorism and regulations to combat terrorism could negatively affect our business.
Like other companies with major industrial facilities, we may be targets of terrorist activities. Generally, our plants and facilities store significant quantities of materials that can be dangerous if mishandled. Any damage to infrastructure facilities, such as electric generation, transmission and distribution facilities, or injury to employees who could be direct targets or indirect casualties of an act of terrorism, may affect our operations. Any disruption of our ability to produce or distribute our products could result in a significant decrease in revenues and require significant additional costs to replace, repair or insure our assets, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Due to concerns related to terrorism, the toxic properties of ammonia, or the potential use of certain nitrogen products as explosives, we are subject to various security laws and regulations. U.S. security laws include the Maritime Transportation Security Act of 2002 and the Chemical Facility Anti-Terrorism Standards (although this legislation is currently expired). Governmental entities could implement new or impose more stringent regulations affecting the security of our plants, terminals
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and warehouses or the transportation and use of fertilizers and other nitrogen products. These regulations could result in higher operating costs or limitations on the sale of our products and could result in significant unanticipated costs, lower revenues and reduced profit margins. It is also possible that governmental entities in the United States or elsewhere could impose additional limitations on the use, sale or distribution of the specific nitrogen products that can be used as explosives, thereby limiting our ability to manufacture or sell those products, or exposing us to legal liability if our products were used illicitly.
Our operations and the production and handling of our products involve significant risks and hazards. We are not fully insured against all potential hazards and risks incident to our business and as a result, may not be able to adequately cover our losses.
Our operations are subject to hazards inherent in the manufacture, transportation, storage and distribution of chemical products, including ammonia, which is highly toxic and can be corrosive, and ammonium nitrate, which is explosive. These hazards include: explosions; fires; extreme weather and natural disasters; train derailments, collisions, vessel groundings and other transportation and maritime incidents; leaks and ruptures involving storage tanks, pipelines and rail cars; spills, discharges and releases of toxic or hazardous substances or gases; deliberate sabotage and terrorist incidents; mechanical failures; unscheduled plant downtime; labor difficulties and other risks. Some of these hazards can cause bodily injury and loss of life, severe damage to or destruction of property and equipment and environmental damage and may result in suspension of operations for an extended period of time and/or the imposition of civil or criminal penalties and liabilities.
Our exposure to these risks and hazards is exemplified by a fire and explosion that occurred at a fertilizer storage and distribution facility in West, Texas, in 2013. The fire and explosion resulted in 15 fatalities and claims of injuries to approximately 200 people, and damaged or destroyed a number of homes and buildings around the facility. We did not own or operate the facility or directly sell our products to the facility, but products that we manufactured and sold to others were delivered to the facility and may have been stored at the facility at the time of the incident. We were named as defendants along with other companies in lawsuits, in which the claims against us have since been resolved, alleging various theories of negligence, strict liability, and breach of warranty in connection with the incident.
We maintain property, business interruption, casualty and liability insurance policies, but we are not fully insured against all potential hazards and risks incident to our business, and certain hazards and risks associated with our operations may not be insurable. If we were to incur significant liability for which we were not fully insured, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. We are subject to various self-insured retentions, deductibles and limits under these insurance policies. The policies also contain exclusions and conditions that could have a material adverse impact on our ability to receive indemnification thereunder. Our policies are generally renewed annually. As a result of market conditions, our premiums, self-insured retentions and deductibles for certain insurance policies can increase substantially and, in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. In addition, significantly increased costs could lead us to decide to reduce, or possibly eliminate, coverage. We may be unable to buy and maintain insurance with adequate limits and reasonable pricing terms and conditions.
Our international operations and business activities expose us to risks that could negatively affect our business, financial condition, results of operations and cash flows.
Our international business operations are subject to numerous risks and uncertainties, including difficulties and costs associated with complying with a wide variety of complex laws, treaties and regulations; unexpected or conflicting changes in regulatory environments; currency fluctuations; tax rates that may exceed those in the United States; earnings that may be subject to withholding requirements; and changes in global trade policy, including the imposition of tariffs, embargoes, exchange controls or other restrictions.
Changes in global trade policies can lead to the imposition of new taxes, levies, duties, tariffs or quotas affecting agricultural commodities, fertilizer or industrial products. These can alter or impact costs, trade flows, demand for our products, access to raw materials, capital equipment, and other supplies, and regional supply and demand balances for our products. Changes to tariffs on imports into the United States, retaliatory tariffs on U.S. exports, and potential renegotiation of trade deals may impact our existing operations or our planned strategic ventures and could adversely affect our business, financial condition, results of operations and cash flows.
Our principal reporting currency is the U.S. dollar and our business operations and investments outside the United States increase our risk related to fluctuations in foreign currency exchange rates. The main currencies to which we are exposed, besides the U.S. dollar, are the Canadian dollar, the British pound and the euro. These exposures may change over time as business practices evolve and economic conditions change. We may selectively reduce some foreign currency exchange rate risk by, among other things, requiring contracted purchases of our products to be settled in, or indexed to, the U.S. dollar or a
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currency freely convertible into U.S. dollars, or hedging through foreign currency derivatives. These efforts, however, may not be effective and could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We are subject to anti-corruption laws and regulations and economic sanctions programs in various jurisdictions, including the following: U.S. Foreign Corrupt Practices Act of 1977, the United Kingdom Bribery Act 2010, the Canadian Corruption of Foreign Public Officials Act; regulations under the Comprehensive Iran Sanctions, Accountability, and Divestment Act of 2010; and economic sanctions programs administered by the United Nations, the EU and the Office of Foreign Assets Control of the U.S. Department of the Treasury. As a result of doing business internationally, we are exposed to risks of violating anti-corruption laws and sanctions regulations applicable in those countries where we, our partners or our agents operate. Violations of anti-corruption and sanctions laws and regulations are punishable by civil penalties, including fines, denial of export privileges, injunctions, asset seizures, debarment from government contracts (and termination of existing contracts) and revocations or restrictions of licenses, as well as criminal fines and imprisonment. The violation of applicable laws by our employees, consultants, agents or partners could subject us to penalties and could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We are also subject to antitrust and competition laws in various jurisdictions. We cannot predict how these laws or their interpretation, administration and enforcement will change over time. Changes in antitrust laws globally, or in their interpretation, administration or enforcement, may limit our existing or future operations and growth.
Further, we are subject to continually evolving GHG regulations and other environmental laws and regulations in various jurisdictions. Changes in these regulations in any jurisdiction to which we are subject, or in their interpretation, administration or enforcement, may have a material adverse effect on our business, financial condition, results of operations and cash flows and may increase costs associated with compliance, particularly in the event of a cross-jurisdictional conflict.
The occurrence of any one or more of these factors could increase our costs and adversely affect our results of operations.
Financial Risks
Our indebtedness could adversely affect our cash flow, prevent us from fulfilling our obligations and impair our ability to pursue or achieve other business objectives.
As of December 31, 2025, we had approximately $3.25 billion of total funded indebtedness, consisting solely of unsecured senior notes with varying maturity dates between 2034 and 2044, or approximately 29% of our total capitalization (total debt plus total equity), and an additional $750 million of unsecured senior borrowing availability (reflecting no outstanding borrowings and no outstanding letters of credit) for general corporate purposes under our revolving credit agreement. Our debt service obligations will impact our earnings and cash flow as long as the indebtedness is outstanding.
Our indebtedness could, as a result of our debt service obligations or through the operation of the financial and other restrictive covenants to which we are subject under the agreements and instruments governing that indebtedness and otherwise, have important consequences. For example, it could:
•make it more difficult for us to pay or refinance our debts as they become due during adverse economic and industry conditions because any related decrease in revenues could cause us not to have sufficient cash flows from operations to make our scheduled debt payments;
•cause us to be less able to take advantage of significant business opportunities, such as acquisition opportunities, and to react to changes in market or industry conditions;
•cause us to use a portion of our cash flow from operations for debt service, reducing the availability of cash to fund working capital and capital expenditures, and other business activities;
•cause us to be more vulnerable to general adverse economic and industry conditions;
•expose us to the risk of increased interest rates because certain of our borrowings, including borrowings under our revolving credit agreement, could be at variable rates of interest;
•make us more leveraged than some of our competitors, which could place us at a competitive disadvantage;
•restrict our ability to pay dividends on our common stock or to repurchase shares of our common stock;
•limit our ability to borrow additional amounts to fund working capital, capital expenditures and other general corporate purposes; and
•result in our credit ratings being downgraded, which could increase the cost of further borrowings.
We consider options to refinance our outstanding indebtedness from time to time. Our ability to obtain any financing, whether through the issuance of new debt securities or otherwise, and the terms of any such financing are dependent on, among other things, our financial condition, financial market conditions within our industry and generally, interest rate fluctuations, credit ratings and numerous other factors, including factors beyond our control. Consequently, in the event that we need to
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access the credit markets, including to refinance our debt, there can be no assurance that we will be able to obtain financing on acceptable terms or within an acceptable timeframe, if at all. An inability to obtain financing with acceptable terms when needed could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The terms of our existing indebtedness allow us to incur significant additional debt. If we incur additional indebtedness, the risks that we face as a result of our leverage could intensify. If our financial condition or operating results deteriorate, our relations with our creditors, including the holders of our outstanding debt securities, the lenders under our revolving credit agreement and our suppliers, may be materially and adversely affected.
Tax matters, including changes in tax laws or rates, adverse determinations by taxing authorities and imposition of new taxes could adversely affect our results of operations and financial condition.
We are subject to taxes in the United States, where most of our operations are located, and in several foreign jurisdictions where our subsidiaries are organized or conduct business. Tax laws or rates, including tax credits relating to decarbonization projects, in the various jurisdictions in which we operate may be subject to significant change. Our future effective tax rate could also be affected by changes in our mix of earnings from jurisdictions with differing statutory tax rates and tax systems, changes in valuation of deferred tax assets and liabilities or changes in tax laws or their interpretation.
The Inflation Reduction Act of 2022 expanded production tax credits for carbon sequestration and introduced clean hydrogen production tax credits. The One Big Beautiful Bill Act, enacted in July 2025, further modified carbon sequestration tax credits and limited the duration of the clean hydrogen production tax credits. Further changes to the underlying legislation or the final guidance issued may impact our ability to receive anticipated tax credits for our low-carbon ammonia projects.
We are also subject to regular reviews, examinations and audits by the Internal Revenue Service (IRS) and other taxing authorities in jurisdictions where we conduct business. Although we believe our tax estimates are reasonable, if a taxing authority disagrees with the positions we have taken, we could face additional tax liabilities, including interest and penalties. There can be no assurance that payment of such additional amounts upon final adjudication of any disputes will not have a material impact on our financial condition, results of operations and cash flows.
We have used the cash we generate outside the United States primarily to fund development of our business in non-U.S. jurisdictions. If the funds generated by our U.S. business are not sufficient to meet our need for cash in the United States or if cash generated outside the United States exceeds the needs of such non-U.S. operations, we may repatriate a portion of our future international earnings to the United States. Under the tax laws of the foreign countries in which we operate, those international earnings could be subject to withholding taxes when repatriated; therefore, the repatriation of those earnings could result in an increase in our worldwide effective tax rate and an increase in our use of cash to pay these taxes.
We also need to comply with other new, evolving or revised tax laws and regulations. The enactment of, or increases in, carbon taxes or value added taxes, or other changes in the application of existing taxes, in markets in which we are currently active, or may be active in the future, or on specific products that we sell or with which our products compete, could have an adverse effect on our financial condition and results of operations.
Our business is subject to risks involving derivatives and the risk that our hedging activities might not prevent losses.
From time to time, we use natural gas derivatives to hedge our financial exposure to the price volatility of natural gas, the principal raw material we use in the production of nitrogen-based products. We may use natural gas futures, swaps and option contracts traded in over-the-counter markets or on exchanges. From time to time, we may also use fixed-price, physical purchase and sales contracts to hedge our exposure to natural gas price volatility. To manage our exposure to changes in foreign currency exchange rates, we may from time to time use foreign currency derivatives (primarily forward exchange contracts).
Our use of derivatives 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 that do not qualify for, or to which we do not apply, hedge accounting. To the extent that our derivative positions lose value, we may be required to post collateral with our counterparties, adversely affecting our liquidity.
Hedging arrangements are imperfect and unhedged risks will always exist. In addition, our hedging activities may themselves give rise to various risks that could adversely affect us. For example, we are exposed to counterparty credit risk when our derivatives are in a net asset position. The counterparties to our derivatives are multi-national commercial banks, major financial institutions or large energy companies.
Our liquidity could be negatively impacted by a counterparty default on settlement of one or more of our derivative financial instruments or by the triggering of any cross-default provisions or credit support requirements against us.
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Additionally, the International Swaps and Derivative Association master netting arrangements for most of our derivative instruments contain credit-risk-related contingent features, such as cross-default provisions and credit support requirements. In the event of certain defaults or a credit ratings downgrade, our counterparty may request early termination and net settlement of certain derivative trades or may require us to collateralize derivatives in a net liability position.
At other times we may not utilize derivatives or derivative strategies to hedge certain risks or to reduce the financial exposure of price volatility. As a result, we may not prevent certain material adverse impacts that could have been mitigated through the use of derivative strategies.
Environmental and Regulatory Risks
We are subject to numerous environmental, health and safety laws, regulations and permitting requirements, as well as potential environmental liabilities, which may require us to make substantial expenditures or modify business plans.
We are subject to numerous environmental, health and safety laws and regulations in the United States, Canada, the United Kingdom, Trinidad and other locations, including laws and regulations relating to the generation, handling and disposal of hazardous substances and wastes; the introduction of new chemicals or substances into a market; the cleanup of hazardous substance releases; the discharge of regulated substances to land, air or water; and the demolition and cleanup of plant sites upon permanent closure. The laws and regulations across jurisdictions are increasingly complex and sometimes conflicting. Relevant U.S. laws include the Clean Air Act, the Clean Water Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), and the Toxic Substances Control Act. The Infrastructure Investment and Jobs Act of 2021 reinstated and doubled the Superfund tax on chemicals, including ammonia and nitric acid. These taxes run through December 31, 2031 and apply to the domestic production and import of ammonia and nitric acid products, except to the extent such products are used in fertilizer or animal feed, used as fuel or exported.
As a producer of nitrogen products working with hazardous substances, our business faces risks of spills, discharges or other releases of those substances into the environment. Certain environmental laws, including CERCLA, impose joint and several liability, without regard to fault, for cleanup costs on persons who have disposed of or released hazardous substances into the environment or who own or operate property where hazardous substances have been released or disposed of by other parties. Given the nature of our business, we have incurred, are incurring currently, and are likely to incur periodically in the future, liabilities under CERCLA and other environmental cleanup laws at our current facilities or facilities previously owned or operated by us or other acquired businesses, adjacent or nearby third-party facilities or offsite disposal locations. Because liability under CERCLA, and various U.S. state analogues, can be joint and several, a party may be required to bear more than its proportional share of cleanup costs at a site where it has liability if payments cannot be obtained from other responsible parties. The costs associated with future cleanup activities that we may be required to conduct or finance may be material. Additionally, we may become liable to third parties for damages, including personal injury and property damage, resulting from the disposal or release of hazardous substances into the environment.
Violations of environmental, health and safety laws can result in substantial penalties, court or administrative orders to undertake capital improvements, such as installing pollution-control equipment, civil and criminal sanctions, permit revocations, and facility shutdowns. Environmental, health and safety laws change regularly and could become more stringent over time. As a result, we have not always been and may not always be in full compliance with all environmental, health and safety laws and regulations. We may be subject to more stringent enforcement of existing or new environmental, health and safety laws in the future. Future environmental, health and safety laws and regulations or reinterpretation of or changes to current laws and regulations may require us to make substantial expenditures or modify business plans. The extent and nature of existing, proposed and future environmental, health and safety regulations are increasingly uncertain in light of recent U.S. Supreme Court decisions, including Loper Bright Enterprises v. Raimondo, that limit deference to regulatory agencies in the context of certain regulatory decisions. Our costs to comply with, or any liabilities under, these laws and regulations could have a material adverse effect on our business, financial condition, results of operations and cash flows.
From time to time, our production, distribution or storage of ammonia and other hazardous or regulated substances has resulted in accidental releases that have temporarily disrupted our operations and/or resulted in liability for administrative penalties, cleanup costs, and/or claims for personal injury. To date, our costs to resolve these liabilities have not been material. However, we could incur significant costs if we experience a significant accidental release and our liability coverage is not sufficient to pay for all or a large part of any judgments against us, or if our insurance carrier refuses coverage for these losses.
We hold numerous environmental and other governmental permits and approvals authorizing our facility operations. Expansion or modification of our operations or development of new operations is predicated upon securing necessary environmental or other permits or approvals, and in some cases, the ability of our partners, lessors and other third-party providers, as applicable, to secure such permits or approvals. More stringent environmental, health and safety laws and
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regulations, a reinterpretation of or changes to current laws and regulations, or community or interest group opposition to permits and approvals could make it more difficult to obtain or renew necessary governmental permits or approvals. Further, a focus on local and community effects of industrial operations, including chemical plants, pipelines and carbon sequestration wells, could impact issuances of new or renewal of existing permits. A government agency’s denial of or delay in issuing a new or renewed regulatory permit or approval, or revocation or substantial modification of an existing permit or approval, a legal challenge to our permits, or a determination that we have violated a law or permit could have a material adverse effect on our ability to continue facility operations and on our business, financial condition, results of operations and cash flows.
Regulatory or legislative provisions related to GHG emissions in the jurisdictions in which we operate or conduct business could materially adversely affect our business, financial condition, results of operations and cash flows.
Our production facilities emit GHGs, such as CO 2 and nitrous oxide. The primary raw material used in our production process is natural gas, which releases methane when extracted from the earth and when transported. Conventional ammonia production is considered an emissions- and energy-intensive industry because it generates CO 2 as an unavoidable chemical byproduct. We are subject to GHG regulations in the United Kingdom, Canada, the European Union and the United States. In the United States, our existing facilities, which are considered large emitters of GHGs, currently are only subject to GHG emissions reporting obligations, which the current U.S. presidential administration has proposed to eliminate. In certain jurisdictions, new facilities that we build, or existing facilities that we modify in the future, could also be subject to GHG emissions standards included in their air permits.
Concern over the effects of climate change has driven many countries to establish ever more ambitious GHG reduction targets and initiatives to achieve them. These targets and initiatives are subject to significant change based on political leadership that could impact our business. The U.S. government has made, proposed, and may propose further, policy, regulatory and enforcement changes that may result in the narrowing and/or repeal of environmental and climate change-related laws, regulations, commitments and implementation thereof. These changes, and any administrative and judicial challenges to them or further changes by future administrations, create uncertainty for our business. For example, adoption of a proposed rule to repeal the GHG emissions reporting obligations for most source categories, without changes to the IRS’ guidance on the process for documenting clean energy tax credits, may delay or eliminate our ability to realize anticipated tax credits or limit our low-carbon ammonia export opportunities. Any changes to clean energy tax credit programs utilized by us may impact our ability to receive anticipated tax credits for our low-carbon ammonia projects, which, in turn, could negatively affect the profitability of these projects. Moreover, lowering of GHG reduction targets and the efforts to achieve them, in or outside the United States, may prevent or significantly reduce the development of demand for our low-carbon ammonia products.
Canadian regulations impose a price on excess GHG emissions. These regulations price carbon dioxide equivalent (CO 2 e) emissions standards of our Canadian facilities based on emissions per unit of production. If CO 2 e emissions exceed the applicable standards, the excess emissions must be offset, by obtaining qualifying credits or offsets or paying a direct emissions charge per metric ton, with the regulated price to increase annually through 2030. Those regulations are being reviewed at the federal and provincial levels in 2026, which could result in an increase in the costs our Canadian facilities incur.
Beginning on January 1, 2026, importers of nitrogen fertilizer products into the EU became subject to its carbon border adjustment mechanism (CBAM) and will be required to purchase certificates in 2027 reflecting the direct and indirect carbon emissions embedded in covered imports. While some EU member state officials, including from France and Italy, are advocating that the EU Commission temporarily suspend the application of the CBAM to fertilizers, or for fertilizers to be wholly excluded from it, the EU has not yet adopted an exemption process, and it remains unclear whether such efforts will be successful. Other governments are also considering border taxes for carbon-intensive products, including the United Kingdom, which is introducing a carbon border adjustment mechanism currently expected to apply from January 1, 2027. The imposition of border taxes, the details of their implementation and uncertainty arising from suspensions of or exemptions to them may impact the development of a market for low-carbon ammonia, investments in low-carbon ammonia, including our returns on such investments, and trade flows, which could adversely impact our business.
More stringent GHG regulations, if enacted, are likely to have a significant impact on us, because our production facilities emit GHGs such as CO 2 and nitrous oxide and because natural gas is the primary raw material used in our production process. GHG regulations may require us to make changes in our operating activities that would increase operating costs, reduce efficiency, limit output, require capital improvements to our facilities, increase costs for or limit the availability of energy, raw materials or transportation, or otherwise materially adversely affect our business, financial condition, results of operations and cash flows. Changes could also be made to tax or other regulatory policies related to decarbonization, electricity generation or clean energy that could impact our business and investment decisions. To the extent that GHG restrictions are not imposed in countries where our competitors operate, or on competing products, or are less stringent than regulations that are or may be imposed on us or our products, our competitors may have cost or other competitive advantages over us.
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In addition to regulations concerning the emission of GHGs, many jurisdictions have implemented or are considering regulations requiring the disclosure of certain climate and other sustainability information, including related to companies’ efforts to reduce GHG emissions, impacts on the environment and risks associated with climate change, as well as regulations concerning environmental claims (such as the UK Green Claims Code and EU Empowering Consumers Directive 2024/825), breaches of which may result in significant financial penalties. Such requirements could inform future regulatory or enforcement action or influence demand for our products in a manner that could negatively impact us.
Strategic Risks
The market for low-carbon ammonia may be slow to develop, may not develop to the size expected or may not develop at all. Moreover, we may not be successful in the development and implementation of our low-carbon ammonia projects in a timely or economic manner, or at all, due to a number of factors, many of which are beyond our control.
We have made and expect to continue to make significant investments in our clean energy strategy (including our low-carbon ammonia projects) that may not create any or our expected value of such investments if demand for low-carbon ammonia does not develop and mature to the size and at the rate we expect. Demand for low-carbon ammonia is dependent in part on the developing market for low-carbon hydrogen, for which ammonia can serve as a transport and storage mechanism. These markets are heavily influenced by demand for clean energy, technology evolution and federal, state and local government laws, regulations and policies concerning GHG emissions, renewable electricity, clean energy, and corporate accountability in the United States and abroad. These factors may also affect the market criteria for low-carbon ammonia, including the degree of reduction of direct GHG emissions and the requirements of renewable electricity.
We believe the demand for low-carbon ammonia could take several years to materialize and then ten or more years to fully develop and mature, and we cannot be certain that this demand or the demand for low-carbon hydrogen will grow to the size or at the rate we expect or at all. In 2025, hydrogen was estimated to account for approximately 2% of global energy needs.
The recognition and acceptance of low-carbon ammonia as a transport and storage mechanism for low-carbon hydrogen, the use of low-carbon ammonia as a fuel in its own right, the use of low-carbon ammonia as a fertilizer, and the development and growth of end market demand and applications for low-carbon hydrogen and low-carbon ammonia are uncertain and dependent on a number of factors outside of our control. These factors include the extent to which and rate at which cost competitive renewable energy capacity increases, the pricing of traditional and alternative sources of energy, the realization of technological improvements required to increase the efficiency and lower the costs of production of low-carbon ammonia, the uncertainty of changes in regulatory environments, the rate and extent of infrastructure investment and development which may be affected by the relevant parties’ ability to obtain permits for these investments, the availability of tax benefits and other incentives, the implementation of policy in jurisdictions providing economic support for or otherwise mandating decarbonization and our ability to provide low-carbon ammonia offerings cost-effectively. In addition, further development of alternative decarbonization technologies may result in viable alternatives to the use of low-carbon ammonia for many potential decarbonization applications, resulting in lower-than-expected market demand growth relative to our current expectations. If a sustainable market for low-carbon ammonia or hydrogen fails to develop, develops more slowly than we anticipate, or develops in a way that is not viable to serve with our assets and capabilities, we may decide not to implement, or may not be successful in implementing, one or more elements of our multi-year strategic plan or may have committed to investments involving substantial capital expenditures which might not yield returns required to justify such investments.
Our clean energy strategy also depends on the realization of certain technical improvements required to increase the efficiency and lower the costs of production of low-carbon ammonia. Over time, as we seek to convert additional existing facilities to low-carbon production and further expand our low-carbon ammonia production capacity, we may face operational difficulties and execution risks related to the design, development and construction work to do so. If our assumptions about the engineering and project execution requirements necessary to successfully build or convert the facility capacity that we are contemplating and to scale up to larger production quantities prove to be incorrect, we may be unable to produce substantial quantities of low-carbon ammonia, and the cost to construct such low-carbon ammonia facilities, or the production costs associated with the operation of such facilities, may be higher than we project. The production of low-carbon ammonia depends to a large extent upon the ability of third parties to develop Class VI carbon sequestration wells and CO 2 transportation pipelines, which currently do not exist at large scale and are subject to a permitting process and operational risks, which may result in delays, impact viability in some or all situations, or create long-term liabilities. For example in October 2025, Louisiana’s government established new permitting criteria and policy guidance for the state’s Class VI underground injection control program for carbon sequestration, including emphasizing public engagement, economic development, and local community investment, and imposed an indefinite moratorium on all new applications for Class VI underground injection wells while the state works through pending applications.
Recently, many proposed low-carbon ammonia projects have been announced or considered, and future hydrogen, energy, or environmental/carbon policies may support development of additional nitrogen production outside North America. In the
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event that the growth in supply of low-carbon ammonia and low-carbon hydrogen exceeds the growth in demand for those products, the resulting unfavorable supply and demand balance could lead to lower selling prices than we expect for many of our products, which could negatively affect our business, financial condition, results of operations and cash flows.
Demand for low-carbon ammonia and other nitrogen fertilizers is also incentivized by the availability of environmental attribute credit and incentive programs, including tax credits. There is no assurance that programs providing credits and incentives for production of environmental attributes and markets for them will continue to be available or exist. With respect to the voluntary trade of environmental attributes, there is a risk that purchasers may elect to cease such purchases for various reasons that are inherent to their business plans, or because of changing economic, political contexts or other conditions that cannot be controlled by us, including shifting preferences for types of environmental attributes. The pricing and value of certain environmental attributes is also difficult to determine and may fluctuate. Several factors may affect the price of environmental attributes that are beyond our control, including but not limited to, the underlying markets and legislative and regulatory changes, including the level of commitment to the goals of multinational climate commitments by both governments and corporations and other private and public initiatives aimed at measuring, accounting and reducing GHG emissions, and the Company’s and its partners’ technologies to reduce carbon intensity.
If we fail to successfully enter into or close collaborations, joint ventures, partnerships or acquisitions, or successfully manage such transactions, it could adversely affect our business and growth opportunities.
From time to time, we consider possible expansions of our business, both within the United States and elsewhere. Major investments in our business, including acquisitions, partnerships, joint ventures, business combination transactions or other major investments, such as our low-carbon ammonia projects, require significant managerial resources, the diversion of which from our other activities or opportunities may negatively affect the existing operations of our business. We may be unable to identify or successfully compete for certain acquisition targets, which may hinder or prevent us from acquiring a target or completing other transactions. The risks of any expansion of our business through investments, acquisitions, partnerships, joint ventures or business combination transactions may increase due to the significant capital and other resources that we may have to commit to any such expansion, which may not be recoverable if the expansion initiative to which they were devoted is ultimately not implemented. In addition, these efforts may require capital resources that could otherwise be used for the improvement and expansion of our existing business. As a result of these and other factors, including general economic risk, we may not be able to realize our projected returns or other expected benefits from acquisitions, partnerships, joint ventures, business combination transactions or other major investments. Among the risks associated with the pursuit and consummation of acquisitions, partnerships, joint ventures or other major investments or business combinations are those involving:
•difficulties in integrating the parties’ operations, systems, technologies, products, cultures, and personnel;
•incurrence of significant transaction-related expenses;
•potential integration or restructuring costs;
•potential impairment charges related to the goodwill, intangible assets or other assets to which any such transaction relates, in the event that the economic benefits of such transaction prove to be less than anticipated;
•other unanticipated costs associated with such transactions;
•our ability to achieve operating and financial efficiencies, synergies and cost savings;
•our ability to obtain the desired financial or strategic benefits from any such transaction;
•the parties’ ability to retain key business relationships, including with employees, customers, partners and suppliers;
•potential loss of key personnel;
•entry into markets or involvement with products with which we have limited current or prior experience or in which competitors may have stronger positions;
•assumption of contingent liabilities, including litigation;
•exposure to unanticipated liabilities, including litigation;
•differences in the parties’ internal control environments, which may require significant time and resources to resolve in conformity with applicable legal and accounting standards;
•increased scope, geographic diversity and complexity of our operations;
•the tax effects of any such transaction; and
•the potential for costly and time-consuming litigation, including stockholder lawsuits.
International acquisitions, partnerships, joint ventures, investments or business combinations and other international expansions of our business involve additional risks and uncertainties, including the impact of tariffs on the import of industrial goods and the export of nitrogen products, exchange controls or other restrictions, nationalization of properties by foreign governments and difficulties and costs of complying with a wide variety of complex laws, treaties and regulations.
We have and may enter into joint ventures to invest in our business. For example, in 2025, we entered into a joint venture with two Japanese partners to build a greenfield plant to produce low-carbon ammonia. This joint venture and other similar
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arrangements we may enter into may involve significant risks and uncertainties, including the ability of us and our strategic partners to cooperate, us and our strategic partners having inconsistent interests or goals, ours and our partners ability to realize tax, financial and other programs incentivizing low-carbon production, and the potential that our strategic partners may be unable or unwilling to meet their financial or other obligations to the joint venture, which may negatively impact the expected benefits of the joint venture and cause us to incur additional expense or suffer reputational damage. In addition, due to the nature of these arrangements, we may have limited ability to direct or influence the management of the joint venture, which may limit our ability to assist and oversee the design and implementation of the joint venture’s business as well as its accounting, legal, governance, human resources, information technology, and other administrative systems. This may expose us to additional risks and uncertainties because we may be dependent upon and subject to liability, losses, or reputational damage relating to systems, controls, and personnel that are not under our control. These risks may be exacerbated when the joint venture is operating outside the United States due to geopolitical and political uncertainty and differences in language, culture, and regulation, as well as the factors listed above that are relevant to our international operations.
Moreover, legal proceedings or other risks from acquisitions and other business combinations may arise years after a transaction has been completed and may involve matters unrelated to the business acquired. For example, in 2022, we were named along with other parties in certain product liability actions relating to a product containing the herbicide paraquat, which was allegedly sold, manufactured, distributed and/or marketed by Terra Industries Inc. (Terra) before it exited such lines of business, which exit occurred more than ten years before CF Holdings acquired Terra in April 2010.
Further, our major capital projects depend on the availability and performance of engineering firms, construction firms, equipment and material suppliers, transportation providers and other vendors necessary to design and implement those projects on a timely basis and on acceptable terms. Our major capital projects are subject to a number of risks, any of which could prevent us from completing such projects in a timely or economic manner or at all, including, cost overruns, non-performance of third parties, slowdowns or other delays in contemplated construction timelines, modularization of certain components, the inability to obtain necessary permits or other permitting matters, adverse weather, defects in materials and workmanship, labor and raw material shortages, transportation constraints, changes to international trade-related policy, engineering and construction change orders, errors in design, construction or start-up, and other unforeseen difficulties.
If we finance acquisitions, partnerships, joint ventures, business combination transactions or other major investments by issuing equity or convertible or other debt securities or loans, our existing stockholders may be diluted or we could face constraints under the terms of, and as a result of the repayment and debt-service obligations under, the additional indebtedness. A business combination transaction with another company could result in our stockholders receiving cash or shares of another entity on terms that such stockholders may not consider desirable. Further, regulatory approvals associated with a business combination may result in divestitures or other changes to our business, the effects of which are difficult to predict.
Failure of technologies to perform, develop or be available as expected could adversely affect our ability to produce low-carbon ammonia and our financial results or reputation.
We may implement technologies, which are beyond our experience base, in the ammonia production process at designs and at scales beyond what has been successfully done previously. Adapting these technologies for new applications can create nontraditional performance risks to our operations. For example, we are developing at our Blue Point complex a low-carbon ammonia plant using autothermal reforming (ATR) with CCS. While ATR’s are widely used today for hydrogen and synthesis gas production, they have not been widely used for ammonia production and not at the scale contemplated for the low-carbon ammonia plant we are developing at our Blue Point complex. Even with extensive preparation and diligence when investing in new technologies, new operational challenges may arise in introducing ATR technology and a failure of CCS technology to successfully capture, transport and sequester CO 2 would inhibit our ability to produce, certify and market low-carbon ammonia.
Failure of our and our business partners’ technologies to work as predicted, or unintended consequences of new designs or uses, could lead to cost overruns, project delays, financial penalties, or damage to our reputation. We may face difficulties marketing products produced using new technologies including, but not limited to, low-carbon ammonia, which may adversely impact our sales and financial results. In addition, certain large-scale projects may contain processes or technologies that we have not operated at the same scale or in the same combination, and although such projects generally include technologies and processes that have been demonstrated previously by others, such technologies or processes may be new to us and may introduce new risks to our operations. Additionally, there is a risk that our and our business partners’ new technologies may fail to deliver expected benefits, become obsolete or be replaced by other market alternatives. Performance difficulties on these larger projects may have a material adverse effect on our operations and financial results. In addition, performance challenges may adversely affect our reputation and our ability to obtain future contracts. Further, CCS providers and carbon transporters may experience increased demand for their services which may limit availability and increase costs for these services, which may adversely affect our ability to continue deployment of CCS for our low-carbon ammonia projects.
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FORWARD LOOKING STATEMENTS
From time to time, in this Annual Report on Form 10-K as well as in other written reports and oral statements, we make forward-looking statements that are not statements of historical fact and may involve a number of risks and uncertainties. These statements relate to analyses and other information that are based on forecasts of future results and estimates of amounts not yet determinable. These statements may also relate to our prospects, future developments and business strategies. We use the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “will” or “would” and similar terms and phrases, including references to assumptions, to identify forward-looking statements. These forward-looking statements are made based on currently available competitive, financial and economic data, our current expectations, estimates, forecasts and projections about the industries and markets in which we operate and management’s beliefs and assumptions concerning future events affecting us. These statements are not guarantees of future performance and are subject to risks, uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control. Therefore, our actual results may differ materially from what is expressed in or implied by any forward-looking statements. We caution you not to place undue reliance on any forward-looking statements. We do not undertake any responsibility to release publicly any revisions to these forward-looking statements to take into account events or circumstances that occur after the date of this document. Additionally, we do not undertake any responsibility to provide updates regarding the occurrence of any unanticipated events which may cause actual results to differ from those expressed or implied by the forward-looking statements contained in this document.
Important factors that could cause actual results to differ materially from our expectations are disclosed under “Risk Factors” and elsewhere in this Annual Report on Form 10-K. Such factors include, among others:
•our ability to complete the projects at our Blue Point complex, including the construction of a low-carbon ammonia production facility with our joint venture partners and scalable infrastructure on schedule and on budget or at all;
•our ability to fund the capital expenditure needs related to the joint venture at our Blue Point complex, which may exceed our current estimates;
•the cyclical nature of our business and the impact of global supply and demand on our selling prices and operating results;
•the global commodity nature of our nitrogen products, the conditions in the global market for nitrogen products, and the intense global competition from other producers;
•announced or future tariffs, retaliatory measures, and global trade relations, including the potential impact of tariffs and retaliatory measures on the price and availability of materials for our capital projects and maintenance;
•conditions in the United States, Europe and other agricultural areas, including the influence of governmental policies and technological developments on the demand for our fertilizer products;
•the volatility of natural gas prices in North America and globally;
•weather conditions and the impact of adverse weather events;
•the seasonality of the fertilizer business;
•the impact of changing market conditions on our forward sales programs;
•difficulties in securing the supply and delivery of raw materials or utilities, increases in their costs or delays or interruptions in their delivery;
•reliance on third party providers of transportation services and equipment, including those related to carbon dioxide sequestration;
•our reliance on a limited number of key facilities;
•risks associated with cybersecurity;
•acts of terrorism and regulations to combat terrorism;
•the significant risks and hazards involved in producing and handling our products against which we may not be fully insured;
•risks associated with international operations;
•our ability to manage our indebtedness and any additional indebtedness that may be incurred;
•risks associated with changes in tax laws and adverse determinations by taxing authorities, including any potential changes in tax regulations and our qualification for tax credits;
•risks involving derivatives and the effectiveness of our risk management and hedging activities;
•potential liabilities and expenditures related to environmental, health and safety laws and regulations and permitting requirements;
•regulatory provisions and requirements related to GHG emissions and sustainability matters, including announced or future changes in environmental or climate change or sustainability laws;
•the development and growth of the market for low-carbon ammonia and the risks and uncertainties relating to the development and implementation of our low-carbon ammonia projects;
•risks associated with investments in and expansions of our business, including unanticipated adverse consequences and the significant resources that could be required; and
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•failure of technologies to perform, develop or be available as expected, including the low-carbon ATR ammonia production facility with carbon capture and sequestration technologies being constructed at our Blue Point complex.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 1C. CYBERSECURITY.
Cybersecurity risk management, including our processes for assessing, identifying and managing material risks from cybersecurity threats, is an integral part of our overall enterprise risk management (ERM) program. The ERM program includes an annual assessment process designed to identify risks, including those from cybersecurity threats, that could affect achievement of our business, operations and strategic objectives and to understand, assess, and prioritize those risks. The ERM program also intends to facilitate the implementation of risk management strategies and risk mitigation processes across the Company that are responsive to the Company’s risk profile, overall business strategies, and specific material risk exposures. The ERM program seeks to integrate consideration of risk and risk management into business decision-making throughout the Company, including through the implementation of policies and procedures intended to ensure that necessary information with respect to material risks, including material risks from cybersecurity threats, is appropriately communicated to senior executives and the Board of Directors (Board) or relevant committees. The Board regularly reviews and discusses with members of management responsible for risk management the guidelines and policies governing the ERM process. This includes the key risks identified in the ERM process, the likelihood of occurrence and the potential impact assigned to those risks by management, in addition to the risk mitigation strategies in each instance.
The Audit Committee of the Board oversees management’s cybersecurity risk management efforts. Our chief information officer oversees information technology, cybersecurity risk and efforts to prevent and mitigate such risks. The Audit Committee receives periodic reports summarizing threat detection and mitigation plans, audits of internal controls, summaries of training activities and certification achievements, assessments of cybersecurity program effectiveness and reports on other cybersecurity priorities and initiatives. This is in addition to management’s periodic updates on cybersecurity incidents involving the Company or other industry and global participants. The Audit Committee also receives quarterly updates on the efficacy of our cybersecurity program and risk management from our chief information officer and other members of management that are tasked with monitoring cybersecurity risks. Our chief information officer has over 10 years of experience overseeing cybersecurity teams at both the Company and two other public companies. Our chief information officer is supported by a dedicated team of certified cybersecurity professionals, with an average of over 13 years of relevant experience.
Our cybersecurity strategy prioritizes governance, identification, protection, detection, analysis, response and recovery to known, anticipated, or unexpected cyber threats. The strategy emphasizes effective management of cyber risks and resilience against cyber threats. We maintain a formal cybersecurity program structured around the National Institute of Standards and Technology (NIST) Cybersecurity Framework (CSF), a voluntary framework created by industry and the U.S. government to promote the protection of our infrastructure from cybersecurity risks. We contract with an external auditing firm to assess our cybersecurity controls relative to industry peers using the NIST CSF, which has six functions: govern, identify, protect, detect, respond and recover. We consistently evaluate the threat landscape, utilizing a multifaceted approach to cybersecurity risks that through a zero trust strategy focuses on prevention, detection, and mitigation, which includes the following programs and practices:
•Our cybersecurity team conducts an annual review of cybersecurity risks at the ERM level, integrating significant cybersecurity risks into our overall ERM program. We remain committed to increasing investments in cybersecurity, which includes providing additional training for end-users, utilizing a zero trust methodology, identifying and safeguarding critical assets, and reinforcing monitoring and alerting capabilities. Our proactive approach involves regular testing of defenses through simulations and penetration tests, both technically and through a comprehensive review of operational policies and procedures. At the managerial level, our cybersecurity team consistently monitors alerts and holds regular meetings to discuss threat levels, trends, and remediation strategies. Additionally, we conduct periodic external penetration tests and maturity testing to assess the effectiveness of our security controls, including processes, procedures, and our readiness to face the evolving threat landscape.
•We consider and assess the cybersecurity risks associated with the utilization of third-party service providers, including cybersecurity vendors, consultants, and auditors, under our third-party risk management program. Pursuant to the program, we evaluate security and data privacy controls prior to sharing or authorizing the hosting of sensitive data in computing environments managed by third parties. In addition, our standard terms and conditions with third-party service providers feature contractual provisions mandating specific security protections.
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•Our cybersecurity incident response plan is designed to detect and address potential threats that may impact the confidentiality, integrity, and availability of our technology systems. The response plan includes coordinated processes for handling security and data privacy incidents, encompassing communication and effective response, and as appropriate, escalation to the Audit Committee or the Board.
•Our global business continuity program includes information technology disaster recovery, supporting resilience in both our business and information technology.
To date, we have not identified any risks from cybersecurity threats, including as a result of any previous cybersecurity incidents, that have materially affected or that we believe are reasonably likely to materially affect our business strategy, results of operations, or financial condition. We cannot, however, eliminate all risks from cybersecurity threats or provide assurances that we have not experienced an undetected cybersecurity incident. For more information about these risks, see the disclosure in Item 1A. Risk Factors under “Operational Risks—Failure, inadequacy, breach of, or unauthorized access to, our information technology systems or those of third-party service providers or customers could negatively affect our business and operations.”
ITEM 2. PROPERTIES.
Information regarding our facilities and properties is included in Item 1. Business—Manufacturing Facilities and Item 1. Business—Storage Facilities and Other Properties.
ITEM 3. LEGAL PROCEEDINGS.
We are and may be, from time to time, party to various legal proceedings, government investigations and environmental proceedings. Legal proceedings may include ordinary, routine legal proceedings related to the usual conduct of our business and proceedings regarding public utility and transportation rates, environmental matters, taxes and permits relating to the operations of our various plants and facilities. In addition, from time to time, we receive communications from government or regulatory agencies concerning investigations or allegations of noncompliance with laws or regulations in jurisdictions in which we operate.
For information on pending proceedings relating to environmental remediation matters, see Item 1. Business—Environmental, Health and Safety—CERCLA/Remediation Matters.
ITEM 4. MINE SAFETY DISCLOSURES.
Not applicable.
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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Our common stock is traded on the New York Stock Exchange under the symbol “CF.” As of February 16, 2026, there were 629 stockholders of record.
The following table sets forth share repurchases, on a trade date basis, for each of the three months of the quarter ended December 31, 2025:

| Issuer Purchases of Equity Securities
Period | Total number of shares (or units) purchased |  | Average price paid per share (or unit)(1) |  | Total number of shares (or units) purchased as part of publicly announced plans or programs(2) |  | Maximum number (or approximate dollar value) of shares (or units) that may yet be purchased under the plans or programs (in thousands)(2)
October 1, 2025 - October 31, 2025 | 1,593,521 |  | (3) | $ | 85.36 |  |  | 1,593,478 |  |  | $ | 1,925,480 |
November 1, 2025 - November 30, 2025 | 2,000,161 |  |  | 80.31 |  |  | 2,000,161 |  |  | 1,764,850 |
December 1, 2025 - December 31, 2025 | 541,602 |  |  | 79.41 |  |  | 541,602 |  |  | 1,721,844 |
Total | 4,135,284 |  |  | 82.14 |  |  | 4,135,241 |  |  |

__________________________________________________________________________
(1)Average price paid per share of CF Industries Holdings, Inc. (CF Holdings) common stock repurchased under the 2022 Share Repurchase Program, as defined below, or the 2025 Share Repurchase Program, as defined below, is the execution price, excluding commissions paid to brokers and excise taxes.
(2)On November 2, 2022, we announced that our Board of Directors (the Board) authorized the repurchase of up to $3 billion of CF Holdings common stock, which was effective through December 31, 2025 (the 2022 Share Repurchase Program). On May 6, 2025, we announced that the Board authorized the repurchase of up to $2 billion of CF Holdings common stock commencing upon completion of the 2022 Share Repurchase Program and effective through December 31, 2029 (the 2025 Share Repurchase Program). These share repurchase programs are discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Share Repurchase Programs and in Note 19—Stockholders’ Equity, in the notes to consolidated financial statements included in Item 8. Financial Statements and Supplementary Data.
(3)Includes 43 shares withheld to pay employee tax obligations upon the lapse of restrictions on restricted stock units.
ITEM 6. [RESERVED]
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
You should read the following discussion and analysis in conjunction with the consolidated financial statements and related notes included in Item 8. Financial Statements and Supplementary Data. All references to “CF Holdings,” “we,” “us,” “our” and “the Company” refer to CF Industries Holdings, Inc. and its subsidiaries, except where the context makes clear that the reference is to CF Industries Holdings, Inc. only and not its subsidiaries. All references to “CF Industries” refer to CF Industries, Inc., a 100% owned subsidiary of CF Industries Holdings, Inc. References to tons refer to short tons. Notes referenced in this discussion and analysis refer to the notes to consolidated financial statements that are found in Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements. For a discussion and analysis of the year ended December 31, 2024 compared to the year ended December 31, 2023, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2024 Annual Report on Form 10-K filed with the Securities and Exchange Commission (SEC) on February 20, 2025. The following is an outline of the discussion and analysis included herein:
•Overview of CF Holdings
•Market Conditions and Current Developments
•Financial Executive Summary
•Items Affecting Comparability of Results
•Consolidated Results of Operations
•Operating Results by Business Segment
•Liquidity and Capital Resources
•Critical Accounting Estimates
•Recent Accounting Pronouncements
Overview of CF Holdings
Our Company
Our mission is to provide clean energy to feed and fuel the world sustainably. With our employees focused on safe and reliable operations, environmental stewardship, and disciplined capital and corporate management, we are on a path to decarbonize our ammonia production network – the world’s largest – to enable low-carbon hydrogen and nitrogen products for energy, fertilizer, emissions abatement, and other industrial activities. Our value chain consists of manufacturing complexes in the United States, Canada and the United Kingdom, an extensive storage, transportation and distribution network in North America, and logistics capabilities enabling a global reach. In July 2025, we completed a significant decarbonization project at our Donaldsonville, Louisiana, complex to enable the production of low-carbon ammonia. Additionally, we are executing further decarbonization projects in our existing network and constructing a greenfield low-carbon ammonia plant at our Blue Point complex to drive our strategy to leverage our unique capabilities to accelerate the world’s transition to clean energy.
Our principal customers are cooperatives, retailers, independent fertilizer distributors, traders, wholesalers and industrial users. Our core product is anhydrous ammonia (ammonia), which contains 82% nitrogen and 18% hydrogen. Products derived from ammonia that are most often used as nitrogen fertilizers include granular urea, urea ammonium nitrate solution (UAN) and ammonium nitrate (AN). AN is also used extensively by the commercial explosives industry as a component of explosives. Products derived from ammonia that are sold primarily to industrial customers include diesel exhaust fluid (DEF), urea liquor, nitric acid and aqua ammonia. In addition, our low-carbon products are expected to be used for existing and new applications, such as power generation and steel production in Japan, and to help customers reduce the economic impact of European regulations on the price of carbon.
Our principal assets as of December 31, 2025 include:
•six U.S. manufacturing facilities, located in Donaldsonville, Louisiana (the largest ammonia production complex in the world); Sergeant Bluff, Iowa (our Port Neal complex); Yazoo City, Mississippi; Claremore, Oklahoma (our Verdigris complex); Woodward, Oklahoma; and Waggaman, Louisiana. The Waggaman facility is wholly owned by us, and the other five U.S. manufacturing facilities are wholly owned directly or indirectly by CF Industries Nitrogen, LLC (CFN), of which we own approximately 89% and CHS Inc. (CHS) owns the remainder (see Note 18—Noncontrolling Interests for additional information on our strategic venture with CHS);
•two Canadian manufacturing facilities, located in Medicine Hat, Alberta (the largest ammonia production complex in Canada) and Courtright, Ontario;
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•a United Kingdom manufacturing facility located in Billingham;
•an extensive system of terminals and associated transportation equipment located primarily in the Midwestern United States;
•a 50% interest in Point Lisas Nitrogen Limited (PLNL), an ammonia production joint venture located in Trinidad and Tobago (Trinidad) that we account for under the equity method; and
•a 40% interest in Blue Point Number One, LLC, a joint venture formed on April 8, 2025 (the Blue Point joint venture), to construct a manufacturing plant at our Blue Point complex located in Modeste, Louisiana. The joint venture entity is a variable interest entity (VIE) of which we are the primary beneficiary. As a result, we consolidate this entity in our consolidated financial statements, with the combined 60% equity interest owned by our joint venture partners recorded as noncontrolling interests. See “Our Strategy—Blue Point joint venture,” below, for additional information.
Our Strategy
At our core, CF Industries is a producer of ammonia. We use the Haber-Bosch process to fix atmospheric nitrogen with hydrogen from natural gas to produce anhydrous ammonia, whose chemical composition is NH 3. We sell the ammonia itself or upgrade it to products such as granular urea, UAN and DEF. A majority of the ammonia and ammonia-derived products we manufacture are used as fertilizer, as the nitrogen content provides energy essential for crop growth. Other important uses of our products include emissions control.
Our strategy is to leverage our unique capabilities to accelerate the world’s transition to clean energy. Our unique capabilities include: advantaged production, unmatched distribution and logistics network, operational excellence and disciplined capital stewardship.
Our leadership in ammonia production enables us to drive continued operational excellence in our underlying business while investing in decarbonization technologies to produce ammonia with a lower carbon intensity than that of ammonia produced through traditional processes (“low-carbon ammonia”). These investments allow us to pursue demand for low-carbon ammonia and upgraded products for both traditional and new applications. Traditional applications include agriculture, where low-carbon nitrogen products can be used to reduce the carbon footprint of food production and the life cycle carbon intensity of ethanol production. New growth opportunities include power generation and marine shipping, which are hard-to-abate industries for which low-carbon ammonia offers a potential path to significantly lower carbon footprints as it does not contain or emit carbon when combusted.
Decarbonizing our existing network
At our Donaldsonville and Yazoo City complexes, our decarbonization projects are leveraging carbon capture and sequestration (CCS) to enable us to convert a portion of our existing ammonia production to low-carbon ammonia production. CCS requires the construction of carbon dioxide (CO 2) dehydration and compression units to enable process CO 2 captured from the ammonia production process to be transported and sequestered, which prevents approximately 60% of the CO 2 generated by ammonia production from being emitted to the atmosphere. For each facility we have contracted with ExxonMobil to transport and permanently store the captured CO 2.
In July 2025, construction, commissioning and start-up of the dehydration and compression unit at our Donaldsonville complex was completed for a total cost of approximately $200 million. The dehydration and compression unit enables the transportation and permanent geological sequestration of up to 2 million metric tons of CO 2 annually, depending on gross ammonia production and consumption of CO 2 for upgraded products. This sequestered CO 2 would otherwise be emitted into the atmosphere. ExxonMobil, our CCS partner for this project, is transporting and permanently storing the CO 2. The project qualifies for tax credits under Section 45Q of the Internal Revenue Code (45Q Tax Credits), which provide a tax credit per metric ton of CO 2 captured and disposed of in secure geological storage. As a result of the Donaldsonville CCS project, we have the capacity to produce up to approximately 1.9 million tons of low-carbon ammonia annually at our Donaldsonville complex.
On an interim basis, ExxonMobil is storing CO 2 from our Donaldsonville complex in permanent geologic sites through enhanced oil recovery. Upon receiving its Class VI permit, ExxonMobil plans to transition to dedicated permanent storage, starting with its Rose CCS project (Rose). Rose is one of many dedicated permanent storage sites ExxonMobil is developing along the Gulf Coast to expand its integrated CCS network. The U.S. Environmental Protection Agency issued the final Class VI permits for Rose in October 2025. Beginning of storage activities at Rose also requires authorization from the Railroad Commission of Texas.
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Construction of the dehydration and compression unit at our Yazoo City complex is expected to cost approximately $100 million. At Yazoo City, CCS is expected to commence in 2028, following construction, commissioning and start-up, and annually is expected to enable the transportation and sequestration of up to approximately 500,000 metric tons of CO 2 that would otherwise have been emitted into the atmosphere. The Yazoo City CCS project is expected to qualify for 45Q Tax Credits, which provide a tax credit per metric ton of CO 2 captured and disposed of in secure geological storage.
In the fourth quarter of 2025, we completed a nitric acid plant abatement project at our Verdigris complex. The abatement project is expected to significantly reduce nitrous oxide emissions from the plant, lowering CO 2 equivalent emissions by over 600,000 metric tons on an annual basis.
Blue Point joint venture
On April 8, 2025, we formed the Blue Point joint venture, with JERA Co., Inc. (JERA), Japan’s largest energy company, and Mitsui & Co., Ltd. (Mitsui), a leading global investment and trading company, to construct a low-carbon ammonia production facility at our Blue Point complex located in Modeste, Louisiana. We hold 40% ownership, JERA holds 35% ownership, and Mitsui holds 25% ownership in the Blue Point joint venture. Under the terms of the Blue Point joint venture’s limited liability company agreement, JERA had a conditional option that, if the specified condition were met, JERA could reduce its ownership percentage below 35% but not lower than 20%. We would have had the right and obligation to increase our ownership by the same amount had JERA opted to reduce its ownership. The option expired and is no longer exercisable.
The Blue Point joint venture is expected to construct an autothermal reforming (ATR) ammonia production facility with a CO 2 dehydration and compression unit to prepare captured CO 2 for transportation and sequestration. Engineering, equipment procurement and pre-construction activities at our Blue Point complex began in the second quarter of 2025. Construction of the ammonia production facility is expected to begin in 2026, with low-carbon ammonia production expected to begin in 2029. We are responsible for overseeing and managing the development, construction, operation and maintenance of the ammonia production facility under contracts with the Blue Point joint venture. We, JERA and Mitsui are required to purchase low-carbon ammonia produced by the Blue Point joint venture in accordance with our respective ownership percentages once production commences.
We estimate that the cost of the low-carbon ATR ammonia production facility with CCS technologies will be approximately $3.7 billion. We anticipate that approximately one-third of the estimated cost is related to materials that will be imported to the United States, with the majority of imported materials expected to arrive in Louisiana in 2028. Pursuant to periodic capital calls, the Blue Point joint venture members will fund the cost of the facility’s engineering, procurement and construction according to their respective ownership percentages. During the year ended December 31, 2025, we, JERA and Mitsui made capital contributions of $195 million, $170 million and $121 million, respectively, to the Blue Point joint venture. We funded $152 million of our contributions with cash and $43 million through a non-cash contribution of a license to use certain intellectual property.
The low-carbon ammonia production facility is designed with an annual nameplate capacity of approximately 1.4 million metric tons (approximately 1.5 million tons) and is expected to capture greater than 95% of the CO 2 generated from its production of ammonia. The facility is expected to capture, compress and dehydrate approximately 2.3 million metric tons of CO 2 annually. Pursuant to a long-term offtake agreement, a joint venture between a subsidiary of Occidental Petroleum Corporation and Enbridge Inc. would then transport the CO 2 and permanently sequester it in a Class VI well at its Pelican Sequestration Hub in Louisiana, which is currently under development. The ammonia production facility is expected to qualify for 45Q Tax Credits, which provide a tax credit per metric ton of CO 2 captured and disposed of in secure geological storage.
In June 2025, the Blue Point joint venture executed agreements, including a long-term supply agreement, with a subsidiary of Linde plc for them to design, construct, own, operate and maintain an air separation unit (ASU) at our Blue Point complex to supply oxygen and nitrogen to the low-carbon ATR ammonia production facility. Thus, our estimate of the cost of the low-carbon ATR ammonia production facility of approximately $3.7 billion, as noted above, excludes the costs to construct an ASU.
In addition, we plan to invest approximately $550 million to build scalable infrastructure at our Blue Point complex to supply the ammonia production facility with services, including product storage and vessel loading. We will own and operate this infrastructure, and the Blue Point joint venture will compensate us for these services.
We determined that the Blue Point joint venture is a VIE of which we are the primary beneficiary. As a result, we consolidate this VIE in our consolidated financial statements, with the combined 60% equity interest owned by JERA and Mitsui recorded as noncontrolling interests. See “Liquidity and Capital Resources—Blue Point Joint Venture,” below, and Note 14—Variable Interest Entity, for additional information on the Blue Point joint venture.
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Low-carbon ammonia demand
We believe that our decarbonization projects provide us with benefits: progress toward our long-term emissions reduction goals, a significant return profile, and a differentiated product offering to existing and new customers.
In 2025, we completed our first sales of low-carbon ammonia at a premium to traditional ammonia consumers in Europe and Africa as they began to establish a low-carbon ammonia supply chain. We expect continued demand growth for low-carbon ammonia and upgraded products into Europe as customers seek to reduce the additional costs imposed by the European Union’s regulations, including the carbon border adjustment mechanism in respect of GHG emissions associated with the production of imported ammonia and upgraded products.
In 2025, our expectation that there is developing demand for low-carbon ammonia for new applications of our products was confirmed through our joint venture partners, JERA and Mitsui. They have committed low-carbon ammonia volumes from the Blue Point joint venture for power generation and steel production, among other uses, which represent new applications for our products. In December 2025, both JERA and Mitsui were certified as a Supplier of Low-Carbon Hydrogen and its Derivatives by Japan’s Ministry of Economy, Trade and Industry. The certifications were granted under the “Support Focusing on the Price Gap” scheme established in accordance with the Hydrogen Society Promotion Act.
We continue to engage in discussions with existing and potential customers who have interest in using low-carbon ammonia for traditional applications as well as for the supply of low-carbon ammonia for new applications. We are evaluating and are in various stages of discussions with other companies for long-term offtake and/or potential joint investments related to new and traditional applications for low-carbon ammonia. These discussions continue to advance as we gain greater clarity regarding demand for low-carbon ammonia, including associated carbon intensity requirements, government incentives and regulatory developments.
Industry Factors
We operate in a highly competitive, global industry. Our operating results are influenced by a broad range of factors, including those outlined below.
Global Supply and Demand Factors
Our products are global commodities or derived from global commodities and are subject to price competition. The customers for our products make their purchasing decisions principally on the basis of delivered price and, to a lesser extent, on low-carbon attributes, reliability, customer service and product quality. The selling prices of our products fluctuate in response to global market conditions, changes in supply and demand and cost factors.
Historically, global fertilizer demand has been driven primarily by population growth, gross domestic product growth, changes in dietary habits, planted acreage, and application rates, among other things. We expect these key variables to continue to have major impacts on long-term fertilizer demand for the foreseeable future. Short-term fertilizer demand growth may depend on global economic conditions, farm sector income, weather patterns, the level of global grain stocks relative to consumption, fertilizer application rates, and governmental regulations, including fertilizer subsidies or requirements mandating increased use of bio-fuels or industrial nitrogen products, such as DEF. Geopolitical factors such as temporary disruptions in fertilizer trade related to government intervention, shipping delays and/or cost increases resulting from regional conflicts or changes in the buying/selling patterns of key exporting/consuming countries, including China, India, Russia and Brazil, among others, often play a major role in shaping near-term market fundamentals. The economics of nitrogen-based fertilizer manufacturing play a key role in decisions to increase or reduce production capacity. Supply of fertilizers is generally driven by available capacity and operating rates, raw material costs and availability, government policies and global trade. Raw materials are dependent on energy sources such as natural gas or coal; therefore, supply costs are affected by the supply of and demand for those commodities.
Global Trade in Fertilizer
Profitability of our products within a particular geographic region is determined not only by the relationship between global supply and demand, but also by the supply/demand balance within that region. Regional supply and demand can be influenced significantly by factors affecting trade within regions. Some of these factors include the relative cost to produce and deliver product, relative currency values, the availability of credit, agricultural supply and demand, industrial product demand and policies such as emissions abatement, government support for manufacturers or purchasers and governmental nitrogen product trade policies, including the imposition of duties, tariffs or quotas, that affect foreign trade or investment. Government energy or carbon policies may also affect regional nitrogen supply and demand. The development of additional natural gas reserves in North America has decreased natural gas costs in North America relative to the rest of the world, making North
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American nitrogen fertilizer producers more competitive. Changes in currency values may also alter our cost competitiveness relative to producers in other regions of the world.
North American nitrogen fertilizer demand for certain products is dependent on imports to balance supply and demand, and imports traditionally account for a significant portion of nitrogen fertilizer products consumed in North America. Producers of nitrogen-based fertilizers located in the Middle East, Trinidad, Africa and Russia have been major exporters to North America in recent years.
Farmers’ Economics
The demand for fertilizer is affected by the aggregate crop planting decisions and fertilizer application rate decisions of individual farmers. Individual farmers make planting decisions based largely on prospective profitability of a harvest, while the specific varieties and amounts of fertilizer they apply depend on factors like their current liquidity, soil conditions, weather patterns, crop and fertilizer prices, fertilizer products used and timing of applications, expected yields and the types of crops planted.
Market Conditions and Current Developments
Government Policies
Since January 20, 2025, the Trump administration has imposed, modified and proposed additional tariffs on a range of products from most countries around the world, including global tariffs and tariffs on imports from Canada pursuant to the International Emergency Economic Powers Act (IEEPA). The Trump administration has negotiated and is negotiating tariff and trade agreements that have resulted in, and will continue to result in, changes to existing tariffs and other trade policies in the United States and globally. From March 6, 2025, the United States excluded from IEEPA-based tariffs any products that entered the United States duty-free as a good of Canada pursuant to the United States-Mexico-Canada Agreement, such that U.S. tariffs on Canadian imports were not applicable to our Canadian production. Effective November 13, 2025, the Trump administration exempted most fertilizer products, including urea, UAN and AN, but not ammonia, from IEEPA global tariffs announced on April 5, 2025.
On February 20, 2026, the U.S. Supreme Court ruled that IEEPA does not authorize the president to impose tariffs, including IEEPA-based global tariffs and tariffs on imports from Canada. Invoking other legal authority, the president responded by imposing a 10% tariff on most products imported into the United States on or after February 24, 2026, which may run for up to 150 days absent further congressional extension. The proclamation imposing the 10% tariff continues the IEEPA tariff exemptions that were applicable to our Canadian production and to most fertilizer products, which are both described above. The Supreme Court decision did not modify non-IEEPA tariffs, including tariffs on imports of certain steel and aluminum products and their derivatives which may impact the cost of our capital equipment, including for development and construction at our Blue Point complex.
Trade agreements that were recently negotiated between the United States and the European Union (EU) and several other countries, may be continued or paused, or further negotiations regarding trade agreements may result in changes to the magnitude, timing or other aspects of tariffs between these countries. For example, the EU is seeking clarity from the Trump administration on tariffs to be imposed in response to the U.S. Supreme Court decision before fully implementing the United States-European Union Framework on an Agreement on Reciprocal, Fair, and Balanced Trade, in which the EU committed to eliminate its tariffs on U.S. imports of nitrogen fertilizer products.
There remains significant uncertainty regarding recent tariff developments. Proposed or enacted tariffs and changes to U.S. trading policies may be reinstituted, paused, removed or changed at any time and may also be subject to litigation. Retaliatory tariffs or other imposition of taxes and duties on U.S. exports to trading partners may also be significant and occur at any time. Changes in U.S. trade policy or changes in other countries’ trade policies has and may continue to lead to uncertainty in the global marketplace, impact the supply and demand balance in many regions, and increase the cost of capital equipment and other supplies, which could adversely affect our business, financial condition, results of operations and cash flows.
President Trump signed an Executive Order (EO) on December 6, 2025, on competitive activity in the food supply chain. The EO directs the Attorney General and the Federal Trade Commission to each establish a Food Supply Chain Security Task Force to investigate price-fixing and anti-competitive practices across the sector, including fertilizer, and take action as necessary, including bringing enforcement actions and proposing new regulatory approaches. The EO is particularly focused on “foreign entities” and “foreign control” within the food supply chain.
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U.S. Tax Legislation
On July 4, 2025, H.R.1 - One Big Beautiful Bill Act (the Act) was enacted into law. The Act makes permanent certain elements of the Tax Cuts and Jobs Act, including 100% bonus depreciation on qualified property, and modifies several international tax provisions, including the foreign-derived intangible income deduction. The legislation has multiple effective dates, with certain provisions becoming effective in fiscal year 2025 and the majority taking effect in future years. We began reflecting the impact of the Act in the third quarter of 2025, and it did not have a material impact on our income tax expense for the year ended December 31, 2025. In addition, we expect the Act will not have a material impact on our income tax expense in future periods. However, certain provisions of the Act affected the timing of cash tax payments in 2025 and are expected to affect the timing of cash tax payments in future periods.
Nitrogen Selling Prices and Sales Volume
Our nitrogen products are globally traded commodities with selling prices that fluctuate in response to global market conditions, changes in supply and demand, and other cost factors including domestic and local conditions. Intense global competition—reflected in import volumes and prices—strongly influences delivered prices for nitrogen fertilizers. In general, the prevailing global prices for nitrogen products must be at a level to incent the high-cost marginal producer to produce product at a breakeven or above price, or else they would cease production and leave a portion of global demand unsatisfied.
Average selling prices for all of our major products were higher in 2025 than in 2024 due primarily to strong global demand for all nitrogen products and supply disruptions due to geopolitical issues, including unexpected production outages in Egypt, Iran and Russia. Global demand was particularly strong in North America, India and Brazil. The average selling price for our products was $372 per ton in 2025 compared to $313 per ton in 2024. The 19% increase in the average selling price for our products in 2025 compared to 2024 resulted in a year-over-year increase in net sales of approximately $1.06 billion.
Our total sales volume was 1% higher in 2025 than in 2024, due primarily to higher sales volume in our Ammonia and UAN segments, partially offset by lower sales volume in our Granular Urea and AN segments. We shipped 19.1 million tons of product in 2025 compared to 18.9 million tons in 2024. This resulted in an increase in net sales of approximately $84 million for 2025 compared to 2024. The increase was due to higher supply availability as a result of increased production in 2025 compared to 2024, which was adversely impacted by production outages from a winter storm in the first quarter of 2024.
Sales volume for our products in 2025, 2024 and 2023 is shown in the table below.

| 2025 |  | 2024 |  | 2023
| Sales Volume (tons) |  | Net Sales |  | Sales Volume (tons) |  | Net Sales |  | Sales Volume (tons) |  | Net Sales
| (tons in thousands; dollars in millions)
Ammonia | 4,597 |  |  | $ | 2,176 |  |  | 4,085 |  |  | $ | 1,736 |  |  | 3,546 |  |  | $ | 1,679 |
Granular Urea | 4,109 |  |  | 1,781 |  |  | 4,522 |  |  | 1,600 |  |  | 4,570 |  |  | 1,823 |
UAN | 6,947 |  |  | 2,161 |  |  | 6,771 |  |  | 1,678 |  |  | 7,237 |  |  | 2,068 |
AN | 1,327 |  |  | 421 |  |  | 1,464 |  |  | 419 |  |  | 1,571 |  |  | 497 |
Other(1) | 2,077 |  |  | 545 |  |  | 2,101 |  |  | 503 |  |  | 2,206 |  |  | 564 |
Total | 19,057 |  |  | $ | 7,084 |  |  | 18,943 |  |  | $ | 5,936 |  |  | 19,130 |  |  | $ | 6,631 |

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(1)Other segment products primarily include DEF, urea liquor, nitric acid and aqua ammonia.
Natural Gas
Natural gas is the principal raw material used to produce our nitrogen products. Natural gas is both a chemical feedstock and a fuel used to produce nitrogen products. Natural gas is the largest and most volatile component of the manufacturing cost for our nitrogen products, representing approximately 34% and 28%, respectively, of our production costs in 2025 and 2024. All of our ammonia manufacturing plants are located in the United States and Canada. As a result, the price of natural gas in North America directly impacts a substantial portion of our operating expenses.
During 2025, natural gas prices in North America generally traded in a range of $3.00 to $4.00 per MMBtu. Below normal temperatures combined with higher LNG exports led to an increase in prices in the first quarter of 2025. Natural gas storage inventories at the end of the first quarter of 2025 fell behind both 2024 and historical averages. Production increased through the second and third quarter of 2025, lowering prices during the summer period. Demand from power generation was lower throughout the summer as electricity generators utilized greater amounts of renewable and coal generation in lieu of
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natural gas to meet demand. Strong injections during the summer refill period led to above average levels to start the winter period, keeping a ceiling on prices. The cold start to winter and higher LNG exports led to the price increase experienced in the fourth quarter of 2025.
The following table presents the average daily market price of natural gas at the Henry Hub, the most heavily-traded natural gas pricing point in North America, and our cost of natural gas used for production, which includes the impact of realized natural gas derivatives:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023 |  | 2025 v. 2024 |  | 2024 v. 2023
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.
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Financial Executive Summary
We reported net earnings attributable to common stockholders of $1.46 billion in 2025 compared to $1.22 billion in 2024, an increase in net earnings of $237 million, or 19%. The increase in net earnings attributable to common stockholders primarily reflects an increase in gross margin of $668 million partially offset by the following factors: (i) a higher income tax provision due to higher net earnings in 2025, (ii) higher net earnings attributable to noncontrolling interests, (iii) higher net interest expense, and (iv) asset impairment, as described under “Yazoo City Incident” and “Abandonment of Electrolyzer Project,” above.
Gross margin increased by $668 million, or 32%, to $2.72 billion for the year ended December 31, 2025 compared to $2.06 billion for the year ended December 31, 2024. The increase in gross margin was due primarily to a 19% increase in average selling prices to $372 per ton in 2025 from $313 per ton in 2024, which increased gross margin by $1.06 billion, partially offset by higher natural gas costs, including the impact of realized derivatives, which decreased gross margin by $316 million.
Diluted net earnings per share attributable to common stockholders increased $2.23 per share, to $8.97 per share in 2025 compared to $6.74 per share in 2024 due to higher net earnings and lower weighted-average common shares outstanding as a result of shares repurchased under our share repurchase programs. Diluted weighted-average common shares outstanding were 162.2 million shares for the year ended December 31, 2025, a decrease of 10% compared to diluted weighted-average common shares outstanding of 180.7 million shares for the year ended December 31, 2024.
Items Affecting Comparability of Results
During the years ended December 31, 2025 and 2024, we reported net earnings attributable to common stockholders of $1.46 billion and $1.22 billion, respectively. In addition to the impact of market conditions and current developments, including 45Q Tax Credits, discussed above, certain items affected the comparability of our financial results during the years ended December 31, 2025 and 2024. The following table and related discussion outline these items and their impact on the comparability of our financial results for these periods. The descriptions of items below that refer to amounts in the table refer to the pre-tax amounts unless otherwise noted.

| 2025 |  | 2024 |  |  |  |  |
| Pre-Tax | After-Tax(1) |  | Pre-Tax | After-Tax(1) |  |  |  |  |  |
| (in millions) |  |  |
Unrealized net mark-to-market loss (gain) on natural gas derivatives(2) | $ | 5 |  | $ | 4 |  |  | $ | (35) |  | $ | (27) |  |  |  |  |  |  |
Gain on foreign currency transactions(3)(4) | (5) |  | (5) |  |  | — |  | — |  |  |  |  |  |  |
Asset impairment | 76 |  | 58 |  |  | — |  | — |  |  |  |  |  |  |
Loss on sale of Ince facility(5) | 23 |  | 21 |  |  | — |  | — |  |  |  |  |  |  |
Blue Point joint venture construction costs(3)(4) | 10 |  | 9 |  |  | — |  | — |  |  |  |  |  |  |
Loss on debt extinguishment | 6 |  | 4 |  |  | — |  | — |  |  |  |  |  |  |
Pension settlement loss(6) | 1 |  | 1 |  |  | — |  | — |  |  |  |  |  |  |
Impact of employee benefit plan policy change(7) | — |  | — |  |  | (16) |  | (13) |  |  |  |  |  |  |
Integration costs | — |  | — |  |  | 4 |  | 3 |  |  |  |  |  |  |
Canada Revenue Agency Competent Authority Matter: |  |  |  |  |  |  |  |  |  |  |
Interest expense (income)—net(8) | — |  | — |  |  | (39) |  | (38) |  |  |  |  |  |  |

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(1)For 2025, the tax impact is calculated utilizing a marginal effective rate of approximately 23.5%, except for the loss on sale of Ince facility, which reflects the amount of income tax benefit recognized. For 2024, the tax impact is calculated utilizing a marginal effective rate of 23.6%.
(2)Included in cost of sales in our consolidated statements of operations.
(3)Included in other operating—net in our consolidated statements of operations.
(4)Includes results related to the Blue Point joint venture, of which we have a 40% equity interest. The after-tax impact for amounts related to the Blue Point joint venture does not include a tax provision on the 60% attributable to noncontrolling interests.
(5)Included in U.K. operations restructuring in our consolidated statement of operations.
(6)Included in other non-operating—net in our consolidated statement of operations.
(7)Included in cost of sales and selling, general and administrative expenses in our consolidated statement of operations.
(8)Included in interest expense and interest income in our consolidated statement of operations.
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Unrealized net mark-to-market loss (gain) on natural gas derivatives
Natural gas is the largest and most volatile single component of the manufacturing cost for our nitrogen-based products. At certain times, we have managed the risk of changes in natural gas prices through the use of derivative financial instruments. The derivatives that we use for this purpose are primarily natural gas fixed price swaps, basis swaps and options. We use natural gas derivatives as an economic hedge of natural gas price risk, but without the application of hedge accounting. This can result in volatility in reported earnings due to the unrealized mark-to-market adjustments that occur from changes in the value of the derivatives, which are reflected in cost of sales in our consolidated statements of operations. In 2025, we recognized an unrealized net mark-to-market loss of $5 million compared to a gain of $35 million in 2024.
Gain on foreign currency transactions
In 2025, we recognized a gain on foreign currency transactions of $5 million. (Gain) loss on foreign currency transactions consists of foreign currency exchange rate impacts on foreign currency denominated transactions, including cash held in a foreign currency.
Asset impairment
In 2025, we recognized total charges of $76 million, consisting of asset impairment related to property, plant and equipment at our Donaldsonville and Yazoo City facilities. See “Market Conditions and Current Developments—Yazoo City Incident” and “Market Conditions and Current Developments—Abandonment of Electrolyzer Project,” above, for additional information.
Loss on sale of Ince facility
In the second quarter of 2022, we approved and announced our proposed plan to restructure our U.K. operations, including the planned permanent closure of the Ince facility, which had been idled since September 2021. In the third quarter of 2022, the final restructuring plan was approved, and the facility was subsequently decommissioned. In the first quarter of 2025, we sold our Ince facility and recognized a loss of $23 million, which is reflected in U.K. operations restructuring in our consolidated statement of operations in 2025. See Note 6—Property, Plant and Equipment—Net for additional information on the sale of our Ince facility.
Blue Point joint venture construction costs
In 2025, the Blue Point joint venture incurred development costs that were not eligible for capitalization of approximately $10 million related to the construction of the low-carbon ammonia production facility at our Blue Point complex. See “Overview of CF Holdings—Our Strategy—Blue Point joint venture,” above, and Note 14—Variable Interest Entity, for additional information on the Blue Point joint venture.
Loss on debt extinguishment
On November 26, 2025, we issued $1 billion aggregate principal amount of 5.300% senior notes due 2035 (the 2035 Notes). The net proceeds, after deducting discounts and offering expenses, from the issuance and sale of the 2035 Notes were approximately $989 million.
On December 26, 2025, we used approximately $756 million of the net proceeds from the issuance of the 2035 Notes for the prepayment in full of the outstanding $750 million aggregate principal amount of the 4.500% senior secured notes due 2026 (the 2026 Notes). As a result, we recognized a loss on debt extinguishment of $6 million, consisting primarily of the premium paid on the redemption of the $750 million principal amount of the 2026 Notes prior to their scheduled maturity.
See “Liquidity and Capital Resources—Debt—Senior Notes,” below, for additional information.
Pension settlement loss
In the fourth quarter of 2025, we entered into an agreement with an insurance company to purchase group annuity contracts for both of our Canadian pension plans, including a buy-out annuity contract to transfer to the insurance company approximately $40 million of projected benefit obligation for one of the plans. The transactions closed on December 5, 2025 and were funded with proceeds from the sale of pension plan trust assets. As a result of the buy-out annuity contract purchased, in the fourth quarter of 2025, we recognized a non-cash pre-tax pension settlement loss of $1 million related to the settled obligations. See Note 11—Pension and Other Postretirement Benefits for additional information.
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Impact of employee benefit plan policy change
In 2024, we recognized income of $16 million pertaining to a policy change to an employee benefit plan that was included in both cost of sales and selling, general and administrative expenses in our consolidated statement of operations.
Integration costs
In 2024, we incurred integration costs of $4 million related to our acquisition of an ammonia production facility located in Waggaman, Louisiana on December 1, 2023. We did not incur integration costs in 2025.
Canada Revenue Agency Competent Authority Matter
In the third quarter of 2024, we were informed that the Canada Revenue Agency (CRA) granted one of our Canadian subsidiaries discretionary interest relief for certain tax years from 2006 through 2011, which were previously settled through arbitration proceedings between the United States and Canadian competent authorities. In the fourth quarter of 2024, we received the interest relief from the CRA consisting of interest refunds of $21 million and related interest of $2 million, and we were informed that the Alberta Tax and Revenue Administration (Alberta TRA) granted us discretionary interest relief in parallel with the CRA relief. The interest relief from the Alberta TRA was estimated to be approximately $16 million, consisting of interest refunds of $15 million and related interest of $1 million, based on estimates and foreign currency exchange rates as of December 31, 2024. As a result, in our consolidated statement of operations for the year ended December 31, 2024, we recognized $39 million of income consisting of a $36 million reduction in interest expense and $3 million of interest income.
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Consolidated Results of Operations
The following table presents our consolidated results of operations and certain supplemental data for the years ended December 31, 2025, 2024 and 2023:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023 |  | 2025 v. 2024 |  | 2024 v. 2023
| (in millions, except as noted)
Net sales | $ | 7,084 |  |  | $ | 5,936 |  |  | $ | 6,631 |  |  | $ | 1,148 |  |  | 19 | % |  | $ | (695) |  |  | (10) | %
Cost of sales (COS) | 4,360 |  |  | 3,880 |  |  | 4,086 |  |  | 480 |  |  | 12 | % |  | (206) |  |  | (5) | %
Gross margin | 2,724 |  |  | 2,056 |  |  | 2,545 |  |  | 668 |  |  | 32 | % |  | (489) |  |  | (19) | %
Gross margin percentage | 38.5 | % |  | 34.6 | % |  | 38.4 | % |  | 3.9 | % |  |  |  | (3.8) | % |  |
Selling, general and administrative expenses | 364 |  |  | 320 |  |  | 289 |  |  | 44 |  |  | 14 | % |  | 31 |  |  | 11 | %
Asset impairment | 76 |  |  | — |  |  | — |  |  | 76 |  |  | N/M |  | — |  |  | — | %
U.K. 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 | 14 |  |  | 4 |  |  | (8) |  |  | 10 |  |  | 250 | % |  | 12 |  |  | N/M
Operating earnings | 2,300 |  |  | 1,746 |  |  | 2,230 |  |  | 554 |  |  | 32 | % |  | (484) |  |  | (22) | %
Interest expense | 155 |  |  | 121 |  |  | 150 |  |  | 34 |  |  | 28 | % |  | (29) |  |  | (19) | %
Interest income | (81) |  |  | (123) |  |  | (158) |  |  | 42 |  |  | 34 | % |  | 35 |  |  | 22 | %
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) | %
Income tax provision | 441 |  |  | 285 |  |  | 410 |  |  | 156 |  |  | 55 | % |  | (125) |  |  | (30) | %
Net earnings | 1,798 |  |  | 1,477 |  |  | 1,838 |  |  | 321 |  |  | 22 | % |  | (361) |  |  | (20) | %
Less: 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) | %
Diluted net earnings per share attributable to common stockholders | $ | 8.97 |  |  | $ | 6.74 |  |  | $ | 7.87 |  |  | $ | 2.23 |  |  | 33 | % |  | $ | (1.13) |  |  | (14) | %
Diluted weighted-average common shares outstanding | 162.2 |  |  | 180.7 |  |  | 193.8 |  |  | (18.5) |  |  | (10) | % |  | (13.1) |  |  | (7) | %
Dividends declared per common share | $ | 2.00 |  |  | $ | 2.00 |  |  | $ | 1.60 |  |  | $ | — |  |  | — | % |  | $ | 0.40 |  |  | 25 | %
Natural gas supplemental data (per MMBtu) |  |  |  |  |  |  |  |  |  |  |  |  |
Natural gas costs in COS(1) | $ | 3.30 |  |  | $ | 2.28 |  |  | $ | 3.26 |  |  | $ | 1.02 |  |  | 45 | % |  | $ | (0.98) |  |  | (30) | %
Realized derivatives loss in COS(2) | 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 loss (gain) on natural gas derivatives | $ | 5 |  |  | $ | (35) |  |  | $ | (39) |  |  | $ | 40 |  |  | N/M |  | $ | 4 |  |  | 10 | %
Depreciation and amortization | $ | 898 |  |  | $ | 925 |  |  | $ | 869 |  |  | $ | (27) |  |  | (3) | % |  | $ | 56 |  |  | 6 | %
Capital expenditures | $ | 950 |  |  | $ | 518 |  |  | $ | 499 |  |  | $ | 432 |  |  | 83 | % |  | $ | 19 |  |  | 4 | %
Sales volume by product tons (000s) | 19,057 |  |  | 18,943 |  |  | 19,130 |  |  | 114 |  |  | 1 | % |  | (187) |  |  | (1) | %
Production volume by product tons (000s): |  |  |  |  |  |  |  |  |  |  |  |  |
Ammonia(3) | 10,120 |  |  | 9,800 |  |  | 9,496 |  |  | 320 |  |  | 3 | % |  | 304 |  |  | 3 | %
Granular urea | 4,262 |  |  | 4,404 |  |  | 4,544 |  |  | (142) |  |  | (3) | % |  | (140) |  |  | (3) | %
UAN (32%)(4) | 6,934 |  |  | 6,753 |  |  | 6,852 |  |  | 181 |  |  | 3 | % |  | (99) |  |  | (1) | %
AN | 1,253 |  |  | 1,392 |  |  | 1,520 |  |  | (139) |  |  | (10) | % |  | (128) |  |  | (8) | %

______________________________________________________________________________
N/M—Not Meaningful
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(1)Includes the cost of natural gas used for production and related transportation that is included in cost of sales during the period under the first-in, first-out inventory cost method.
(2)Includes realized gains and losses on natural gas derivatives settled during the period. Excludes unrealized mark-to-market gains and losses on natural gas derivatives.
(3)Gross ammonia production, including amounts subsequently upgraded on-site into granular urea, UAN, or AN.
(4)UAN product tons assume a 32% nitrogen content basis for production volume.
The following is a discussion and analysis of our consolidated results of operations for the year ended December 31, 2025, compared to the year ended December 31, 2024. For a discussion and analysis of our consolidated results of operations for the year ended December 31, 2024 compared to the year ended December 31, 2023, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2024 Annual Report on Form 10-K filed with the SEC on February 20, 2025.
Net Sales
Our net sales are derived primarily from the sale of nitrogen products and are determined by the quantities of nitrogen products we sell and the selling prices we realize. The volumes, mix and selling prices we realize are determined to a great extent by a combination of global and regional supply and demand factors. Net sales also include shipping and handling costs that are billed to our customers. Sales incentives are reported as a reduction in net sales.
Our total net sales increased $1.15 billion, or 19%, to $7.08 billion in 2025 compared to $5.94 billion in 2024 due primarily to higher average selling prices and, to a lesser extent, higher sales volume.
Our average selling price was $372 per ton in 2025 compared to $313 per ton in 2024, an increase of 19%. Average selling prices for all of our major products were higher in 2025 than 2024 due primarily to strong demand for all nitrogen products and supply disruptions due to geopolitical issues, including unexpected production outages in Egypt, Iran and Russia. Global demand was particularly strong in North America, India and Brazil. The impact of higher average selling prices resulted in an increase in net sales of approximately $1.06 billion for 2025 compared to 2024.
Our total sales volume of 19.1 million product tons in 2025 was 1% higher compared to 18.9 million product tons in 2024, as higher sales volume in our Ammonia and UAN segments was partially offset by lower sales volume in our Granular Urea and AN segments. The impact of higher sales volume was an increase in net sales of approximately $84 million.
Gross ammonia production for 2025 increased to approximately 10.1 million tons compared to 9.8 million tons in 2024, which was adversely impacted by production outages from a winter storm in the first quarter of 2024. We expect gross ammonia production for 2026 will be approximately 9.5 million tons reflecting a decrease from 2025 due in part to the outage at our Yazoo City complex. See “Market Conditions and Current Developments—Yazoo City Incident,” above, for additional information.
Cost of Sales
Our cost of sales includes manufacturing costs, purchased product costs, distribution and storage costs, and freight. Manufacturing costs, the most significant element of cost of sales, consist primarily of raw materials, realized and unrealized gains and losses on natural gas derivatives, maintenance, direct labor, depreciation and other plant overhead expenses. Natural gas is the principal raw material used in our production of nitrogen products. Purchased product costs primarily include the cost to purchase nitrogen fertilizers to augment or replace production at our facilities. Distribution costs consist of the cost of freight required to transport finished products from our manufacturing facilities to our distribution facilities, which are recognized in cost of sales when the product is sold to our customers. Storage costs consist of costs incurred prior to final shipment to customers. Freight consists of shipping and handling costs incurred by us to deliver the product to our customer’s intended destination.
Our total cost of sales increased $480 million, or 12%, to $4.36 billion in 2025 as compared to $3.88 billion in 2024. The increase in our cost of sales primarily reflects higher realized natural gas costs, including the impact of realized derivatives, which increased cost of sales by $316 million. Cost of sales also includes the impact of a $5 million unrealized net mark-to-market loss on natural gas derivatives in 2025 compared to a $35 million gain in 2024, which increased cost of sales by $40 million.
Cost of sales averaged $229 per ton in 2025, a 12% increase from $204 per ton in 2024. Our cost of natural gas, including the impact of realized derivatives, increased 38% to $3.31 per MMBtu in 2025 from $2.40 per MMBtu in 2024. See “Market Conditions and Current Developments—Natural Gas,” above, for additional information about the factors impacting natural gas prices.
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Selling, General and Administrative Expenses
Our selling, general and administrative expenses consist primarily of corporate office expenses such as salaries and other payroll-related costs for our executive, administrative, legal, financial, IT, and sales functions, as well as professional service fees, including those for corporate initiatives, amortization of definite-lived intangible assets, and certain taxes and insurance.
Selling, general and administrative expenses increased $44 million, or 14%, to $364 million in 2025 compared to $320 million in 2024. The increase reflects higher incentive compensation due primarily to strong operating performance and higher costs related to certain corporate initiatives, including our clean energy initiatives.
Asset Impairment
In 2025, we recognized total charges of $76 million, consisting of asset impairment related to property, plant and equipment at our Donaldsonville and Yazoo City facilities. See “Market Conditions and Current Developments—Yazoo City Incident” and “Market Conditions and Current Developments—Abandonment of Electrolyzer Project,” above, for additional information.
U.K. Operations Restructuring
In the second quarter of 2022, we approved and announced our proposed plan to restructure our U.K. operations, including the planned permanent closure of the Ince facility, which had been idled since September 2021. In the third quarter of 2022, the final restructuring plan was approved, and the facility was subsequently decommissioned. In the first quarter of 2025, we sold our Ince facility and recognized a loss of $23 million. See Note 6—Property, Plant and Equipment—Net for additional information on the sale of our Ince facility.
Acquisition and Integration Costs
In 2024, we incurred integration costs of $4 million related to our December 1, 2023 acquisition of an ammonia production facility located in Waggaman, Louisiana. We did not incur integration costs in 2025.
Other Operating—Net
Other operating—net includes administrative costs that do not relate directly to our central operations and can include foreign currency transaction gains and losses, unrealized gains and losses on foreign currency derivatives, litigation expenses, gains and losses on the disposal of fixed assets, costs related to our clean energy initiatives, such as front-end engineering and design (FEED) study costs and development costs for our Blue Point joint venture, and 45Q Tax Credits.
Other operating—net was $25 million of income in 2025 compared to $10 million of income in 2024. Higher income in 2025 was due primarily to approximately $42 million of 45Q Tax Credits earned as a result of CO 2 sequestered in the second half of 2025 and lower FEED study costs for our clean energy initiatives compared to 2024. These factors that increased income were partially offset by lower gains on sales of emission credits compared to 2024. See “Our Strategy,” above, for additional information related to our clean energy initiatives.
Equity in Earnings (Loss) of Operating Affiliate
Equity in earnings (loss) of operating affiliate consists of our 50% ownership interest in PLNL. We include our share of the net earnings from our equity method investment in PLNL as an element of earnings from operations because this investment provides additional production and is integrated with our other supply chain and sales activities.
Equity in earnings of operating affiliate was $14 million in 2025 compared to $4 million in 2024. Equity in earnings of operating affiliate in 2025 reflects an increase in the operating results of PLNL due primarily to higher ammonia selling prices and higher sales volume due to a plant turnaround at the PLNL facility that occurred in the second quarter of 2024 that did not recur in 2025, partially offset by higher natural gas costs.
See “Critical Accounting Estimates—Recoverability of Long-Lived Assets, Goodwill and Investment in Unconsolidated Affiliate,” below, for information on the status of PLNL’s gas supply contract with The National Gas Company of Trinidad and Tobago Limited, which was scheduled to expire on January 1, 2026.
Interest Expense
Interest expense includes interest on our long-term debt, amortization of the related fees required to execute financing agreements, annual fees pursuant to our revolving credit agreement and interest on tax liabilities. Capitalized interest relating to
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the construction of major capital projects reduces interest expense as the interest is capitalized and amortized over the estimated useful lives of the related assets.
Interest expense was $155 million in 2025 compared to $121 million in 2024. The increase of $34 million was due primarily to a $36 million reduction in interest expense recognized in 2024 that did not recur in 2025 related to discretionary interest relief on Canadian tax matters. This is further described above under “Items Affecting Comparability of Results—Canada Revenue Agency Competent Authority Matter.” In addition, higher interest expense in 2025 reflects the higher outstanding principal balance of senior notes outstanding for the one-month period between the issuance of the 2035 Notes in November 2025 and the redemption of the 2026 Notes in December 2025.
Interest Income
Interest income includes amounts earned on our cash, cash equivalents, and investments and any interest earned related to income tax refunds.
Interest income was $81 million in 2025 compared to $123 million in 2024. The decrease of $42 million was due primarily to a decrease in interest income on short-term investments and $3 million in interest income related to discretionary interest relief on Canadian tax matters that was granted in the third quarter of 2024 that did not recur in 2025. This is further described above under “Items Affecting Comparability of Results—Canada Revenue Agency Competent Authority Matter.”
Loss on debt extinguishment
Loss on debt extinguishment of $6 million in 2025 is described above under “Items Affecting Comparability of Results—Loss on debt extinguishment.”
Income Tax Provision
Our income tax provision for 2025 was $441 million on pre-tax income of $2.24 billion, or an effective tax rate of 19.7%, compared to an income tax provision of $285 million on pre-tax income of $1.76 billion, or an effective tax rate of 16.2%, in 2024. The higher effective tax rate in 2025 compared to 2024 was due primarily to increases in unrecognized tax benefits related to U.S. tax positions under the Internal Revenue Service audit in 2025. The increase also reflects discrete tax benefits recognized in 2024 that did not recur in 2025, including decreases in unrecognized tax benefits arising from transfer pricing matters, the release of a valuation allowance in the United Kingdom, and the remeasurement of state deferred taxes related to tax rate changes. These items that resulted in a higher effective tax rate in 2025 were partially offset by favorable state tax adjustments claimed on amended returns in 2025.
Our effective tax rate is impacted by earnings attributable to the noncontrolling interests as our consolidated income tax provision does not include a tax provision on the earnings attributable to the noncontrolling interests. Our effective tax rate for 2025 of 19.7%, which is based on pre-tax income of $2.24 billion, would be 3.5 percentage points higher, or 23.2%, if based on pre-tax income exclusive of the earnings attributable to the noncontrolling interests of $343 million. Our effective tax rate for 2024 of 16.2%, which is based on pre-tax income of $1.76 billion, would be 2.8 percentage points higher, or 19.0%, if based on pre-tax income exclusive of the earnings attributable to the noncontrolling interests of $259 million.
See Note 10—Income Taxes for additional information.
Net Earnings Attributable to Noncontrolling Interests
Net earnings attributable to noncontrolling interests includes the net earnings attributable to the approximately 11% CHS minority equity interest in CFN, a subsidiary of CF Holdings, and the combined 60% equity interest owned by our joint venture partners in Blue Point Number One, LLC, a joint venture formed on April 8, 2025, that is a VIE of which we are the primary beneficiary.
Net earnings attributable to noncontrolling interests increased $84 million, or 32%, to $343 million in 2025 compared to $259 million in 2024 due primarily to higher earnings of CFN driven by higher average selling prices and the impact of higher sales volume, partially offset by higher natural gas costs. In addition, the increase also reflects the earnings attributable to the noncontrolling interests in the Blue Point joint venture, which was formed in the second quarter of 2025. See “Overview of CF Holdings—Our Strategy—Blue Point joint venture,” above, Note 14—Variable Interest Entity and Note 18—Noncontrolling Interests for additional information on the Blue Point joint venture.
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Diluted Net Earnings Per Share Attributable to Common Stockholders
Net earnings per share attributable to common stockholders increased 33% to $8.97 per diluted share in 2025 from $6.74 per diluted share in 2024. This increase was due primarily to higher net earnings driven by an increase in gross margin and lower weighted-average common shares outstanding. Diluted weighted-average common shares outstanding declined 10% from 180.7 million shares for 2024 to 162.2 million shares for 2025, due primarily to repurchases of common shares under our share repurchase programs.
Operating Results by Business Segment
Our reportable segments consist of Ammonia, Granular Urea, UAN, AN and Other. These segments are differentiated by products. Our management uses gross margin to evaluate segment performance and allocate resources. Total other operating costs and expenses (consisting primarily of selling, general and administrative expenses and other operating—net) and non-operating expenses (consisting primarily of interest and income taxes), are centrally managed and are not included in the measurement of segment profitability reviewed by management. See Note 21—Segment Disclosures for additional information.
The following table presents summary operating results by business segment:

| Ammonia |  | Granular Urea(1) |  | UAN(1) |  | AN(1) |  | Other(1) |  | Consolidated
| (in millions)
Year ended December 31, 2025 |  |  |  |  |  |  |  |  |  |  |
Net sales | $ | 2,176 |  |  | $ | 1,781 |  |  | $ | 2,161 |  |  | $ | 421 |  |  | $ | 545 |  |  | $ | 7,084 |
Cost of sales | 1,494 |  |  | 944 |  |  | 1,240 |  |  | 342 |  |  | 340 |  |  | 4,360 |
Gross margin | $ | 682 |  |  | $ | 837 |  |  | $ | 921 |  |  | $ | 79 |  |  | $ | 205 |  |  | $ | 2,724 |
Gross margin percentage | 31.3 | % |  | 47.0 | % |  | 42.6 | % |  | 18.8 | % |  | 37.6 | % |  | 38.5 | %
Year ended December 31, 2024 |  |  |  |  |  |  |  |  |  |  |
Net sales | $ | 1,736 |  |  | $ | 1,600 |  |  | $ | 1,678 |  |  | $ | 419 |  |  | $ | 503 |  |  | $ | 5,936 |
Cost of sales | 1,243 |  |  | 926 |  |  | 1,069 |  |  | 340 |  |  | 302 |  |  | 3,880 |
Gross margin | $ | 493 |  |  | $ | 674 |  |  | $ | 609 |  |  | $ | 79 |  |  | $ | 201 |  |  | $ | 2,056 |
Gross margin percentage | 28.4 | % |  | 42.1 | % |  | 36.3 | % |  | 18.9 | % |  | 40.0 | % |  | 34.6 | %
Year ended December 31, 2023 |  |  |  |  |  |  |  |  |  |  |
Net sales | $ | 1,679 |  |  | $ | 1,823 |  |  | $ | 2,068 |  |  | $ | 497 |  |  | $ | 564 |  |  | $ | 6,631 |
Cost of sales | 1,138 |  |  | 1,010 |  |  | 1,251 |  |  | 359 |  |  | 328 |  |  | 4,086 |
Gross margin | $ | 541 |  |  | $ | 813 |  |  | $ | 817 |  |  | $ | 138 |  |  | $ | 236 |  |  | $ | 2,545 |
Gross margin percentage | 32.2 | % |  | 44.6 | % |  | 39.5 | % |  | 27.8 | % |  | 41.8 | % |  | 38.4 | %

_______________________________________________________________________________
(1)The cost of ammonia and other products that are upgraded in the production of Granular Urea, UAN, AN and Other products is transferred at cost into the results of those products.
The following is a discussion and analysis of our operating results by business segment for the year ended December 31, 2025 compared to the year ended December 31, 2024. For a discussion and analysis of our operating results by business segment for the year ended December 31, 2024 compared to the year ended December 31, 2023, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2024 Annual Report on Form 10-K filed with the SEC on February 20, 2025.
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Ammonia Segment
Our Ammonia segment produces anhydrous ammonia (ammonia), which is the base product that we manufacture, containing 82% nitrogen and 18% hydrogen. The results of our Ammonia segment consist of sales of ammonia to external customers for its nitrogen content as a fertilizer, in emissions control and in other industrial applications. In addition, we upgrade ammonia into other nitrogen products such as granular urea, UAN and AN.
The following table presents summary operating data for our Ammonia segment:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023 |  | 2025 v. 2024 |  | 2024 v. 2023
| (in millions, except as noted)
Net sales | $ | 2,176 |  |  | $ | 1,736 |  |  | $ | 1,679 |  |  | $ | 440 |  |  | 25 | % |  | $ | 57 |  |  | 3 | %
Cost of sales | 1,494 |  |  | 1,243 |  |  | 1,138 |  |  | 251 |  |  | 20 | % |  | 105 |  |  | 9 | %
Gross margin | $ | 682 |  |  | $ | 493 |  |  | $ | 541 |  |  | $ | 189 |  |  | 38 | % |  | $ | (48) |  |  | (9) | %
Gross margin percentage | 31.3 | % |  | 28.4 | % |  | 32.2 | % |  | 2.9 | % |  |  |  | (3.8) | % |  |
Sales volume by product tons (000s) | 4,597 |  |  | 4,085 |  |  | 3,546 |  |  | 512 |  |  | 13 | % |  | 539 |  |  | 15 | %
Sales volume by nutrient tons (000s)(1) | 3,770 |  |  | 3,349 |  |  | 2,908 |  |  | 421 |  |  | 13 | % |  | 441 |  |  | 15 | %
Average selling price per product ton | $ | 473 |  |  | $ | 425 |  |  | $ | 473 |  |  | $ | 48 |  |  | 11 | % |  | $ | (48) |  |  | (10) | %
Average selling price per nutrient ton(1) | $ | 577 |  |  | $ | 518 |  |  | $ | 577 |  |  | $ | 59 |  |  | 11 | % |  | $ | (59) |  |  | (10) | %
Gross margin per product ton | $ | 148 |  |  | $ | 121 |  |  | $ | 153 |  |  | $ | 27 |  |  | 22 | % |  | $ | (32) |  |  | (21) | %
Gross margin per nutrient ton(1) | $ | 181 |  |  | $ | 147 |  |  | $ | 186 |  |  | $ | 34 |  |  | 23 | % |  | $ | (39) |  |  | (21) | %
Depreciation and amortization | $ | 249 |  |  | $ | 239 |  |  | $ | 171 |  |  | $ | 10 |  |  | 4 | % |  | $ | 68 |  |  | 40 | %
Unrealized net mark-to-market loss (gain) on natural gas derivatives | $ | 2 |  |  | $ | (13) |  |  | $ | (11) |  |  | $ | 15 |  |  | N/M |  | $ | (2) |  |  | (18) | %

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N/M—Not Meaningful
(1)Ammonia represents 82% nitrogen content. Nutrient tons represent the tons of nitrogen within the product tons.
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Net Sales. Net sales in our Ammonia segment increased by $440 million, or 25%, to $2.18 billion in 2025 from $1.74 billion in 2024. The increase in our net sales reflects a 13% increase in sales volume, and an 11% increase in average selling prices. Ammonia sales volume in 2025 was 4.6 million tons, an increase of 13% compared to 4.1 million tons in 2024. The increase in sales volume was due primarily to higher supply availability as a result of increased production in the first quarter of 2025 compared to the first quarter of 2024, which was adversely impacted by production outages from a winter storm.
Average selling prices increased to $473 per ton in 2025 compared to $425 per ton in 2024 due primarily to strong global nitrogen demand and supply disruptions due to geopolitical issues, including unexpected production outages in Egypt, Iran and Russia.
Cost of Sales. Cost of sales in our Ammonia segment averaged $325 per ton in 2025, a 7% increase from $304 per ton in 2024. The increase was due primarily to higher realized natural gas costs, including the impact of realized derivatives, partially offset by lower costs for maintenance activity in 2025 compared to 2024, which included higher costs for maintenance, repairs and certain unabsorbed fixed costs as a result of plant downtime, including the impact of the adverse weather in the first quarter of 2024 as discussed above.
Gross Margin. Gross margin in our Ammonia segment increased by $189 million, or 38%, to $682 million in 2025 from $493 million in 2024, and our gross margin percentage was 31.3% in 2025 compared to 28.4% in 2024. The increase in gross margin was due primarily to an 11% increase in average selling prices, which increased gross margin by $246 million, and an increase in sales volume, which increased gross margin by $118 million. These factors that increased gross margin were partially offset by the impact of higher realized natural gas costs, including the impact of realized derivatives, which decreased gross margin by $111 million, and a net increase in manufacturing, maintenance and other costs, which decreased gross margin by $49 million. Gross margin also includes the impact of a $2 million unrealized net mark-to-market loss on natural gas derivatives in 2025 compared to a $13 million gain in 2024.
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Granular Urea Segment
Our Granular Urea segment produces granular urea, which contains 46% nitrogen. Produced from ammonia and carbon dioxide, it has the highest nitrogen content of any of our solid nitrogen fertilizers. Granular urea is produced at our Donaldsonville, Port Neal and Medicine Hat complexes.
The following table presents summary operating data for our Granular Urea segment:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023 |  | 2025 v. 2024 |  | 2024 v. 2023
| (in millions, except as noted)
Net sales | $ | 1,781 |  |  | $ | 1,600 |  |  | $ | 1,823 |  |  | $ | 181 |  |  | 11 | % |  | $ | (223) |  |  | (12) | %
Cost of sales | 944 |  |  | 926 |  |  | 1,010 |  |  | 18 |  |  | 2 | % |  | (84) |  |  | (8) | %
Gross margin | $ | 837 |  |  | $ | 674 |  |  | $ | 813 |  |  | $ | 163 |  |  | 24 | % |  | $ | (139) |  |  | (17) | %
Gross margin percentage | 47.0 | % |  | 42.1 | % |  | 44.6 | % |  | 4.9 | % |  |  |  | (2.5) | % |  |
Sales volume by product tons (000s) | 4,109 |  |  | 4,522 |  |  | 4,570 |  |  | (413) |  |  | (9) | % |  | (48) |  |  | (1) | %
Sales volume by nutrient tons (000s)(1) | 1,890 |  |  | 2,080 |  |  | 2,102 |  |  | (190) |  |  | (9) | % |  | (22) |  |  | (1) | %
Average selling price per product ton | $ | 433 |  |  | $ | 354 |  |  | $ | 399 |  |  | $ | 79 |  |  | 22 | % |  | $ | (45) |  |  | (11) | %
Average selling price per nutrient ton(1) | $ | 942 |  |  | $ | 769 |  |  | $ | 867 |  |  | $ | 173 |  |  | 22 | % |  | $ | (98) |  |  | (11) | %
Gross margin per product ton | $ | 204 |  |  | $ | 149 |  |  | $ | 178 |  |  | $ | 55 |  |  | 37 | % |  | $ | (29) |  |  | (16) | %
Gross margin per nutrient ton(1) | $ | 443 |  |  | $ | 324 |  |  | $ | 387 |  |  | $ | 119 |  |  | 37 | % |  | $ | (63) |  |  | (16) | %
Depreciation and amortization | $ | 253 |  |  | $ | 284 |  |  | $ | 285 |  |  | $ | (31) |  |  | (11) | % |  | $ | (1) |  |  | — | %
Unrealized net mark-to-market loss (gain) on natural gas derivatives | $ | 1 |  |  | $ | (9) |  |  | $ | (11) |  |  | $ | 10 |  |  | N/M |  | $ | 2 |  |  | 18 | %

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N/M—Not Meaningful
(1)Granular urea represents 46% nitrogen content. Nutrient tons represent the tons of nitrogen within the product tons.
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Net Sales. Net sales in our Granular Urea segment increased $181 million, or 11%, to $1.78 billion in 2025 compared to $1.60 billion in 2024 due primarily to a 22% increase in average selling prices, partially offset by a 9% decrease in sales volume. Average selling prices increased to $433 per ton in 2025 compared to $354 per ton in 2024 due primarily to strong global nitrogen demand and supply disruptions due to geopolitical issues, including unexpected production outages in Egypt, Iran and Russia. Sales volume in 2025 was 4.1 million tons, a decrease of 9% compared to 4.5 million tons in 2024 due primarily to decreased supply availability as a result of lower production due to management’s decision to favor UAN production over granular urea and lower beginning inventory entering 2025.
Cost of Sales. Cost of sales in our Granular Urea segment averaged $229 per ton in 2025, a 12% increase from $205 per ton in 2024, due primarily to higher realized natural gas costs, including the impact of realized derivatives.
Gross Margin. Gross margin in our Granular Urea segment increased by $163 million, or 24%, to $837 million in 2025 from $674 million in 2024, and our gross margin percentage was 47.0% in 2025 compared to 42.1% in 2024. The increase in gross margin was due primarily to a 22% increase in average selling prices, which increased gross margin by $315 million. This increase in gross margin was partially offset by higher realized natural gas costs, including the impact of realized derivatives, which decreased gross margin by $79 million, a 9% decrease in sales volume, which decreased gross margin by $60 million, and a net increase in manufacturing, maintenance and other costs, which decreased gross margin by $3 million. Gross margin also includes the impact of a $1 million unrealized net mark-to-market loss on natural gas derivatives in 2025 compared to a $9 million gain in 2024.
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UAN Segment
Our UAN segment produces urea ammonium nitrate solution (UAN). UAN, a liquid fertilizer product with a nitrogen content that typically ranges from 28% to 32%, is produced by combining urea and ammonium nitrate. UAN is produced at our Courtright, Donaldsonville, Port Neal, Verdigris, Woodward, and Yazoo City complexes.
The following table presents summary operating data for our UAN segment:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023 |  | 2025 v. 2024 |  | 2024 v. 2023
| (in millions, except as noted)
Net sales | $ | 2,161 |  |  | $ | 1,678 |  |  | $ | 2,068 |  |  | $ | 483 |  |  | 29 | % |  | $ | (390) |  |  | (19) | %
Cost of sales | 1,240 |  |  | 1,069 |  |  | 1,251 |  |  | 171 |  |  | 16 | % |  | (182) |  |  | (15) | %
Gross margin | $ | 921 |  |  | $ | 609 |  |  | $ | 817 |  |  | $ | 312 |  |  | 51 | % |  | $ | (208) |  |  | (25) | %
Gross margin percentage | 42.6 | % |  | 36.3 | % |  | 39.5 | % |  | 6.3 | % |  |  |  | (3.2) | % |  |
Sales volume by product tons (000s) | 6,947 |  |  | 6,771 |  |  | 7,237 |  |  | 176 |  |  | 3 | % |  | (466) |  |  | (6) | %
Sales volume by nutrient tons (000s)(1) | 2,199 |  |  | 2,142 |  |  | 2,283 |  |  | 57 |  |  | 3 | % |  | (141) |  |  | (6) | %
Average selling price per product ton | $ | 311 |  |  | $ | 248 |  |  | $ | 286 |  |  | $ | 63 |  |  | 25 | % |  | $ | (38) |  |  | (13) | %
Average selling price per nutrient ton(1) | $ | 983 |  |  | $ | 783 |  |  | $ | 906 |  |  | $ | 200 |  |  | 26 | % |  | $ | (123) |  |  | (14) | %
Gross margin per product ton | $ | 133 |  |  | $ | 90 |  |  | $ | 113 |  |  | $ | 43 |  |  | 48 | % |  | $ | (23) |  |  | (20) | %
Gross margin per nutrient ton(1) | $ | 419 |  |  | $ | 284 |  |  | $ | 358 |  |  | $ | 135 |  |  | 48 | % |  | $ | (74) |  |  | (21) | %
Depreciation and amortization | $ | 265 |  |  | $ | 268 |  |  | $ | 288 |  |  | $ | (3) |  |  | (1) | % |  | $ | (20) |  |  | (7) | %
Unrealized net mark-to-market loss (gain) on natural gas derivatives | $ | 2 |  |  | $ | (10) |  |  | $ | (11) |  |  | $ | 12 |  |  | N/M |  | $ | 1 |  |  | 9 | %

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N/M—Not Meaningful
(1)UAN represents between 28% and 32% of nitrogen content, depending on the concentration specified by the customer. Nutrient tons represent the tons of nitrogen within the product tons.
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Net Sales. Net sales in our UAN segment increased $483 million, or 29%, to $2.16 billion in 2025 compared to $1.68 billion in 2024 due primarily to a 25% increase in average selling prices and a 3% increase in sales volume. Average selling prices increased to $311 per ton in 2025 compared to $248 per ton in 2024 due primarily to strong global nitrogen demand and supply disruptions due to geopolitical issues, including unexpected production outages in Egypt, Iran and Russia. The increase in sales volume was due primarily to higher supply availability as a result of higher production in 2025 compared to 2024 and inventory drawdown to meet strong domestic and international demand in the second quarter of 2025.
Cost of Sales. Cost of sales in our UAN segment averaged $178 per ton in 2025, a 13% increase from $158 per ton in 2024, due primarily to higher realized natural gas costs, including the impact of realized derivatives.
Gross Margin. Gross margin in our UAN segment increased by $312 million, or 51%, to $921 million in 2025 from $609 million in 2024, and our gross margin percentage was 42.6% in 2025 compared to 36.3% in 2024. The increase in gross margin was due primarily to a 25% increase in average selling prices, which increased gross margin by $424 million, and a 3% increase in sales volume, which increased gross margin by $33 million. These factors that increased gross margin were partially offset by higher realized natural gas costs, including the impact of realized derivatives, which decreased gross margin by $99 million, and a net increase in manufacturing, maintenance and other costs, which decreased gross margin by $34 million. Gross margin also includes the impact of a $2 million unrealized net mark-to-market loss on natural gas derivatives in 2025 compared to a $10 million gain in 2024.
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AN Segment
Our AN segment produces ammonium nitrate (AN). AN, which has a nitrogen content between 29% and 35%, is produced by combining anhydrous ammonia and nitric acid. AN is used as nitrogen fertilizer and is also used extensively by the commercial explosives industry as a component of explosives. AN is produced at our Yazoo City and Billingham complexes.
The following table presents summary operating data for our AN segment:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023 |  | 2025 v. 2024 |  | 2024 v. 2023
| (in millions, except as noted)
Net sales | $ | 421 |  |  | $ | 419 |  |  | $ | 497 |  |  | $ | 2 |  |  | — | % |  | $ | (78) |  |  | (16) | %
Cost of sales | 342 |  |  | 340 |  |  | 359 |  |  | 2 |  |  | 1 | % |  | (19) |  |  | (5) | %
Gross margin | $ | 79 |  |  | $ | 79 |  |  | $ | 138 |  |  | $ | — |  |  | — | % |  | $ | (59) |  |  | (43) | %
Gross margin percentage | 18.8 | % |  | 18.9 | % |  | 27.8 | % |  | (0.1) | % |  |  |  | (8.9) | % |  |
Sales volume by product tons (000s) | 1,327 |  |  | 1,464 |  |  | 1,571 |  |  | (137) |  |  | (9) | % |  | (107) |  |  | (7) | %
Sales volume by nutrient tons (000s)(1) | 457 |  |  | 501 |  |  | 538 |  |  | (44) |  |  | (9) | % |  | (37) |  |  | (7) | %
Average selling price per product ton | $ | 317 |  |  | $ | 286 |  |  | $ | 316 |  |  | $ | 31 |  |  | 11 | % |  | $ | (30) |  |  | (9) | %
Average selling price per nutrient ton(1) | $ | 921 |  |  | $ | 836 |  |  | $ | 924 |  |  | $ | 85 |  |  | 10 | % |  | $ | (88) |  |  | (10) | %
Gross margin per product ton | $ | 60 |  |  | $ | 54 |  |  | $ | 88 |  |  | $ | 6 |  |  | 11 | % |  | $ | (34) |  |  | (39) | %
Gross margin per nutrient ton(1) | $ | 173 |  |  | $ | 158 |  |  | $ | 257 |  |  | $ | 15 |  |  | 9 | % |  | $ | (99) |  |  | (39) | %
Depreciation and amortization | $ | 33 |  |  | $ | 39 |  |  | $ | 48 |  |  | $ | (6) |  |  | (15) | % |  | $ | (9) |  |  | (19) | %
Unrealized net mark-to-market gain on natural gas derivatives | $ | — |  |  | $ | (1) |  |  | $ | (2) |  |  | $ | 1 |  |  | 100 | % |  | $ | 1 |  |  | 50 | %

_______________________________________________________________________________
(1)AN represents between 29% and 35% of nitrogen content. Nutrient tons represent the tons of nitrogen within the product tons.
Yazoo City Incident
In November 2025, we experienced an incident in the AN upgrade area at our Yazoo City complex. The facility’s ammonia plant and other upgrade units were not damaged by the incident. However, the incident required us to temporarily idle all production at the site. Management is conducting an investigation into the cause of the incident and determining the required equipment and installation timeline to rebuild. Management does not expect production to resume until the fourth quarter of 2026 at the earliest based on time required for fabrication and delivery of certain required equipment. See “Market Conditions and Current Developments—Yazoo City Incident,” above, for additional information. The Yazoo City incident does not impact AN production at our Billingham complex.
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Net Sales. Net sales in our AN segment increased $2 million to $421 million in 2025 from $419 million in 2024 due primarily to an 11% increase in average selling prices, partially offset by a 9% decrease in sales volume. Average selling prices increased to $317 per ton in 2025 compared to $286 per ton in 2024 due primarily to strong global nitrogen demand and supply disruptions due to geopolitical issues, including unexpected production outages in Egypt, Iran and Russia. Sales volume decreased due primarily to lower supply availability due to lower production in 2025 as a result of the incident at our Yazoo City complex described above.
Cost of Sales. Cost of sales in our AN segment averaged $257 per ton in 2025, an 11% increase from $232 per ton in 2024. The increase was due primarily to (i) costs incurred due to the idling of the Yazoo City plant, (ii) a higher proportion of AN sales in the United Kingdom compared to the prior year, which include higher costs per ton due to purchasing ammonia for upgrade to AN compared to the cost of natural gas used to produce ammonia, and (iii) higher realized natural gas costs, including the impact of realized derivatives, for our North American operations.
Gross Margin. Gross margin in our AN segment was $79 million in both 2025 and 2024, and our gross margin percentage was 18.8% in 2025 compared to 18.9% in 2024. An 11% increase in average selling prices increased gross margin by $35 million. This increase in gross margin was offset by a 9% decrease in sales volume, which decreased gross margin by $16 million, higher realized natural gas costs, including the impact of realized derivatives, which decreased gross margin by $11 million, a net increase in manufacturing, maintenance and other costs, which decreased gross margin by $7 million, and the impact of a $1 million unrealized net mark-to-market gain on natural gas derivatives in 2024 that did not recur in 2025.
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Other Segment
Our Other segment primarily includes the following products:
•diesel exhaust fluid (DEF), an aqueous urea solution typically made with 32.5% or 50% high-purity urea and the remainder deionized water;
•urea liquor, a liquid product that we sell in concentrations of 40%, 50% and 70% high-purity urea as a chemical intermediate; and
•nitric acid, a nitrogen-based mineral acid that is used in the production of nitrate-based fertilizers, nylon precursors and other specialty chemicals.
The following table presents summary operating data for our Other segment:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023 |  | 2025 v. 2024 |  | 2024 v. 2023
| (in millions, except as noted)
Net sales | $ | 545 |  |  | $ | 503 |  |  | $ | 564 |  |  | $ | 42 |  |  | 8 | % |  | $ | (61) |  |  | (11) | %
Cost of sales | 340 |  |  | 302 |  |  | 328 |  |  | 38 |  |  | 13 | % |  | (26) |  |  | (8) | %
Gross margin | $ | 205 |  |  | $ | 201 |  |  | $ | 236 |  |  | $ | 4 |  |  | 2 | % |  | $ | (35) |  |  | (15) | %
Gross margin percentage | 37.6 | % |  | 40.0 | % |  | 41.8 | % |  | (2.4) | % |  |  |  | (1.8) | % |  |
Sales volume by product tons (000s) | 2,077 |  |  | 2,101 |  |  | 2,206 |  |  | (24) |  |  | (1) | % |  | (105) |  |  | (5) | %
Sales volume by nutrient tons (000s)(1) | 418 |  |  | 411 |  |  | 434 |  |  | 7 |  |  | 2 | % |  | (23) |  |  | (5) | %
Average selling price per product ton | $ | 262 |  |  | $ | 239 |  |  | $ | 256 |  |  | $ | 23 |  |  | 10 | % |  | $ | (17) |  |  | (7) | %
Average selling price per nutrient ton(1) | $ | 1,304 |  |  | $ | 1,224 |  |  | $ | 1,300 |  |  | $ | 80 |  |  | 7 | % |  | $ | (76) |  |  | (6) | %
Gross margin per product ton | $ | 99 |  |  | $ | 96 |  |  | $ | 107 |  |  | $ | 3 |  |  | 3 | % |  | $ | (11) |  |  | (10) | %
Gross margin per nutrient ton(1) | $ | 490 |  |  | $ | 489 |  |  | $ | 544 |  |  | $ | 1 |  |  | — | % |  | $ | (55) |  |  | (10) | %
Depreciation and amortization | $ | 65 |  |  | $ | 61 |  |  | $ | 64 |  |  | $ | 4 |  |  | 7 | % |  | $ | (3) |  |  | (5) | %
Unrealized net mark-to-market gain on natural gas derivatives | $ | — |  |  | $ | (2) |  |  | $ | (4) |  |  | $ | 2 |  |  | 100 | % |  | $ | 2 |  |  | 50 | %

_______________________________________________________________________________
(1)Nutrient tons represent the tons of nitrogen within the product tons.
Year Ended December 31, 2025 Compared to Year Ended December 31, 2024
Net Sales. Net sales in our Other segment increased $42 million, or 8%, to $545 million in 2025 from $503 million in 2024 due primarily to a 10% increase in average selling prices. Average selling prices increased to $262 per ton in 2025 compared to $239 per ton in 2024 due primarily to strong global nitrogen demand and supply disruptions due to geopolitical issues, including unexpected production outages in Egypt, Iran and Russia.
Cost of Sales. Cost of sales in our Other segment averaged $163 per ton in 2025, a 14% increase from $143 per ton in 2024, due primarily to the impact of higher realized natural gas costs, including the impact of realized derivatives, and costs incurred due to the idling of the Yazoo City plant. See “AN Segment—Yazoo City Incident,” above, for additional information.
Gross Margin. Gross margin in our Other segment increased by $4 million, or 2%, to $205 million in 2025 from $201 million in 2024, and our gross margin percentage was 37.6% in 2025 compared to 40.0% in 2024. The increase in gross margin was due primarily to a 10% increase in average selling prices, which increased gross margin by $44 million. This increase in gross margin was partially offset by a net increase in manufacturing, maintenance and other costs, which decreased gross margin by $22 million, and higher realized natural gas costs, including the impact of realized derivatives, which decreased gross margin by $16 million. Gross margin also includes the impact of a $2 million unrealized net mark-to-market gain on natural gas derivatives in 2024 that did not recur in 2025.
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Liquidity and Capital Resources
Our primary uses of cash are generally for operating costs, working capital, capital expenditures, debt service, investments, taxes, share repurchases, dividends, and our clean energy initiatives. Our working capital requirements are affected by several factors, including demand for our products, selling prices, the level of customer advances, raw material costs, freight costs and seasonal factors inherent in the business. We may also utilize our cash to fund acquisitions. In addition, we may from time to time seek to retire or purchase our outstanding debt through cash purchases, in open market or privately negotiated transactions or otherwise. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
Generally, our primary source of cash is cash from operations, which includes cash generated by customer advances. We may also from time to time access the capital markets or engage in borrowings under our revolving credit agreement.
On September 4, 2025, CF Holdings and CF Industries entered into the First Amended and Restated Revolving Credit Agreement (the Revolving Credit Agreement), which amended and restated our senior unsecured revolving credit facility that was scheduled to mature October 26, 2028 (the Prior Credit Agreement). The Revolving Credit Agreement provides for revolving credit facility commitments of up to $750 million with a maturity of September 4, 2030. See “Debt—Revolving Credit Agreement,” below, for additional information.
On November 26, 2025, CF Industries issued $1 billion aggregate principal amount of the 2035 Notes. The net proceeds, after deducting discounts and offering expenses, from the issuance and sale of the 2035 Notes were approximately $989 million. On December 26, 2025, in accordance with the optional redemption provisions in the indenture governing the 2026 Notes, we used approximately $756 million of the net proceeds for the prepayment (including payment of a make-whole amount of $4 million and accrued interest of $2 million) in full of the outstanding $750 million aggregate principal amount of the 2026 Notes. See “Debt—Senior Notes,” below, for additional information.
At December 31, 2025, we were in compliance with all applicable covenant requirements under the Revolving Credit Agreement and senior notes, and unused borrowing capacity under the Revolving Credit Agreement was $750 million.
As of December 31, 2025, our cash and cash equivalents balance was $1.98 billion, an increase of $368 million from $1.61 billion at December 31, 2024, and consisted of the following:

| December 31, 2025 |  | December 31, 2024
| (in millions)
Cash and cash equivalents, excluding amounts related to Blue Point Number One, LLC | $ | 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
Cash equivalents include highly liquid investments that are readily convertible to known amounts of cash with original maturities of three months or less. Under our short-term investment policy, we may invest our cash balances, either directly or through mutual funds, in several types of investment-grade securities, including notes and bonds issued by governmental entities or corporations. Securities issued by governmental entities include those issued directly by the U.S. and Canadian federal governments; those issued by state, local or other governmental entities; and those guaranteed by entities affiliated with governmental entities.
Blue Point Joint Venture
On April 8, 2025, we formed the Blue Point joint venture with JERA and Mitsui to construct a low-carbon ammonia production facility at our Blue Point complex located in Modeste, Louisiana. We hold 40% ownership, JERA holds 35% ownership, and Mitsui holds 25% ownership in the Blue Point joint venture. Under the terms of the Blue Point joint venture’s limited liability company agreement, JERA had a conditional option that, if the specified condition were met, JERA could reduce its ownership percentage below 35% but not lower than 20%. We would have had the right and obligation to increase our ownership by the same amount had JERA opted to reduce its ownership. The option expired and is no longer exercisable.
The Blue Point joint venture is expected to construct an ATR ammonia production facility with a CO 2 dehydration and compression unit to prepare captured CO 2 for transportation and sequestration. Engineering, equipment procurement and pre-construction activities at our Blue Point complex began in the second quarter of 2025. Construction of the ammonia production facility is expected to begin in 2026, with low-carbon ammonia production expected to begin in 2029.
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We estimate that the cost of the low-carbon ATR ammonia production facility with CCS technologies will be approximately $3.7 billion. We anticipate that approximately one-third of the estimated cost is related to materials that will be imported to the United States, with the majority of imported materials expected to arrive in Louisiana in 2028. Pursuant to periodic capital calls, the Blue Point joint venture members will fund the cost of the facility’s engineering, procurement and construction according to their respective ownership percentages. During 2025, we, JERA and Mitsui made capital contributions of $195 million, $170 million and $121 million, respectively, to the Blue Point joint venture. We funded $152 million of our contributions with cash and $43 million through a non-cash contribution of a license to use certain intellectual property.
In June 2025, the Blue Point joint venture executed agreements, including a long-term supply agreement, with a subsidiary of Linde plc for them to design, construct, own, operate and maintain an air separation unit (ASU) at our Blue Point complex to supply oxygen and nitrogen to the low-carbon ATR ammonia production facility. Thus, our estimate of the cost of the low-carbon ATR ammonia production facility of $3.7 billion, as noted above, excludes the costs to construct an ASU.
In addition, we plan to invest approximately $550 million to build scalable infrastructure at our Blue Point complex to supply the ammonia production facility with services, including product storage and vessel loading. This infrastructure will be constructed with a similar timeline as the ammonia production facility noted above.
See “Overview of CF Holdings—Our Strategy—Blue Point joint venture,” above, and Note 14—Variable Interest Entity, for additional information on the Blue Point joint venture.
Capital Spending
We make capital expenditures to sustain our asset base, increase our capacity or capabilities, improve plant efficiency, comply with various environmental, health and safety requirements, and invest in our clean energy strategy. Capital expenditures totaled $950 million in 2025 compared to $518 million in 2024, and consisted of the following:

| December 31, 2025 |  | December 31, 2024
| (in millions)
Existing operations | $ | 620 |  |  | $ | 507 |
Blue Point joint venture(1) | 307 |  |  | — |
Blue Point complex scalable infrastructure | 9 |  |  | — |
Capitalized interest | 14 |  |  | 11 |
Total capital expenditures | $ | 950 |  |  | $ | 518 |

_______________________________________________________________________________
(1)Amounts represent 100% of the Blue Point joint venture capital spending, of which 60% is funded by our joint venture partners through capital contributions to the joint venture. See “Overview of CF Holdings—Our Strategy—Blue Point joint venture,” above, and Note 14—Variable Interest Entity, for additional information on the Blue Point joint venture.
The Blue Point joint venture is consolidated in our financial statements, including our statements of cash flows. We currently anticipate that our consolidated capital expenditures for 2026 to be approximately $1.3 billion, consisting of approximately $550 million for our existing operations and approximately $600 million representing the Blue Point joint venture’s planned capital expenditures related to construction of the low-carbon ATR ammonia production facility at our Blue Point complex. Also, we anticipate our 2026 capital spending will include approximately $150 million related to our construction of the Blue Point complex scalable infrastructure.
Of the Blue Point joint venture’s $600 million of planned 2026 capital expenditures, approximately $240 million will be funded by us, representing our 40% equity interest in the Blue Point joint venture, and approximately $360 million will be funded by our partners in the joint venture, representing their combined 60% equity interest in the Blue Point joint venture.
For 2026, we anticipate that our capital expenditures will be funded primarily from available cash, including cash from operations, in addition to contributions received from our Blue Point joint venture partners pursuant to periodic capital calls as discussed under “Blue Point Joint Venture, ” above.
Planned capital expenditures are generally subject to change due to delays in regulatory approvals or permitting, unanticipated increases in cost, changes in scope and completion time, engineering and construction change orders, performance of third parties, delays in the receipt of equipment, adverse weather, defects in materials and workmanship, labor or material shortages, impact of tariffs, retaliatory measures or other changes in trade policy, transportation constraints, acceleration or delays in the timing of the work and other unforeseen difficulties. Any of these changes in planned capital
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expenditures, individually or in the aggregate, could have a material impact on our results of operations and cash flows. See “—Forward-Looking Statements” for additional risks related to our planned capital expenditures.
Share Repurchase Programs
Our Board of Directors (the Board) has authorized certain programs to repurchase shares of our common stock. These programs have generally permitted repurchases to be made from time to time in the open market, through privately-negotiated transactions, through block transactions, through accelerated share repurchase programs or otherwise. The manner, timing and amount of repurchases will be determined by our management based on the evaluation of market conditions, stock price and other factors.
On November 2, 2022, the Board authorized the repurchase of up to $3 billion of CF Holdings common stock, which commenced in the second quarter of 2023 upon completion of our previous share repurchase program and was effective through December 31, 2025 (the 2022 Share Repurchase Program). On May 6, 2025, the Board authorized the repurchase of up to $2 billion of CF Holdings common stock commencing upon the completion of the 2022 Share Repurchase Program and effective through December 31, 2029 (the 2025 Share Repurchase Program). In October 2025, we completed the 2022 Share Repurchase Program and commenced repurchases under the 2025 Share Repurchase Program.
The following table summarizes the share repurchases under the 2025 Share Repurchase Program and the 2022 Share Repurchase Program.

| 2025 Share Repurchase Program |  | 2022 Share Repurchase Program
| Shares |  | Amounts(1) |  | Shares |  | Amounts(1)
| (in millions)
Shares repurchased in 2023 | — |  |  | $ | — |  |  | 5.6 |  |  | $ | 425 |
Shares repurchased in 2024 | — |  |  | $ | — |  |  | 18.8 |  |  | $ | 1,513 |
Shares repurchased in 2025: |  |  |  |  |  |  |
First quarter | — |  |  | $ | — |  |  | 5.4 |  |  | $ | 434 |
Second quarter | — |  |  | — |  |  | 2.8 |  |  | 202 |
Third quarter | — |  |  | — |  |  | 4.3 |  |  | 364 |
Fourth quarter | 3.4 |  |  | 278 |  |  | 0.7 |  |  | 62 |
Total shares repurchased in 2025 | 3.4 |  |  | $ | 278 |  |  | 13.2 |  |  | $ | 1,062 |
Shares repurchased as of December 31, 2025 | 3.4 |  |  | $ | 278 |  |  | 37.6 |  |  | $ | 3,000 |

_____________________________________________________________________________
(1)As defined in the share repurchase programs, amounts reflect the price paid for the shares of common stock repurchased, excluding commissions paid to brokers and excise taxes.
In 2025, we completed the 2022 Share Repurchase Program with the repurchase of 13.2 million shares for $1.06 billion, and we repurchased 3.4 million shares under the 2025 Share Repurchase Program for $278 million. In 2025, we retired 17.1 million shares of repurchased stock, including shares repurchased under the 2022 Share Repurchase Program and the 2025 Share Repurchase Program. In 2024, we retired 18.7 million shares of repurchased stock. As of December 31, 2025 and 2024, we held zero shares and 0.4 million shares, of treasury stock, respectively.
Government Policies
The policies or laws of governments around the world can result in the imposition of taxes, duties, tariffs or other restrictions or regulatory requirements on imports and exports of raw materials, finished goods or services from a particular country or region of the world. The policies and laws of governments can also impact the subsidization of natural gas prices, and subsidies or quotas applied to domestic producers or farmers. Due to the critical role that fertilizers play in food production, the construction and operation of fertilizer plants often are influenced by economic, political and social objectives. Additionally, the import or export of fertilizer can be subject to local taxes imposed by governments which can have the effect of either encouraging or discouraging import and export activity. The impact of changes in governmental policies or laws or the political or social objectives of a country could have a material impact on fertilizer demand and selling prices and therefore could impact our liquidity. In addition, political leadership, including the current U.S. presidential administration and regulatory leadership, have proposed, and may propose further, policy, regulatory, and enforcement changes, which are and may continue to be subject to administrative and judicial challenges, that create additional uncertainty for our business.
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Canada Revenue Agency Competent Authority Matter
In the third quarter of 2024, we were informed that the CRA granted one of our Canadian subsidiaries discretionary interest relief for certain tax years from 2006 through 2011, which were previously settled through arbitration proceedings between the United States and Canadian competent authorities. In the fourth quarter of 2024, we received interest relief from the CRA consisting of interest refunds of $21 million and related interest of $2 million, and we were informed that the Alberta TRA granted us discretionary interest relief in parallel with the CRA relief. The interest relief from the Alberta TRA was estimated to be approximately $16 million, consisting of interest refunds of $15 million and related interest of $1 million, based on estimates and foreign currency exchange rates as of December 31, 2024. During the fourth quarter of 2025, the Alberta TRA finalized interest relief owed to the Company, which was applied as credits to our account and is available to offset future income tax owed to the Alberta TRA.
Repatriation of Foreign Earnings and Income Taxes
We have operations in Canada, the United Kingdom and a 50% interest in a joint venture in Trinidad. Historically, the estimated additional U.S. and foreign income taxes due upon repatriation of the earnings of these foreign operations to the United States were recognized in our consolidated financial statements as the earnings were recognized, unless the earnings were considered to be permanently reinvested based upon our then current plans. However, the cash payment of the income tax liabilities associated with repatriation of earnings from foreign operations occurred at the time of the repatriation. As a result, the recognition of income tax expense related to foreign earnings, as applicable, and the payment of taxes resulting from repatriation of those earnings could occur in different periods.
In light of changes made by the Tax Cuts and Jobs Act, commencing with the 2018 tax year, the United States no longer taxes earnings of foreign subsidiaries even when such earnings are earned or repatriated to the United States, unless such earnings are subject to U.S. rules on passive income or certain anti-abuse provisions. Foreign subsidiary earnings may still be subject to withholding taxes when repatriated to the United States.
Cash balances held by our joint venture are maintained at sufficient levels to fund local operations as accumulated earnings are repatriated from the joint venture on a periodic basis.
As of December 31, 2025, approximately $555 million of our consolidated cash and cash equivalents balance of $1.98 billion was held by our Canadian and United Kingdom subsidiaries. The Company does not have an indefinite reinvestment assertion in any of our foreign subsidiaries. As of December 31, 2025, we recorded a deferred tax liability of $21 million on the undistributed earnings of our Canadian subsidiaries.
Debt
Revolving Credit Agreement
On September 4, 2025, CF Holdings and CF Industries entered into the First Amended and Restated Revolving Credit Agreement (the Revolving Credit Agreement), which amended and restated the Prior Credit Agreement. The Revolving Credit Agreement provides for revolving credit facility commitments of up to $750 million with a maturity of September 4, 2030, and has a letter of credit sub-limit of $125 million and a swingline loan sub-limit of $75 million. Borrowings under the Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions, share repurchases and other general corporate purposes. CF Industries is the lead borrower, and CF Holdings is the sole guarantor, under the Revolving Credit Agreement. CF Industries may designate as borrowers one or more wholly-owned subsidiaries that are organized in the United States or any state thereof, the District of Columbia, England and Wales or any other jurisdiction as mutually agreed to by all of the lenders party to the Revolving Credit Agreement and the administrative agent.
Borrowings under the Revolving Credit Agreement can be denominated in U.S. dollars, Canadian dollars, euros and British pounds. Borrowings in U.S. dollars bear interest at an annual rate equal to, at our option, an applicable adjusted term secured overnight financing rate (or a similar benchmark rate for non-U.S. dollar borrowings) plus a specified margin, or base rate plus a specified margin. We are required to pay a commitment fee on the undrawn portion of the commitments under the Revolving Credit Agreement and customary letter of credit fees. The specified margins and the amount of the commitment fee will depend on CF Holdings’ credit rating at the time.
The Revolving Credit Agreement contains representations and warranties and affirmative and negative covenants, including one financial covenant. The financial covenant requires the total net leverage ratio (as defined in the Revolving Credit Agreement) to be no greater than 3.75:1.00 (or 4.25:1.00 for a period of four fiscal quarters after certain material acquisitions) as of the last day of each fiscal quarter.
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The Revolving Credit Agreement contains events of default (with notice requirements and cure periods, as applicable) customary for a financing of this type, including, but not limited to, non-payment of principal, interest or fees; inaccuracy of representations and warranties in any material respect; and failure to comply with specified covenants. Upon the occurrence and during the continuance of an event of default under the Revolving Credit Agreement and after any applicable cure period, subject to specified exceptions, the administrative agent may, and at the request of the requisite lenders is required to, accelerate the loans under the Revolving Credit Agreement or terminate the lenders’ commitments under the Revolving Credit Agreement.
As of December 31, 2025, we were in compliance with all covenants under the Revolving Credit Agreement.
As of December 31, 2025, we had unused borrowing capacity under the Revolving Credit Agreement of $750 million and no outstanding letters of credit under the Revolving Credit Agreement. In addition, there were no borrowings outstanding under the Prior Credit Agreement as of December 31, 2024, or during the years ended December 31, 2025 or 2024.
Letters of Credit Under Reimbursement Agreement
We are party to a reimbursement agreement providing for the issuance of up to $425 million of letters of credit. As of December 31, 2025, approximately $339 million of letters of credit were outstanding under this agreement. The primary purpose of the letters of credit outstanding is to provide credit support to Canadian taxing authorities for amounts related to certain tax years that were reassessed and objected to, and which have been accepted for consideration under the bilateral settlement provisions of the U.S.-Canada tax treaty by the United States and Canadian competent authorities.
Senior Notes
Long-term debt presented on our consolidated balance sheets as of December 31, 2025 and 2024 consisted of the following debt securities issued by CF Industries:

| Effective Interest Rate |  | December 31, 2025 |  | December 31, 2024
|  | Principal Outstanding |  | Carrying Amount(1) |  | Principal Outstanding |  | Carrying Amount(1)
|  |  | (in millions)
Public Senior Notes: |  |  |  |  |  |  |  |  |
5.150% due March 2034 | 5.293% |  | $ | 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 |
5.375% due March 2044 | 5.478% |  | 750 |  |  | 741 |  |  | 750 |  |  | 741 |
Senior Secured Notes: |  |  |  |  |  |  |  |  |
4.500% due December 2026(2) | 4.783% |  | — |  |  | — |  |  | 750 |  |  | 746 |
Total long-term debt |  |  | $ | 3,250 |  |  | $ | 3,215 |  |  | $ | 3,000 |  |  | $ | 2,971 |

_______________________________________________________________________________
(1)Carrying amount is net of unamortized debt discount and deferred debt issuance costs. Total unamortized debt discount was $5 million and $6 million as of December 31, 2025 and 2024, respectively, and total deferred debt issuance costs were $30 million and $23 million as of December 31, 2025 and 2024, respectively.
(2)Effective August 23, 2021, these notes were no longer secured, in accordance with the terms of the applicable indenture.
On November 26, 2025, CF Industries issued $1 billion aggregate principal amount of the 2035 Notes, which are fully and unconditionally guaranteed by CF Holdings. The net proceeds, after deducting discounts and offering expenses, from the issuance and sale of the 2035 Notes were approximately $989 million. On December 26, 2025, we used approximately $756 million of the net proceeds to redeem in full the outstanding $750 million aggregate principal amount of the 2026 Notes. As a result, we recognized a loss on debt extinguishment of $6 million, consisting primarily of the premium paid on the redemption of the $750 million principal amount of the 2026 Notes prior to their scheduled maturity. We intend that the remainder of the net proceeds will be used for general corporate purposes.
Pursuant to Rule 3-10 of Regulation S-X and Rule 12h-5 of the Exchange Act, subsidiary issuers of obligations guaranteed by their parent company are not required to provide separate financial statements, provided that the subsidiary obligor is consolidated into such parent company’s consolidated financial statements, such related guarantee is “full and unconditional” and, subject to certain exceptions as set forth below, the alternative disclosure required by Rule 13-01 is provided, which includes narrative disclosure and summarized financial information. CF Holdings owns substantially all of its assets and conducts substantially all of its operations through CF Industries, and CF Industries is consolidated into CF Holdings’ financial statements. Our Public Senior Notes either meet the conditions of this requirement or are otherwise not
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required to be presented. Accordingly, separate consolidated financial statements of CF Industries have not been presented.
Furthermore, as permitted under Rule 13-01(a)(4)(vi) of Regulation S-X, summarized financial information for CF Industries has been excluded because the assets, liabilities and results of operations of CF Industries are not materially different than the corresponding amounts in CF Holdings’ consolidated financial statements incorporated by reference herein, and because management believes such summarized financial information would not be material for investors.
Under the indentures (including the applicable supplemental indentures) governing our senior notes due 2034, 2035, 2043 and 2044 identified in the table above (the Public Senior Notes), each series of Public Senior Notes is guaranteed by CF Holdings. Interest on the Public Senior Notes is payable semiannually, and the Public Senior Notes are redeemable at our option, in whole at any time or in part from time to time, at specified make-whole redemption prices.
The indentures governing the Public Senior Notes contain covenants that limit, among other things, the ability of CF Holdings and its subsidiaries, including CF Industries, to incur liens on certain assets to secure debt, to engage in sale and leaseback transactions, to merge or consolidate with other entities and to sell, lease or transfer all or substantially all of the assets of CF Holdings and its subsidiaries to another entity. Each of the indentures governing the Public Senior Notes provides for customary events of default, which include (subject in certain cases to customary grace and cure periods), among others, nonpayment of principal or interest on the applicable Public Senior Notes; failure to comply with other covenants or agreements under the indenture; certain defaults on other indebtedness; the failure of CF Holdings’ guarantee of the applicable Public Senior Notes to be enforceable; and specified events of bankruptcy or insolvency. Under each indenture governing the Public Senior Notes, in the case of an event of default arising from one of the specified events of bankruptcy or 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.
Under each of the indentures governing the Public Senior Notes, specified changes of control involving CF Holdings or CF Industries, when accompanied by a ratings downgrade, as defined with respect to the applicable series of Public Senior Notes, constitute change of control repurchase events. Upon the occurrence of a change of control repurchase event with respect to a series of Public Senior Notes, unless CF Industries has exercised its option to redeem such Public Senior Notes, CF Industries will be required to offer to repurchase them at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but not including, the date of repurchase.
Forward Sales and Customer Advances
We offer our customers the opportunity to purchase products from us on a forward basis at prices and on delivery dates we propose. Therefore, our reported fertilizer selling prices and margins may differ from market spot prices and margins available at the time of shipment.
Customer advances, which typically represent a portion of the contract’s value, are received shortly after the contract is executed, with any remaining unpaid amount generally being collected by the time control transfers to the customer, thereby reducing or eliminating the accounts receivable related to such sales. Any cash payments received in advance from customers in connection with forward sales contracts are reflected on our consolidated balance sheets as a current liability until control transfers and revenue is recognized. As of December 31, 2025 and 2024, we had $77 million and $118 million, respectively, in customer advances on our consolidated balance sheets.
While customer advances are generally a significant source of liquidity, the level of forward sales contracts is affected by many factors, including current market conditions, our customers’ outlook of future market fundamentals and seasonality. During periods of declining prices, customers tend to delay purchasing fertilizer in anticipation that prices in the future will be lower than the current prices. If the level of sales under our forward sales programs were to decrease in the future, our cash received from customer advances would likely decrease and our accounts receivable balances would likely increase. Additionally, borrowing under the Revolving Credit Agreement could become necessary. Due to the volatility inherent in our business and changing customer expectations, we cannot estimate the amount of future forward sales activity.
Under our forward sales programs, a customer may delay delivery of an order due to weather conditions or other factors. These delays generally subject the customer to potential charges for storage or may be grounds for termination of the contract by us. Such a delay in scheduled shipment or termination of a forward sales contract due to a customer’s inability or unwillingness to perform may negatively impact our reported sales.
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Natural Gas
Natural gas is the principal raw material used to produce our nitrogen products. Natural gas is both a chemical feedstock and a fuel used to produce nitrogen products. Natural gas is the largest and most volatile component of the manufacturing cost for our nitrogen products, representing approximately 34% of our total production costs in 2025. As a result of these factors, natural gas prices have a significant impact on our operating expenses and can thus affect our liquidity. Natural gas costs in our cost of sales, including the impact of realized natural gas derivatives, increased 38% to $3.31 per MMBtu in 2025 from $2.40 per MMBtu in 2024.
We enter into agreements for a portion of our future natural gas supply and related transportation. As of December 31, 2025, our natural gas purchase agreements have terms that range from five months to five years and a total minimum commitment of approximately $2.87 billion, and our natural gas transportation agreements have terms that range from one to five years and a total minimum commitment of approximately $254 million. Our minimum commitments to purchase and transport natural gas are based on prevailing market-based forward prices excluding reductions for plant maintenance and turnaround activities.
All of our ammonia manufacturing plants are located in the United States and Canada. As a result, the price of natural gas in North America directly impacts a substantial portion of our operating expenses. During the three-year period ended December 31, 2025, the daily closing price at the Henry Hub, the most heavily-traded natural gas pricing point in North America, reached a low of $1.23 per MMBtu on four consecutive days in November 2024 and a high of $12.97 per MMBtu on four consecutive days in January 2024.
Derivative Financial Instruments
We use derivative financial instruments to reduce our exposure to changes in prices for natural gas that will be purchased in the future. Natural gas is the largest and most volatile component of our manufacturing cost for nitrogen-based products. From time to time, we may also use derivative financial instruments to reduce our exposure to changes in foreign currency exchange rates. Volatility in reported quarterly earnings can result from the unrealized mark-to-market adjustments in the value of the derivatives. In 2025, we recognized an unrealized net mark-to-market loss of $5 million compared to a gain of $35 million in 2024, which is reflected in cost of sales in our consolidated statements of operations.
Derivatives expose us to counterparties and the risks associated with their ability to meet the terms of the contracts. For derivatives that are in net asset positions, we are exposed to credit loss from nonperformance by the counterparties. We control our credit risk through the use of multiple counterparties that are multinational commercial banks, other major financial institutions or large energy companies, and the use of International Swaps and Derivatives Association (ISDA) master netting arrangements. The ISDA agreements are master netting arrangements commonly used for over-the-counter derivatives that mitigate exposure to counterparty credit risk, in part, by creating contractual rights of netting and setoff, the specifics of which vary from agreement to agreement.
The ISDA agreements for most of our derivative instruments contain credit-risk-related contingent features, such as cross default provisions. In the event of certain defaults or termination events, our counterparties may request early termination and net settlement of certain derivative trades or may require us to collateralize derivatives in a net liability position. As of December 31, 2025 and 2024, the aggregate fair value of the derivative instruments with credit-risk-related contingent features in net liability positions was $4 million and zero, respectively, which also approximates the fair value of the assets that may be needed to settle the obligations if the credit-risk-related contingent features were triggered at the reporting dates.
As of December 31, 2025, our open natural gas derivative contracts consisted of natural gas basis swaps for 13.5 million MMBtus. As of December 31, 2024, our open natural gas derivative contracts consisted of natural gas fixed price swaps and basis swaps for 16.0 million MMBtus. At both December 31, 2025 and 2024, we had no cash collateral on deposit with counterparties for derivative contracts. The credit support documents executed in connection with certain of our ISDA agreements generally provide us and our counterparties the right to set off collateral against amounts owing under the ISDA agreements upon the occurrence of a default or a specified termination event.
Defined Benefit Pension Plans
In the fourth quarter of 2025, pursuant to the implementation of our retirement plan strategy for our Canadian and U.K. pension plans, we entered into agreements with insurance companies to purchase non-participating group buy-in annuity contracts (buy-in contracts), and for one of our Canadian plans, a non-participating group buy-out annuity contract that transferred the majority of the plan’s projected benefit obligation to the insurance company. While the buy-in contracts did not transfer the projected benefit obligations to the insurance companies, they were structured to align with the projected benefits
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for each of the plans and are held as pension trust assets. As a result of these transactions, we do not expect to have significant required contributions for our Canadian or U.K. pension plans.
As a result of the planned windup of our U.S. pension plan with an effective termination date of December 31, 2025, we expect to contribute approximately $9 million to this plan in 2026, representing the estimated plan termination liability.
We contributed $2 million to our pension plans in 2025. See Note 11—Pension and Other Postretirement Benefits for additional information.
Distributions to Noncontrolling Interests in CFN
The CFN Board of Managers approved semi-annual distribution payments for the years ended December 31, 2025, 2024 and 2023, in accordance with CFN’s limited liability company agreement, as follows:

Approved and paid |  | Distribution Period |  | Distribution Amount (in millions) |
First quarter of 2026 |  | Six months ended December 31, 2025 |  | $ | 201 |  |
Third quarter of 2025 |  | Six months ended June 30, 2025 |  | 175 |  |
First quarter of 2025 |  | Six months ended December 31, 2024 |  | 129 |  |
Third quarter of 2024 |  | Six months ended June 30, 2024 |  | 164 |  |
First quarter of 2024 |  | Six months ended December 31, 2023 |  | 144 |  |
Third quarter of 2023 |  | Six months ended June 30, 2023 |  | 204 |  |

Cash Flows
Net cash provided by operating activities in 2025 was $2.75 billion, an increase of $481 million compared to $2.27 billion in 2024. The increase in cash flow from operations was due primarily to an increase in gross margin, driven by increased average selling prices and higher sales volume, partially offset by higher natural gas costs. During 2025, net changes in working capital also impacted cash flow from operations by contributing $200 million less toward net cash from operations in 2025 than in 2024. These changes primarily occurred in changes in accounts receivable and inventories.
Net cash used in investing activities was $933 million in 2025 compared to $469 million in 2024, or an increase of $464 million. During 2025, capital expenditures totaled $950 million compared to $518 million in 2024. Our capital expenditures for 2025 included $307 million related to the Blue Point joint venture.
Net cash used in financing activities was $1.48 billion in 2025 compared to $2.21 billion in 2024. In 2025, we received proceeds of approximately $999 million, net of discounts, from the issuance of the 2035 Notes, which were used to fund the prepayment of the $750 million of 2026 Notes and the related make-whole payment of $4 million. In addition, the decrease in net cash used in financing activities was due primarily to contributions from noncontrolling interests in 2025 of $291 million, a decrease in share repurchases in 2025 compared to 2024, and a decrease in dividends paid on common stock in 2025 compared to 2024 due to lower shares outstanding as a result of common shares repurchased under our share repurchase programs. In 2025, we paid $1.37 billion for share repurchases compared to $1.51 billion for share repurchases in 2024. In 2025, dividends paid on common stock were $326 million in 2025 compared to $364 million in 2024.
Critical Accounting Estimates
Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP). U.S. GAAP requires that we select policies and make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates. We base our estimates on historical experience, technological assessment, opinions of appropriate outside experts, and the most recent information available to us. Actual results may differ from these estimates. Changes in estimates that may have a material impact on our results are discussed in the context of the underlying financial statements to which they relate. The following discussion presents information about our most critical accounting estimates.
Recoverability of Long-Lived Assets, Goodwill and Investment in Unconsolidated Affiliate
We review the carrying values of our property, plant and equipment and other long-lived assets, including our finite-lived intangible assets, goodwill and our investment in an unconsolidated affiliate in accordance with U.S. GAAP in order to assess recoverability. Factors that we must estimate when performing impairment tests include production and sales volumes, selling
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prices, raw material costs, operating rates, operating expenses, inflation, discount rates, exchange rates, tax rates, capital spending and the impact that future market dynamics and geopolitical events could have on these factors. Judgment is involved in estimating each of these factors, which include inherent uncertainties. The factors we use are consistent with those used in our internal planning process. The recoverability of the values associated with our goodwill, long-lived assets and our investment in an unconsolidated affiliate is dependent upon future operating performance of the specific businesses to which they are attributed. Certain of the operating assumptions are particularly sensitive to the cyclical nature of the fertilizer industry. Adverse changes in demand for our products, increases in supply and the availability and costs of key raw materials could significantly affect the results of our review.
The recoverability and impairment tests of long-lived assets are required only when conditions exist that indicate the carrying value may not be recoverable. For goodwill, impairment tests are required at least annually, or more frequently whenever events or circumstances indicate that the carrying value may not be recoverable. Our investment in an unconsolidated affiliate is reviewed for impairment whenever events or circumstances indicate that its carrying value may not be recoverable. When circumstances indicate that the fair value of our investment is less than its carrying value, and the reduction in value is other than temporary, the reduction in value would be recognized immediately in earnings.
We evaluate goodwill for impairment in the fourth quarter at the reporting unit level. Our evaluation generally begins with a qualitative assessment of the factors that could impact the significant inputs used to estimate fair value. If after performing the qualitative assessment, we determine that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, then no further analysis is necessary. However, if it is unclear based on the results of the qualitative test, we perform a quantitative test, which involves comparing the fair value of a reporting unit with its carrying amount, including goodwill. We use an income-based valuation method, determining the present value of future cash flows, to estimate the fair value of a reporting unit. If the fair value of a reporting unit exceeds its carrying amount, no further testing is necessary. If the fair value of the reporting unit is less than its carrying amount, goodwill impairment would be recognized equal to the amount of the carrying value in excess of the reporting unit’s fair value, limited to the total amount of goodwill allocated to the reporting unit.
We review property, plant and equipment and other long-lived assets at the asset group level in order to assess recoverability based on expected future undiscounted cash flows. If the sum of the expected future net undiscounted cash flows is less than the carrying value, an impairment loss would be recognized. The impairment loss is measured as the amount by which the carrying value exceeds the fair value of the long-lived assets.
In November 2025, we experienced an incident in the AN upgrade area at our Yazoo City complex that required us to temporarily idle all production at the site. As a result of the damage incurred and based on estimates and assumptions of a preliminary review of the impact, we recorded an impairment of certain fixed assets within our North American AN asset group of $25 million. We concluded that the incident necessitated evaluations of the long-lived assets within our North American AN asset group and the goodwill allocated to our North American AN reporting unit to determine if their fair value had declined to below their carrying value. The results of our long-lived asset impairment test indicated that there was no additional impairment, and the results of our goodwill impairment test concluded that the goodwill allocated to our North American AN reporting unit was not impaired. See Note 6—Property, Plant and Equipment—Net and Note 7—Goodwill and Other Intangible Assets for additional information.
PLNL is our joint venture investment in Trinidad and operates an ammonia plant that relies on natural gas supplied, under a gas sales contract (the NGC Contract), by The National Gas Company of Trinidad and Tobago Limited (NGC). The joint venture is accounted for under the equity method. From time to time, the PLNL joint venture has experienced curtailments in the supply of natural gas from NGC, which has reduced the ammonia production at PLNL.
In the third quarter of 2023, PLNL entered into the NGC Contract, which replaced the previous gas sales contract that PLNL had with NGC. Due to the terms of the NGC Contract, in the third quarter of 2023, we assessed our investment in PLNL for impairment and determined that the carrying value of our equity method investment in PLNL exceeded its fair value. As a result, we recorded an impairment of our equity method investment in PLNL of $43 million, which is reflected in equity in earnings (loss) of operating affiliate in our consolidated statement of operations for the year ended December 31, 2023.
The NGC Contract was scheduled to expire on January 1, 2026. NGC and PLNL have entered into short-term extension letter agreements that provide for the continued supply of gas while the parties seek to negotiate terms and conditions for a new gas sales contract for 2026. Any NGC commitment to supply gas is dependent on mutual agreement of such terms and conditions between NGC and PLNL. Furthermore, any NGC commitment to supply gas beyond 2026 would require further negotiations between NGC and PLNL.
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If NGC does not make sufficient quantities of natural gas available to PLNL at prices and terms that permit profitable operations, PLNL may cease operating its facility, which would trigger an impairment assessment of our remaining investment in PLNL. The carrying value of our equity method investment in PLNL at December 31, 2025 was $32 million.
Projected Benefit Obligations
The projected benefit obligations (PBOs) for our defined benefit pension plans are affected by plan design, actuarial estimates and discount rates. Key assumptions that affect our PBO are discount rates and, in addition for our United Kingdom plans, inflation rates, including an adjusted U.K. retail price index (RPI).
Given the derisking activities resulting from a revision to our retirement plan strategy, including the plan terminations of two of the North American pension plans effective December 31, 2025, and the purchase of a buy-out annuity contract in the fourth quarter of 2025 that transferred approximately 94% of the other North American pension plan’s liability to an insurance company, the key assumptions used to value the PBO of our North American plans as of December 31, 2025, were not considered critical accounting estimates.
For our United Kingdom plans, the December 31, 2025 PBO was computed based on a weighted-average discount rate of 5.5% for our United Kingdom plans, which was based on yields for high-quality (AA rated or better) fixed income debt securities that match the timing and amounts of expected benefit payments as of the measurement date of December 31, 2025. Declines in comparable bond yields would increase our PBO. For our United Kingdom plans, the 2.8% RPI used to calculate our PBO is developed using a U.K. government gilt prices only retail price inflation curve, which is based on the difference between yields on fixed interest government bonds and index-linked government bonds.
For our United Kingdom pension plans, our PBO was $335 million as of December 31, 2025, which was $22 million lower than pension plan assets. The table below estimates the impact of a 50 basis point increase or decrease in the key assumptions on our December 31, 2025 PBO for our United Kingdom pension plans:

|  |  |  |  | Increase/(Decrease) in December 31, 2025 PBO
|  |  | United Kingdom Plans
Assumption |  |  |  |  | +50 bps |  | -50 bps
|  |  |  |  | (in millions) |  |
Discount Rate |  |  |  |  | $ | (17) |  |  | $ | 18 |
RPI |  |  |  |  | 9 |  |  | (9) |

See Note 11—Pension and Other Postretirement Benefits for further discussion of our pension plans.
Income Taxes
We are subject to the income tax laws of the many jurisdictions in which we operate, and we recognize expense, assets and liabilities based on estimates of amounts that ultimately will be determined to be taxable or deductible in tax returns filed in various jurisdictions. These tax laws are complex, and how they apply to our facts is sometimes open to interpretation. We recognize the effect of income tax positions only if sustaining those positions is more likely than not. Tax positions that meet the more likely than not recognition threshold but are not highly certain are measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement with the taxing authority. Differences in interpretation of the tax laws and regulations, including negotiations with taxing authorities in various jurisdictions and resolution of disputes arising from federal, state and international tax audits, can result in differences in taxes paid, which may be higher or lower than our estimates. The judgments made at a point in time may change from previous conclusions based on the outcome of tax audits, as well as changes to, or further interpretations of, tax laws and regulations, and these changes could significantly impact the provision for income taxes, the amount of taxes payable and the deferred tax asset and liability balances. We adjust our income tax provision in the period in which these changes occur. As of December 31, 2025, we have recorded a reserve for unrecognized tax benefits, including penalties and interest, of $357 million.
We also engage in a significant amount of cross-border transactions. The taxability of cross-border transactions has received an increasing level of scrutiny among regulators across the globe, including the jurisdictions in which we operate. The tax rules and regulations of the various jurisdictions in which we operate are complex, and in many cases, there is not symmetry between the rules of the various jurisdictions. As a result, there are instances where regulators within the jurisdictions involved in a cross-border transaction may reach different conclusions regarding the taxability of the transaction in their respective jurisdictions based on the same set of facts and circumstances. We work closely with regulators to reach a common understanding and conclusion regarding the taxability of cross-border transactions.
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Recent Accounting Pronouncements
See Note 3—New Accounting Standards for a discussion of recent accounting pronouncements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Our business operations give rise to market risk exposure due to changes in commodity prices, interest rates and foreign currency exchange rates.
To manage such risks, we may, from time to time, utilize derivatives that enable us to mitigate the adverse effects of financial market risk. Our use of derivatives 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 to which we do not apply hedge accounting. To the extent that our derivative positions lose value, our counterparties may request early termination and net settlement of certain derivative trades or, under certain ISDA agreements, may require us to collateralize derivatives in a net liability position, adversely affecting our liquidity.
Commodity Prices
Our gross margin, cash flows and estimates of future cash flows related to nitrogen-based products are sensitive not only to selling prices of our products, but also to changes in market prices of natural gas and other raw materials. A $1.00 per MMBtu change in the price of natural gas would change the cost to produce a ton of ammonia, granular urea, UAN (assuming a 32% nitrogen content) and AN by approximately $32, $22, $14 and $16, respectively.
Natural gas is the largest and most volatile component of the manufacturing cost for nitrogen-based products. From time to time, we utilize natural gas derivatives to hedge our financial exposure to the price volatility of natural gas, the principal raw material we use in the production of nitrogen-based products. We may use natural gas futures, swaps and option contracts traded in over-the-counter markets or on exchanges. These derivatives settle using primarily a NYMEX futures price index, which represents the basis for fair value at any given time. The contracts represent anticipated natural gas needs for future periods and settlements are scheduled to coincide with anticipated natural gas purchases during those future periods. As of December 31, 2025, we had natural gas derivative contracts covering certain periods through March 2027.
As of December 31, 2025 and 2024, we had open natural gas derivative contracts for 13.5 million MMBtus and 16.0 million MMBtus, respectively. A $1.00 per MMBtu increase in the forward curve prices of natural gas at December 31, 2025 would result in a favorable change in the fair value of these derivative positions of approximately $13 million, and a $1.00 per MMBtu decrease in the forward curve prices of natural gas would change their fair value unfavorably by approximately $13 million.
In addition, from time to time, we may purchase nitrogen products on the open market to augment or replace production at our facilities.
Interest Rates
As of December 31, 2025, we had four series of senior notes totaling $3.25 billion of principal outstanding with maturity dates of March 15, 2034, November 26, 2035, June 1, 2043 and March 15, 2044. The senior notes have fixed interest rates. As of December 31, 2025, the carrying value and fair value of our senior notes was approximately $3.22 billion and $3.13 billion, respectively.
Our primary exposure to interest rate risk results from borrowings under our revolving credit agreement, if any, which bear current market rates of interest plus a specified margin. As of December 31, 2025 and 2024, and during the years then ended, there were no borrowings outstanding under our revolving credit agreement.
Foreign Currency Exchange Rates
We are directly exposed to changes in the value of the Canadian dollar, the British pound and the euro. We generally do not maintain any exchange rate derivatives or hedges related to these currencies, but we may from time to time use foreign currency derivatives (primarily forward exchange contracts) to mitigate foreign currency exchange rate risk.
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CF INDUSTRIES HOLDINGS, INC.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
CF Industries Holdings, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of CF Industries Holdings, Inc. and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 25, 2026 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Measurements of projected benefit obligations
As discussed in Note 11 to the consolidated financial statements, the Company’s projected benefit obligation (PBO) associated with its defined benefit pension plans established in the United Kingdom was $335 million as of December 31, 2025. The Company’s PBO represents an actuarially determined estimate of the present value of the vested benefits to which each eligible employee is currently entitled, based on the employee’s expected date of separation or retirement. Determining the PBO requires the Company to make assumptions, including the selection of a discount rate for each of the United Kingdom plans.
We identified the evaluation of the Company’s measurements of the PBO as a critical audit matter. Specialized skills were needed to evaluate the discount rates utilized in the measurement of the PBO for each of the United Kingdom plans. In addition, subjective auditor judgment was required to evaluate these discount rates, as minor changes to these discount rates could have a significant impact on the PBO.
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The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s PBO accounting process, including controls related to the determination of discount rates. We involved actuarial professionals with specialized skills and knowledge, who assisted in:
•developing an understanding and assessing the methods used by the Company’s actuaries to develop the discount rates
•evaluating the relevance and reliability of information used by the Company’s actuaries in the development of the discount rates
•evaluating discount rates using benchmark yield curves for the United Kingdom, adjusted for the assessment of the timing of payments expected to be made to beneficiaries under the Company’s United Kingdom pension plans, and comparing those to the Company’s selected discount rates for the United Kingdom plans.
(signed) KPMG LLP
We have served as the Company’s auditor since 1983.
Chicago, Illinois
February 25, 2026
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CF INDUSTRIES HOLDINGS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions, except per share amounts)
Net sales | $ | 7,084 |  |  | $ | 5,936 |  |  | $ | 6,631 |
Cost of sales | 4,360 |  |  | 3,880 |  |  | 4,086 |
Gross margin | 2,724 |  |  | 2,056 |  |  | 2,545 |
Selling, general and administrative expenses | 364 |  |  | 320 |  |  | 289 |
Asset impairment | 76 |  |  | — |  |  | — |
U.K. operations restructuring | 23 |  |  | — |  |  | 10 |
Acquisition and integration costs | — |  |  | 4 |  |  | 39 |
Other operating—net | (25) |  |  | (10) |  |  | (31) |
Total other operating costs and expenses | 438 |  |  | 314 |  |  | 307 |
Equity in earnings (loss) of operating affiliate | 14 |  |  | 4 |  |  | (8) |
Operating earnings | 2,300 |  |  | 1,746 |  |  | 2,230 |
Interest expense | 155 |  |  | 121 |  |  | 150 |
Interest income | (81) |  |  | (123) |  |  | (158) |
Loss on debt extinguishment | 6 |  |  | — |  |  | — |
Other non-operating—net | (19) |  |  | (14) |  |  | (10) |
Earnings before income taxes | 2,239 |  |  | 1,762 |  |  | 2,248 |
Income tax provision | 441 |  |  | 285 |  |  | 410 |
Net earnings | 1,798 |  |  | 1,477 |  |  | 1,838 |
Less: Net earnings attributable to noncontrolling interests | 343 |  |  | 259 |  |  | 313 |
Net earnings attributable to common stockholders | $ | 1,455 |  |  | $ | 1,218 |  |  | $ | 1,525 |
Net earnings per share attributable to common stockholders: |  |  |  |  |
Basic | $ | 8.98 |  |  | $ | 6.75 |  |  | $ | 7.89 |
Diluted | $ | 8.97 |  |  | $ | 6.74 |  |  | $ | 7.87 |
Weighted-average common shares outstanding: |  |  |  |  |
Basic | 162.1 |  |  | 180.4 |  |  | 193.3 |
Diluted | 162.2 |  |  | 180.7 |  |  | 193.8 |

See Accompanying Notes to Consolidated Financial Statements.
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CF INDUSTRIES HOLDINGS, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Net earnings | $ | 1,798 |  |  | $ | 1,477 |  |  | $ | 1,838 |
Other comprehensive income (loss): |  |  |  |  |
Foreign currency translation adjustment—net of taxes | 70 |  |  | (75) |  |  | 33 |
Defined benefit plans—net of taxes | (25) |  |  | 4 |  |  | (12) |
| 45 |  |  | (71) |  |  | 21 |
Comprehensive income | 1,843 |  |  | 1,406 |  |  | 1,859 |
Less: Comprehensive income attributable to noncontrolling interests | 343 |  |  | 259 |  |  | 313 |
Comprehensive income attributable to common stockholders | $ | 1,500 |  |  | $ | 1,147 |  |  | $ | 1,546 |

See Accompanying Notes to Consolidated Financial Statements.
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CF INDUSTRIES HOLDINGS, INC.
CONSOLIDATED BALANCE SHEETS

| December 31,
| 2025 |  | 2024
| (in millions, except share and per share amounts)
Assets |  |  |
Current assets: |  |  |
Cash and cash equivalents (amount related to variable interest entity (VIE)—2025: $130) | $ | 1,982 |  |  | $ | 1,614 |
Accounts receivable—net | 488 |  |  | 404 |
Inventories | 383 |  |  | 314 |
Prepaid income taxes | 105 |  |  | 145 |
Other current assets (amount related to VIE—2025: $1) | 27 |  |  | 43 |
Total current assets | 2,985 |  |  | 2,520 |
Property, plant and equipment—net (amount related to VIE—2025: $361) | 6,715 |  |  | 6,735 |
Investment in affiliate | 32 |  |  | 29 |
Goodwill | 2,493 |  |  | 2,492 |
Intangible assets—net | 473 |  |  | 507 |
Operating lease right-of-use assets | 410 |  |  | 266 |
Other assets (amount related to VIE—2025: $1) | 980 |  |  | 917 |
Total assets | $ | 14,088 |  |  | $ | 13,466 |
Liabilities and Equity |  |  |
Current liabilities: |  |  |
Accounts payable and accrued expenses (amount related to VIE—2025: $52) | $ | 681 |  |  | $ | 603 |
Income taxes payable | — |  |  | 2 |
Customer advances | 77 |  |  | 118 |
Current operating lease liabilities | 110 |  |  | 86 |
Other current liabilities | 19 |  |  | 9 |
Total current liabilities | 887 |  |  | 818 |
Long-term debt | 3,215 |  |  | 2,971 |
Deferred income taxes | 869 |  |  | 871 |
Operating lease liabilities | 311 |  |  | 189 |
Supply contract liability | 694 |  |  | 724 |
Other liabilities (amount related to VIE—2025: $1) | 337 |  |  | 301 |
Equity: |  |  |
Stockholders’ equity: |  |  |
Preferred stock—$0.01 par value, 50,000,000 shares authorized | — |  |  | — |
Common stock—$0.01 par value, 500,000,000 shares authorized, 2025—153,552,162 shares issued and 2024—170,237,254 shares issued | 2 |  |  | 2 |
Paid-in capital | 1,197 |  |  | 1,284 |
Retained earnings | 3,874 |  |  | 4,009 |
Treasury stock—at cost, 2025—0 shares and 2024—354,264 shares | — |  |  | (30) |
Accumulated other comprehensive loss | (235) |  |  | (280) |
Total stockholders’ equity | 4,838 |  |  | 4,985 |
Noncontrolling interests | 2,937 |  |  | 2,607 |
Total equity | 7,775 |  |  | 7,592 |
Total liabilities and equity | $ | 14,088 |  |  | $ | 13,466 |

See Accompanying Notes to Consolidated Financial Statements.
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CF INDUSTRIES HOLDINGS, INC.
CONSOLIDATED STATEMENTS OF EQUITY

| Common Stockholders |  |  |  |
| $0.01 Par Value Common Stock |  | Treasury Stock |  | Paid-In Capital |  | Retained Earnings |  | Accumulated Other Comprehensive Loss |  | Total Stockholders’ Equity |  | Noncontrolling Interests |  | Total Equity
| (in millions)
Balance as of December 31, 2022 | $ | 2 |  |  | $ | — |  |  | $ | 1,412 |  |  | $ | 3,867 |  |  | $ | (230) |  |  | $ | 5,051 |  |  | $ | 2,802 |  |  | $ | 7,853 |
Net earnings | — |  |  | — |  |  | — |  |  | 1,525 |  |  | — |  |  | 1,525 |  |  | 313 |  |  | 1,838 |
Other comprehensive income | — |  |  | — |  |  | — |  |  | — |  |  | 21 |  |  | 21 |  |  | — |  |  | 21 |
Purchases of treasury stock | — |  |  | (585) |  |  | — |  |  | — |  |  | — |  |  | (585) |  |  | — |  |  | (585) |
Retirement of treasury stock | — |  |  | 605 |  |  | (59) |  |  | (546) |  |  | — |  |  | — |  |  | — |  |  | — |
Acquisition of treasury stock under employee stock plans | — |  |  | (22) |  |  | — |  |  | — |  |  | — |  |  | (22) |  |  | — |  |  | (22) |
Issuance of $0.01 par value common stock under employee stock plans | — |  |  | 2 |  |  | (1) |  |  | — |  |  | — |  |  | 1 |  |  | — |  |  | 1 |
Stock-based compensation expense | — |  |  | — |  |  | 37 |  |  | — |  |  | — |  |  | 37 |  |  | — |  |  | 37 |
Cash dividends ($1.60 per share) | — |  |  | — |  |  | — |  |  | (311) |  |  | — |  |  | (311) |  |  | — |  |  | (311) |
Distributions declared to noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (459) |  |  | (459) |
Balance as of December 31, 2023 | $ | 2 |  |  | $ | — |  |  | $ | 1,389 |  |  | $ | 4,535 |  |  | $ | (209) |  |  | $ | 5,717 |  |  | $ | 2,656 |  |  | $ | 8,373 |
Net earnings | — |  |  | — |  |  | — |  |  | 1,218 |  |  | — |  |  | 1,218 |  |  | 259 |  |  | 1,477 |
Other comprehensive loss | — |  |  | — |  |  | — |  |  | — |  |  | (71) |  |  | (71) |  |  | — |  |  | (71) |
Purchases of treasury stock | — |  |  | (1,528) |  |  | — |  |  | — |  |  | — |  |  | (1,528) |  |  | — |  |  | (1,528) |
Retirement of treasury stock | — |  |  | 1,522 |  |  | (141) |  |  | (1,381) |  |  | — |  |  | — |  |  | — |  |  | — |
Acquisition of treasury stock under employee stock plans | — |  |  | (26) |  |  | — |  |  | — |  |  | — |  |  | (26) |  |  | — |  |  | (26) |
Issuance of $0.01 par value common stock under employee stock plans | — |  |  | 2 |  |  | — |  |  | — |  |  | — |  |  | 2 |  |  | — |  |  | 2 |
Stock-based compensation expense | — |  |  | — |  |  | 36 |  |  | — |  |  | — |  |  | 36 |  |  | — |  |  | 36 |
Cash dividends ($2.00 per share) | — |  |  | — |  |  | — |  |  | (363) |  |  | — |  |  | (363) |  |  | — |  |  | (363) |
Distributions declared to noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (308) |  |  | (308) |
Balance as of December 31, 2024 | $ | 2 |  |  | $ | (30) |  |  | $ | 1,284 |  |  | $ | 4,009 |  |  | $ | (280) |  |  | $ | 4,985 |  |  | $ | 2,607 |  |  | $ | 7,592 |
Net earnings | — |  |  | — |  |  | — |  |  | 1,455 |  |  | — |  |  | 1,455 |  |  | 343 |  |  | 1,798 |
Other comprehensive income | — |  |  | — |  |  | — |  |  | — |  |  | 45 |  |  | 45 |  |  | — |  |  | 45 |
Purchases of treasury stock | — |  |  | (1,353) |  |  | — |  |  | — |  |  | — |  |  | (1,353) |  |  | — |  |  | (1,353) |
Retirement of treasury stock | — |  |  | 1,395 |  |  | (131) |  |  | (1,264) |  |  | — |  |  | — |  |  | — |  |  | — |
Acquisition of treasury stock under employee stock plans | — |  |  | (14) |  |  | — |  |  | — |  |  | — |  |  | (14) |  |  | — |  |  | (14) |
Issuance of $0.01 par value common stock under employee stock plans | — |  |  | 2 |  |  | (1) |  |  | — |  |  | — |  |  | 1 |  |  | — |  |  | 1 |
Stock-based compensation expense | — |  |  | — |  |  | 45 |  |  | — |  |  | — |  |  | 45 |  |  | — |  |  | 45 |
Cash dividends ($2.00 per share) | — |  |  | — |  |  | — |  |  | (326) |  |  | — |  |  | (326) |  |  | — |  |  | (326) |
Contributions from noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 291 |  |  | 291 |
Distributions declared to noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (304) |  |  | (304) |
Balance as of December 31, 2025 | $ | 2 |  |  | $ | — |  |  | $ | 1,197 |  |  | $ | 3,874 |  |  | $ | (235) |  |  | $ | 4,838 |  |  | $ | 2,937 |  |  | $ | 7,775 |

See Accompanying Notes to Consolidated Financial Statements.
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CF INDUSTRIES HOLDINGS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Operating Activities: |  |  |  |  |
Net earnings | $ | 1,798 |  |  | $ | 1,477 |  |  | $ | 1,838 |
Adjustments to reconcile net earnings to net cash provided by operating activities: |  |  |  |  |
Depreciation and amortization | 898 |  |  | 925 |  |  | 869 |
Deferred income taxes | 6 |  |  | (115) |  |  | 81 |
Stock-based compensation expense | 45 |  |  | 36 |  |  | 37 |
Unrealized net loss (gain) on natural gas derivatives | 5 |  |  | (35) |  |  | (39) |
Impairment of equity method investment in PLNL | — |  |  | — |  |  | 43 |
Loss on debt extinguishment | 6 |  |  | — |  |  | — |
Asset impairment | 76 |  |  | — |  |  | — |
Pension settlement loss | 1 |  |  | — |  |  | — |
Gain on sale of emission credits | (8) |  |  | (47) |  |  | (39) |
Loss on disposal of property, plant and equipment | 3 |  |  | 12 |  |  | 4 |
Loss on sale of Ince facility | 23 |  |  | — |  |  | — |
Undistributed (earnings) loss of affiliate—net of taxes | (4) |  |  | (2) |  |  | 3 |
Changes in assets and liabilities: |  |  |  |  |
Accounts receivable—net | (98) |  |  | 77 |  |  | 100 |
Inventories | (88) |  |  | (28) |  |  | 152 |
Accrued and prepaid income taxes | 38 |  |  | 1 |  |  | (44) |
Accounts payable and accrued expenses | 72 |  |  | 44 |  |  | (88) |
Customer advances | (41) |  |  | (11) |  |  | (100) |
Other—net | 20 |  |  | (63) |  |  | (60) |
Net cash provided by operating activities | 2,752 |  |  | 2,271 |  |  | 2,757 |
Investing Activities: |  |  |  |  |
Additions to property, plant and equipment | (950) |  |  | (518) |  |  | (499) |
Proceeds from sale of property, plant and equipment | 6 |  |  | 3 |  |  | 1 |
Purchase of Waggaman ammonia production facility | — |  |  | 2 |  |  | (1,223) |
Proceeds from sale of Ince facility | 4 |  |  | — |  |  | — |
Purchase of emission credits | (1) |  |  | (3) |  |  | (2) |
Proceeds from sale of emission credits | 8 |  |  | 47 |  |  | 39 |
Other—net | — |  |  | — |  |  | 5 |
Net cash used in investing activities | (933) |  |  | (469) |  |  | (1,679) |
Financing Activities: |  |  |  |  |
Proceeds from long-term borrowings | 999 |  |  | — |  |  | — |
Repayments of short-term borrowings | (754) |  |  | — |  |  | — |
Financing fees | (12) |  |  | — |  |  | (2) |
Dividends paid on common stock | (326) |  |  | (364) |  |  | (311) |
Contributions from noncontrolling interests | 291 |  |  | — |  |  | — |
Distributions to noncontrolling interests | (304) |  |  | (308) |  |  | (459) |
Purchases of treasury stock | (1,365) |  |  | (1,509) |  |  | (580) |
Proceeds from issuances of common stock under employee stock plans | 1 |  |  | 2 |  |  | 2 |
Cash paid for shares withheld for taxes | (14) |  |  | (26) |  |  | (22) |
Net cash used in financing activities | (1,484) |  |  | (2,205) |  |  | (1,372) |
Effect of exchange rate changes on cash and cash equivalents | 33 |  |  | (15) |  |  | 3 |
Increase (decrease) in cash and cash equivalents | 368 |  |  | (418) |  |  | (291) |
Cash and cash equivalents at beginning of period | 1,614 |  |  | 2,032 |  |  | 2,323 |
Cash and cash equivalents at end of period | $ | 1,982 |  |  | $ | 1,614 |  |  | $ | 2,032 |

See Accompanying Notes to Consolidated Financial Statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Background and Basis of Presentation
Our mission is to provide clean energy to feed and fuel the world sustainably. With our employees focused on safe and reliable operations, environmental stewardship, and disciplined capital and corporate management, we are on a path to decarbonize our ammonia production network – the world’s largest – to enable low-carbon hydrogen and nitrogen products for energy, fertilizer, emissions abatement, and other industrial activities. Our value chain consists of manufacturing complexes in the United States, Canada and the United Kingdom, an extensive storage, transportation and distribution network in North America, and logistics capabilities enabling a global reach. In July 2025, we completed a significant decarbonization project at our Donaldsonville, Louisiana, complex to enable the production of low-carbon ammonia. Additionally, we are executing further decarbonization projects in our existing network and constructing a greenfield low-carbon ammonia plant at our Blue Point complex to drive our strategy to leverage our unique capabilities to accelerate the world’s transition to clean energy.
Our principal customers are cooperatives, retailers, independent fertilizer distributors, traders, wholesalers and industrial users. Our core product is anhydrous ammonia (ammonia), which contains 82% nitrogen and 18% hydrogen. Products derived from ammonia that are most often used as nitrogen fertilizers include granular urea, urea ammonium nitrate solution (UAN) and ammonium nitrate (AN). AN is also used extensively by the commercial explosives industry as a component of explosives. Products derived from ammonia that are sold primarily to industrial customers include diesel exhaust fluid (DEF), urea liquor, nitric acid and aqua ammonia. In addition, our low-carbon products are expected to be used for existing and new applications, such as power generation and steel production in Japan, and to help customers reduce the economic impact of European regulations on the price of carbon.
The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States (U.S. GAAP).
All references to “CF Holdings,” “the Company,” “we,” “us” and “our” refer to CF Industries Holdings, Inc. and its subsidiaries, except where the context makes clear that the reference is to CF Industries Holdings, Inc. only and not its subsidiaries. All references to “CF Industries” refer to CF Industries, Inc., a 100% owned subsidiary of CF Industries Holdings, Inc.
Our principal assets as of December 31, 2025 include:
•six U.S. manufacturing facilities, located in Donaldsonville, Louisiana; Sergeant Bluff, Iowa (our Port Neal complex); Yazoo City, Mississippi; Claremore, Oklahoma (our Verdigris complex); Woodward, Oklahoma; and Waggaman, Louisiana. The Waggaman facility is wholly owned by us, and the other five U.S. manufacturing facilities are wholly owned directly or indirectly by CF Industries Nitrogen, LLC (CFN), of which we own approximately 89% and CHS Inc. (CHS) owns the remainder. See Note 18—Noncontrolling Interests for additional information on our strategic venture with CHS;
•two Canadian manufacturing facilities, located in Medicine Hat, Alberta and Courtright, Ontario;
•a United Kingdom manufacturing facility, located in Billingham;
•an extensive system of terminals and associated transportation equipment located primarily in the Midwestern United States;
•a 50% interest in Point Lisas Nitrogen Limited (PLNL), an ammonia production joint venture located in Trinidad and Tobago (Trinidad) that we account for under the equity method; and
•a 40% interest in Blue Point Number One, LLC, a joint venture formed on April 8, 2025 (the Blue Point joint venture), to construct a manufacturing plant at our Blue Point complex located in Modeste, Louisiana. The joint venture entity is a variable interest entity (VIE) of which we are the primary beneficiary. As a result, we consolidate this entity in our consolidated financial statements, with the combined 60% equity interest owned by our joint venture partners recorded as noncontrolling interests. See Note 14—Variable Interest Entity for additional information.
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2. Summary of Significant Accounting Policies
Consolidation and Noncontrolling Interests
The consolidated financial statements of CF Holdings include the accounts of CF Industries, all majority-owned subsidiaries and the Blue Point joint venture, a VIE of which we are the primary beneficiary. All significant intercompany transactions and balances have been eliminated.
We own approximately 89% of the membership interests in CFN and consolidate CFN in our financial statements. CHS’ minority equity interest in CFN is included in noncontrolling interests in our consolidated financial statements. We hold a 40% interest in Blue Point Number One, LLC, a joint venture formed on April 8, 2025. The combined 60% equity interest owned by our joint venture partners is recorded as noncontrolling interests. See Note 14—Variable Interest Entity and Note 18—Noncontrolling Interests for additional information.
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses for the periods presented. Such estimates and assumptions are used for, but are not limited to, net realizable value of inventories, environmental remediation liabilities, environmental and litigation contingencies, asset retirement obligations, the cost of emission credits required to meet environmental regulations, the cost of customer incentives, the fair values utilized in the allocation of purchase price in an acquisition, useful lives of property and identifiable intangible assets, the evaluation of potential impairments of property, investments, identifiable intangible assets and goodwill, income tax reserves and the assessment of the realizability of deferred tax assets, measurement of the fair values of investments for which markets are not active, the determination of the funded status and annual expense of defined benefit pension and other postretirement plans and the valuation of stock-based compensation awards granted to employees.
Revenue Recognition
We follow a five-step model for revenue recognition. The five steps are: (1) identification of the contract(s) with the customer, (2) identification of the performance obligation(s) in the contract(s), (3) determination of the transaction price, (4) allocation of the transaction price to the performance obligation(s), and (5) recognition of revenue when (or as) each performance obligation is satisfied. Control of our products transfers to our customers when the customer is able to direct the use of, and obtain substantially all of the benefits from, our products, which occurs at the later of when title or risk of loss transfers to the customer. Control generally transfers to the customer at a point in time upon loading of our product onto transportation equipment or delivery to a customer destination. Revenue from forward sales programs is recognized on the same basis as other sales regardless of when the customer advances are received.
In situations where we have agreed to arrange delivery of the product to the customer’s intended destination and control of the product transfers upon loading of our product, we have elected to not identify delivery of the product as a performance obligation. We account for freight income associated with the delivery of these products as freight revenue, since this activity fulfills our obligation to transfer the product to the customer. Shipping and handling costs incurred by us are included in cost of sales.
We offer cash incentives to certain customers based on the volume of their purchases over a certain period. Customer incentives are reported as a reduction in net sales.
Cash and Cash Equivalents
Cash and cash equivalents include highly liquid investments that are readily convertible to known amounts of cash with original maturities of three months or less. The carrying value of cash and cash equivalents approximates fair value.
Investments
Short-term investments and noncurrent investments are accounted for primarily as available-for-sale securities reported at fair value. Changes in the fair value of available-for-sale debt securities are recognized in other comprehensive income. Changes in the fair value of available-for-sale equity securities are recognized through earnings. The carrying values of short-term investments, if any, approximate fair values because of the short maturities and the highly liquid nature of these investments.
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Inventories
Inventories are reported at the lower of cost and net realizable value with cost determined on a first-in, first-out and average cost basis. Inventory includes the cost of materials, production labor and production overhead. Inventory at warehouses and terminals also includes distribution costs to move inventory to the distribution facilities. Net realizable value is reviewed at least quarterly. Fixed production costs related to idle capacity are not included in the cost of inventory but are charged directly to cost of sales in the period incurred.
Investment in Unconsolidated Affiliate
The equity method of accounting is used for our investment in an affiliate that we do not consolidate, but over which we have the ability to exercise significant influence. Our equity method investment for which the results are included in operating earnings consists of our 50% ownership interest in PLNL, which operates an ammonia production facility in Trinidad. Our share of the net earnings from this investment is reported as an element of earnings from operations because PLNL’s operations provide additional production and are integrated with our supply chain and sales activities in the Ammonia segment.
Profits resulting from sales or purchases with equity method investees are eliminated until realized by the investee or investor, respectively. Investments in affiliates are reviewed for impairment whenever events or circumstances indicate that the carrying value may not be recoverable. If circumstances indicate that the fair value of an investment in an affiliate is less than its carrying value, and the reduction in value is other than temporary, the reduction in value would be recognized immediately in earnings.
See Note 8—Equity Method Investment for additional information.
Property, Plant and Equipment
Property, plant and equipment are stated at cost. Depreciation and amortization are computed using the straight-line method and are recorded over the estimated useful life of the property, plant and equipment. Useful lives are as follows:

| Years
Mobile and office equipment | 3 to 10
Production facilities, including machinery and equipment | 2 to 30
Land improvements | 10 to 30
Buildings | 10 to 40

We periodically review the useful lives assigned to our property, plant and equipment and we change the estimates to reflect the results of those reviews.
Scheduled inspections, replacements and overhauls of plant machinery and equipment at our continuous process manufacturing facilities during a full plant shutdown are referred to as plant turnarounds. Plant turnarounds are accounted for under the deferral method, as opposed to the direct expense or built-in overhaul methods. Under the deferral method, expenditures related to turnarounds are capitalized in property, plant and equipment when incurred and amortized to production costs on a straight-line basis over the period benefited, which is until the next scheduled turnaround in up to five years. If the direct expense method were used, all turnaround costs would be expensed as incurred. Internal employee costs and overhead amounts are not considered turnaround costs and are not capitalized. Turnaround costs are classified as investing activities and included in capital expenditures in our consolidated statements of cash flows. See Note 6—Property, Plant and Equipment—Net for additional information.
Recoverability of Long-Lived Assets
We review property, plant and equipment and other long-lived assets at the asset group level in order to assess recoverability based on expected future undiscounted cash flows whenever events or circumstances indicate that the carrying value may not be recoverable. If the sum of the expected future net undiscounted cash flows is less than the carrying value, an impairment loss would be recognized. The impairment loss is measured as the amount by which the carrying value exceeds the fair value of the asset. For property, plant and equipment that is planned for abandonment, we first consider a market or income-based valuation method. In situations where a secondary market does not exist and the assets have been idled and planned for abandonment and therefore will not generate future cash flows from operations, we estimate a salvage value for those assets. See Note 6—Property, Plant and Equipment—Net for additional information.
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Goodwill
Goodwill represents the excess of the purchase price of an acquired entity over the amounts assigned to the assets acquired and liabilities assumed. Goodwill is not amortized, but is reviewed for impairment annually or more frequently whenever events or circumstances indicate that the carrying value may not be recoverable. We perform our annual goodwill impairment review in the fourth quarter of each year at the reporting unit level. Our evaluation generally begins with a qualitative assessment of the factors that could impact the significant inputs used to estimate fair value. If after performing the qualitative assessment, we determine that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill, then no further analysis is necessary. However, if the results of the qualitative test are unclear, we perform a quantitative test, which involves comparing the fair value of a reporting unit with its carrying amount, including goodwill. We use an income-based valuation method, determining the present value of future cash flows, to estimate the fair value of a reporting unit. If the fair value of a reporting unit exceeds its carrying amount, no further analysis is necessary. If the fair value of the reporting unit is less than its carrying amount, goodwill impairment would be recognized equal to the amount of the carrying value in excess of the reporting unit’s fair value, limited to the total amount of goodwill allocated to the reporting unit. See Note 7—Goodwill and Other Intangible Assets for additional information.
Leases
Right-of-use (ROU) assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. ROU assets and lease liabilities are recognized at the lease commencement date based on the present value of lease payments over the lease term. The discount rate used to calculate the present value represents our secured incremental borrowing rate and is calculated based on the treasury yield curve commensurate with the term of each lease, and a spread representative of our secured borrowing costs. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.
Leases may be classified as either operating leases or finance leases. We have made an accounting policy election to not include leases with an initial term of 12 months or less on the balance sheet. For finance leases, if any, ROU assets are generally amortized on a straight-line basis over the shorter of the asset’s useful life or the lease term. Interest expense is recognized using the effective interest method and based on the lease liability at period end. For operating leases, rental payments, including rent holidays, leasehold incentives, and scheduled rent increases are expensed on a straight-line basis. Leasehold improvements are amortized over the shorter of the depreciable lives of the corresponding fixed assets or the lease term including any applicable renewals. For our rail car leases, barge tow charters, and terminal and warehouse storage agreements, we have made an accounting policy election to not separate lease and non-lease components, such as operating costs and maintenance, due to sufficient data not being available. As a result, the non-lease components are included in the ROU assets and lease liabilities on our consolidated balance sheet. See Note 24—Leases for additional information.
Income Taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those differences are projected to be recovered or settled. Realization of deferred tax assets is dependent on our ability to generate sufficient taxable income of an appropriate character in future periods. A valuation allowance is established if it is determined to be more likely than not that a deferred tax asset will not be realized. Significant judgment is applied in evaluating the need for and magnitude of appropriate valuation allowances against deferred tax assets.
Interest and penalties related to unrecognized tax benefits are reported as interest expense and income tax expense, respectively.
See Note 10—Income Taxes for additional information.
Customer Advances
Customer advances represent cash received from customers following acceptance of orders under our forward sales programs. Under such advances, the customer prepays a portion of the value of the sales contract prior to obtaining control of the product, thereby reducing or eliminating accounts receivable from customers. Revenue is recognized when the customer obtains control of the product.
Derivative Financial Instruments
Natural gas is the principal raw material used to produce nitrogen-based products. We manage the risk of changes in natural gas prices primarily through the use of derivative financial instruments. The derivative instruments that we use are
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primarily natural gas fixed price swaps, basis swaps and options traded in the over-the-counter (OTC) markets. The derivatives reference primarily a NYMEX futures price index, which represent the basis for fair value at any given time. These derivatives are traded in months forward and settlements are scheduled to coincide with anticipated gas purchases during those future periods. From time to time, we may also use derivative financial instruments to reduce our exposure to changes in foreign currency exchange rates. We do not use derivatives for trading purposes and are not a party to any leveraged derivatives.
Derivative financial instruments are accounted for at fair value and recognized as current or noncurrent assets and liabilities on our consolidated balance sheets. We use natural gas derivatives as an economic hedge of natural gas price risk, but without the application of hedge accounting. As a result, changes in fair value of these contracts are recognized in earnings. The fair values of derivative instruments and any related cash collateral are reported on a gross basis rather than on a net basis. Cash flows related to natural gas derivatives are reported as operating activities.
See Note 16—Derivative Financial Instruments for additional information.
Debt Issuance Costs
Costs associated with the issuance of debt are recorded on the balance sheet as a direct deduction from the carrying amount of the related debt liability. Costs associated with entering into revolving credit facilities are recorded as an asset in noncurrent assets. All debt issuance costs are amortized over the term of the related debt using the effective interest rate method. Debt issuance discounts are netted against the related debt and are amortized over the term of the debt using the effective interest method. See Note 12—Financing Agreements for additional information.
Environmental
Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations are expensed. Expenditures that increase the capacity or extend the useful life of an asset, improve the safety or efficiency of the operations, or mitigate or prevent future environmental contamination are capitalized. Liabilities are recorded when it is probable that an obligation has been incurred and the costs can be reasonably estimated. Environmental liabilities are not discounted.
Emission Credits
Emission credits may be generated by or granted to us through emissions trading systems or other regulatory programs. From time to time, we may also purchase emission credits. We have elected to account for emission credits using the intangible asset model. Under this model, emission credits that are purchased are measured at their cost basis and tested for impairment annually. We do not recognize any internally generated emission credits under the intangible asset model until a monetary transaction occurs, such as a sale of the emission credits. If a facility exceeds regulatory emissions allowance levels and offsetting credits are not held by us, our obligation is recognized as an operating expense and a liability at the fair value of the emissions allowance deficit.
45Q Tax Credits
Section 45Q of the Internal Revenue Code provides a refundable tax credit (45Q Tax Credits) for each metric ton of carbon dioxide (CO 2) captured and disposed of in secure geological storage. The 45Q Tax Credits are available for a 12-year period beginning on the date carbon capture and sequestration facilities are placed into service. We account for earned 45Q Tax Credits as grants related to income by analogy to the grant model within International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance. We recognize the benefit of the 45Q Tax Credits as a reduction to income taxes payable upon completion of qualifying carbon capture and sequestration activities, based upon the volume of CO 2 sequestered. Income from 45Q Tax Credits is recognized on a systematic basis in the same period the related expenses are recognized and included in Other operating—net on our consolidated statement of operations. Any 45Q Tax Credits earned but not recognized as income during a period would be recorded as deferred revenue. The 45Q Tax Credits contain provisions allowing for reclamation of the credit value should previously credited CO 2 cease to be disposed of in an approved manner. We do not believe it is probable that a recapture event will arise; therefore, we recognize the full value of our earned 45Q Tax Credits.
Stock-based Compensation
We grant stock-based compensation awards under our equity and incentive plans. The awards that have been granted to date are nonqualified stock options, restricted stock awards, restricted stock units and performance restricted stock units. The cost of employee services received in exchange for the awards is measured based on the fair value of the award on the grant date and is recognized as expense on a straight-line basis over the period during which the employee is required to provide the
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services. We have elected to recognize equity award forfeitures as they occur in determining the compensation cost to be recognized in each period. See Note 20—Stock-based Compensation for additional information.
Treasury Stock
We periodically retire treasury shares acquired through repurchases of our common stock and return those shares to the status of authorized but unissued. We account for treasury stock transactions under the cost method. For each reacquisition of common stock, the number of shares and the acquisition price for those shares is added to the treasury stock count and total value. When treasury shares are retired, we allocate the excess of the repurchase price over the par value of shares acquired to both retained earnings and paid-in capital. The portion allocated to paid-in capital is determined by applying the average paid-in capital per share, and the remaining portion is recorded to retained earnings. Payments of excise taxes associated with treasury stock repurchases are classified as a financing activity in our consolidated statements of cash flows.
Litigation
From time to time, we are subject to ordinary, routine legal proceedings related to the usual conduct of our business. We may also be involved in proceedings regarding public utility and transportation rates, environmental matters, taxes and permits relating to the operations of our various plants and facilities. Accruals for such contingencies are recorded to the extent management concludes their occurrence is probable and the financial impact of an adverse outcome is reasonably estimable. Legal fees are recognized as incurred and are not included in accruals for contingencies. Disclosure for specific legal contingencies is provided if the likelihood of occurrence is at least reasonably possible and the exposure is considered material to the consolidated financial statements.
In making determinations of likely outcomes of litigation matters, many factors are considered. These factors include, but are not limited to, history, scientific and other evidence, and the specifics and status of each matter. If the assessment of various factors changes, the estimates may change. Predicting the outcome of claims and litigation, and estimating related costs and exposure, involves substantial uncertainties that could cause actual costs to vary materially from estimates and accruals.
Foreign Currency Translation and Remeasurement
We translate the financial statements of our foreign subsidiaries with non-U.S. dollar functional currencies using period-end exchange rates for assets and liabilities and weighted-average exchange rates for each period for revenues and expenses. The resulting translation adjustments are recorded as a separate component of accumulated other comprehensive income (loss) within stockholders’ equity.
Foreign currency-denominated monetary assets and liabilities are remeasured into U.S. dollars at exchange rates existing at the respective balance sheet dates. Gains and losses resulting from these foreign currency transactions are included in other operating—net in our consolidated statements of operations. Gains and losses resulting from intercompany foreign currency transactions that are of a long-term investment nature, if any, are reported in other comprehensive income.
3. New Accounting Standards
Recently Adopted Pronouncement
We adopted Accounting Standards Update (ASU) No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures for the year ended December 31, 2025. This ASU adds new guidance that further enhances income tax disclosures, primarily through standardization and disaggregation of rate reconciliation categories and income taxes paid by jurisdiction. The modified disclosure requirements of this ASU were applied on a retrospective basis and are reflected in Note 10—Income Taxes and Note 22—Supplemental Cash Flow Information.
Recently Issued Pronouncements
In November 2024, the Financial Accounting Standards Board (FASB) issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. This ASU requires disclosure, within the footnotes to the financial statements, of specified costs and expenses disaggregated from the amounts presented on consolidated statements of operations. The guidance in this ASU is effective for fiscal years beginning after December 15, 2026, and interim periods within fiscal years beginning after December 15, 2027, with early adoption permitted. We are currently evaluating the impact that our adoption of this ASU will have on the disclosures in our consolidated financial statements.
In December 2025, the FASB issued ASU No. 2025-10, Government Grants (Topic 832): Accounting for Government Grants Received by Business Entities. This ASU establishes guidance on the recognition, measurement, and presentation of
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government grants received by business entities. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2028, with early adoption permitted. We do not expect the adoption of this ASU will have a material effect on our consolidated financial statements.
4. Revenue Recognition
Our performance obligations under a customer contract correspond to each shipment of product that we make to our customer under the contract. As a result, each contract may have more than one performance obligation based on the number of products ordered, the quantity of product to be shipped and the mode of shipment requested by the customer. When we enter into a contract with a customer, we are obligated to provide the product in that contract during a mutually agreed upon time period. Depending on the terms of the contract, either we or the customer arranges delivery of the product to the customer’s intended destination. When we arrange delivery of the product and control of the product transfers upon loading, we recognize freight revenue. For 2025, 2024 and 2023, we recognized freight revenue of $80 million, $78 million and $92 million, respectively.
Certain of our contracts require us to supply products on a continuous basis to the customer. We recognize revenue on these contracts based on the quantity of products transferred to the customer during the period. For 2025, 2024 and 2023, the total amount of revenue for these contracts was $93 million, $115 million and $61 million, respectively.
From time to time, we will enter the marketplace to purchase product in order to satisfy the obligations of our customer contracts. When we purchase product for this purpose, we are the principal in the transaction and recognize revenue on a gross basis. As discussed in Note 8—Equity Method Investment, we have transactions in the normal course of business with PLNL, reflecting our obligation to purchase 50% of the ammonia produced by PLNL at current market prices. Other than products purchased from PLNL, products purchased in the marketplace in order to satisfy the obligations of our customers were not material during 2025, 2024 and 2023.
Transaction Price
We agree with our customers on the selling price of each transaction. This transaction price is generally based on the product, market conditions, including supply and demand balances, freight arrangements including where control transfers, and customer incentives. In our contracts with customers, we allocate the entire transaction price to the sale of product to the customer, which is the basis for the determination of the relative standalone selling price allocated to each performance obligation. Any sales tax, value added tax, and other tax we collect concurrently with our revenue-producing activities are excluded from revenue. Returns of our product by our customers are permitted only when the product is not to specification. Returns were not material during 2025, 2024 and 2023.
We offer cash incentives to certain customers generally based on the volume of their purchases over the fertilizer year ending June 30. Our cash incentives do not provide an option to the customer for additional product. Accrual of these incentives involves the use of estimates, including how much product the customer will purchase and whether the customer will achieve a certain level of purchases within the incentive period. The balances of customer incentives accrued at December 31, 2025 and 2024 were not material.
Revenue Disaggregation
We track our revenue by product and by geography. See Note 21—Segment Disclosures for our revenue by reportable segment, which are Ammonia, Granular Urea, UAN, AN and Other. The following table summarizes our revenue by product and by geography (based on destination of our shipment) for 2025, 2024 and 2023:
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| Ammonia |  | Granular Urea |  | UAN |  | AN |  | Other |  | Total
| (in millions)
Year ended December 31, 2025 |  |  |  |  |  |  |  |  |  |  |
North America | $ | 1,702 |  |  | $ | 1,781 |  |  | $ | 1,865 |  |  | $ | 178 |  |  | $ | 468 |  |  | $ | 5,994 |
Europe and other | 474 |  |  | — |  |  | 296 |  |  | 243 |  |  | 77 |  |  | 1,090 |
Total revenue | $ | 2,176 |  |  | $ | 1,781 |  |  | $ | 2,161 |  |  | $ | 421 |  |  | $ | 545 |  |  | $ | 7,084 |
Year ended December 31, 2024 |  |  |  |  |  |  |  |  |  |  |
North America | $ | 1,452 |  |  | $ | 1,528 |  |  | $ | 1,416 |  |  | $ | 208 |  |  | $ | 421 |  |  | $ | 5,025 |
Europe and other | 284 |  |  | 72 |  |  | 262 |  |  | 211 |  |  | 82 |  |  | 911 |
Total revenue | $ | 1,736 |  |  | $ | 1,600 |  |  | $ | 1,678 |  |  | $ | 419 |  |  | $ | 503 |  |  | $ | 5,936 |
Year ended December 31, 2023 |  |  |  |  |  |  |  |  |  |  |
North America | $ | 1,387 |  |  | $ | 1,767 |  |  | $ | 1,646 |  |  | $ | 253 |  |  | $ | 486 |  |  | $ | 5,539 |
Europe and other | 292 |  |  | 56 |  |  | 422 |  |  | 244 |  |  | 78 |  |  | 1,092 |
Total revenue | $ | 1,679 |  |  | $ | 1,823 |  |  | $ | 2,068 |  |  | $ | 497 |  |  | $ | 564 |  |  | $ | 6,631 |

Accounts Receivable and Customer Advances
Our customers purchase our products through sales on credit or forward sales. Products sold to our customers on credit are recorded as accounts receivable when the customer obtains control of the product. Customers that purchase our products on credit are required to pay in accordance with our customary payment terms, which are generally 30 days or less. For 2025, 2024 and 2023, the amount of customer bad debt expense recognized was not material.
For forward sales, the customer prepays a portion of the value of the sales contract prior to obtaining control of the product. These prepayments, when received, are recorded as customer advances and are recognized as revenue when the customer obtains control of the product. Forward sales are customarily offered for periods of less than one year in advance of when the customer obtains control of the product. As of December 31, 2025 and 2024, we had $77 million and $118 million, respectively, in customer advances on our consolidated balance sheets. The decrease in the balance of customer advances was due primarily to the timing of seasonal UAN sales programs in 2025 compared to 2024. All of our customer advances that were recorded as of December 31, 2024 were recognized as revenue in 2025.
We have certain customer contracts with performance obligations where if the customer does not take the required amount of product specified in the contract, then the customer is required to make a payment to us, the amount of which may vary based upon the terms and conditions of the applicable contract. As of December 31, 2025, excluding contracts with original durations of less than one year, and based on the minimum product tonnage to be sold and current market price estimates, our remaining performance obligations under these contracts were approximately $2.3 billion. We expect to recognize approximately 20% of these performance obligations as revenue in 2026, approximately 32% as revenue during 2027-2029, approximately 16% as revenue during 2030-2032, and the remainder as revenue thereafter. Subject to the terms and conditions of the applicable contracts, if these customers do not satisfy their purchase obligations under such contracts, the minimum amount that they would be required to pay to us under such contracts, in the aggregate, was approximately $1.3 billion as of December 31, 2025. Other than the performance obligations described above, any performance obligations with our customers that were unfulfilled or partially filled at December 31, 2025 will be satisfied in 2026.
All of our contracts require that the period between the payment for goods and the transfer of those goods to the customer occur within normal contractual terms that do not exceed one year; therefore, we have elected the practical expedient and not adjusted the transaction price of any of our contracts to recognize a significant financing component. We have also elected the practical expedient to not capitalize any incremental costs associated with obtaining a contract that has a duration of less than one year, and there were no costs capitalized during 2025, 2024 or 2023.
Supply Contract Liability
In connection with our December 1, 2023 acquisition of the Waggaman ammonia production facility, we entered into a long-term ammonia offtake agreement providing for us to supply up to 200,000 tons of ammonia per year to Dyno Nobel, Inc. (the Supply Contract). The terms of the Supply Contract were determined to be unfavorable compared to market as of the acquisition date. As a result, we recorded an intangible liability with an acquisition date fair value of $757 million, which is being amortized to net sales over the estimated life of the Supply Contract of 25 years. For the years ended December 31, 2025, 2024 and 2023, we amortized $30 million, $30 million and $3 million, respectively, of the Supply Contract liability into net
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sales. As of December 31, 2025 and 2024, we had $694 million and $724 million, respectively, in Supply Contract liability on our consolidated balance sheets. Estimated amortization of the Supply Contract liability for each of the fiscal years from 2026 to 2030 is approximately $30 million.
5. Net Earnings Per Share
Net earnings per share were computed as follows:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions, except per share amounts)
Net earnings attributable to common stockholders | $ | 1,455 |  |  | $ | 1,218 |  |  | $ | 1,525 |
Basic earnings per common share: |  |  |  |  |
Weighted-average common shares outstanding | 162.1 |  |  | 180.4 |  |  | 193.3 |
Net earnings attributable to common stockholders | $ | 8.98 |  |  | $ | 6.75 |  |  | $ | 7.89 |
Diluted earnings per common share: |  |  |  |  |
Weighted-average common shares outstanding | 162.1 |  |  | 180.4 |  |  | 193.3 |
Dilutive common shares—stock-based awards | 0.1 |  |  | 0.3 |  |  | 0.5 |
Diluted weighted-average common shares outstanding | 162.2 |  |  | 180.7 |  |  | 193.8 |
Net earnings attributable to common stockholders | $ | 8.97 |  |  | $ | 6.74 |  |  | $ | 7.87 |

Diluted earnings per common share is calculated using weighted-average common shares outstanding, including the dilutive effect of stock-based awards as determined under the treasury stock method. In the computation of diluted earnings per common share, potentially dilutive stock-based awards are excluded if the effect of their inclusion is anti-dilutive. Shares for anti-dilutive stock-based awards not included in the computation of diluted earnings per common share were zero for the years ended December 31, 2025, 2024 and 2023.
6. Property, Plant and Equipment—Net
Property, plant and equipment—net consists of the following:

| December 31,
| 2025 |  | 2024
| (in millions)
Land | $ | 109 |  |  | $ | 114 |
Machinery and equipment | 13,957 |  |  | 13,801 |
Buildings and improvements | 1,043 |  |  | 1,011 |
Construction in progress | 709 |  |  | 482 |
Property, plant and equipment(1) | 15,818 |  |  | 15,408 |
Less: Accumulated depreciation and amortization | 9,103 |  |  | 8,673 |
Property, plant and equipment—net | $ | 6,715 |  |  | $ | 6,735 |

_______________________________________________________________________________
(1)As of December 31, 2025 and 2024, we had property, plant and equipment that was accrued but unpaid of approximately $118 million and $101 million, respectively.
Depreciation and amortization related to property, plant and equipment was $892 million, $921 million and $861 million in 2025, 2024 and 2023, respectively.
Plant turnarounds—Scheduled inspections, replacements and overhauls of plant machinery and equipment at our continuous process manufacturing facilities during a full plant shutdown are referred to as plant turnarounds. The expenditures related to plant turnarounds are capitalized in property, plant and equipment when incurred.
Scheduled replacements and overhauls of plant machinery and equipment during a plant turnaround include the dismantling, repair or replacement and installation of various components including piping, valves, motors, turbines, pumps, compressors and heat exchangers and the replacement of catalysts. Scheduled inspections, including required safety inspections
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which entail the disassembly of various components such as steam boilers, pressure vessels and other equipment requiring safety certifications, are also conducted during plant turnarounds. Internal employee costs and overhead amounts are not considered plant turnaround costs and are not capitalized.
The following is a summary of capitalized plant turnaround costs:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Net capitalized turnaround costs as of January 1 | $ | 363 |  |  | $ | 352 |  |  | $ | 312 |
Additions | 214 |  |  | 186 |  |  | 165 |
Depreciation | (152) |  |  | (171) |  |  | (138) |
Acquisition of Waggaman ammonia production facility | — |  |  | — |  |  | 16 |
Effect of exchange rate changes and other | 2 |  |  | (4) |  |  | (3) |
Net capitalized turnaround costs as of December 31 | $ | 427 |  |  | $ | 363 |  |  | $ | 352 |

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. 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. See Note 7—Goodwill and Other Intangible Assets for additional information.
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.
United Kingdom Operations
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. For property, plant and equipment within the Ince, U.K. asset group, an asset group planned for abandonment, we first considered use of a market or income-based valuation method. However, given that a secondary market did not exist and the assets had been idled with a planned abandonment and therefore would not generate future cash flows from operations, we estimated the fair value of the asset group by determining the replacement cost of the underlying assets and then adjusting each of the asset categories to an estimated salvage value utilizing industry recognized price publications. In the third quarter of 2022, the final restructuring plan was approved, and the facility was subsequently decommissioned.
In the first quarter of 2025, the Ince facility was sold, including certain liabilities assumed by the buyer, and we recognized a loss of $23 million on the sale. The loss is reflected in U.K. operations restructuring in our consolidated statement of operations for the year ended December 31, 2025.
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7. Goodwill and Other Intangible Assets
Goodwill
The following table shows the carrying amount of goodwill by reportable segment as of December 31, 2025 and 2024:

| Ammonia |  | Granular Urea |  | UAN |  | AN |  | Other |  | Total
| (in millions)
Balance as of December 31, 2024 | $ | 980 |  |  | $ | 828 |  |  | $ | 576 |  |  | $ | 69 |  |  | $ | 39 |  |  | $ | 2,492 |
Effect of exchange rate changes | 1 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 1 |
Balance as of December 31, 2025 | $ | 981 |  |  | $ | 828 |  |  | $ | 576 |  |  | $ | 69 |  |  | $ | 39 |  |  | $ | 2,493 |

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 complex. 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 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 for additional information.
Other Intangible Assets
All of our identifiable intangible assets have definite lives and are presented on our consolidated balance sheets at gross carrying amount, net of accumulated amortization, as follows:

| December 31, 2025 |  | December 31, 2024
| Gross Carrying Amount |  | Accumulated Amortization |  | Net |  | Gross Carrying Amount |  | Accumulated Amortization |  | Net
| (in millions)
Customer relationships | $ | 505 |  |  | $ | (91) |  |  | $ | 414 |  |  | $ | 505 |  |  | $ | (66) |  |  | $ | 439 |
Personal property tax agreement | 71 |  |  | (12) |  |  | 59 |  |  | 71 |  |  | (6) |  |  | 65 |
Carbon credits | — |  |  | — |  |  | — |  |  | 3 |  |  | — |  |  | 3 |
Total intangible assets | $ | 576 |  |  | $ | (103) |  |  | $ | 473 |  |  | $ | 579 |  |  | $ | (72) |  |  | $ | 507 |

Our customer relationships are being amortized over a weighted-average life of approximately 20 years. The intangible asset related to a favorable personal property tax agreement is being amortized over 12 years, representing the remaining term of the agreement as of December 1, 2023, the date of our acquisition of the Waggaman ammonia production facility.
For the years ended December 31, 2025, 2024 and 2023, amortization expense of our definite-lived intangible assets was approximately $32 million, $32 million and $5 million, respectively. Total estimated amortization expense for each of the five succeeding fiscal years is as follows:

| Estimated Amortization Expense
| (in millions)
2026 | $ | 32 |
2027 | 32 |
2028 | 30 |
2029 | 29 |
2030 | 29 |

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8. Equity Method Investment
We have a 50% ownership interest in PLNL, which operates an ammonia production facility in Trinidad. We include our share of the net earnings from this equity method investment as an element of earnings from operations because PLNL provides additional production to our operations and is integrated with our other supply chain and sales activities in the Ammonia segment.
PLNL 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 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.
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. As of December 31, 2025, the total carrying value of our equity method investment in PLNL was $32 million.
In the third quarter of 2023, PLNL entered into the NGC Contract, which replaced the previous gas sales contract that PLNL had with NGC. Due to the terms of the NGC Contract, in the third quarter of 2023, we assessed our investment in PLNL for impairment and determined that the carrying value of our equity method investment in PLNL exceeded its fair value. As a result, we recorded an impairment of our equity method investment in PLNL of $43 million, which is reflected in equity in earnings (loss) of operating affiliate on our consolidated statement of operations for the year ended December 31, 2023.
We have transactions in the normal course of business with PLNL reflecting our obligation to purchase 50% of the ammonia produced by PLNL at current market prices. Our ammonia purchases from PLNL totaled $120 million, $90 million and $142 million in 2025, 2024 and 2023, respectively.
9. Fair Value Measurements
Our cash and cash equivalents and other investments consist of the following:

| December 31, 2025
| Cost Basis |  | Unrealized Gains |  | Unrealized Losses |  | Fair Value
| (in millions)
Cash | $ | 629 |  |  | $ | — |  |  | $ | — |  |  | $ | 629 |
Cash equivalents: |  |  |  |  |  |  |
U.S. and Canadian government obligations | 284 |  |  | — |  |  | — |  |  | 284 |
Other debt securities | 1,069 |  |  | — |  |  | — |  |  | 1,069 |
Total cash and cash equivalents | $ | 1,982 |  |  | $ | — |  |  | $ | — |  |  | $ | 1,982 |
Nonqualified employee benefit trusts | 15 |  |  | 3 |  |  | — |  |  | 18 |

| December 31, 2024
| Cost Basis |  | Unrealized Gains |  | Unrealized Losses |  | Fair Value
| (in millions)
Cash | $ | 168 |  |  | $ | — |  |  | $ | — |  |  | $ | 168 |
Cash equivalents: |  |  |  |  |  |  |
U.S. and Canadian government obligations | 932 |  |  | — |  |  | — |  |  | 932 |
Other debt securities | 514 |  |  | — |  |  | — |  |  | 514 |
Total cash and cash equivalents | $ | 1,614 |  |  | $ | — |  |  | $ | — |  |  | $ | 1,614 |
Nonqualified employee benefit trusts | 15 |  |  | 2 |  |  | — |  |  | 17 |

Under our short-term investment policy, we may invest our cash balances, either directly or through mutual funds, in several types of investment-grade securities, including notes and bonds issued by governmental entities or corporations and also in bank deposits. Securities issued by governmental entities include those issued directly by the U.S. and Canadian federal
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governments; those issued by state, local or other governmental entities; and those guaranteed by entities affiliated with governmental entities.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
The following tables present assets and liabilities included in our consolidated balance sheets as of December 31, 2025 and 2024 that are recognized at fair value on a recurring basis, and indicate the fair value hierarchy utilized to determine such fair value:

| December 31, 2025
| Total Fair Value |  | Quoted Prices in Active Markets (Level 1) |  | Significant Other Observable Inputs (Level 2) |  | Significant Unobservable Inputs (Level 3)
| (in millions)
Cash equivalents | $ | 1,353 |  |  | $ | 1,353 |  |  | $ | — |  |  | $ | — |
Nonqualified employee benefit trusts | 18 |  |  | 18 |  |  | — |  |  | — |
Derivative assets | 1 |  |  | — |  |  | 1 |  |  | — |
Derivative liabilities | (5) |  |  | — |  |  | (5) |  |  | — |

| December 31, 2024
| Total Fair Value |  | Quoted Prices in Active Markets (Level 1) |  | Significant Other Observable Inputs (Level 2) |  | Significant Unobservable Inputs (Level 3)
| (in millions)
Cash equivalents | $ | 1,446 |  |  | $ | 1,446 |  |  | $ | — |  |  | $ | — |
Nonqualified employee benefit trusts | 17 |  |  | 17 |  |  | — |  |  | — |
Derivative assets | 4 |  |  | — |  |  | 4 |  |  | — |
Derivative liabilities | (3) |  |  | — |  |  | (3) |  |  | — |

Cash Equivalents
Cash equivalents include highly liquid investments that are readily convertible to known amounts of cash and have original maturities of three months or less. As of December 31, 2025 and 2024, our cash equivalents consisted primarily of U.S. and Canadian government obligations and money market mutual funds that invest in U.S. government obligations and other investment-grade securities.
Nonqualified Employee Benefit Trusts
We maintain trusts associated with certain nonqualified supplemental pension plans. The fair values of the trust assets are based on daily quoted prices in an active market and are included on our consolidated balance sheets in other assets. Debt securities are accounted for as available-for-sale securities, and changes in fair value are reported in other comprehensive income. Changes in the fair value of available-for-sale equity securities in the trust assets are recognized through earnings.
Derivative Instruments
The derivative instruments that we use are primarily natural gas fixed price swaps, basis swaps and options traded in the OTC markets with multi-national commercial banks, other major financial institutions or large energy companies. The natural gas derivative contracts represent anticipated natural gas needs for future periods, and settlements are scheduled to coincide with anticipated natural gas purchases during those future periods. The natural gas derivative contracts settle using primarily a NYMEX futures price index. To determine the fair value of these instruments, we use quoted market prices from NYMEX and standard pricing models with inputs derived from or corroborated by observable market data such as forward curves supplied by an industry-recognized independent third party. See Note 16—Derivative Financial Instruments for additional information.
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Financial Instruments
The carrying amount and estimated fair value of our financial instruments are as follows:

| December 31, 2025 |  | December 31, 2024
| Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value
| (in millions)
Long-term debt | $ | 3,215 |  |  | $ | 3,131 |  |  | $ | 2,971 |  |  | $ | 2,827 |

The fair value of our long-term debt was based on quoted prices for identical or similar liabilities in markets that are not active or valuation models in which all significant inputs and value drivers are observable and, as a result, they are classified as Level 2 inputs.
The carrying amounts of cash and cash equivalents, as well as any instruments included in other current assets and other current liabilities that meet the definition of financial instruments, approximate fair values because of their short-term maturities.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
We also have assets and liabilities that may be measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on a recurring basis, but are subject to fair value adjustments in certain circumstances, such as when there is evidence of impairment, when there is allocation of purchase price in an acquisition or when a new liability is being established that requires fair value measurement. These include long-lived assets, goodwill and other intangible assets and investments in unconsolidated subsidiaries, such as equity method investments, which may be written down to fair value as a result of impairment. The fair value measurements related to assets and liabilities measured at fair value on a nonrecurring basis rely primarily on Company-specific inputs. Since certain of the Company’s assumptions would involve inputs that are not observable, these fair values would reside within Level 3 of the fair value hierarchy.
In the fourth quarter of 2025, we recorded asset impairment charges related to property, plant and equipment at our Donaldsonville and Yazoo City facilities. See Note 6—Property, Plant and Equipment—Net for additional information.
In 2023, we determined the carrying value of our equity method investment in PLNL exceeded its fair value and recorded an impairment of our equity method investment in PLNL of $43 million. See Note 8—Equity Method Investment for additional information.
10. Income Taxes
The components of earnings before income taxes and the components of our income tax provision are as follows:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Domestic | $ | 2,031 |  |  | $ | 1,533 |  |  | $ | 2,248 |
Non-U.S. | 208 |  |  | 229 |  |  | — |
Earnings before income taxes | $ | 2,239 |  |  | $ | 1,762 |  |  | $ | 2,248 |

Current |  |  |  |  |
Federal | $ | 328 |  |  | $ | 312 |  |  | $ | 271 |
Foreign | 61 |  |  | 42 |  |  | (26) |
State | 46 |  |  | 46 |  |  | 84 |
| 435 |  |  | 400 |  |  | 329 |
Deferred |  |  |  |  |
Federal | 15 |  |  | (89) |  |  | 108 |
Foreign | (9) |  |  | 3 |  |  | (5) |
State | — |  |  | (29) |  |  | (22) |
| 6 |  |  | (115) |  |  | 81 |
Income tax provision | $ | 441 |  |  | $ | 285 |  |  | $ | 410 |

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Differences in the expected income tax provision based on statutory rates applied to earnings before income taxes and the income tax provision reflected in the consolidated statements of operations are summarized below.

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions, except percentages)
Earnings before income taxes | $ | 2,239 |  |  |  |  | $ | 1,762 |  |  |  |  | $ | 2,248 |  |  |
Expected tax provision at U.S. statutory rate of 21% | $ | 470 |  |  | 21.0 | % |  | $ | 370 |  |  | 21.0 | % |  | $ | 472 |  |  | 21.0 | %
Domestic federal reconciling items: |  |  |  |  |  |  |  |  |  |  |
Tax credits | (6) |  |  | (0.3) | % |  | (3) |  |  | (0.2) | % |  | (16) |  |  | (0.7) | %
Nontaxable or nondeductible items: |  |  |  |  |  |  |  |  |  |  |
Net earnings attributable to noncontrolling interests | (72) |  |  | (3.2) | % |  | (54) |  |  | (3.1) | % |  | (66) |  |  | (2.9) | %
Other | (1) |  |  | — | % |  | 6 |  |  | 0.3 | % |  | (3) |  |  | (0.1) | %
Effect of cross-border tax laws | 1 |  |  | — | % |  | 1 |  |  | 0.1 | % |  | 3 |  |  | 0.1 | %
Changes in valuation allowances | 4 |  |  | 0.2 | % |  | 2 |  |  | 0.1 | % |  | 10 |  |  | 0.4 | %
Other: |  |  |  |  |  |  |  |  |  |  |
Foreign-derived intangible income deduction | (27) |  |  | (1.2) | % |  | (27) |  |  | (1.5) | % |  | (20) |  |  | (0.9) | %
Other | 2 |  |  | 0.1 | % |  | 1 |  |  | 0.1 | % |  | 1 |  |  | 0.1 | %
State and local income tax, net of federal income tax effect(1) | 35 |  |  | 1.6 | % |  | 10 |  |  | 0.6 | % |  | 53 |  |  | 2.4 | %
Foreign tax effects | 14 |  |  | 0.6 | % |  | (5) |  |  | (0.3) | % |  | (13) |  |  | (0.6) | %
Changes in unrecognized tax benefits | 21 |  |  | 0.9 | % |  | (16) |  |  | (0.9) | % |  | (11) |  |  | (0.5) | %
Income tax provision | $ | 441 |  |  |  |  | $ | 285 |  |  |  |  | $ | 410 |  |  |
Effective tax rate | 19.7 | % |  |  |  | 16.2 | % |  |  |  | 18.3 | % |  |

______________________________________________________________________________
(1)In both 2025 and 2024, state and local income taxes in Illinois, Iowa, Louisiana, and Minnesota comprise the majority of the state and local income tax, net of federal income tax effect category. In 2023, state and local income taxes in Illinois, Iowa and Minnesota comprise the majority of the state and local income tax, net of federal income tax effect category.
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. As a result, earnings attributable to the noncontrolling interests of $343 million, $259 million and $313 million in 2025, 2024 and 2023, respectively, which are included in earnings before income taxes, impacted the effective tax rate in all three years. See Note 18—Noncontrolling Interests for additional information.
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 resulting in total payments of $224 million, which also reflect the impact of changes in foreign currency exchange rates.
In 2023, due primarily to the availability of additional foreign tax credits to offset in part the increased Canadian tax referenced above, we filed amended tax returns in the United States to request a refund of taxes paid.
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 CRA portion of the interest relief 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
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interest income. 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.
Deferred Taxes
Deferred tax assets and deferred tax liabilities are as follows:

| December 31,
| 2025 |  | 2024
| (in millions)
Deferred tax assets: |  |  |
Net operating loss and capital loss carryforwards, state | $ | 54 |  |  | $ | 56 |
Net operating loss and capital loss carryforwards, foreign | 56 |  |  | 49 |
Retirement and other employee benefits | 8 |  |  | 2 |
Foreign tax credits | 61 |  |  | 57 |
State tax credits | 14 |  |  | 11 |
Operating lease liabilities | 100 |  |  | 66 |
Other | 46 |  |  | 34 |
| 339 |  |  | 275 |
Valuation allowance | (118) |  |  | (107) |
| 221 |  |  | 168 |
Deferred tax liabilities: |  |  |
Depreciation and amortization | (291) |  |  | (273) |
Investments in partnerships | (647) |  |  | (659) |
Operating lease right-of-use assets | (98) |  |  | (63) |
Foreign earnings | (21) |  |  | (14) |
Other | (33) |  |  | (30) |
| (1,090) |  |  | (1,039) |
Net deferred tax liability | $ | (869) |  |  | $ | (871) |

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.
As of December 31, 2025, our net operating loss and capital loss carryforwards consist primarily of state net operating loss carryforwards of $53 million, of which $14 million will expire at various dates between 2036 and 2044 and the remaining $39 million can be carried forward indefinitely, and foreign capital loss carryforwards of $55 million, which can be carried forward indefinitely. Our foreign subsidiaries have operations that do not normally generate capital gains and have no practical plans to do so in the future. As a result, we have recorded a full valuation allowance against all foreign capital loss carryforwards.
As of December 31, 2025, we have state tax credit carryforwards resulting in a deferred tax asset of $14 million. The state tax credits can be carried forward indefinitely.
In 2025, the net increase in the valuation allowance is primarily attributable to an increase of $5 million in a capital loss carryforward and associated valuation allowance generated from the loss on sale of the Ince facility, and an increase of $4 million in excess foreign tax credits associated with certain U.S. taxed foreign branch income. The excess foreign tax credits carried forward, subject to U.S. foreign tax credit limitation rules, are not expected to be utilized prior to expiration and have a full valuation allowance. See Note 6—Property, Plant and Equipment—Net for additional information on the sale of our Ince facility.
In 2024, the net decrease in the valuation allowance is primarily attributable to a reduction of $83 million in a capital loss carryforward and the associated valuation allowance for one of our foreign subsidiaries in Canada. Additionally, based on income generated in the United Kingdom and the reversal of deferred tax assets, the remaining valuation allowance originally recorded in 2022 for one of our foreign subsidiaries in the United Kingdom was released in 2024, resulting in an $11 million decrease to the valuation allowance. Both of these decreases were partially offset by the impact of changes in foreign currency exchange rates.
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In 2023, the net increase in the valuation allowance is primarily attributable to excess foreign tax credits associated with certain U.S. taxed foreign branch income and the impact of changes in foreign currency exchange rates, partially offset by the utilization of deferred tax assets of one of our foreign subsidiaries in the United Kingdom. The excess foreign tax credits carried forward, subject to U.S. foreign tax credit limitation rules, are not expected to be utilized prior to expiration and have a full valuation allowance of $55 million reflecting an increase of $11 million in 2023. Based on recent income generated in the United Kingdom, a portion of the deferred tax assets for which a full valuation allowance had been recorded in 2022 was utilized in 2023, resulting in a $7 million decrease to the deferred tax assets and the valuation allowance of one of our foreign subsidiaries in the United Kingdom.
Unrecognized Tax Benefits
A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

| December 31,
| 2025 |  | 2024
| (in millions)
Unrecognized tax benefits: |  |  |
Balance as of January 1 | $ | 230 |  |  | $ | 222 |
Additions for tax positions taken during the current year | 8 |  |  | 1 |
Additions for tax positions taken during prior years | 53 |  |  | 7 |
Reductions related to lapsed statutes of limitations | — |  |  | — |
Reductions related to settlements with tax jurisdictions | (3) |  |  | — |
Balance as of December 31 | $ | 288 |  |  | $ | 230 |

In 2025, we increased the amount of our unrecognized tax benefit by $58 million, which primarily relate to U.S. tax positions under the Internal Revenue Service audit and refunds claimed on amended state tax returns. As of December 31, 2025, we had $288 million of unrecognized tax benefits.
The majority of our unrecognized tax benefits as of December 31, 2025 relate to transfer pricing positions for tax years after 2011 for certain of our Canadian subsidiaries which were accepted for consideration under the bilateral settlement provisions of the U.S.-Canada tax treaty by the United States and Canadian competent authorities. These unrecognized tax benefits have corollary receivables for the other jurisdiction impacted by the transfer pricing relationship, which are recorded as noncurrent income tax receivables and included in other assets on our consolidated balance sheet. Recognizing these unrecognized tax benefits would result in additional tax expense of $1 million in the future. In addition, in order to mitigate the assessment of future Canadian interest on these Canadian transfer pricing positions, we made payments to the Canadian taxing authorities of CAD $363 million (approximately $267 million) in 2022, which are recorded as noncurrent income tax receivables and included in other assets on our consolidated balance sheet. For the amounts ultimately owed and paid to the Canadian tax authorities upon resolution of these tax years after 2011, the Company would seek refunds of related taxes paid in the United States.
In 2024, we increased the amount of our unrecognized tax benefit by $8 million, which primarily relates to transfer pricing positions.
In 2023, we increased the amount of our unrecognized tax benefits by $74 million, which primarily relates to refunds claimed on the U.S. amended returns filed during the year, as discussed above under Canada Revenue Agency Competent Authority Matter. In addition, we reduced the amount of unrecognized tax benefits by $33 million, reflecting primarily the settlement of issues raised on state and Canadian income tax audits for various open tax years.
We file federal, provincial, state and local income tax returns principally in the United States, Canada and the United Kingdom, as well as in certain other foreign jurisdictions. In general, filed tax returns remain subject to examination by United States tax jurisdictions for years 2017 and thereafter, by Canadian tax jurisdictions for years 2012 and thereafter, and by the United Kingdom for years 2022 and thereafter.
Interest expense and penalties related to our unrecognized tax benefits of $7 million, $8 million and $(4) million were recorded for the years ended December 31, 2025, 2024 and 2023, respectively. As of December 31, 2025, amounts recognized in our consolidated balance sheet for accrued interest and penalties related to our unrecognized tax benefits was $69 million, of which $58 million is included in other liabilities and $11 million is included as a reduction to other assets. As of December 31, 2024, amounts recognized in our consolidated balance sheet for accrued interest and penalties related to our unrecognized tax benefits was $55 million, which was included in other liabilities.
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11. Pension and Other Postretirement Benefits
We maintain five funded pension plans, consisting of three in North America (one U.S. plan and two Canadian plans) and two in the United Kingdom. We also provide group medical insurance benefits, which vary by group and location, to certain retirees in North America. In connection with a revision to our retirement plan strategy, we have completed certain plan amendments and annuity purchases, as described below, intended to ultimately terminate and fully settle all five pension plans in accordance with applicable local regulatory requirements.
Both U.K. pension plans have been closed to new employees and future accruals. In the fourth quarter of 2022, we executed amendments to our North America pension plans, which, among other things, closed the cash balance portion of the U.S. plan that provided benefits based on years of service and interest credits, effective December 31, 2022, and established effective dates for each of the three North America plans to freeze future benefit accruals through the end of 2025. As a result, as of December 31, 2025, all of our North America plans are closed to new employees and future accruals.
In the third quarter of 2025, we amended two of our North America pension plans to terminate each plan effective December 31, 2025.
Purchase of Annuity Contracts in the United Kingdom
During the fourth quarter of 2025, the U.K. pension plan trustees purchased non-participating group buy-in annuity contracts from an insurance company for approximately $349 million. This transaction was funded directly by assets of the pension plans. Under the terms of the annuity contracts, the insurer makes periodic payments to the pension plans equal to the benefits covered by the contracts. The annuity contracts are recognized as plan assets and presented as “Buy-in annuity contracts” in the December 31, 2025 United Kingdom pension plan assets table, below.
Purchase of Annuity Contracts in Canada
For one of our Canadian plans, during the fourth quarter of 2025, we purchased a non-participating group buy-out annuity contract and transferred approximately $40 million, or 94%, of the plan’s liabilities to an insurance company. This transaction was funded with plan assets and reflected as “Pension annuity purchase” in the table below. Under the transaction, the insurance company assumed responsibility for pension benefits and annuity administration for over 200 participants, primarily retirees or their beneficiaries. As a result of this transaction, in the fourth quarter of 2025, we remeasured the plan’s projected benefit obligation and plan assets and recognized a non-cash pre-tax pension settlement loss of $1 million, reflecting the unamortized net unrecognized postretirement benefit costs related to the settled obligations, with a corresponding offset to accumulated other comprehensive loss. For the remaining portion of plan liabilities, we purchased a non-participating group buy-in annuity contract from the insurance company. Under the terms of the annuity contract, the insurer makes periodic payments to the plan equal to the benefits covered by the contract. This annuity contract is recognized as a plan asset and included in the line “Buy-in annuity contracts” in the December 31, 2025 North American pension plan assets table, below.
For the other Canadian pension plan, during the fourth quarter of 2025, we purchased a non-participating group buy-in annuity contract from the insurance company for approximately $60 million. This transaction was funded with plan assets. Under the terms of the annuity contract, the insurer makes periodic payments to the plan equal to the benefits covered by the contract. This annuity contract is recognized as a plan asset and included in the line “Buy-in annuity contracts” in the December 31, 2025 North American pension plan assets table, below.
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Our plan assets, benefit obligations, funded status and amounts recognized on our consolidated balance sheets for our North America and United Kingdom plans as of the December 31 measurement date are as follows:

| Pension Plans |  | Retiree Medical Plans
| North America |  | United Kingdom |  | North America
| December 31, |  | December 31, |  | December 31,
| 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2025 |  | 2024
| (in millions)
Change in plan assets |  |  |  |  |  |  |  |  |  |  |
Fair value of plan assets as of January 1 | $ | 299 |  |  | $ | 313 |  |  | $ | 345 |  |  | $ | 360 |  |  | $ | — |  |  | $ | — |
Return on plan assets | 24 |  |  | 10 |  |  | 9 |  |  | (7) |  |  | — |  |  | — |
Employer contributions | (2) |  |  | — |  |  | 1 |  |  | 22 |  |  | 2 |  |  | 2 |
Pension annuity purchase | (39) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Benefit payments | (14) |  |  | (13) |  |  | (24) |  |  | (24) |  |  | (2) |  |  | (2) |
Foreign currency translation | 5 |  |  | (11) |  |  | 26 |  |  | (6) |  |  | — |  |  | — |
Fair value of plan assets as of December 31 | 273 |  |  | 299 |  |  | 357 |  |  | 345 |  |  | — |  |  | — |
Change in benefit obligation |  |  |  |  |  |  |  |  |  |  |
Benefit obligation as of January 1 | (278) |  |  | (292) |  |  | (317) |  |  | (367) |  |  | (19) |  |  | (20) |
Service cost | (4) |  |  | (5) |  |  | — |  |  | — |  |  | — |  |  | — |
Interest cost | (14) |  |  | (13) |  |  | (18) |  |  | (16) |  |  | (1) |  |  | (1) |
Benefit payments | 14 |  |  | 13 |  |  | 24 |  |  | 24 |  |  | 2 |  |  | 2 |
Foreign currency translation | (4) |  |  | 9 |  |  | (24) |  |  | 5 |  |  | — |  |  | — |
Pension annuity purchase | 40 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Change in assumptions and other | (18) |  |  | 10 |  |  | — |  |  | 37 |  |  | (1) |  |  | — |
Benefit obligation as of December 31 | (264) |  |  | (278) |  |  | (335) |  |  | (317) |  |  | (19) |  |  | (19) |
Funded status as of December 31 | $ | 9 |  |  | $ | 21 |  |  | $ | 22 |  |  | $ | 28 |  |  | $ | (19) |  |  | $ | (19) |

For our North America pension plans, the line titled “change in assumptions and other” for 2025 primarily reflects the impact of an increase in the U.S. plan’s projected benefit obligation to its estimated plan termination liability and, for 2024, primarily reflects the impact of gains due to the increase in discount rates, partially offset by the increase in the interest crediting rate for the cash balance portion of the U.S. plan.
For our United Kingdom pension plans, the line titled “change in assumptions and other” for 2024 primarily reflects gain s due to the increase in discount rates.
Amounts recognized on the consolidated balance sheets consist of the following:

| Pension Plans |  | Retiree Medical Plans
| North America |  | United Kingdom |  | North America
| December 31, |  | December 31, |  | December 31,
| 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2025 |  | 2024
| (in millions)
Other assets | $ | 18 |  |  | $ | 21 |  |  | $ | 22 |  |  | $ | 28 |  |  | $ | — |  |  | $ | — |
Accounts payable and accrued expenses | — |  |  | — |  |  | — |  |  | — |  |  | (2) |  |  | (2) |
Other current liabilities | (9) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Other liabilities | — |  |  | — |  |  | — |  |  | — |  |  | (17) |  |  | (17) |
| $ | 9 |  |  | $ | 21 |  |  | $ | 22 |  |  | $ | 28 |  |  | $ | (19) |  |  | $ | (19) |

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Pre-tax amounts recognized in accumulated other comprehensive loss consist of the following:

| Pension Plans |  | Retiree Medical Plans
| North America |  | United Kingdom |  | North America
| December 31, |  | December 31, |  | December 31,
| 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2025 |  | 2024
| (in millions)
Prior service cost | $ | — |  |  | $ | — |  |  | $ | 1 |  |  | $ | 1 |  |  | $ | — |  |  | $ | — |
Net actuarial loss (gain) | 4 |  |  | (3) |  |  | 94 |  |  | 71 |  |  | (3) |  |  | (5) |
| $ | 4 |  |  | $ | (3) |  |  | $ | 95 |  |  | $ | 72 |  |  | $ | (3) |  |  | $ | (5) |

Net periodic benefit cost (income) and other amounts recognized in other comprehensive (income) loss for the years ended December 31 included the following:

| Pension Plans |  | Retiree Medical Plans
| North America |  | United Kingdom |  | North America
| 2025 |  | 2024 |  | 2023 |  | 2025 |  | 2024 |  | 2023 |  | 2025 |  | 2024 |  | 2023
| (in millions)
Service cost | $ | 4 |  |  | $ | 5 |  |  | $ | 5 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Interest cost | 14 |  |  | 13 |  |  | 13 |  |  | 18 |  |  | 16 |  |  | 16 |  |  | 1 |  |  | 1 |  |  | 1 |
Expected return on plan assets | (16) |  |  | (16) |  |  | (15) |  |  | (27) |  |  | (28) |  |  | (25) |  |  | — |  |  | — |  |  | — |
Settlement loss | 1 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Amortization of actuarial gain | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (1) |
Net periodic benefit cost (income) | 3 |  |  | 2 |  |  | 3 |  |  | (9) |  |  | (12) |  |  | (9) |  |  | 1 |  |  | 1 |  |  | — |
Net actuarial loss (gain) | 8 |  |  | (4) |  |  | (6) |  |  | 17 |  |  | (1) |  |  | 14 |  |  | 2 |  |  | 1 |  |  | (2) |
Settlement loss | (1) |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Amortization of actuarial gain | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 1 |
Total recognized in other comprehensive loss (income) | 7 |  |  | (4) |  |  | (6) |  |  | 17 |  |  | (1) |  |  | 14 |  |  | 2 |  |  | 1 |  |  | (1) |
Total recognized in net periodic benefit cost (income) and other comprehensive loss (income) | $ | 10 |  |  | $ | (2) |  |  | $ | (3) |  |  | $ | 8 |  |  | $ | (13) |  |  | $ | 5 |  |  | $ | 3 |  |  | $ | 2 |  |  | $ | (1) |

Service cost is recognized in cost of sales and selling, general and administrative expenses, and the other components of net periodic benefit cost are recognized in other non-operating—net in our consolidated statements of operations.
The accumulated benefit obligation (ABO) in aggregate for the defined benefit pension plans in North America was approximately $264 million and $277 million as of December 31, 2025 and 2024, respectively. The ABO in aggregate for the defined benefit pension plans in the United Kingdom was approximately $335 million and $317 million as of December 31, 2025 and 2024, respectively. As of December 31, 2025, the ABO for all five of our defined benefit pension plans was equal to each plan’s projected benefit obligation (PBO) as all future benefit accruals were frozen on or before December 31, 2025.
The following table presents aggregated information for those individual defined benefit pension plans that have an ABO in excess of plan assets or a PBO in excess of plan assets as of December 31, which excludes four of the defined benefit pension plans in 2025, and for 2024, excludes all five of the defined benefit pension plans:

| North America |  | United Kingdom
| 2025 |  | 2024 |  | 2025 |  | 2024
| (in millions)
Accumulated benefit obligation | $ | 194 |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Projected benefit obligation | 194 |  |  | — |  |  | — |  |  | — |
Fair value of plan assets | 185 |  |  | — |  |  | — |  |  | — |

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Our pension funding policy in North America is to contribute amounts sufficient to meet minimum legal funding requirements plus discretionary amounts that we may deem to be appropriate. Actual contributions may vary from estimated amounts depending on changes in assumptions, actual returns on plan assets, changes in regulatory requirements and funding decisions.
In accordance with United Kingdom pension legislation, our United Kingdom pension funding policy is to contribute amounts sufficient to meet the funding level target agreed between the employer and the trustees of the United Kingdom plans. Actual contributions are usually agreed with the plan trustees in connection with each triennial valuation and may vary following each such review depending on changes in assumptions, actual returns on plan assets, changes in regulatory requirements and funding decisions. As a result of the buy-in annuity contracts purchased in the fourth quarter of 2025, as discussed above, revised agreements were executed with the plan trustees and cover contributions solely towards each plan’s administrative expenses payable from January 1, 2026 to December 31, 2030, as no additional funding contributions are expected. These administrative expenses are not expected to be material.
We currently estimate that our consolidated pension funding cash contributions for 2026 will be approximately $9 million consisting solely of estimated cash contributions for our U.S. pension plan.
The expected future benefit payments for our pension and retiree medical plans are as follows:

| Pension Plans |  | Retiree Medical Plans
| North America |  | United Kingdom |  | North America
| (in millions)
2026(1) | $ | 263 |  |  | $ | 26 |  |  | $ | 2 |
2027 | — |  |  | 27 |  |  | 2 |
2028 | — |  |  | 27 |  |  | 2 |
2029 | — |  |  | 28 |  |  | 2 |
2030 | — |  |  | 28 |  |  | 2 |
2031-2035 | 10 |  |  | 153 |  |  | 6 |

_______________________________________________________________________________
(1)As of December 31, 2025, the majority of expected future benefit payments for our North American pension plans are projected to occur in 2026 due to the effective plan termination on December 31, 2025 for two of our North American plans.
The following assumptions were used in determining the benefit obligations and expense:

| Pension Plans |  |  |  |  |  | Retiree Medical Plans
| North America |  | United Kingdom |  |  |  | North America
| 2025 |  | 2024 |  | 2023 |  | 2025 |  | 2024 |  | 2023 |  |  |  |  |  | 2025 |  | 2024 |  | 2023
Weighted-average discount rate—obligation | 4.2 | % |  | 5.2 | % |  | 4.8 | % |  | 5.5 | % |  | 5.5 | % |  | 4.6 | % |  |  |  |  |  | 5.1 | % |  | 5.4 | % |  | 4.8 | %
Weighted-average discount rate—expense | 5.2 | % |  | 4.8 | % |  | 5.1 | % |  | 5.5 | % |  | 4.6 | % |  | 4.8 | % |  |  |  |  |  | 5.4 | % |  | 4.8 | % |  | 5.0 | %
Weighted-average cash balance interest crediting rate—obligation | 3.8 | % |  | 4.4 | % |  | 3.9 | % |  | n/a |  | n/a |  | n/a |  |  |  |  |  | n/a |  | n/a |  | n/a
Weighted-average cash balance interest crediting rate—expense | 4.4 | % |  | 3.9 | % |  | 3.9 | % |  | n/a |  | n/a |  | n/a |  |  |  |  |  | n/a |  | n/a |  | n/a
Weighted-average rate of increase in future compensation | n/a |  | 3.3 | % |  | 3.3 | % |  | n/a |  | n/a |  | n/a |  |  |  |  |  | n/a |  | n/a |  | n/a
Weighted-average expected long-term rate of return on assets—expense | 5.1 | % |  | 5.0 | % |  | 4.8 | % |  | 6.1 | % |  | 6.5 | % |  | 6.1 | % |  |  |  |  |  | n/a |  | n/a |  | n/a
Weighted-average retail price index—obligation | n/a |  | n/a |  | n/a |  | 2.8 | % |  | 3.1 | % |  | 3.0 | % |  |  |  |  |  | n/a |  | n/a |  | n/a
Weighted-average retail price index—expense | n/a |  | n/a |  | n/a |  | 3.1 | % |  | 3.0 | % |  | 3.2 | % |  |  |  |  |  | n/a |  | n/a |  | n/a

______________________________________________________________________________
n/a—not applicable
The discount rates for all plans are developed by plan using spot rates derived from a hypothetical yield curve of high quality (AA rated or better) fixed income debt securities as of the year-end measurement date to calculate discounted cash flows (the projected benefit obligation) and solving for a single equivalent discount rate that produces the same projected benefit obligation. In determining our benefit obligation, we use the actuarial present value of the vested benefits to which each eligible
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employee is currently entitled, based on the employee’s expected date of separation or retirement. For the two North American plans with effective termination dates of December 31, 2025, the project benefit obligations were determined on a settlement basis taking into account the estimated plan termination liability.
Prior to December 31, 2025, the cash balance interest crediting rate for the U.S. plan was based on the greater of 10-year Treasuries or 3.0%. Given the pending plan termination, the interest crediting rate after the December 31, 2025 termination date is set at the 5-year average of the plan’s cash balance interest crediting rate prior to the plan termination date, which is the basis for the 2025 assumption of 3.8% shown in the table above.
For our North American plans, the expected long-term rate of return on assets is based on analysis of historical rates of return achieved by equity and non-equity investments and current market characteristics, adjusted for estimated plan expenses and weighted by target asset allocation percentages as applicable. As of January 1, 2026, our weighted-average expected long-term rate of return on assets for our North American plans is 4.5%, which will be used in determining net periodic benefit cost for our North American plans for 2026.
For our United Kingdom plans, the expected long-term rate of return on assets is based on the expected long-term performance of the underlying investments, adjusted for investment managers’ fees and estimated plan expenses. As of January 1, 2026, our weighted-average expected long-term rate of return on assets for our United Kingdom plans is 4.8%, which will be used in determining net periodic benefit cost for our United Kingdom plans for 2026.
The retail price index for our United Kingdom plans is developed using a U.K. Government Gilt Prices Only retail price inflation curve, which is based on the difference between yields on fixed interest government bonds and index-linked government bonds.
For the measurement of the benefit obligation at December 31, 2025 for our primary (U.S.) retiree medical benefit plans, the assumed health care cost trend rates, for pre-age 65 retirees, start with an 8.0% increase in 2026, followed by a gradual decline in increases to 4.5% for 2035 and thereafter. For post-age 65 retirees, the assumed health care cost trend rates start with a 9.3% increase in 2026, followed by a gradual decline in increases to 4.5% for 2035 a nd thereafter. For the measurement of the benefit obligation at December 31, 2024 for our primary (U.S.) retiree medical benefit plans, the assumed health care cost trend rates, for pre-age 65 retirees, started with an 8.4% increase in 2025, followed by a gradual decline in increases to 4.5% for 2034 and thereafter. For post-age 65 retirees, the assumed health care cost trend rates started with a 9.8% increase in 2025, followed by a gradual decline in increases to 4.5% for 2034 and thereafter.
The objectives of the investment policies governing the pension plans are to administer the assets of the plans for the benefit of the participants in compliance with all laws and regulations, and to establish an asset mix that provides for diversification and considers the risk of various different asset classes with the purpose of generating favorable investment returns. The investment policies consider circumstances such as participant demographics, time horizon to retirement and liquidity needs, and provide guidelines for asset allocation, planning horizon, general portfolio issues and investment manager evaluation criteria. The investment strategies for the plans, including target asset allocations and investment vehicles, are subject to change within the guidelines of the policies. As a result of revisions to our retirement plan strategies, our plan assets and investment strategies were updated in the fourth quarter of 2025.
For our U.S. pension plan, the target asset allocation is 100% non-equity, which is generally determined based on analysis of actual historical rates of return and plan needs and circumstances. These investments consist primarily of money market instruments and investments in debt securities that are selected based on investment quality and duration to mitigate volatility of the funded status and annual required contributions. The non-equity investments have a duration profile that is similar to the benefit obligation in order to mitigate the impact of interest rate changes on the funded status. This investment strategy is achieved through the use of mutual funds and individual securities.
The plan assets for our Canadian plans and our United Kingdom plans primarily consist of non-participating group buy-in annuity contracts, as described above. These buy-in annuity contracts are effectively investment assets through which the plans receive payments from the insurers that correspond to the pension benefit payments due to covered participants of the plans. Because the buy-in annuity contracts represent large, illiquid assets for which valuation inputs are unobservable and significant judgment is required in developing assumptions that market participants would use in pricing the assets, they are classified as Level 3 investments within the fair value hierarchy, as reflected in the tables below.
Prior to the purchase of the buy-in annuity contracts in the fourth quarter of 2025, the target asset allocation for our Canadian plans was 100% non-equity, achieved through the use of individual securities. The investments consisted primarily of investments in debt securities selected based on investment quality and duration to mitigate volatility of the funded status and annual required contributions.
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Prior to the purchase of the buy-in annuity contracts in the fourth quarter of 2025, assets of the United Kingdom plans were invested in pooled funds managed by an investment manager appointed by the trustees. The assets were allocated between a growth portfolio and a matching portfolio. The growth portfolio sought a return premium on investments across multiple asset classes. The matching portfolio sought to align asset changes with changes in liabilities due to interest rates and inflation expectations. In 2024, the target asset allocation for one of the United Kingdom plans was 25% in the growth portfolio and 75% in the matching portfolio, and 30% in the growth portfolio and 70% in the matching portfolio for the other.
The fair values of our pension plan assets as of December 31, 2025 and 2024, by major asset class, are as follows:

| North America |  |  |
| December 31, 2025
| Total Fair Value |  | Quoted Prices in Active Markets (Level 1) |  | Significant Other Observable Inputs (Level 2) |  | Significant Unobservable Inputs (Level 3) |  |  |
| (in millions) |  |  |
Cash and cash equivalents(1) | $ | 99 |  |  | $ | — |  |  | $ | 99 |  |  | $ | — |  |  |  |
Short-term investments(2) | 25 |  |  | — |  |  | 25 |  |  | — |  |  |  |
Buy-in annuity contracts(3) | 63 |  |  | — |  |  | — |  |  | 63 |  |  |  |
Fixed income |  |  |  |  |  |  |  |  |  |
U.S. Treasury bonds and notes(4) | 12 |  |  | 12 |  |  | — |  |  | — |  |  |  |
Fixed income mutual funds(5) | 33 |  |  | 33 |  |  | — |  |  | — |  |  |  |
Corporate bonds and notes(6) | 35 |  |  | — |  |  | 35 |  |  | — |  |  |  |
Government and agency securities(7) | 2 |  |  | — |  |  | 2 |  |  | — |  |  |  |
Other(8) | 4 |  |  | — |  |  | 4 |  |  | — |  |  |  |
Total assets at fair value by fair value levels | $ | 273 |  |  | $ | 45 |  |  | $ | 165 |  |  | $ | 63 |  |  |  |

| United Kingdom |  |  |
| December 31, 2025
| Total Fair Value |  | Quoted Prices in Active Markets (Level 1) |  | Significant Other Observable Inputs (Level 2) |  | Significant Unobservable Inputs (Level 3) |  |  |
| (in millions) |  |  |
Cash and cash funds(9) | $ | 4 |  |  | $ | 3 |  |  | $ | 1 |  |  | $ | — |  |  |  |
Buy-in annuity contracts(3) | 352 |  |  | — |  |  | — |  |  | 352 |  |  |  |
Total assets at fair value by fair value levels | $ | 356 |  |  | $ | 3 |  |  | $ | 1 |  |  | $ | 352 |  |  |  |
Funds measured at NAV as a practical expedient(10) | 1 |  |  |  |  |  |  |  |  |  |
Total assets at fair value | $ | 357 |  |  |  |  |  |  |  |  |  |

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| North America
| December 31, 2024
| Total Fair Value |  | Quoted Prices in Active Markets (Level 1) |  | Significant Other Observable Inputs (Level 2) |  | Significant Unobservable Inputs (Level 3)
| (in millions)
Cash and cash equivalents(1) | $ | 2 |  |  | $ | 1 |  |  | $ | 1 |  |  | $ | — |
Equity mutual funds |  |  |  |  |  |  |
Index equity(11) | 41 |  |  | 41 |  |  | — |  |  | — |
Fixed income |  |  |  |  |  |  |
U.S. Treasury bonds and notes(4) | 14 |  |  | 14 |  |  | — |  |  | — |
Fixed income mutual funds(5) | 42 |  |  | 42 |  |  | — |  |  | — |
Corporate bonds and notes(6) | 100 |  |  | — |  |  | 100 |  |  | — |
Government and agency securities(7) | 90 |  |  | — |  |  | 90 |  |  | — |
Other(8) | 10 |  |  | — |  |  | 10 |  |  | — |
Total assets at fair value by fair value levels | $ | 299 |  |  | $ | 98 |  |  | $ | 201 |  |  | $ | — |

| United Kingdom |  |  |
| December 31, 2024
| Total Fair Value |  | Quoted Prices in Active Markets (Level 1) |  | Significant Other Observable Inputs (Level 2) |  | Significant Unobservable Inputs (Level 3) |  |  |
| (in millions) |  |  |
Cash and cash funds(9) | $ | 2 |  |  | $ | 1 |  |  | $ | 1 |  |  | $ | — |  |  |  |
Pooled equity funds(12) | 14 |  |  | — |  |  | 14 |  |  | — |  |  |  |
Pooled diversified funds(13) | 31 |  |  | — |  |  | 31 |  |  | — |  |  |  |
Debt funds |  |  |  |  |  |  |  |  |  |
Pooled U.K. government fixed and index-linked securities funds(14) | 78 |  |  | — |  |  | 78 |  |  | — |  |  |  |
Pooled global debt funds(15) | 124 |  |  | — |  |  | 124 |  |  | — |  |  |  |
Pooled liability-driven investment funds(16) | 52 |  |  | — |  |  | 52 |  |  | — |  |  |  |
Total assets at fair value by fair value levels | $ | 301 |  |  | $ | 1 |  |  | $ | 300 |  |  | $ | — |  |  |  |
Funds measured at NAV as a practical expedient(10) | 43 |  |  |  |  |  |  |  |  |  |
Total assets at fair value | $ | 344 |  |  |  |  |  |  |  |  |  |
Receivable from redemption | 1 |  |  |  |  |  |  |  |  |  |
Total assets | $ | 345 |  |  |  |  |  |  |  |  |  |

_______________________________________________________________________________
(1)Cash and cash equivalents are primarily short-term money market funds.
(2)Short-term investments represent investments in a pooled money market fund that invests primarily in Canadian-dollar denominated debt securities, maturing in no more than one year.
(3)The fair values of the buy-in annuity contracts are estimated based on their exit price, that is, the amount at which the contracts could be sold to a willing third-party buyer.
(4)U.S. Treasury bonds and notes are valued based on quoted market prices in an active market.
(5)The fixed income mutual funds invest primarily in high-quality longer duration fixed income securities, which include bonds, debt securities and other similar instruments. The funds are priced based on a daily published net asset value (NAV).
(6)Corporate bonds and notes, including private placement securities, are valued by institutional bond pricing services, which gather information from market sources and integrate credit information, observed market movements and sector news into their pricing applications and models.
(7)Government and agency securities consist of U.S. municipal bonds and for 2024 only, Canadian provincial bonds. These securities are valued by institutional bond pricing services, which gather information on current trading activity, market movements, trends, and specific data on specialty issues.
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(8)Other includes primarily mortgage-backed, asset-backed securities and U.S. Treasury strips. Mortgage-backed and asset-backed securities are valued by institutional pricing services, which gather information from market sources and integrate credit information, observed market movements and sector news into their pricing applications and models. U.S. Treasury strips are valued using stripped interest and stripped principal yield curves based on data obtained from various dealer contacts and live data sources.
(9)Cash and cash funds include a cash fund that invests primarily in short-dated money market instruments.
(10)Funds measured at NAV as a practical expedient as of December 31, 2025 include a fund of funds that invests primarily in freehold and leasehold property in the United Kingdom. Funds measured at NAV as a practical expedient as of December 31, 2024 include funds of funds with return strategies that provide exposure to various asset classes and credit strategies, as well as alternative investment strategies that may include multi-asset credit strategies, global macro strategies, commodities, fixed income, equities and currency, and funds that invest primarily in freehold and leasehold property in the United Kingdom. The valuation of the funds is based on NAV determined by the fund managers using the value of the underlying assets.
(11)The index equity funds are mutual funds that utilize a passively managed investment approach designed to track specific equity indices. They were valued at quoted market prices in an active market, which represented the NAVs of the shares held by the plan.
(12)Pooled equity funds invest in a broad array of global equity, equity-related securities, a range of diversifiers and may use derivatives for efficient portfolio management. The funds were valued at NAV as determined by the fund managers based on the value of the underlying net assets of the fund.
(13)Pooled diversified funds invest in a broad array of asset classes and a range of diversifiers including the use of derivatives. The funds were valued at NAV as determined by the fund managers based on the value of the underlying net assets of the fund.
(14)Pooled U.K. government fixed and index-linked securities funds invest primarily in Sterling denominated fixed income and inflation-linked fixed income securities issued or guaranteed by the U.K. government and may use derivatives for efficient portfolio management. The funds were valued at NAV as determined by the fund managers based on the value of the underlying net assets of the fund.
(15)Pooled global debt funds invest in a broad array of debt securities from corporate and government bonds to emerging markets and high-yield fixed and floating rate securities of varying maturities and may use derivatives for efficient portfolio management. The funds were valued at NAV as determined by the fund managers based on the value of the underlying net assets of the fund.
(16)Pooled liability-driven investment funds primarily invest, either through a sub-fund or directly, in gilt repurchase agreements, physical U.K. government gilts, other inflation-linked fixed income securities, and derivatives to provide exposure to interest rates and inflation, thus hedging these elements of risk associated with pension liabilities. The funds were valued at NAV as determined by the fund managers based on the value of the underlying net assets of the fund.
We have defined contribution plans covering substantially all employees in North America and the United Kingdom. Depending on the specific provisions of each plan, qualified employees receive company contributions based on a percentage of base salary or base salary and incentive pay, matching of employee contributions up to specified limits, or a combination of both. In 2025, 2024 and 2023, we recognized expense related to our contributions to the defined contribution plans of $41 million, $37 million and $34 million, respectively.
In addition to our qualified defined benefit pension plans, we also maintain certain nonqualified supplemental pension plans for highly compensated employees as defined under federal law. The amounts recognized in accrued expenses and other liabilities in our consolidated balance sheets for these plans were $1 million and $9 million, respectively, as of December 31, 2025, and $1 million and $9 million, respectively, as of December 31, 2024. We recognized expense for these plans of $1 million in each of the years ended December 31, 2025, 2024 and 2023.
12. Financing Agreements
Revolving Credit Agreement
On September 4, 2025, CF Holdings and CF Industries entered into the First Amended and Restated Revolving Credit Agreement (the Revolving Credit Agreement), which amended and restated our senior unsecured revolving credit facility that was scheduled to mature October 26, 2028 (the Prior Credit Agreement). The Revolving Credit Agreement provides for revolving credit facility commitments of up to $750 million with a maturity of September 4, 2030 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.
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Borrowings under the Revolving Credit Agreement can be denominated in U.S. dollars, Canadian dollars, euros and British pounds. Borrowings in U.S. dollars bear interest at an annual rate equal to, at our option, an applicable adjusted term secured overnight financing rate (or a similar benchmark rate for non-U.S. dollar borrowings) plus a specified margin, or base rate plus a specified margin. We are required to pay a commitment fee on the undrawn portion of the commitments under the Revolving Credit Agreement and customary letter of credit fees. The specified margins and the amount of the commitment fee will depend on CF Holdings’ credit rating at the time.
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, 2025, and during the year ended December 31, 2025, there were no borrowings outstanding under the Revolving Credit Agreement. As of December 31, 2024, and during the year ended December 31, 2024, there were no borrowings outstanding under the Prior Credit Agreement.
The Revolving Credit Agreement contains representations and warranties and affirmative and negative covenants, including one financial covenant. As of December 31, 2025, we were in compliance with all covenants under the Revolving Credit Agreement.
Letters of Credit Under Reimbursement Agreement
We are party to a reimbursement agreement providing for the issuance of up to $425 million of letters of credit. As of December 31, 2025, approximately $339 million of letters of credit were outstanding under this agreement. The primary purpose of the letters of credit outstanding is to provide credit support to Canadian taxing authorities for amounts related to certain tax years that were reassessed and objected to, and which have been accepted for consideration under the bilateral settlement provisions of the U.S.-Canada tax treaty by the United States and Canadian competent authorities.
Senior Notes
Long-term debt presented on our consolidated balance sheets as of December 31, 2025 and 2024 consisted of the following debt securities issued by CF Industries:

| Effective Interest Rate |  | December 31, 2025 |  | December 31, 2024
|  | Principal Outstanding |  | Carrying Amount(1) |  | Principal Outstanding |  | Carrying Amount(1)
|  |  | (in millions)
Public Senior Notes: |  |  |  |  |  |  |  |  |
5.150% due March 2034 | 5.293% |  | $ | 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 |
5.375% due March 2044 | 5.478% |  | 750 |  |  | 741 |  |  | 750 |  |  | 741 |
Senior Secured Notes: |  |  |  |  |  |  |  |  |
4.500% due December 2026(2) | 4.783% |  | — |  |  | — |  |  | 750 |  |  | 746 |
Total long-term debt |  |  | $ | 3,250 |  |  | $ | 3,215 |  |  | $ | 3,000 |  |  | $ | 2,971 |

_______________________________________________________________________________
(1)Carrying amount is net of unamortized debt discount and deferred debt issuance costs. Total unamortized debt discount was $5 million and $6 million as of December 31, 2025 and 2024, respectively, and total deferred debt issuance costs were $30 million and $23 million as of December 31, 2025 and 2024, respectively.
(2)Effective August 23, 2021, these notes were no longer secured, in accordance with the terms of the applicable indenture.
On November 26, 2025, CF Industries issued $1 billion aggregate principal amount of 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, in accordance with the optional redemption provisions in the indenture governing the 4.500% senior secured notes due 2026 (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. As a result, we recognized a loss on debt extinguishment of $6 million, consisting primarily of the premium paid on the redemption of the $750 million principal amount of the 2026 Notes prior to their scheduled maturity. We intend that the remainder of the net proceeds be used for general corporate purposes.
Under the indentures (including the applicable supplemental indentures) governing the 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
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Holdings. Interest on the Public Senior Notes is payable semiannually, and the Public Senior Notes are redeemable at our option, in whole at any time or in part from time to time, at specified make-whole redemption prices.
13. Interest Expense
Details of interest expense are as follows:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Interest on borrowings(1) | $ | 155 |  |  | $ | 150 |  |  | $ | 150 |
Fees on financing agreements and other(1) | 10 |  |  | 9 |  |  | 8 |
Interest on tax liabilities(2) | 4 |  |  | (27) |  |  | (2) |
Interest capitalized | (14) |  |  | (11) |  |  | (6) |
Interest expense | $ | 155 |  |  | $ | 121 |  |  | $ | 150 |

_______________________________________________________________________________
(1)See Note 12—Financing Agreements for additional information.
(2)Interest on tax liabilities for the year ended December 31, 2024 primarily relates to discretionary interest relief granted from the CRA and the Alberta TRA. See Note 10—Income Taxes for additional information.
14. Variable Interest Entity
On April 8, 2025, we formed the Blue Point joint venture, Blue Point Number One, LLC, 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 carbon dioxide (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.
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.
In addition, we will build scalable infrastructure at our Blue Point complex to supply the ammonia production facility with services, including product storage and vessel loading.
We determined that the Blue Point joint venture is a VIE of which we are the primary beneficiary. We have a significant variable interest in the Blue Point joint venture through our 40% equity interest. We are considered the primary beneficiary of the VIE as we have both the power to direct the day-to-day operations of the low-carbon ammonia production facility, which are the activities that most significantly impact the economic performance of the VIE, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE, due to our 40% equity interest. 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.
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The table below summarizes the assets and liabilities of the Blue Point joint venture included in our consolidated balance sheet as of December 31, 2025:

|  | December 31, 2025 |  |  |  |
| (in millions)
Assets |  |  |  |  |
Cash and cash equivalents |  | $ | 130 |  |  |  |  |
Other current assets |  | 1 |  |  |  |  |
Property, plant and equipment—net |  | 361 |  |  |  |  |
Other assets |  | 1 |  |  |  |  |
Total assets |  | $ | 493 |  |  |  |  |
Liabilities |  |  |  |  |
Accounts payable and accrued expenses |  | $ | 52 |  |  |  |  |
Other liabilities |  | 1 |  |  |  |  |
Total liabilities |  | $ | 53 |  |  |  |  |

As of December 31, 2025, all assets of the Blue Point joint venture can only be used to settle the obligations of the Blue Point joint venture. In addition, as of December 31, 2025, all liabilities of the Blue Point joint venture are payable to creditors who do not have recourse to the general credit of CF Holdings.
CF Holdings has provided guarantees for certain financial commitments of the Blue Point joint venture to several third-party vendors; however, as of December 31, 2025, no liabilities had been incurred by the Blue Point joint venture to these third-party vendors.
15. Other Operating—Net
Details of other operating—net are as follows:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Loss on disposal of property, plant and equipment | $ | 3 |  |  | $ | 12 |  |  | $ | 4 |
Gain on sale of emission credits | (8) |  |  | (47) |  |  | (39) |
Gain on foreign currency transactions(1) | (5) |  |  | — |  |  | — |
45Q Tax Credits(2) | (42) |  |  | — |  |  | — |
Other(3) | 27 |  |  | 25 |  |  | 4 |
Other operating—net | $ | (25) |  |  | $ | (10) |  |  | $ | (31) |

___________________________________________________________________________
(1)Gain on foreign currency transactions consists of foreign currency exchange rate impacts on foreign currency denominated transactions.
(2)Represents income earned from 45Q Tax Credits, which reduced our current income tax payable for the period.
(3)Other primarily includes the front-end engineering and design study costs related to our clean energy initiatives, development costs for our Blue Point joint venture, commissioning costs for the decarbonization project at our Donaldsonville complex with carbon capture and sequestration, and gains on the recovery of certain precious metals used in the manufacturing process.
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16. Derivative Financial Instruments
We use derivative financial instruments to reduce our exposure to changes in prices for natural gas that will be purchased in the future. Natural gas is the largest and most volatile component of our manufacturing cost for nitrogen-based products. From time to time, we may also use derivative financial instruments to reduce our exposure to changes in foreign currency exchange rates. The derivatives that we use to reduce our exposure to changes in prices for natural gas are primarily natural gas fixed price swaps, basis swaps and options traded in the OTC markets. These natural gas derivatives settle using primarily a NYMEX futures price index, which represents the basis for fair value at any given time. We enter into natural gas derivative contracts with respect to natural gas to be consumed by us in the future, and settlements of those derivative contracts are scheduled to coincide with our anticipated purchases of natural gas used to manufacture nitrogen products during those future periods. We use natural gas derivatives as an economic hedge of natural gas price risk, but without the application of hedge accounting. As a result, changes in fair value of these contracts are recognized in earnings. As of December 31, 2025, we had natural gas derivative contracts covering certain periods through March 2027.
As of December 31, 2025, our open natural gas derivative contracts consisted of natural gas basis swaps for 13.5 million MMBtus of natural gas. As of December 31, 2024, we had open natural gas derivative contracts consisting of natural gas fixed price swaps and basis swaps for 16.0 million MMBtus of natural gas. For the year ended December 31, 2025, we used derivatives to cover approximately 2% of our natural gas consumption.
The effect of derivatives on our consolidated statements of operations is shown in the table below.

| Gain (loss) recognized in income
|  |  | Year ended December 31,
| Location |  | 2025 |  | 2024 |  | 2023
|  |  | (in millions)
Natural gas derivatives |  |  |  |  |  |  |
Unrealized net (losses) gains | Cost of sales |  | $ | (5) |  |  | $ | 35 |  |  | $ | 39 |
Realized net losses | Cost of sales |  | (1) |  |  | (40) |  |  | (139) |
Net derivative losses |  |  | $ | (6) |  |  | $ | (5) |  |  | $ | (100) |

The fair values of derivatives on our consolidated balance sheets are shown below. As of December 31, 2025 and 2024, none of our derivative instruments were designated as hedging instruments. See Note 9—Fair Value Measurements for additional information on derivative fair values.

| Asset Derivatives |  | Liability Derivatives
| Balance Sheet Location |  | December 31, |  | Balance Sheet Location |  | December 31,
|  | 2025 |  | 2024 |  |  | 2025 |  | 2024
|  |  | (in millions) |  |  |  | (in millions)
Natural gas derivatives | Other current assets |  | $ | — |  |  | $ | 4 |  |  | Other current liabilities |  | $ | (5) |  |  | $ | (3) |
Natural gas derivatives | Other assets |  | 1 |  |  | — |  |  | Other liabilities |  | — |  |  | — |

The counterparties to our derivative contracts are multinational commercial banks, major financial institutions and large energy companies. Our derivative contracts are executed with several counterparties under International Swaps and Derivatives Association (ISDA) agreements. The ISDA agreements are master netting arrangements commonly used for OTC derivatives that mitigate exposure to counterparty credit risk, in part, by creating contractual rights of netting and setoff, the specifics of which vary from agreement to agreement. These rights are described further below:
•Settlement netting generally allows us and our counterparties to net, into a single net payable or receivable, ordinary settlement obligations arising between us and our counterparties under the ISDA agreement on the same day, in the same currency, for the same types of derivative instruments, and through the same pairing of offices.
•Close-out netting rights are provided in the event of a default or other termination event (as defined in the ISDA agreements), including bankruptcy. Depending on the cause of early termination, the non-defaulting party may elect to terminate all or some transactions outstanding under the ISDA agreement. The values of all terminated transactions and certain other payments under the ISDA agreement are netted, resulting in a single net close-out amount payable to or by the non-defaulting party.
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•Setoff rights are provided by certain of our ISDA agreements and generally allow a non-defaulting party to elect to set off, against the final net close-out payment, other matured and contingent amounts payable between us and our counterparties under the ISDA agreement or otherwise. Typically, these setoff rights arise upon the early termination of all transactions outstanding under an ISDA agreement following a default or specified termination event.
Most of our ISDA agreements contain credit-risk-related contingent features such as cross default provisions. In the event of certain defaults or termination events, our counterparties may request early termination and net settlement of certain derivative trades or, under certain ISDA agreements, may require us to collateralize derivatives in a net liability position. As of December 31, 2025 and 2024, the aggregate fair value of the derivative instruments with credit-risk-related contingent features in net liability positions was $4 million and zero, respectively, which also approximates the fair value of the assets that may be needed to settle the obligations if the credit-risk-related contingent features were triggered at the reporting dates. The credit support documents executed in connection with certain of our ISDA agreements generally provide us and our counterparties the right to set off collateral against amounts owing under the ISDA agreements upon the occurrence of a default or a specified termination event. As of December 31, 2025 and 2024, we had no cash collateral on deposit with counterparties for derivative contracts.
The following table presents amounts relevant to offsetting of our derivative assets and liabilities as of December 31, 2025 and 2024:

| Amounts presented in consolidated balance sheets(1) |  | Gross amounts not offset in consolidated balance sheets |  |
|  | Financial instruments |  | Cash collateral received (pledged) |  | Net amount
| (in millions)
December 31, 2025 |  |  |  |  |  |  |
Total derivative assets | $ | 1 |  |  | $ | — |  |  | $ | — |  |  | $ | 1 |
Total derivative liabilities | (5) |  |  | — |  |  | — |  |  | (5) |
Net derivative liabilities | $ | (4) |  |  | $ | — |  |  | $ | — |  |  | $ | (4) |
December 31, 2024 |  |  |  |  |  |  |
Total derivative assets | $ | 4 |  |  | $ | — |  |  | $ | — |  |  | $ | 4 |
Total derivative liabilities | (3) |  |  | — |  |  | — |  |  | (3) |
Net derivative assets | $ | 1 |  |  | $ | — |  |  | $ | — |  |  | $ | 1 |

_______________________________________________________________________________
(1)We report the fair values of our derivative assets and liabilities on a gross basis on our consolidated balance sheets. As a result, the gross amounts recognized and net amounts presented are the same.
We do not believe the contractually allowed netting, close-out netting or setoff of amounts owed to, or due from, the counterparties to our ISDA agreements would have a material effect on our financial position.
17. Supplemental Balance Sheet Data
Accounts Receivable—Net
Accounts receivable—net consist of the following:

| December 31,
| 2025 |  | 2024
| (in millions)
Trade | $ | 444 |  |  | $ | 378 |
Other | 44 |  |  | 26 |
Accounts receivable—net | $ | 488 |  |  | $ | 404 |

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Inventories
Inventories consist of the following:

| December 31,
| 2025 |  | 2024
| (in millions)
Finished goods | $ | 332 |  |  | $ | 263 |
Raw materials, spare parts and supplies | 51 |  |  | 51 |
Total inventories | $ | 383 |  |  | $ | 314 |

Other Assets
Other assets consist of the following:

| December 31,
| 2025 |  | 2024
| (in millions)
Spare parts | $ | 228 |  |  | $ | 208 |
Nonqualified employee benefit trusts | 18 |  |  | 17 |
Tax-related assets | 654 |  |  | 638 |
Other | 80 |  |  | 54 |
Total other assets | $ | 980 |  |  | $ | 917 |

Tax-related assets include long-term receivables related to U.S. and Canadian transfer pricing and the related interest, and certain payments to Canadian taxing authorities in 2022. See Note 10—Income Taxes for additional information.
Other includes defined benefit pension plans in a net asset funded status. See Note 11—Pension and Other Postretirement Benefits for additional information.
Accounts Payable and Accrued Expenses
Accounts payable and accrued expenses consist of the following:

| December 31,
| 2025 |  | 2024
| (in millions)
Accounts payable(1) | $ | 148 |  |  | $ | 125 |
Accrued capital expenditures(1) | 51 |  |  | 59 |
Accrued natural gas costs | 127 |  |  | 106 |
Payroll and employee-related costs | 113 |  |  | 69 |
Accrued interest | 32 |  |  | 30 |
Other | 210 |  |  | 214 |
Total accounts payable and accrued expenses | $ | 681 |  |  | $ | 603 |

___________________________________________________________________________
(1)As of December 31, 2025 and 2024, accrued capital expenditures totaled $118 million and $101 million, respectively, of which $65 million and $42 million, respectively, are included within accounts payable in the table above, and as of December 31, 2025, $2 million is included in other liabilities.
Payroll and employee-related costs include accrued salaries and wages, vacation, benefits, incentive plans and payroll taxes.
Accrued interest includes interest payable on our outstanding senior notes. See Note 12—Financing Agreements and Note 13—Interest Expense for additional information.
Other includes accrued utilities, property and other taxes, sales incentives and other credits, accrued litigation settlement costs, and accrued maintenance and professional services.
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Other Current Liabilities
As of December 31, 2025, other current liabilities of $19 million consist primarily of a defined benefit pension plan liability of $9 million and an unrealized loss on natural gas derivatives of $5 million.
As of December 31, 2024, other current liabilities of $9 million consist primarily of an unrealized loss on natural gas derivatives of $3 million and asset retirement obligations of $4 million.
See Note 11—Pension and Other Postretirement Benefits, Note 16—Derivative Financial Instruments and Note 23—Asset Retirement Obligations for additional information.
Other Liabilities
Other liabilities consist of the following:

| December 31,
| 2025 |  | 2024
| (in millions)
Benefit plans and deferred compensation | $ | 47 |  |  | $ | 40 |
Tax-related liabilities | 262 |  |  | 245 |
Other | 28 |  |  | 16 |
Other liabilities | $ | 337 |  |  | $ | 301 |

Benefit plans and deferred compensation include liabilities for pensions, retiree medical benefits, and the noncurrent portion of incentive plans. See Note 11—Pension and Other Postretirement Benefits for additional information.
Tax-related liabilities include reserves for unrecognized tax benefits and the related interest. See Note 10—Income Taxes for additional information.
18. Noncontrolling Interests
We have a strategic venture with CHS under which CHS owns an equity interest in CFN, a subsidiary of CF Holdings, which represents approximately 11% of the membership interests of CFN. We own the remaining membership interests. Under the terms of CFN’s limited liability company agreement, each member’s interest will reflect, over time, the impact of the profitability of CFN, any member contributions made to CFN and withdrawals and distributions received from CFN. We also have a 40% ownership interest in the Blue Point joint venture. JERA and Mitsui own the remaining membership interests. See Note 14—Variable Interest Entity for additional information on the Blue Point joint venture.
For financial reporting purposes, the assets, liabilities and earnings of CFN and the Blue Point joint venture are consolidated into our financial statements. CHS’ interest in CFN and each of JERA’s and Mitsui’s interests in the Blue Point joint venture are recorded in noncontrolling interests in our consolidated financial statements.
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A reconciliation of the beginning and ending balances of noncontrolling interests and distributions payable to noncontrolling interests on our consolidated balance sheets is provided below.

| Year ended December 31,
| 2025 |  | 2024 |  |  |  |  |  | 2023
| CFN |  | Blue Point |  | Total |  | CFN |  |  |  |  |  | CFN |  |  |  |
| (in millions) |  |
Noncontrolling interests: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Balance as of January 1 | $ | 2,607 |  |  | $ | — |  |  | $ | 2,607 |  |  | $ | 2,656 |  |  |  |  |  |  | $ | 2,802 |  |  |  |  |
Issuance of noncontrolling interests in Blue Point Number One, LLC | — |  |  | 291 |  |  | 291 |  |  | — |  |  |  |  |  |  | — |  |  |  |  |
Earnings attributable to noncontrolling interests | 341 |  |  | 2 |  |  | 343 |  |  | 259 |  |  |  |  |  |  | 313 |  |  |  |  |
Declaration of distributions payable | (304) |  |  | — |  |  | (304) |  |  | (308) |  |  |  |  |  |  | (459) |  |  |  |  |
Balance as of December 31 | $ | 2,644 |  |  | $ | 293 |  |  | $ | 2,937 |  |  | $ | 2,607 |  |  |  |  |  |  | $ | 2,656 |  |  |  |  |
Distributions payable to noncontrolling interests: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Balance as of January 1 | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  |  |  |  |  | $ | — |  |  |  |  |
Declaration of distributions payable | 304 |  |  | — |  |  | 304 |  |  | 308 |  |  |  |  |  |  | 459 |  |  |  |  |
Distributions to noncontrolling interests | (304) |  |  | — |  |  | (304) |  |  | (308) |  |  |  |  |  |  | (459) |  |  |  |  |
Balance as of December 31 | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  |  |  |  |  | $ | — |  |  |  |  |

CHS also receives deliveries pursuant to a supply agreement under which CHS has the right to purchase annually from CFN up to approximately 1.1 million tons of granular urea and 580,000 tons of UAN at market prices. As a result of its equity interest in CFN, CHS is entitled to semi-annual cash distributions from CFN. We are also entitled to semi-annual cash distributions from CFN. The amounts of distributions from CFN to us and CHS are based generally on the profitability of CFN and determined based on the volume of granular urea and UAN sold by CFN to us and CHS pursuant to supply agreements, less a formula driven amount based primarily on the cost of natural gas used to produce the granular urea and UAN, and adjusted for the allocation of items such as operational efficiencies and overhead amounts.
On January 30, 2026, the CFN Board of Managers approved semi-annual distribution payments for the distribution period ended December 31, 2025, in accordance with CFN’s limited liability company agreement. On January 30, 2026, CFN distributed $201 million to CHS for the distribution period ended December 31, 2025.
19. Stockholders’ Equity
Common Stock
Our Board of Directors (the Board) has authorized certain programs to repurchase shares of our common stock. These programs have generally permitted repurchases to be made from time to time in the open market, through privately-negotiated transactions, through block transactions, through accelerated share repurchase programs, or otherwise. The manner, timing and amount of repurchases will be determined by our management based on the evaluation of market conditions, stock price and other factors.
On November 2, 2022, the Board authorized the repurchase of up to $3 billion of CF Holdings common stock 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.
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The following table summarizes the share repurchases under the 2025 Share Repurchase Program and the 2022 Share Repurchase Program.

| 2025 Share Repurchase Program |  | 2022 Share Repurchase Program
| Shares |  | Amounts(1) |  | Shares |  | Amounts(1)
| (in millions)
Shares repurchased in 2023 | — |  |  | $ | — |  |  | 5.6 |  |  | $ | 425 |
Shares repurchased in 2024 | — |  |  | $ | — |  |  | 18.8 |  |  | $ | 1,513 |
Shares repurchased in 2025: |  |  |  |  |  |  |
First quarter | — |  |  | $ | — |  |  | 5.4 |  |  | $ | 434 |
Second quarter | — |  |  | — |  |  | 2.8 |  |  | 202 |
Third quarter | — |  |  | — |  |  | 4.3 |  |  | 364 |
Fourth quarter | 3.4 |  |  | 278 |  |  | 0.7 |  |  | 62 |
Total shares repurchased in 2025 | 3.4 |  |  | $ | 278 |  |  | 13.2 |  |  | $ | 1,062 |
Shares repurchased as of December 31, 2025 | 3.4 |  |  | $ | 278 |  |  | 37.6 |  |  | $ | 3,000 |

______________________________________________________________________________
(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.
The shares we repurchase are held as treasury stock. If the Board authorizes us to retire the shares, they are returned to the status of authorized but unissued shares. As part of the retirements, we reduce our treasury stock, paid-in capital and retained earnings balances. 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 354,264 shares, respectively, of treasury stock.
Changes in common shares outstanding are as follows:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
Beginning balance | 169,882,990 |  |  | 188,188,401 |  |  | 195,604,404 |
Exercise of stock options | 22,485 |  |  | 46,285 |  |  | 39,106 |
Issuance of restricted stock(1) | 413,843 |  |  | 769,607 |  |  | 664,200 |
Purchase of treasury shares(2) | (16,767,156) |  |  | (19,121,303) |  |  | (8,119,309) |
Ending balance | 153,552,162 |  |  | 169,882,990 |  |  | 188,188,401 |

_______________________________________________________________________________
(1)Includes shares issued from treasury.
(2)Consists of shares repurchased under share repurchase programs and shares withheld to pay employee tax obligations upon the vesting of restricted stock or the exercise of stock options.
Preferred Stock
CF Holdings is authorized to issue 50 million shares of $0.01 par value preferred stock. Our Third Amended and Restated Certificate of Incorporation authorizes the Board, without any further stockholder action or approval, to issue these shares in one or more classes or series, and (except in the case of our Series A Junior Participating Preferred Stock, 500,000 shares of which are authorized and the terms of which were specified in the original certificate of incorporation of CF Holdings) to fix the rights, preferences and privileges of the shares of each wholly unissued class or series and any of its qualifications, limitations or restrictions. The Series A Junior Participating Preferred Stock had been established in CF Holdings’ original certificate of incorporation in connection with our former stockholder rights plan that expired in 2015. No shares of preferred stock have been issued.
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Accumulated Other Comprehensive Loss
Changes to accumulated other comprehensive loss and the impact on other comprehensive income (loss) are as follows:

| Foreign Currency Translation Adjustment |  |  |  | Unrealized Gain (Loss) on Derivatives |  | Defined Benefit Plans |  | Accumulated Other Comprehensive Loss
| (in millions)
Balance as of December 31, 2022 | $ | (179) |  |  |  |  | $ | 3 |  |  | $ | (54) |  |  | $ | (230) |
Loss arising during the period | — |  |  |  |  | — |  |  | (6) |  |  | (6) |
Reclassification to earnings(1) | — |  |  |  |  | — |  |  | (1) |  |  | (1) |
Effect of exchange rate changes and deferred taxes | 33 |  |  |  |  | — |  |  | (5) |  |  | 28 |
Balance as of December 31, 2023 | $ | (146) |  |  |  |  | $ | 3 |  |  | $ | (66) |  |  | $ | (209) |
Gain arising during the period | — |  |  |  |  | — |  |  | 4 |  |  | 4 |
Effect of exchange rate changes and deferred taxes | (75) |  |  |  |  | — |  |  | — |  |  | (75) |
Balance as of December 31, 2024 | $ | (221) |  |  |  |  | $ | 3 |  |  | $ | (62) |  |  | $ | (280) |
Loss arising during the period | — |  |  |  |  | — |  |  | (27) |  |  | (27) |
Reclassification to earnings(1): |  |  |  |  |  |  |  |  |
Settlement loss | — |  |  |  |  | — |  |  | 1 |  |  | 1 |
Effect of exchange rate changes and deferred taxes | 70 |  |  |  |  | — |  |  | 1 |  |  | 71 |
Balance as of December 31, 2025 | $ | (151) |  |  |  |  | $ | 3 |  |  | $ | (87) |  |  | $ | (235) |

_______________________________________________________________________________
(1) Reclassifications out of accumulated other comprehensive loss to the consolidated statements of operations were not material.

20. Stock-based Compensation
2022 Equity and Incentive Plan
In May 2022, our shareholders approved the CF Industries Holdings, Inc. 2022 Equity and Incentive Plan (the 2022 Equity and Incentive Plan), including 2.5 million new shares of the Company’s common stock available for grant thereunder as part of our pay-for-performance compensation program, which we use to provide incentives that are aligned with the interests of our shareholders. The 2022 Equity and Incentive Plan replaced the CF Industries Holdings, Inc. 2014 Equity and Incentive Plan (the 2014 Equity and Incentive Plan) and permits grants of stock options, stock appreciation rights, restricted stock, restricted stock units and other stock-based awards, which in each case may be conditioned on performance criteria, to employees and certain consultants of the Company and its subsidiaries and non-employee directors of the Company.
Share Reserve and Individual Award Limits
The maximum number of shares reserved for the grant of awards under the 2022 Equity and Incentive Plan is the sum of (i) 2.5 million shares, plus (ii) the number of shares that remain available for new grants under the 2014 Equity and Incentive Plan when the 2022 Equity and Incentive Plan was approved by shareholders, plus (iii) the number of shares subject to stock options granted under the 2014 Equity and Incentive Plan or the CF Industries Holdings, Inc. 2009 Equity and Incentive Plan that were outstanding when the 2022 Equity and Incentive Plan was approved by shareholders, but only to the extent such awards terminate or expire without the delivery of shares, plus (iv) 1.61 times the number of shares subject to restricted stock or restricted stock unit awards (including performance restricted stock unit awards) granted under the 2014 Equity and Incentive Plan that were outstanding when the 2022 Equity and Incentive Plan was approved by shareholders, but only to the extent such awards terminate or expire without the delivery of shares. In no event will the number of shares available for issuance under the 2022 Equity and Incentive Plan exceed 10,615,515 shares. Shares issued with respect to all awards granted under the 2022 Equity and Incentive Plan are counted against the share reserve on a one-for-one basis. The shares subject to any outstanding award under the 2022 Equity and Incentive Plan will be available for subsequent award and issuance under the 2022 Equity and Incentive Plan to the extent those awards subsequently expire, are forfeited or cancelled, or terminate for any reason prior to issuance of the shares subject to those awards. In addition, shares tendered or withheld in payment of the exercise price of an award and shares withheld by the Company to satisfy tax withholding obligations related to an award will be available for subsequent award under the 2022 Equity and Incentive Plan. As of December 31, 2025, we had approximately 6.3 million shares available for future awards under the 2022 Equity and Incentive Plan. The 2022 Equity and Incentive Plan provides that
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no more than 5.0 million shares may be issued pursuant to the exercise of incentive stock options, subject to adjustment upon certain capitalization events.
Restricted Stock Awards, Restricted Stock Units and Performance Restricted Stock Units
The fair value of a restricted stock award (RSA) or a restricted stock unit (RSU) is equal to the number of shares subject to the award multiplied by the closing market price of our common stock on the date of grant. We estimated the fair value of each performance restricted stock unit (PSU) on the date of grant using a Monte Carlo simulation. Generally, RSUs vest in three equal annual installments following the date of grant. PSUs are granted to key employees and generally vest three years from the date of grant subject to the attainment of applicable performance goals during the performance period. The RSAs awarded to non-management members of the Board vest the earlier of one year from the date of the grant or the date of the next annual stockholder meeting. During the vesting period, the holders of the RSAs are entitled to dividends and voting rights. During the vesting period, the holders of the RSUs are paid dividend equivalents in cash to the extent we pay cash dividends. PSUs accrue dividend equivalents to the extent we pay cash dividends on our common stock during the performance and vesting periods. Upon vesting of the PSUs, holders are paid the cash equivalent of the dividends paid during the performance and vesting periods based on the shares of common stock, if any, delivered in settlement of PSUs. Holders of RSUs and PSUs are not entitled to voting rights unless and until the awards have vested.
A summary of restricted stock activity during the year ended December 31, 2025 is presented below.

| Restricted Stock Awards |  | Restricted Stock Units |  | Performance Restricted Stock Units
| Shares |  | Weighted- Average Grant-Date Fair Value |  | Shares |  | Weighted- Average Grant-Date Fair Value |  | Shares |  | Weighted- Average Grant-Date Fair Value
Outstanding as of December 31, 2024 | 23,367 |  |  | $ | 79.59 |  |  | 471,657 |  |  | $ | 79.36 |  |  | 272,000 |  |  | $ | 84.66 |
Granted | 24,033 |  |  | 81.98 |  |  | 262,093 |  |  | 85.66 |  |  | 152,390 |  |  | 87.60 |
Restrictions lapsed (vested)(1) | (23,367) |  |  | 79.59 |  |  | (197,545) |  |  | 78.15 |  |  | (141,616) |  |  | 85.25 |
Forfeited | — |  |  | — |  |  | (13,105) |  |  | 83.64 |  |  | (3,257) |  |  | 85.89 |
Outstanding as of December 31, 2025 | 24,033 |  |  | 81.98 |  |  | 523,100 |  |  | 82.86 |  |  | 279,517 |  |  | 85.95 |

_______________________________________________________________________________
(1)For performance restricted stock units, the shares represent the performance restricted stock units granted in 2022, for which the three-year performance period ended December 31, 2024.
The 2025, 2024 and 2023 weighted-average grant-date fair value for RSAs was $81.98, $79.59 and $74.79, for RSUs was $85.66, $80.45 and $81.44, and for PSUs was $87.60, $86.76 and $93.61, respectively. The fair value of restricted stock vested was $35 million, $62 million and $55 million for the years ended December 31, 2025, 2024 and 2023, respectively.
Stock Options
Under the 2014 Equity and Incentive Plan and our other predecessor plans, we granted to plan participants nonqualified stock options to purchase shares of our common stock. The exercise price of these options was equal to the market price of our common stock on the date of grant. The contractual life of each option was ten years and generally one-third of the options vested on each of the first three anniversaries of the date of grant. No stock option awards were granted under the 2014 Equity and Incentive Plan or our other predecessor plans after 2017, and no stock option awards have been granted under the 2022 Equity and Incentive Plan.
As of December 31, 2025, 54,160 options were outstanding and exercisable, with a weighted‑average exercise price of $32.85, a weighted‑average remaining contractual term of 0.8 years, and an aggregate intrinsic value of $2 million. The aggregate intrinsic value represents the total pre-tax intrinsic value, based on our closing stock price of $77.34 as of December 31, 2025, which would have been received by the option holders had all option holders exercised their options as of that date. During 2025, 22,485 options were exercised, which had a pre‑tax intrinsic value of $1 million, and no related tax benefit was realized.
Compensation Cost
Compensation cost is recorded primarily in selling, general and administrative expenses. The following table summarizes stock-based compensation costs and related income tax benefits:
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| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Stock-based compensation expense | $ | 45 |  |  | $ | 36 |  |  | $ | 37 |
Income tax benefit | (4) |  |  | (8) |  |  | (9) |
Stock-based compensation expense, net of income taxes | $ | 41 |  |  | $ | 28 |  |  | $ | 28 |

As of December 31, 2025, pre-tax unrecognized compensation cost was $24 million for RSAs and RSUs, which will be recognized over a weighted-average period of 1.6 years, and $6 million for PSUs, which will be recognized over a weighted-average period of 1.6 years.
21. Segment Disclosures
Our reportable segments consist of Ammonia, Granular Urea, UAN, AN and Other. These segments are differentiated by products. Our chief operating decision maker (CODM) is our President and Chief Executive Officer, who uses gross margin to evaluate segment performance and allocate resources. The CODM meets periodically with other members of senior management to analyze segment performance, including comparing actual results to projected results, with consideration to the costs incurred to produce and deliver the product. In addition, our CODM uses gross margin by reportable segment to make key operating decisions, such as the determination of capital expenditures and the allocation of operating budgets, to help guide strategic decisions to align with company-wide goals. 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 the CODM. The ammonia and other products that are upgraded into Granular Urea, UAN, AN and Other products are transferred at cost into the results of those products.
Our assets, with the exception of goodwill, are not monitored by or reported to our CODM by segment; therefore, we do not present total assets by segment. Goodwill by segment is presented in Note 7—Goodwill and Other Intangible Assets.
Segment data for gross margin, including sales and cost of sales, which also includes significant expenses, for the years ended December 31, 2025, 2024 and 2023 are presented in the tables below.

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Ammonia |  |  |  |  |
Net sales | $ | 2,176 |  |  | $ | 1,736 |  |  | $ | 1,679 |
Cost of sales: |  |  |  |  |
Natural gas, including the impact of realized derivatives(1) | 431 |  |  | 283 |  |  | 407 |
Unrealized net mark-to-market loss (gain) on natural gas derivatives | 2 |  |  | (13) |  |  | (11) |
Depreciation and amortization(2) | 280 |  |  | 269 |  |  | 174 |
Distribution and storage(3) | 221 |  |  | 187 |  |  | 192 |
Freight(4) | 52 |  |  | 50 |  |  | 42 |
Other segment items(5) | 508 |  |  | 467 |  |  | 334 |
Total cost of sales | 1,494 |  |  | 1,243 |  |  | 1,138 |
Gross margin | $ | 682 |  |  | $ | 493 |  |  | $ | 541 |

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| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Granular Urea |  |  |  |  |
Net sales | $ | 1,781 |  |  | $ | 1,600 |  |  | $ | 1,823 |
Cost of sales: |  |  |  |  |
Natural gas, including the impact of realized derivatives(1) | 301 |  |  | 241 |  |  | 363 |
Unrealized net mark-to-market loss (gain) on natural gas derivatives | 1 |  |  | (9) |  |  | (11) |
Depreciation and amortization(2) | 253 |  |  | 284 |  |  | 285 |
Distribution and storage(3) | 10 |  |  | 9 |  |  | 10 |
Freight(4) | 33 |  |  | 32 |  |  | 43 |
Other segment items(5) | 346 |  |  | 369 |  |  | 320 |
Total cost of sales | 944 |  |  | 926 |  |  | 1,010 |
Gross margin | $ | 837 |  |  | $ | 674 |  |  | $ | 813 |

UAN |  |  |  |  |
Net sales | $ | 2,161 |  |  | $ | 1,678 |  |  | $ | 2,068 |
Cost of sales: |  |  |  |  |
Natural gas, including the impact of realized derivatives(1) | 339 |  |  | 234 |  |  | 367 |
Unrealized net mark-to-market loss (gain) on natural gas derivatives | 2 |  |  | (10) |  |  | (11) |
Depreciation and amortization(2) | 265 |  |  | 268 |  |  | 288 |
Distribution and storage(3) | 61 |  |  | 60 |  |  | 67 |
Freight(4) | 148 |  |  | 142 |  |  | 156 |
Other segment items(5) | 425 |  |  | 375 |  |  | 384 |
Total cost of sales | 1,240 |  |  | 1,069 |  |  | 1,251 |
Gross margin | $ | 921 |  |  | $ | 609 |  |  | $ | 817 |

AN |  |  |  |  |
Net sales | $ | 421 |  |  | $ | 419 |  |  | $ | 497 |
Cost of sales: |  |  |  |  |
Natural gas, including the impact of realized derivatives(1) | 39 |  |  | 34 |  |  | 51 |
Unrealized net mark-to-market gain on natural gas derivatives | — |  |  | (1) |  |  | (2) |
Depreciation and amortization(2) | 33 |  |  | 39 |  |  | 48 |
Distribution and storage(3) | — |  |  | 1 |  |  | 2 |
Freight(4) | 30 |  |  | 29 |  |  | 24 |
Other segment items(5) | 240 |  |  | 238 |  |  | 236 |
Total cost of sales | 342 |  |  | 340 |  |  | 359 |
Gross margin | $ | 79 |  |  | $ | 79 |  |  | $ | 138 |

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| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Other(6) |  |  |  |  |
Net sales | $ | 545 |  |  | $ | 503 |  |  | $ | 564 |
Cost of sales: |  |  |  |  |
Natural gas, including the impact of realized derivatives(1) | 53 |  |  | 37 |  |  | 63 |
Unrealized net mark-to-market gain on natural gas derivatives | — |  |  | (2) |  |  | (4) |
Depreciation and amortization(2) | 65 |  |  | 61 |  |  | 64 |
Distribution and storage(3) | 3 |  |  | 1 |  |  | 3 |
Freight(4) | 64 |  |  | 59 |  |  | 65 |
Other segment items(5) | 155 |  |  | 146 |  |  | 137 |
Total cost of sales | 340 |  |  | 302 |  |  | 328 |
Gross margin | $ | 205 |  |  | $ | 201 |  |  | $ | 236 |

Consolidated |  |  |  |  |
Net sales | $ | 7,084 |  |  | $ | 5,936 |  |  | $ | 6,631 |
Cost of sales: |  |  |  |  |
Natural gas, including the impact of realized derivatives(1) | 1,163 |  |  | 829 |  |  | 1,251 |
Unrealized net mark-to-market loss (gain) on natural gas derivatives | 5 |  |  | (35) |  |  | (39) |
Depreciation and amortization(2) | 896 |  |  | 921 |  |  | 859 |
Distribution and storage(3) | 295 |  |  | 258 |  |  | 274 |
Freight(4) | 327 |  |  | 312 |  |  | 330 |
Other segment items(5) | 1,674 |  |  | 1,595 |  |  | 1,411 |
Total cost of sales | 4,360 |  |  | 3,880 |  |  | 4,086 |
Gross margin | $ | 2,724 |  |  | $ | 2,056 |  |  | $ | 2,545 |
Total other operating costs and expenses(7) | 438 |  |  | 314 |  |  | 307 |
Equity in earnings (loss) of operating affiliate(8) | 14 |  |  | 4 |  |  | (8) |
Operating earnings | $ | 2,300 |  |  | $ | 1,746 |  |  | $ | 2,230 |

_______________________________________________________________________________
(1)Natural gas costs include the impact of realized gains and losses on natural gas derivatives settled during the period.
(2)For the years ended December 31, 2025, 2024 and 2023, depreciation and amortization does not include $32 million, $34 million and $13 million, respectively, of depreciation and amortization allocated to Corporate, which includes amortization of definite-lived intangible assets. For the years ended December 31, 2025, 2024 and 2023, depreciation and amortization does not include $30 million, $30 million and $3 million, respectively, related to amortization of the supply contract liability, which is recognized in net sales. See Note 4—Revenue Recognition for additional information.
(3)Distribution and storage costs consist of the cost of freight required to transport finished products from our manufacturing facilities to our distribution facilities and the costs to operate our network of distribution facilities in North America.
(4)Freight costs consist of the costs incurred by us to deliver products from one of our plants or distribution facilities to the customer. Freight costs are generally charged to the customer and included in net sales. In situations when control of the product transfers upon loading and the customer requests that we arrange delivery of the product, the amount of freight included in net sales is considered freight revenue. See Note 4—Revenue Recognition for additional information.
(5)Other segment items is primarily comprised of payroll, services, materials and supplies, and utilities at our manufacturing facilities.
(6)Other consists of all other products not included in our Ammonia, Granular Urea, UAN, or AN segments. All other products primarily include DEF, urea liquor, nitric acid and aqua ammonia.
(7)Total other operating costs and expenses for the year ended December 31, 2025 includes $76 million of asset impairment related to property, plant and equipment at our Donaldsonville and Yazoo City facilities. See Note 6—Property, Plant and Equipment—Net for additional information.
(8)Equity in loss of operating affiliate for the year ended December 31, 2023 includes an impairment of our equity method investment in PLNL of $43 million. See Note 8—Equity Method Investment for additional information.
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Enterprise-wide data by geographic region is as follows:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Sales by geographic region (based on destination of shipments): |  |  |  |  |
United States | $ | 5,338 |  |  | $ | 4,419 |  |  | $ | 4,856 |
Foreign: |  |  |  |  |
Canada | 598 |  |  | 534 |  |  | 607 |
North America, excluding U.S. and Canada | 58 |  |  | 72 |  |  | 75 |
United Kingdom | 378 |  |  | 327 |  |  | 346 |
Other foreign | 712 |  |  | 584 |  |  | 747 |
Total foreign | 1,746 |  |  | 1,517 |  |  | 1,775 |
Consolidated | $ | 7,084 |  |  | $ | 5,936 |  |  | $ | 6,631 |

| December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Property, plant and equipment—net by geographic region: |  |  |  |  |
United States | $ | 6,196 |  |  | $ | 6,172 |  |  | $ | 6,538 |
Foreign: |  |  |  |  |
Canada | 403 |  |  | 426 |  |  | 466 |
United Kingdom | 116 |  |  | 137 |  |  | 137 |
Total foreign | 519 |  |  | 563 |  |  | 603 |
Consolidated | $ | 6,715 |  |  | $ | 6,735 |  |  | $ | 7,141 |

Our principal customers are cooperatives, retailers, independent fertilizer distributors, traders, wholesalers and industrial users. In 2025, 2024 and 2023, CHS accounted for approximately 13%, 12% and 13% of our consolidated net sales, respectively. See Note 18—Noncontrolling Interests for additional information.
22. Supplemental Cash Flow Information
The following provides additional information relating to cash flow activities:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Cash paid during the year for: |  |  |  |  |
Interest—net of interest capitalized | $ | 137 |  |  | $ | 118 |  |  | $ | 145 |
Income taxes—net of refunds: |  |  |  |  |
U.S. federal | $ | 252 |  |  | $ | 336 |  |  | $ | 263 |
U.S. state and local: |  |  |  |  |
Illinois | * |  | * |  | 22 |
Other | 38 |  |  | 47 |  |  | 52 |
Total U.S. state and local | 38 |  |  | 47 |  |  | 74 |
Foreign: |  |  |  |  |
Canada | 23 |  |  | 24 |  |  | 32 |
Other | 8 |  |  | 3 |  |  | 4 |
Total foreign | 31 |  |  | 27 |  |  | 36 |
Total income taxes—net of refunds | $ | 321 |  |  | $ | 410 |  |  | $ | 373 |

_____________________________________________________________________________
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* For the years ended December 31, 2025 and 2024, amounts for this jurisdiction were below the threshold for separate disclosure. As such, these amounts are reflected in Other.
Interest—net of interest capitalized for the year ended December 31, 2024 includes a reduction of approximately $21 million reflecting interest relief received from the CRA related to certain tax years from 2006 through 2011. See Note 10—Income Taxes for additional information.

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Supplemental disclosure of noncash investing and financing activities: |  |  |  |  |
Change in capitalized expenditures in accounts payable, accrued expenses and other liabilities | $ | 17 |  |  | $ | 33 |  |  | $ | 15 |
Change in accrued share repurchases, including accrued excise taxes | (12) |  |  | 19 |  |  | 5 |

23. Asset Retirement Obligations
Asset retirement obligations (AROs) are legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. AROs are initially recognized as incurred when sufficient information exists to estimate fair value. We have AROs at our nitrogen manufacturing complexes and at our distribution and storage facilities that are conditional upon cessation of operations. These AROs include certain decommissioning activities as well as the removal and disposal of certain chemicals, waste materials, structures, equipment, vessels, piping and storage tanks. Also included are reclamation of land and the closure of certain effluent ponds and/or waste storage areas. The most recent estimate of the aggregate cost of conditional AROs for our complexes and facilities, expressed in 2025 dollars, is approximately $142 million, which excludes recorded AROs discussed below.
We have not recorded a liability for these conditional AROs as of December 31, 2025, because we do not believe there is currently a reasonable basis for estimating a date or range of dates of cessation of operations at our nitrogen manufacturing facilities or our distribution and storage facilities, which is necessary in order to estimate fair value. In reaching this conclusion, we considered the historical performance of each complex or facility and considered factors such as planned maintenance, asset replacements and upgrades of plant and equipment, which if conducted as in the past, can extend the physical lives of our nitrogen manufacturing facilities and our distribution and storage facilities indefinitely. We also considered the possibility of changes in technology, risk of obsolescence, and availability of raw materials in arriving at our conclusion.
In the first quarter of 2025, we completed the sale of our facility in Ince, United Kingdom, which had been permanently closed since 2022. The sale agreement included indemnification provisions that released us from all known and unknown environmental liabilities. Upon transfer of the environmental permit to the new owner in the third quarter of 2025, the recorded ARO liability of $4 million was derecognized.
As of December 31, 2025, amounts recorded for AROs, which relate to certain assets for which a fair value can be estimated, were not material.
24. Leases
We have operating leases for certain property and equipment under various noncancelable agreements, the most significant of which are rail car leases and barge tow charters for the distribution of our products. The rail car leases currently have minimum terms ranging from one to eleven years and the barge tow charter commitments range from one to six years. Our rail car leases and barge tow charters commonly contain provisions for automatic renewal that can extend the lease term unless cancelled by either party. We also have operating leases for terminal and warehouse storage for our distribution system, some of which contain minimum throughput requirements. The storage agreements contain minimum terms generally ranging from one to four years and commonly contain provisions for automatic renewal thereafter unless cancelled by either party. The renewal provisions for our rail car leases, barge tow charters and terminal and warehouse storage agreements are not reasonably certain to be exercised.
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The components of lease costs were as follows:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Operating lease cost | $ | 126 |  |  | $ | 112 |  |  | $ | 113 |
Short-term lease cost | 31 |  |  | 40 |  |  | 30 |
Variable lease cost | 4 |  |  | 5 |  |  | 4 |
Total lease cost | $ | 161 |  |  | $ | 157 |  |  | $ | 147 |

Supplemental cash flow information related to leases was as follows:

| Year ended December 31,
| 2025 |  | 2024 |  | 2023
| (in millions)
Operating cash flows - cash paid for amounts included in the measurement of operating lease liabilities | $ | 118 |  |  | $ | 98 |  |  | $ | 107 |
Right-of-use (ROU) assets obtained in exchange for operating lease obligations | 252 |  |  | 107 |  |  | 103 |

Supplemental balance sheet information related to leases was as follows:

| December 31,
| 2025 |  | 2024
| (in millions)
Operating lease ROU assets | $ | 410 |  |  | $ | 266 |
Current operating lease liabilities | $ | 110 |  |  | $ | 86 |
Operating lease liabilities | 311 |  |  | 189 |
Total operating lease liabilities | $ | 421 |  |  | $ | 275 |

Other information related to leases was as follows:

| December 31,
| 2025 |  | 2024
Operating leases |  |  |
Weighted-average remaining lease term | 5 years |  | 5 years
Weighted-average discount rate | 5.1 | % |  | 5.0 | %

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The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2025:

| Operating lease payments |  |
| (in millions)
2026 | $ | 128 |  |  |
2027 | 105 |  |  |
2028 | 90 |  |  |
2029 | 70 |  |  |
2030 | 37 |  |  |
Thereafter | 55 |  |  |
Total lease payments | 485 |  |  |
Less: imputed interest | (64) |  |  |
Present value of lease liabilities | 421 |  |  |
Less: Current operating lease liabilities | (110) |  |  |
Operating lease liabilities | $ | 311 |  |  |

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A. CONTROLS AND PROCEDURES.
(a) Disclosure Controls and Procedures. The Company’s management, with the participation of the Company’s principal executive officer and principal financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based on such evaluation, the Company’s principal executive officer and principal financial officer have concluded that, as of the end of such period, the Company’s disclosure controls and procedures are effective in (i) ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including the Company’s principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.
(b) Management’s Report on Internal Control over Financial Reporting.
Management’s Report on Internal Control over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, for the Company. Under the supervision and with the participation of our senior management, including our principal executive officer and principal financial officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2025, using the criteria set forth in the Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Based on this assessment, management has concluded that our internal control over financial reporting is effective as of December 31, 2025. KPMG LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements, has issued an attestation report on the Company’s internal control over financial reporting as of December 31, 2025, which appears on the following page.
(c) Changes in Internal Control over Financial Reporting. Other than changes due to the Company’s implementation of a new procurement and plant asset management system, which began in the second quarter of 2025 and was completed in the fourth quarter of 2025, there have not been any changes in the Company’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
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Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
CF Industries Holdings, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited CF Industries Holdings, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements), and our report dated February 25, 2026 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
(signed) KPMG LLP
Chicago, Illinois
February 25, 2026
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ITEM 9B. OTHER INFORMATION.
During the quarter ended December 31, 2025, there were no Rule 10b5-1 trading arrangements (as defined in Item 408(a) of Regulation S-K) or non-Rule 10b5-1 trading arrangements (as defined in Item 408(c) of Regulation S-K) adopted or terminated by any director or officer (as defined in Rule 16a-1(f) under the Exchange Act) of CF Industries Holdings, Inc., except as follows:
On November 12, 2025, Bert A. Frost, Executive Vice President and Chief Commercial Officer, adopted a Rule 10b5-1 trading arrangement for the sale of up to 11,196 shares of Common Stock, subject to certain conditions, between March 2, 2026 and August 4, 2026.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS.
Not applicable.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
Information appearing in the Proxy Statement under the headings “Proposal 1: Election of Directors—Director Nominees”; “Proposal 1: Election of Directors—Director Nominee Biographies”; “Executive Officers”; “Corporate Governance—Committees of the Board—Audit Committee”; and, if required, “Delinquent Section 16(a) Reports” is incorporated herein by reference.
We have adopted a Code of Corporate Conduct that applies to our employees, directors and officers, including our principal executive officer, principal financial officer and principal accounting officer. The Code of Corporate Conduct is posted on our corporate website, www.cfindustries.com. We will provide an electronic or paper copy of this document free of charge upon request. In the event of any amendments to, or waivers from, a provision of the Code of Corporate Conduct affecting the chief executive officer, chief financial officer, controller or persons performing similar functions, we intend to promptly post on our corporate website a description of the amendment or waiver as required under applicable SEC rules.
We have adopted a Policy on Insider Trading applicable to our directors, officers, employees and certain other persons and entities (collectively, “covered persons”) that we believe is reasonably designed to promote compliance with insider trading laws, rules, and regulations and any applicable listing standard. Among other things, our insider trading policy prohibits covered persons who are aware of any material nonpublic information about the Company from, directly or indirectly through family members or other persons or entities as described in the policy, (i) transacting in Company securities, except as provided for therein or (ii) recommending the purchase or sale of any Company securities. A copy of our Policy on Insider Trading is filed as Exhibit 19 with this Annual Report on Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION.
During the last completed fiscal year, John W. Eaves, Javed Ahmed, Susan Ellerbusch (from May 2025), Stephen J. Hagge, Anne P. Noonan and Michael J. Toelle (from January 2025 to May 2025) served as the members of the Compensation and Management Development Committee of the Board.
Information appearing under the following headings of the Proxy Statement is incorporated herein by reference: “Compensation Discussion and Analysis,” “Compensation Discussion and Analysis—Compensation Discussion and Analysis: In Detail—Other Compensation Governance Practices and Considerations—Compensation and Benefits Risk Analysis,” “Compensation Committee Report,” “Executive Compensation” and “Corporate Governance—Director Compensation.”
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
Information appearing under the following headings of the Proxy Statement is incorporated herein by reference: “Common Stock Ownership—Common Stock Ownership of Certain Beneficial Owners” and “Common Stock Ownership—Common Stock Ownership of Directors and Management.”
We currently issue stock-based compensation under the CF Industries Holdings, Inc. 2022 Equity and Incentive Plan (the 2022 Equity and Incentive Plan) which permits grants of stock options, stock appreciation rights, restricted stock, restricted stock units and other stock-based awards, which in each case may be conditioned on performance criteria, to employees and certain consultants of the Company and its subsidiaries and non-employee directors of the Company.
Equity Compensation Plan Information as of December 31, 2025

Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights(1) |  | Weighted-average exercise price of outstanding options, warrants and rights(2) |  | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in the first column)(3)
Equity compensation plans approved by security holders | 1,659,478 |  |  | $ | 32.85 |  |  | 6,310,718 |
Equity compensation plans not approved by security holders | — |  |  | — |  |  | — |
Total | 1,659,478 |  |  | $ | 32.85 |  |  | 6,310,718 |

_______________________________________________________________________________
(1)Includes 54,160 shares issuable pursuant to outstanding nonqualified stock options, 523,100 shares issuable pursuant to restricted stock units (RSUs) and 1,082,218 shares issuable pursuant to performance restricted stock units (PSUs) under the 2022 Equity and Incentive Plan and the CF Industries Holdings, Inc. 2014 Equity and Incentive Plan. PSUs are subject to attainment of the applicable performance goals during the three-year performance period and are reflected at their maximum potential payout. The PSUs included in this table reflect the full amount awarded to plan participants in 2023, 2024 and 2025. The three-year performance periods for the PSUs awarded in 2023, 2024 and 2025 are in each case composed of three one-year periods with performance goals set annually. Because accounting rules require performance goals to be set before a PSU is determined for accounting purposes to have been granted, the number of PSUs reported as outstanding as of December 31, 2025 in Note 20—Stock-based Compensation reflects all of the PSUs awarded in 2023, but only two-thirds of the PSUs awarded in 2024 and one-third of the PSUs awarded in 2025.
(2)RSUs and PSUs are not reflected in the weighted-average exercise price as these awards do not have an exercise price.
(3)Under the 2022 Equity and Incentive Plan, upon the grant of an award, the number of shares available for issuance is reduced by one share for each share subject to or issued in respect of such awards. Under the 2022 Equity and Incentive Plan, shares withheld for taxes on awards are added to the number of shares available for issuance.
See Note 20—Stock-based Compensation for additional information on the 2022 Equity and Incentive Plan.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
Information appearing in the Proxy Statement under the headings “Corporate Governance—Director Independence” and “Policy Regarding Related Person Transactions” is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
Information appearing in the Proxy Statement under the headings “Proposal 3: Ratification of Selection of Independent Registered Public Accounting Firm for 2026—Audit and Non-Audit Fees” and “Proposal 3: Ratification of Selection of Independent Registered Public Accounting Firm for 2026—Pre-Approval of Audit and Non-Audit Services” is incorporated herein by reference.
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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a)Documents filed as part of this report:

(1) |  | All financial statements:
The following financial statements are included in Part II, Item 8. Financial Statements and Supplementary Data:
| Report of Independent Registered Public Accounting Firm (KPMG LLP, Chicago, IL, PCAOB ID: 185) | 64
| Consolidated Statements of Operations | 66
| Consolidated Statements of Comprehensive Income | 67
| Consolidated Balance Sheets | 68
| Consolidated Statements of Equity | 69
| Consolidated Statements of Cash Flows | 70
| Notes to Consolidated Financial Statements | 71
Financial statement schedules are omitted because they are not applicable or the required information is included in the consolidated financial statements or notes thereto.
(2) |  | Exhibits |
A list of exhibits filed with this Annual Report on Form 10-K (or incorporated by reference to exhibits previously filed or furnished) is provided in the Exhibit Index on page 119 of this report.

ITEM 16. FORM 10-K SUMMARY.
None.
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EXHIBIT INDEX

EXHIBIT NO. |  | DESCRIPTION
2.1 |  | Agreement and Plan of Merger, dated as of July 21, 2005, by and among CF Industries Holdings, Inc., CF Merger Corp. and CF Industries, Inc. (incorporated by reference to Exhibit 2.1 to Amendment No. 3 to CF Industries Holdings, Inc.'s Registration Statement on Form S-1 filed with the SEC on July 26, 2005, File No. 333-124949)
2.2 |  | Agreement and Plan of Merger, dated as of March 12, 2010, by and among CF Industries Holdings, Inc., Composite Merger Corporation and Terra Industries Inc. (incorporated by reference to Exhibit 2.1 to CF Industries Holdings, Inc.'s Current Report on Form 8-K filed with the SEC on March 12, 2010)
2.3 |  | Asset Purchase Agreement, dated October 28, 2013, among CF Industries Holdings, Inc., CF Industries, Inc. and The Mosaic Company (incorporated by reference to Exhibit 2.1 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on November 1, 2013)*
2.4 |  | Second Amended and Restated Limited Liability Company Agreement of CF Industries Nitrogen, LLC, dated as of December 18, 2015, by and between CF Industries Sales, LLC and CHS Inc. (incorporated by reference to Exhibit 2.4 to CF Industries Holdings, Inc.’s Annual Report on Form 10-K filed with the SEC on February 24, 2022) *,**
2.5 |  | First Amendment to the Second Amended and Restated Limited Liability Company Agreement of CF Industries Nitrogen, LLC, dated as of March 30, 2018, by and among CF Industries Nitrogen, LLC, CF Industries Sales, LLC, CF USA Holdings, LLC and CHS Inc. (incorporated by reference to Exhibit 2.1 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on May 3, 2018)*
2.6 |  | Asset Purchase Agreement, dated as of March 20, 2023, by and among Dyno Nobel Louisiana Ammonia, LLC, CF Industries East Point, LLC, and, solely for the purposes of Article X, Incitec Pivot Limited and CF Industries Holdings, Inc. (incorporated by reference to Exhibit 2.1 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on March 20, 2023)*
3.1 |  | Third Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on May 5, 2023)
3.2 |  | Fifth Amended and Restated Bylaws of CF Industries Holdings, Inc., effective December 13, 2022 (incorporated by reference to Exhibit 3.1 to CF Industries Holdings, Inc.'s Current Report on Form 8-K filed with the SEC on December 15, 2022)
4.1 |  | Specimen common stock certificate (incorporated by reference to Exhibit 4.3 to CF Industries Holdings, Inc.'s Current Report on Form 8-K filed with the SEC on July 25, 2017)
4.2 |  | Description of common stock of CF Industries Holdings, Inc. (incorporated by reference to Exhibit 4.2 to CF Industries Holdings, Inc.'s Annual Report on Form 10-K filed with the SEC on February 22, 2024)
4.3 |  | Indenture, dated as of May 23, 2013, among CF Industries, Inc., CF Industries Holdings, Inc. and Computershare Trust Company, N.A., as successor trustee (incorporated by reference to Exhibit 4.1 to CF Industries Holdings, Inc.'s Current Report on Form 8-K filed with the SEC on May 23, 2013)
4.4 |  | Second Supplemental Indenture, dated as of May 23, 2013, among CF Industries, Inc., CF Industries Holdings, Inc. and Computershare Trust Company, N.A., as successor trustee, relating to CF Industries, Inc.’s 4.950% Senior Notes due 2043 (includes form of note) (the “2043 Notes Supplement”) (incorporated by reference to Exhibit 4.3 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on May 23, 2013)
4.5 |  | First Supplement, dated as of November 21, 2016, relating to the 2043 Notes Supplement (incorporated by reference to Exhibit 4.12 to CF Industries Holdings, Inc.’s Annual Report on Form 10-K filed with the SEC on February 23, 2017)
4.6 |  | Second Supplement, dated as of March 29, 2018, relating to the 2043 Notes Supplement (incorporated by reference to Exhibit 4.3 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on May 3, 2018)
4.7 |  | Third Supplement, dated as of March 22, 2019, relating to the 2043 Notes Supplement (incorporated by reference to Exhibit 4.3 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on May 2, 2019)
4.8 |  | Fourth Supplement, dated as of January 28, 2022, relating to the 2043 Notes Supplement (incorporated by reference to Exhibit 4.4 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on February 1, 2022)

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EXHIBIT NO. |  | DESCRIPTION
4.9 |  | Third Supplemental Indenture, dated as of March 11, 2014, among CF Industries, Inc., CF Industries Holdings, Inc. and Computershare Trust Company, N.A., as successor trustee, relating to CF Industries, Inc.’s 5.150% Senior Notes due 2034 (includes form of note) (the “2034 Notes Supplement”) (incorporated by reference to Exhibit 4.2 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on March 11, 2014)
4.10 |  | First Supplement, dated as of November 21, 2016, relating to the 2034 Notes Supplement (incorporated by reference to Exhibit 4.14 to CF Industries Holdings, Inc.’s Annual Report on Form 10-K filed with the SEC on February 23, 2017)
4.11 |  | Second Supplement, dated as of March 29, 2018, relating to the 2034 Notes Supplement (incorporated by reference to Exhibit 4.4 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on May 3, 2018)
4.12 |  | Third Supplement, dated as of March 22, 2019, relating to the 2034 Notes Supplement (incorporated by reference to Exhibit 4.4 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on May 2, 2019)
4.13 |  | Fourth Supplement, dated as of January 28, 2022, relating to the 2034 Notes Supplement (incorporated by reference to Exhibit 4.3 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on February 1, 2022)
4.14 |  | Fourth Supplemental Indenture, dated as of March 11, 2014, among CF Industries, Inc., CF Industries Holdings, Inc. and Computershare Trust Company, N.A., as successor trustee, relating to CF Industries, Inc.'s 5.375% Senior Notes due 2044 (includes form of note) (the “2044 Notes Supplement”) (incorporated by reference to Exhibit 4.3 to CF Industries Holdings, Inc.'s Current Report on Form 8-K filed with the SEC on March 11, 2014)
4.15 |  | First Supplement, dated as of November 21, 2016, relating to the 2044 Notes Supplement (incorporated by reference to Exhibit 4.16 to CF Industries Holdings, Inc.’s Annual Report on Form 10-K filed with the SEC on February 23, 2017)
4.16 |  | Second Supplement, dated as of March 29, 2018, relating to the 2044 Notes Supplement (incorporated by reference to Exhibit 4.5 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on May 3, 2018)
4.17 |  | Third Supplement, dated as of March 22, 2019, relating to the 2044 Notes Supplement (incorporated by reference to Exhibit 4.5 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on May 2, 2019)
4.18 |  | Fourth Supplement, dated as of January 31, 2022, relating to the 2044 Notes Supplement (incorporated by reference to Exhibit 4.5 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on February 1, 2022)
4.19 |  | Indenture, dated as of November 21, 2016, among CF Industries Holdings, Inc., CF Industries, Inc., the Subsidiary Guarantors (as defined therein) party thereto and Computershare Trust Company, N.A., as successor trustee, relating to CF Industries, Inc.’s 4.500% Senior Secured Notes due 2026 (includes form of note) (the “2026 Notes Indenture”) (incorporated by reference to Exhibit 4.2 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on November 22, 2016)
4.20 |  | First Supplemental Indenture, dated as of March 29, 2018, relating to the 2026 Notes Indenture (incorporated by reference to Exhibit 4.7 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on May 3, 2018)
4.21 |  | Second Supplemental Indenture, dated as of March 22, 2019, relating to the 2026 Notes Indenture (incorporated by reference to Exhibit 4.7 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on May 2, 2019)
4.22 |  | Third Supplemental Indenture, dated as of January 28, 2022, relating to the 2026 Notes Indenture (incorporated by reference to Exhibit 4.2 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on February 1, 2022)
4.23 |  | Indenture, dated as of November 6, 2025, by and among CF Industries, Inc., CF Industries Holdings, Inc. and Wilmington Trust, National Association, relating to debt securities of CF Industries, Inc. (incorporated by reference to Exhibit 4.3 to CF Industries, Inc.’s and CF Industries Holdings, Inc.’s Registration Statement on Form S-3 filed with the SEC on November 6, 2025)

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EXHIBIT NO. |  | DESCRIPTION
4.24 |  | Supplemental Indenture No. 1, dated as of November 26, 2025, by and among CF Industries, Inc., CF Industries Holdings, Inc. and Wilmington Trust, National Association, as Trustee, to the Indenture dated as of November 6, 2025 (incorporated by reference to Exhibit 4.2 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on November 26, 2025)
10.1 |  | Change in Control Severance Agreement, effective as of September 1, 2009, amended as of October 20, 2010, amended further and restated as of February 17, 2014 and amended further and restated and effective as of January 4, 2026 by and between CF Industries Holdings, Inc. and Christopher D. Bohn (incorporated by reference to Exhibit 10.1 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on December 19, 2025)***
10.2 |  | Change in Control Severance Agreement, effective as of November 21, 2008, by and between CF Industries Holdings, Inc. and Bert A. Frost (incorporated by reference to Exhibit 10.11 to CF Industries Holdings, Inc.’s Annual Report on Form 10-K filed with the SEC on February 26, 2009)***
10.3 |  | Change in Control Severance Agreement, effective as of November 19, 2007 and amended and restated as of March 6, 2009, by and between CF Industries Holdings, Inc. and Richard A. Hoker (incorporated by reference to Exhibit (e)(9) to CF Industries Holdings, Inc.’s Solicitation/Recommendation Statement on Schedule 14D-9 filed with the SEC on March 23, 2009)***
10.4 |  | Change in Control Severance Agreement, effective as of October 9, 2017, by and between CF Industries Holdings, Inc. and Susan L. Menzel (incorporated by reference to Exhibit 10.1 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on November 2, 2017)***
10.5 |  | Change in Control Severance Agreement, effective as of April 24, 2007, amended as of July 24, 2007, and amended further and restated as of February 17, 2014, by and between CF Industries Holdings, Inc. and W. Anthony Will (incorporated by reference to Exhibit 99.1 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on February 20, 2014)***
10.6 |  | Change in Control Severance Agreement, effective as of February 2, 2012, and amended and restated as of September 1, 2019, by and between CF Industries Holdings, Inc. and Ashraf K. Malik (incorporated by reference to Exhibit 10.1 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on October 31, 2019)***
10.7 |  | Change in Control Severance Agreement, effective as of February 27, 2020, by and between CF Industries Holdings, Inc. and Linda M. Dempsey (incorporated by reference to Exhibit 10.1 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on May 7, 2020)***
10.8 |  | Change in Control Severance Agreement, effective as of October 17, 2023, by and between CF Industries Holdings, Inc. and Michael P. McGrane (incorporated by reference to Exhibit 10.2 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on November 2, 2023)***
10.9 |  | Change in Control Severance Agreement, effective as of June 17, 2024, by and between CF Industries Holdings, Inc. and Gregory D. Cameron (incorporated by reference to Exhibit 10.2 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on August 8, 2024)***
10.10 |  | Separation and Release Agreement, dated January 12, 2026, between CF Industries Holdings, Inc. and Gregory D. Cameron (incorporated by reference to Exhibit 10.1 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on January 13, 2026)***
10.1 1 |  | Form of Amendment to Change in Control Severance Agreement (incorporated by reference to Exhibit 10.3 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on December 24, 2015)***
10.1 2 |  | Form of Indemnification Agreement with Officers and Directors (incorporated by reference to Exhibit 10.10 to Amendment No. 2 to CF Industries Holdings, Inc.’s Registration Statement on Form S-1 filed with the SEC on July 20, 2005, File No. 333-124949)***
10.1 3 |  | CF Industries Holdings, Inc. 2014 Equity and Incentive Plan (incorporated by reference to Appendix C to CF Industries Holdings, Inc.’s Definitive Proxy Statement on Schedule 14A filed with the SEC on April 3, 2014)***
10.1 4 |  | Amendment, dated as of July 21, 2016, to the CF Industries Holdings, Inc. 2014 Equity and Incentive Plan (incorporated by reference to Exhibit 10.4 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on August 4, 2016)***
10.1 5 |  | CF Industries Holdings, Inc. 2022 Equity and Incentive Plan (incorporated by reference to Appendix B to CF Industries Holdings, Inc.’s definitive proxy statement on Schedule 14A filed with the SEC on March 30, 2022)***

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EXHIBIT NO. |  | DESCRIPTION
10.1 6 |  | CF Industries Holdings, Inc. Supplemental Benefit and Deferral Plan (incorporated by reference to Exhibit 10.16 to CF Industries Holdings, Inc.’s Annual Report on Form 10-K filed with the SEC on February 23, 2023)***
10.1 7 |  | First Amendment of CF Industries Holdings, Inc. Supplemental Benefit and Deferral Plan (incorporated by reference to Exhibit 10.17 to CF Industries Holdings, Inc.’s Annual Report on Form 10-K filed with the SEC on February 23, 2023)***
10.1 8 |  | Second Amendment of CF Industries Holdings, Inc. Supplemental Benefit and Deferral Plan (incorporated by reference to Exhibit 10.18 to CF Industries Holdings, Inc.’s Annual Report on Form 10-K filed with the SEC on February 23, 2023)***
10.19 |  | Third Amendment of CF Industries Holdings, Inc. Supplemental Benefit and Deferral Plan (incorporated by reference to Exhibit 10.1 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on October 31, 2024)***
10.2 0 |  | Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.32 to CF Industries Holdings, Inc.’s Annual Report on Form 10-K filed with the SEC on February 23, 2017)***
10.2 1 |  | Form of Restricted Stock Unit Award Agreement under CF Industries Holdings, Inc. 2022 Equity and Incentive Plan (incorporated by reference to Exhibit 10.3 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on May 13, 2022)***
10.22 |  | Form of Performance Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.43 to CF Industries Holdings, Inc.’s Annual Report on Form 10-K filed with the SEC on February 22, 2019)***
10.2 3 |  | Form of Performance Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 to CF Industries Holdings, Inc.'s Current Report on Form 8-K filed with the SEC on December 15, 2022)***
10.24 |  | Form of Non-Employee Director Restricted Stock Award Agreement under CF Industries Holdings, Inc. 2022 Equity and Incentive Plan (incorporated by reference to Exhibit 10.2 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on May 13, 2022)***
10.25 |  | Form of Equity Award Amendment Letter Agreement, dated as of July 21, 2016 (incorporated by reference to Exhibit 10.5 to CF Industries Holdings, Inc.’s Quarterly Report on Form 10-Q filed with the SEC on August 4, 2016)***
10.26 |  | CF Industries Holdings, Inc. Annual Incentive Plan effective as of January 1, 2019 (incorporated by reference to Exhibit 10.1 to CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on December 14, 2018)***
10.27 |  | CF Industries Holdings, Inc. Annual Incentive Plan, as amended and restated effective as of January 1, 2023 (incorporated by reference to Exhibit 10.1 to CF Industries Holdings, Inc.'s Current Report on Form 8-K filed with the SEC on December 15, 2022)***
10.28 |  | Amended and Restated Nitrogen Fertilizer Purchase Agreement, dated December 18, 2015, between CF Industries Nitrogen, LLC and CHS Inc. (incorporated by reference to Exhibit 10.37 to CF Industries Holdings, Inc.’s Annual Report on Form 10-K filed with the SEC on February 24, 2022)****
10.29 |  | First Amended and Restated Revolving Credit Agreement, dated as of September 4, 2025, by and among CF Industries Holdings, Inc., CF Industries, Inc., the designated borrower from time to time party thereto, the lenders from time to time party thereto, Citibank, N.A., as administrative agent, and the issuing banks from time to time party thereto (incorporated by reference to Exhibit 10.1 of CF Industries Holdings, Inc.’s Current Report on Form 8-K filed with the SEC on September 9, 2025)
19 |  | Policy on Insider Trading (incorporated by reference to Exhibit 19 to CF Industries Holdings, Inc.’s Annual Report on Form 10-K filed with the SEC on February 20, 202 5)
21 |  | Subsidiaries of the registrant
22.1 |  | List of Subsidiary Guarantors and Issuers of Guaranteed Securities (incorporated by reference to Exhibit 22.1 to CF Industries, Inc.’s and CF Industries Holdings, Inc.’s Registration Statement on Form S-3 filed with the SEC on November 6, 2025)
23 |  | Consent of KPMG LLP, independent registered public accounting firm
31.1 |  | Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2 |  | Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

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CF INDUSTRIES HOLDINGS, INC.

EXHIBIT NO. |  | DESCRIPTION
32.1 |  | Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2 |  | Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
97 |  | Policy related to recovery of erroneously awarded compensation (incorporated by reference to Exhibit 97 to CF Industries Holdings, Inc.'s Annual Report on Form 10-K filed with the SEC on February 22, 2024)
101 |  | The following financial information from CF Industries Holdings, Inc.’s Annual Report on Form 10-K for the fiscal year ended December 31, 2025, formatted in Inline XBRL (eXtensible Business Reporting Language): (1) Consolidated Statements of Operations, (2) Consolidated Statements of Comprehensive Income, (3) Consolidated Balance Sheets, (4) Consolidated Statements of Equity, (5) Consolidated Statements of Cash Flows and (6) Notes to Consolidated Financial Statements
104 |  | Cover Page Interactive Data File (embed within the Inline XBRL document and included in Exhibit 101)

_______________________________________________________________________________
* Schedules (or similar attachments) have been omitted pursuant to Item 601(a)(5) of Regulation S-K.
** Portions omitted pursuant to Item 601(b)(2)(ii) of Regulation S-K.
*** Denotes management contract or compensatory plan or arrangement.
**** Portions omitted pursuant to Item 601(b)(10)(iv) of Regulation S-K.
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CF INDUSTRIES HOLDINGS, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

|  |  | CF INDUSTRIES HOLDINGS, INC.
Date: | February 25, 2026 |  | By: | /s/ CHRISTOPHER D. BOHN
|  |  |  | Christopher D. Bohn President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature |  | Title(s) |  | Date
/s/ CHRISTOPHER D. BOHN |  | President and Chief Executive Officer, Director (Principal Executive Officer) |  | February 25, 2026
Christopher D. Bohn |  |  |
/s/ RICHARD A. HOKER |  | Vice President and Corporate Controller and Interim Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) |  | February 25, 2026
Richard A. Hoker |  |  |
/s/ STEPHEN J. HAGGE |  | Chair of the Board of Directors, Director |  | February 25, 2026
Stephen J. Hagge |  |  |
/s/ JAVED AHMED |  | Director |  | February 25, 2026
Javed Ahmed |  |  |
/s/ ROBERT C. ARZBAECHER |  | Director |  | February 25, 2026
Robert C. Arzbaecher |  |  |
/s/ DEBORAH L. DEHAAS |  | Director |  | February 25, 2026
Deborah L. DeHaas |  |  |
/s/ JOHN W. EAVES |  | Director |  | February 25, 2026
John W. Eaves |  |  |
/s/ SUSAN A. ELLERBUSCH |  | Director |  | February 25, 2026
Susan A. Ellerbusch |  |  |
/s/ JESUS MADRAZO YRIS |  | Director |  | February 25, 2026
Jesus Madrazo Yris |  |  |  |
/s/ ANNE P. NOONAN |  | Director |  | February 25, 2026
Anne P. Noonan |  |  |
/s/ MICHAEL J. TOELLE |  | Director |  | February 25, 2026
Michael J. Toelle |  |  |
/s/ THERESA E. WAGLER |  | Director |  | February 25, 2026
Theresa E. Wagler |  |  |
/s/ CELSO L. WHITE |  | Director |  | February 25, 2026
Celso L. White |  |  |
/s/ W. ANTHONY WILL |  | Director |  | February 25, 2026
W. Anthony Will |  |  |

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