CF Industries Holdings, Inc. (CF) FY 2021 MD&A

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 only to CF Industries Holdings, Inc. itself 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 and references to tonnes refer to metric 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, 2020 compared to December 31, 2019, you should read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2020 Annual Report on Form 10-K filed with the Securities and Exchange Commission (SEC) on February 24, 2021. The following is an outline of the discussion and analysis included herein:

•Overview of CF Holdings

•Our Company

•Our Commitment to a Clean Energy Economy

•Industry Factors

•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 green and blue hydrogen and nitrogen products for energy, fertilizer, emissions abatement, and other industrial activities. Our nine manufacturing complexes in the United States, Canada and the United Kingdom, an extensive storage, transportation and distribution network in North America, and logistics capabilities enabling a global reach underpin our strategy to leverage our unique capabilities to accelerate the world’s transition to clean energy. Our principal customers are cooperatives, independent fertilizer distributors, traders, wholesalers and industrial users. Our core product is anhydrous ammonia (ammonia), which contains 82% nitrogen and 18% hydrogen. Our nitrogen products that are upgraded from ammonia are granular urea, urea ammonium nitrate solution (UAN) and ammonium nitrate (AN). Our other nitrogen products include diesel exhaust fluid (DEF), urea liquor, nitric acid and aqua ammonia, which are sold primarily to our industrial customers, and compound fertilizer products (NPKs), which are solid granular fertilizer products for which the nutrient content is a combination of nitrogen, phosphorus and potassium.

Our principal assets as of December 31, 2021 include:

•five U.S. nitrogen manufacturing facilities, located in Donaldsonville, Louisiana (the largest nitrogen complex in the world); Port Neal, Iowa; Yazoo City, Mississippi; Verdigris, Oklahoma; and Woodward, Oklahoma. These 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 Interest for additional information on our strategic venture with CHS;

•two Canadian nitrogen manufacturing facilities, located in Medicine Hat, Alberta (the largest nitrogen complex in Canada) and Courtright, Ontario;

•two United Kingdom nitrogen manufacturing facilities, located in Billingham and Ince;

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

•a 50% interest in Point Lisas Nitrogen Limited (PLNL), an ammonia production joint venture located in the Republic of Trinidad and Tobago that we account for under the equity method.

Our Commitment to a Clean Energy Economy

We are taking significant steps to support a global hydrogen and clean fuel economy, through the production of green and blue ammonia. Since ammonia is one of the most efficient ways to transport and store hydrogen and is also a fuel in its own right, we believe that the Company, as the world’s largest producer of ammonia, with an unparalleled manufacturing and distribution network and deep technical expertise, is uniquely positioned to fulfill anticipated demand for hydrogen and ammonia from green and blue sources. Our approach includes green ammonia production, which refers to ammonia produced through a carbon-free process, and blue ammonia production, which relates to ammonia produced by conventional processes but with CO2 removed through carbon capture and sequestration (CCS) and other certified carbon abatement projects.

In October 2020, we announced an initial green ammonia project at our Donaldsonville complex. In April 2021, we signed an engineering and procurement contract with thyssenkrupp to supply a 20 MW alkaline water electrolysis plant to produce green hydrogen at our Donaldsonville complex. Construction and installation, which is being managed by us, began in the fourth quarter of 2021 and is expected to finish in 2023, with an estimated total cost of approximately $100 million. The cost of the project is expected to fit within our annual capital expenditure budgets. We will integrate the green hydrogen generated by the electrolysis plant into existing ammonia synthesis loops to enable the production of approximately 20,000 tons per year of green ammonia. We believe that, when completed in 2023, the Donaldsonville green ammonia project will be the largest of its kind in North America.

In the third quarter of 2021, we signed a memorandum of understanding with Mitsui & Co., Inc. (Mitsui) that will guide us in a joint exploration of the development of blue ammonia projects in the United States. The preliminary studies we are conducting with Mitsui cover areas such as blue ammonia supply and supply chain infrastructure, CO2 transportation and storage, expected environmental impacts, and blue ammonia economics and marketing opportunities in Japan and in other countries.

We have also announced steps to produce blue ammonia from our ammonia production network. In the fourth quarter of 2021, our Board of Directors authorized projects that we believe will enable the annual production of up to 1.25 million tons of blue ammonia from our existing network starting in 2024. The projects will involve constructing units at our Donaldsonville and Yazoo City complexes that dehydrate and compress CO2, a process essential for CO2 transport via pipeline to sequestration sites. Management expects that, once the units are in service and sequestration is initiated, we could sequester up to 2.5 million tons of CO2 per year (2 million tons at Donaldsonville and 500,000 tons at Yazoo City). Under current regulations, the projects would be expected to qualify for tax credits under Section 45Q of the Internal Revenue Code, which provides a credit per tonne of CO2 sequestered.

Construction of the units at the Donaldsonville complex is expected to begin in 2022 and to be completed in 2024, with an estimated total cost of $200 million. The Yazoo City project will be timed to coincide with CO2 transport pipeline construction. Once started, the project is expected to be completed in three years with an estimated total cost of $85 million. In addition, we are currently in advanced discussions with several parties regarding transportation and sequestration of CO2 from Donaldsonville.

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 globally traded 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 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

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consumption, fertilizer application rates, and governmental regulations, including fertilizer subsidies or requirements mandating increased use of bio-fuels or industrial nitrogen products. Other geopolitical factors like temporary disruptions in fertilizer trade related to government intervention or changes in the buying/selling patterns of key exporting/consuming countries such as 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 these commodities.

Global Trade in Fertilizer

In addition to the relationship between global supply and demand, profitability within a particular geographic region is determined 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 and governmental nitrogen product trade policies, including the imposition of duties, tariffs or quotas, that affect foreign trade or investment. The development of additional natural gas reserves in North America over the last decade has decreased natural gas costs relative to the rest of the world, making North 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.

Imports account for a significant portion of the nitrogen fertilizer consumed in North America. Producers of nitrogen-based fertilizers located in the Middle East, the Republic of Trinidad and Tobago, North Africa and Russia have been major exporters to North America in recent years. As a result, the North American nitrogen fertilizer market for certain nitrogen products is dependent on imports to balance supply and demand.

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

Selling Prices and Sales Volume

The selling prices for all of our major products were higher in 2021 than 2020, driven by the impact of a tighter global nitrogen supply and demand balance, as a result of strong global demand as well as decreased global supply availability as higher global energy costs drove lower global operating rates. The average selling price for our products for 2021 and 2020 was $353 per ton and $203 per ton, respectively. The increase in average selling prices of 74% in 2021 from 2020 resulted in an increase in net sales of approximately $2.76 billion.

Our total sales volume was 9% lower in 2021 than in 2020 with lower sales volume reported in all segments. We shipped 18.5 million tons of product in 2021 compared to 20.3 million tons in 2020 due primarily to lower supply from the impact of both planned and unplanned maintenance activity and the impact of weather-related outages. The lower sales volumes also reflect the idling of certain portions of our U.K. operations in September due to the United Kingdom energy crisis, which is further discussed below. Lower sales volume resulted in a decrease in net sales of approximately $404 million.

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Sales volume for our products in 2021, 2020 and 2019 is shown in the table below.

Natural Gas Prices

Natural gas is the principal raw material used to produce our nitrogen products. We use natural gas both as a chemical feedstock and as a fuel to produce nitrogen products. Natural gas is a significant cost component of manufactured nitrogen products, representing approximately 40% of our production costs in 2021. 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 the National Balancing Point, the major trading point for natural gas in the United Kingdom:

Most of our nitrogen fertilizer manufacturing facilities 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. North American natural gas prices during 2021 were higher on average than during 2020 due to tight supply and demand conditions within the market. Demand for natural gas was strong throughout 2021 as cold weather early in the year, including the impact of Winter Storm Uri in February, contributed to strength in demand. Warmer weather in the summer of 2021 contributed to higher natural gas usage for electrical generation, and the economy emerging from COVID-19 pandemic conditions added to the strong summer demand. The supply response from natural gas producers during 2021 was insufficient to offset these demand factors, leading to higher prices throughout the year. In addition, liquefied natural gas (LNG) exports increased significantly in 2021 compared to 2020 as favorable pricing differentials between North America and global natural gas prices led LNG facilities in the United States to run at near maximum levels. The average daily market price at the Henry Hub, the most heavily-traded natural gas pricing point in North America, was $3.82 per MMBtu for 2021 compared to $1.99 per MMBtu for 2020, an increase of 92%. During 2021, the daily closing price at the Henry Hub reached a low of $2.36 per MMBtu on April 7, 2021 and a high of $23.61 per MMBtu on February 18, 2021 as a result of Winter Storm Uri.

In February 2021, the central portion of the United States experienced extreme and unprecedented cold weather due to the impact of Winter Storm Uri. Certain natural gas suppliers and natural gas pipelines declared force majeure events due to natural gas well freeze-offs or frozen equipment. This occurred at the same time as large increases in natural gas demand were occurring due to the cold temperatures. Due to these unprecedented factors, several states declared a state of emergency, and natural gas was redirected for residential use. At certain of our manufacturing locations, we reduced our natural gas consumption, and, as a consequence, our plants at these locations either operated at reduced rates or temporarily suspended operations. We net settled certain natural gas contracts with our suppliers and received prevailing market prices, which were in excess of our cost. As a result, we recognized a gain of $112 million, which is reflected in cost of sales in our consolidated statement of operations for the year ended December 31, 2021.

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Our two nitrogen manufacturing facilities located in the United Kingdom are subject to fluctuations associated with the price of natural gas in Europe. The price of natural gas in the United Kingdom increased throughout 2021 and reached unprecedented high levels in the third quarter, and even higher levels in the fourth quarter. The increase in natural gas prices was due to the combination of low storage levels in Europe, reduced supply from Russia, and a tight global supply and demand balance in the LNG market as a result of strong demand in both Europe and Asia to fill storage locations in anticipation of winter. Due to the high price levels for natural gas, we halted certain of our U.K. manufacturing operations in September 2021. See the discussion under “United Kingdom Energy Crisis,” below, for further information.

The major natural gas trading point for the United Kingdom is the National Balancing Point (NBP). The average daily market price at NBP was $15.50 per MMBtu for 2021 compared to $3.20 per MMBtu for 2020, an increase of 384%. During 2021, the daily closing price at NBP reached a low of $5.58 per MMBtu on February 23, 2021 and a high of $60.10 per MMBtu on December 22, 2021. The average daily market price of natural gas at NBP for January 2022 was $25.91 per MMBtu.

In 2021, the total cost of natural gas used for production at all of our locations, which includes the impact of realized natural gas derivatives and excludes the $112 million gain that resulted from the net settlement of certain natural gas contracts with our suppliers, increased 88% to $4.21 from $2.24 per MMBtu in 2020. This increase in natural gas costs resulted in a decrease in gross margin of $663 million.

United Kingdom Energy Crisis

During the third quarter of 2021, the United Kingdom began experiencing an energy crisis that included a substantial increase in the price of natural gas. In the first half of 2021, natural gas prices had increased to levels that were considered high compared to historical prices, and prices then more than doubled in the third quarter of 2021.

On September 15, 2021, we announced the halt of operations at both our Ince and Billingham manufacturing facilities in the United Kingdom due to negative profitability driven by the high cost of natural gas. The halt of operations at our U.K. plants impacted the availability of certain products in the United Kingdom, including carbon dioxide, which is a byproduct of ammonia production. Due to the critical nature of carbon dioxide to certain industries in the United Kingdom, on September 21, 2021, we entered into an interim agreement with the U.K. government. Under the terms of the agreement, the U.K. government agreed to cover the costs to restart the ammonia plant at Billingham and to offset losses incurred from production for a 21-day period. As a result, we resumed production of ammonia at the Billingham facility in order to produce carbon dioxide for the United Kingdom. While the interim agreement was in place, we entered into new carbon dioxide pricing and offtake agreements with our customers, which had an initial term through January 31, 2022. The amount of financial support provided by the U.K. government under the terms of the interim agreement was not material. As of the filing of this report, production continues at our Billingham facility and continues to be idled at our Ince facility.

During the third quarter of 2021, the U.K. energy crisis necessitated an evaluation of the long-lived assets, including the definite-lived intangible assets, and goodwill of our U.K. operations to determine if their fair value had declined to below their carrying value. We concluded that a decline in fair value had occurred, and we recorded long-lived asset and goodwill impairment charges of $495 million. The continued impacts of the U.K. energy crisis in the fourth quarter of 2021 triggered an additional impairment test, and we recognized an additional goodwill impairment charge of $26 million. We recognized total impairment charges of $521 million in 2021, consisting of long-lived and intangible asset impairment charges of $236 million and goodwill impairment charges of $285 million. See “Items Affecting Comparability of Results—U.K. energy crisis impacts,” and “Liquidity and Capital Resources—United Kingdom Energy Crisis,” below, Note 6—United Kingdom Energy Crisis and Impairment Charges, Note 7—Property, Plant and Equipment—Net and Note 8—Goodwill and Other Intangible Assets for further information. As of December 31, 2021, after the recognition of the $521 million of impairment charges noted above, we have no remaining goodwill related to our U.K. operations, and the remaining long-lived assets related to our U.K. operations were approximately $425 million, consisting primarily of property, plant and equipment.

The results of our U.K. operations are included in our Ammonia, AN and Other segments, and account for a small portion of our consolidated gross margin. For the year ended December 31, 2021, our U.K. operations generated negative gross margin representing approximately 1% of our consolidated gross margin. For the year ended December 31, 2020, gross margin generated by our U.K. operations accounted for 2% of our consolidated gross margin.

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Manufacturing Costs and Granular Urea Purchases

In 2021, we experienced lower production levels and higher manufacturing and maintenance costs than in 2020. Certain of our plants operated at lower operating rates or temporarily suspended operations during 2021 due to the lack of natural gas due to Winter Storm Uri or the impact of Hurricane Ida, or due to maintenance activity, including activity that was deferred from 2020 as a result of the COVID-19 pandemic. In 2021, we had the highest level of maintenance activity in our history, including turnarounds at seven of our 17 ammonia plants. Because of these factors, including the halt of operations in the United Kingdom, we incurred higher costs for manufacturing, maintenance and repair activity for both scheduled and unscheduled downtime in 2021.

In response to the lower production in 2021 as a result of weather conditions and maintenance activity, we procured additional granular urea in order to meet customer obligations and provide additional manufacturing flexibility. In the year ended December 31, 2021, we purchased approximately $71 million of granular urea, which we sold to customers for $68 million.

COVID-19 Pandemic

In March 2020, the World Health Organization characterized the outbreak of coronavirus disease 2019 (COVID-19) as a pandemic. Due to the use of fertilizer products in crop production to support the global food supply chain, our business operations were designated as part of the critical infrastructure by the United States and as essential businesses in the United Kingdom and Canada, with corresponding designations by those states and provinces in which we operate. As a result, our manufacturing complexes were permitted to continue to operate and, through the date of this report, we have not suspended or shutdown operations as a result of the pandemic. In addition, we have continued to ship products by all modes of transportation to our customers, and we have not experienced any significant delays in marine, rail or truck transportation services due to the pandemic. Through the date of this report, we have not experienced any meaningful impact in customer demand as a result of the pandemic.

In response to the pandemic along with the rise of new variants of COVID-19, we instituted and have continued to enforce safety precautions and encourage safe behavior in order to protect the health and well-being of all of our employees. We will continue to monitor safety guidelines related to COVID-19 as issued by governmental authorities and adjust our safety protocols, as needed.

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Financial Executive Summary

We reported net earnings attributable to common stockholders of $917 million in 2021 compared to $317 million in 2020, an increase in net earnings of 189%, or $600 million. Diluted net earnings per share attributable to common stockholders increased $2.77 per share, to $4.24 per share in 2021 compared to $1.47 per share in 2020. These increases were due primarily to higher operating results driven by an increase in gross margin, partially offset by impairment charges related to our U.K. operations.

Impact of higher gross margin

Gross margin increased by $1.59 billion in 2021 to $2.39 billion as compared to $801 million in 2020. The following table and related discussion describe the significant factors that drove the increase in gross margin.

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(1)Selling price and volume impact of granular urea purchased to satisfy customer commitments is reflected in the Increase in Purchased Urea column.

(2)Higher natural gas costs include the impact, if any, of realized natural gas derivatives.

(3)Represents the variance in the net unrealized mark-to-market gains and losses on natural gas derivatives compared to the prior year period.

(4)Represents the impact of the incremental tons compared to the prior year period.

•Average selling prices increased 74% in 2021 to $353 per ton from $203 per ton in 2020, which increased gross margin by approximately $2.76 billion,

•Sales volume decreased 9% to 18.5 million product tons in 2021 from 20.3 million product tons in 2020, which reduced gross margin by approximately $92 million,

•The cost of natural gas used for production increased 88% to $4.21 per MMBtu in 2021 from $2.24 per MMBtu in 2020, which reduced gross margin by $663 million,

•We incurred higher manufacturing, maintenance and other costs, which reduced gross margin by $494 million, due primarily to higher plant turnaround and maintenance activity,

•We purchased 201,000 tons of granular urea for $71 million to meet customer obligations, which we sold to customers for $68 million, and

•The gain on the net settlement of certain natural gas contracts with our suppliers as a result of Winter Storm Uri was $112 million.

Impact of impairment charges

Net earnings and diluted net earnings per share in 2021 were impacted by impairment charges related to our U.K. operations of $521 million, consisting of long-lived and intangible asset impairment charges of $236 million and goodwill impairment charges of $285 million. The after-tax impact of the impairment charges to net earnings attributable to common stockholders and diluted net earnings per share attributable to common stockholders was $463 million and $2.14, respectively. See “Market Conditions and Current Developments—United Kingdom Energy Crisis,” above, Note 6—United Kingdom Energy Crisis and Impairment Charges, Note 7—Property, Plant and Equipment—Net and Note 8—Goodwill and Other Intangible Assets, for further information.

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The following table includes gross margin, operating earnings, earnings before income taxes, net earnings attributable to common stockholders and diluted net earnings per share attributable to common stockholders for 2021, and shows the impact of the impairment charges on each of these measures by also including the corresponding “as adjusted” measure, which excludes the before- and after-tax impacts of the impairment charges. Management utilizes these “as adjusted” measures, and believes they provide useful information to investors, for assessing period-to-period changes in our underlying operating performance, because these “as adjusted” measures exclude the non-cash impairment charges that resulted from the U.K. energy crisis, as more fully described above.

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(1)The “as adjusted” financial measures presented above are non-GAAP financial measures that should be viewed in addition to, and not as an alternative for, our reported results calculated and presented in accordance with accounting principles generally accepted in the United States (U.S. GAAP).

Items Affecting Comparability of Results

In addition to the impact of market conditions discussed above, certain items impacted the comparability of our financial results during the years ended December 31, 2021 and 2020. The following table and related discussion outline these items and how they impacted the comparability of our financial results during these periods. During the years ended December 31, 2021 and 2020, we reported net earnings attributable to common stockholders of $917 million and $317 million, respectively.

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(1)The tax impact is calculated utilizing a marginal effective rate of 23.6% and 23.2% in 2021 and 2020, respectively, except for asset impairments, which reflects the amount of income tax benefit recognized on the long-lived and intangible asset impairment charges.

(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)Included in interest expense, interest income and income tax provision in our consolidated statements of operations.

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The following describes the significant items that impacted the comparability of our financial results in 2021 and 2020. Descriptions of items below that refer to amounts in the table above, refer to the pre-tax amounts, except for the discussion under Terra amended tax returns.

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 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 2021 and 2020, we recognized an unrealized net mark-to-market loss (gain) on natural gas derivatives of $25 million and $(6) million, respectively.

COVID impacts

In March 2020, a short-term bonus program was initiated to compensate operational employees for continuing their critical tasks at the beginning of the COVID-19 pandemic. The bonus program concluded in June 2020. Approximately $19 million was paid as part of the program and was recognized in cost of sales in our consolidated statement of operations for the year ended December 31, 2020.

In addition, certain plant turnaround activities were deferred because of the COVID-19 pandemic. As a result, we incurred $7 million of expense for the year ended December 31, 2020, which was recognized in cost of sales in our consolidated statement of operations.

Asset impairments

As a result of the U.K. energy crisis and the events described under “Market Conditions and Current Developments—United Kingdom Energy Crisis,” above, we recognized impairment charges of $521 million in 2021, including long-lived and intangible asset impairment charges of $236 million and goodwill impairment charges of $285 million. See Note 6—United Kingdom Energy Crisis and Impairment Charges, Note 7—Property, Plant and Equipment—Net and Note 8—Goodwill and Other Intangible Assets, for further information.

Loss on foreign currency transactions, including intercompany loans

In 2021 and 2020, we recognized losses of $6 million and $5 million, respectively, which consist of foreign currency exchange rate impacts on foreign currency denominated transactions, including the impact of changes in foreign currency exchange rates on intercompany loans that were not permanently invested.

Engineering cost write-off

In 2020, a project at one of our nitrogen complexes was cancelled and, as a result, $9 million of previously capitalized engineering costs were expensed in the year ended December 31, 2020. The expense is reflected in other operating—net in our consolidated statement of operations.

Loss on sale of surplus land

In 2020, we recognized a loss of $2 million on the sale of surplus land, which is reflected in other operating—net in our consolidated statement of operations.

Insurance proceeds

We recognized income of $37 million in 2020 related to insurance claims at one of our nitrogen complexes, which consisted of $35 million related to business interruption insurance proceeds and $2 million related to property insurance proceeds. These proceeds are reflected in other operating—net in our consolidated statement of operations.

Loss on debt extinguishment

On March 20, 2021, we redeemed in full all of the remaining $250 million outstanding principal amount of the 3.400% senior secured notes due December 2021 (the 2021 Notes) in accordance with the optional redemption provisions in the indenture governing the 2021 Notes. The total aggregate redemption price paid in connection with the redemption of the 2021 Notes was $258 million, including accrued interest. As a result, we recognized a loss on debt extinguishment of $6 million, consisting primarily of the premium paid on the redemption of the 2021 Notes prior to their scheduled maturity.

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On September 10, 2021, we redeemed $250 million principal amount, representing one-third of the $750 million principal amount outstanding immediately prior to such redemption, of the 3.450% senior notes due 2023 (the 2023 Notes), in accordance with the optional redemption provisions in the indenture governing the 2023 Notes. The total aggregate redemption price paid in connection with the redemption of the 2023 Notes was approximately $265 million, including accrued interest. As a result, we recognized a loss on debt extinguishment of $13 million, consisting primarily of the premium paid on the redemption of the $250 million principal amount of the 2023 Notes prior to their scheduled maturity.

Terra amended tax returns

We completed the acquisition of Terra Industries Inc. (Terra) in April 2010. After the acquisition, we determined that the manner in which Terra reported the repatriation of cash from foreign affiliates to its U.S. parent for U.S. and foreign income tax purposes was not appropriate. As a result, in 2012 we amended certain tax returns, including Terra’s income and withholding tax returns, back to 1999 (the Amended Tax Returns) and paid additional income and withholding taxes, and related interest and penalties. In 2013, the Internal Revenue Service (IRS) commenced an examination of the U.S. tax aspects of the Amended Tax Returns.

In 2020, we received IRS Notices indicating the amount of tax and interest to be refunded and received with respect to the income tax and withholding tax returns. As a result, we recognized $26 million ($23 million, net of tax) of interest-related income and $18 million of additional income tax benefit. See “Liquidity and Capital Resources—Terra Amended Tax Returns,” below, for additional information.

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Consolidated Results of Operations

The following table presents our consolidated results of operations and supplemental data:

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N/M—Not Meaningful

(1)For a discussion and analysis of the year ended December 31, 2019, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2020 Annual Report on Form 10-K filed with the SEC on February 24, 2021.

(2)Includes the cost of natural gas and related transportation that is included in cost of sales during the period under the first-in, first-out inventory cost method. 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.

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The following is a discussion and analysis of our consolidated results of operations for the year ended December 31, 2021 compared to the year ended December 31, 2020. For a discussion and analysis of our consolidated results of operations for the year ended December 31, 2020 compared to the year ended December 31, 2019, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2020 Annual Report on Form 10-K filed with the SEC on February 24, 2021.

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 $2.41 billion, or 59%, to $6.54 billion in 2021 compared to $4.12 billion in 2020 due to a 74% increase in average selling prices, partially offset by a 9% decrease in sales volume.

Average selling prices were $353 per ton in 2021 compared to $203 per ton in 2020, an increase of 74%, due to higher average selling prices across all of our segments, primarily driven by the impact of a tighter global nitrogen supply and demand balance, as a result of strong global demand and decreased global supply availability as higher global energy costs drove lower global operating rates. Our total sales volume of 18.5 million product tons in 2021 was 9% lower compared to 20.3 million product tons in 2020 as a result of decreased supply due to lower production due primarily to a high level of plant turnaround and maintenance activity and downtime resulting from the impacts of Winter Storm Uri and Hurricane Ida.

Gross ammonia production for 2021 was approximately 9.3 million tons compared to 10.4 million tons in 2020. Management expects gross ammonia production for 2022 will return to historical levels (9.5 to 10.0 million tons) based on normal operating conditions and a return to a typical level of planned maintenance activities.

Cost of Sales

Our cost of sales includes manufacturing costs, purchased product costs, and distribution costs. 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. 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 plants to our distribution facilities, which are recognized in cost of sales when the product is sold to our customers, and storage costs incurred prior to final shipment to customers.

Our cost of sales increased $828 million, or 25%, to $4.15 billion in 2021 as compared to $3.32 billion in 2020. The increase in our cost of sales was due primarily to higher costs for natural gas, including the impact of realized derivatives, which increased cost of sales by $663 million; higher manufacturing, maintenance and other costs, which increased cost of sales by $494 million; and higher costs for purchased products as we purchased $71 million of granular urea in 2021 to meet customer obligations. Cost of sales also includes the impact of a $25 million unrealized net mark-to-market loss on natural gas derivatives in 2021 compared to a $6 million gain in 2020.

These items increasing our cost of sales were partially offset by the $112 million gain we recognized from the net settlement of certain natural gas contracts with our suppliers in February 2021 due to Winter Storm Uri as described above under the heading “Natural Gas Prices” in the section titled “Market Conditions and Current Developments.” The $112 million gain on the net settlement of certain natural gas contracts in February 2021 is reflected in, and had the effect of reducing, our cost of sales in 2021. In addition, there was a $312 million decline in cost of sales in 2021, as compared to 2020, due primarily to a 9% decline in sales volume.

Cost of sales averaged $224 per ton in 2021, a 37% increase from $164 per ton in 2020. The cost of natural gas used for production, including the impact of realized derivatives, increased 88% to $4.21 per MMBtu in 2021 from $2.24 per MMBtu in 2020. The cost of natural gas used for production of $4.21 per MMBtu in 2021 does not include the $112 million gain from the net settlement of certain natural gas contracts in February 2021.

Selling, General and Administrative Expenses

Our selling, general and administrative expenses consist primarily of corporate office expenses such as salaries and other payroll-related costs for our executive, administrative, legal, financial, IT, and sales functions, as well as certain taxes and insurance and other professional service fees, including those for corporate initiatives.

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Selling, general and administrative expenses increased $17 million, or 8%, to $223 million in 2021 from $206 million in 2020. The increase was due primarily to higher incentive compensation, due to strong operating performance.

Long-lived and Intangible Asset Impairment and Goodwill Impairment

In 2021, we recognized total impairment charges of $521 million, consisting of long-lived and intangible asset impairment charges of $236 million and goodwill impairment charges of $285 million. See “United Kingdom Energy Crisis” under “Market Conditions and Current Developments,” above for further information.

Other Operating—Net

Other operating—net includes administrative costs that do not relate directly to our central operations. Costs included in “other operating costs” can include foreign currency transaction gains and losses, unrealized gains and losses on foreign currency derivatives, litigation expenses and gains and losses on the disposal of fixed assets.

Other operating—net was $39 million of income in 2021 compared to $17 million of income in 2020. The income in 2021 primarily includes a gain of $29 million on sales of carbon credits. In addition, other operating—net includes the amount received under the terms of the agreement with the U.K. government associated with the restart of our Billingham facility, partially offset by a loss on foreign currency transactions of $6 million, which includes the impact of changes in foreign currency exchange rates on intercompany loans that were not permanently invested. The income in 2020 primarily includes insurance proceeds of $37 million, partially offset by $9 million of expense related to the cancellation of a project, which is described in the section above titled “Items Affecting Comparability of Results—Engineering cost write-off,” and a loss on foreign currency transactions of $5 million.

Equity in Earnings of Operating Affiliate

Equity in earnings 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. Our share of the net earnings includes the amortization of certain tangible assets identified as part of the application of purchase accounting at acquisition.

Equity in earnings of operating affiliate was $47 million in 2021 compared to $11 million in 2020. The increase was due primarily to an increase in the operating results of PLNL as a result of higher ammonia selling prices partially offset by higher natural gas costs.

Interest Expense—Net

Our interest expense—net includes the interest expense on our long-term debt, amortization of the related fees required to execute financing agreements, annual fees pursuant to our revolving credit agreement and interest on tax liabilities. Capitalized interest relating to the construction of major capital projects reduces interest expense as the interest is capitalized and amortized over the estimated useful lives of the related assets. Interest expense—net also includes interest income, which includes amounts earned on our cash, cash equivalents, and investments and any interest earned related to income tax refunds.

Net interest expense increased by $22 million to $183 million in 2021 from $161 million in 2020. The increase was due primarily to $26 million of interest income in 2020 related to the finalization of the Terra amended tax returns, which is more fully described under “Items Affecting Comparability of Results—Terra Amended Tax Returns,” above.

Loss on Debt Extinguishment

On March 20, 2021, we redeemed in full all of the remaining $250 million outstanding principal amount of the 2021 Notes in accordance with the optional redemption provisions in the indenture governing the 2021 Notes. The total aggregate redemption price paid in connection with the redemption on the 2021 Notes was $258 million, including accrued interest. As a result, we recognized a loss on debt extinguishment of $6 million, consisting primarily of the premium paid on the redemption of the 2021 Notes prior to their scheduled maturity.

On September 10, 2021, we redeemed $250 million principal amount, representing one-third of the $750 million principal amount outstanding immediately prior to such redemption, of the 2023 Notes, in accordance with the optional redemption provisions in the indenture governing the 2023 Notes. The total aggregate redemption price paid in connection with the redemption of the 2023 Notes was approximately $265 million, including accrued interest. As a result, we recognized a loss on debt extinguishment of $13 million, consisting primarily of the premium paid on the redemption of the $250 million principal amount of the 2023 Notes prior to their scheduled maturity.

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Other Non-Operating—Net

Other non-operating—net was $16 million of income in 2021 compared to $1 million of income in 2020. The $16 million of income in 2021 was due primarily to a gain of $20 million on the sale of EU carbon credits that, due to Brexit, could no longer be utilized by our U.K. plants for carbon emission obligations in the United Kingdom.

Income Tax Provision

Our income tax provision for 2021 was $283 million on pre-tax income of $1,543 million, or an effective tax rate of 18.3%, compared to an income tax provision of $31 million on pre-tax income of $463 million, or an effective tax rate of 6.7%, in 2020.

For 2021, we did not record an income tax benefit related to the goodwill impairment charges described in Note 6—United Kingdom Energy Crisis and Impairment Charges as the goodwill impairment charges are non-deductible for income tax purposes. Our income tax provision for 2021 includes a $26 million benefit reflecting the impact of agreement on certain issues related to U.S. federal income tax audits, including a discrete income tax benefit of approximately $15 million due to the reversal of an accrual for unrecognized tax benefits as a result of the effective settlement of the U.S. federal income tax audit for the 2012-2016 tax years.

For 2020, our income tax provision includes a $27 million benefit related to the settlement of certain U.S. and foreign income tax audits, which primarily related to the settlement of the audit of the Terra amended tax returns, which is more fully described under “Items Affecting Comparability of Results—Terra Amended Tax Returns,” above.

Our effective tax rate is impacted by earnings attributable to the noncontrolling interest in CFN, as our consolidated income tax provision does not include a tax provision on the earnings attributable to the noncontrolling interest. Our effective tax rate for 2021 of 18.3%, which is based on pre-tax income of $1,543 million, would be 5.3 percentage points higher, or 23.6%, if based on pre-tax income exclusive of the earnings attributable to the noncontrolling interest of $343 million. Our effective tax rate for 2020 of 6.7%, which is based on pre-tax income of $463 million, would be 2.2 percentage points higher, or 8.9%, if based on pre-tax income exclusive of the earnings attributable to the noncontrolling interest of $115 million.

Both 2021 and 2020 were impacted by additional discrete tax items. See Note 11—Income Taxes for additional information.

Net Earnings Attributable to Noncontrolling Interest

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

Net earnings attributable to noncontrolling interest increased $228 million, or 198%, to $343 million in 2021 compared to $115 million in 2020 due to higher earnings of CFN driven by higher average selling prices due primarily to a tighter global nitrogen supply and demand balance as higher global energy costs drove lower global operating rates.

Diluted Net Earnings Per Share Attributable to Common Stockholders

Net earnings per share attributable to common stockholders increased 188% to $4.24 per diluted share in 2021 from $1.47 per diluted share in 2020. This increase is due primarily to higher operating results driven by an increase in gross margin, partially offset by impairment charges related to our U.K. operations.

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Operating Results by Business Segment

Our reportable segment structure reflects how our chief operating decision maker, as defined in U.S. GAAP, assesses the performance of our reportable segments and makes decisions about resource allocation. 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. The following table presents summary operating results by business segment and the major drivers of the variance in net sales, cost of sales and gross margin:

_______________________________________________________________________________

(1)Selling price and volume impact of granular urea purchased to satisfy customer commitments is reflected in the Increase in Purchased Urea column.

(2)Higher natural gas costs include the impact, if any, of realized natural gas derivatives.

(3)Represents the variance in the net unrealized mark-to-market gains and losses on natural gas derivatives compared to the prior year period.

(4)Represents the impact of the incremental tons compared to the prior year period.

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The following is a discussion and analysis of our operating results by business segment for the year ended December 31, 2021 compared to the year ended December 31, 2020. For a discussion and analysis of our operating results by business segment for the year ended December 31, 2020 compared to the year ended December 31, 2019, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2020 Annual Report on Form 10-K filed with the SEC on February 24, 2021.

Ammonia Segment

Our ammonia segment produces anhydrous ammonia (ammonia), which is our most concentrated nitrogen product. Ammonia contains 82% nitrogen and 18% hydrogen. The results of our ammonia segment consist of sales of ammonia to external customers. In addition, ammonia is the base nitrogen product that we upgrade into other nitrogen products such as granular urea, UAN and AN. We produce ammonia at all of our nitrogen manufacturing complexes.

The following table presents summary operating data for our ammonia segment:

_______________________________________________________________________________

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, 2021 Compared to Year Ended December 31, 2020

Net Sales. Net sales in our ammonia segment increased by $767 million, or 75%, to $1.79 billion in 2021 from $1.02 billion in 2020 due primarily to an 84% increase in average selling prices, partially offset by a 5% decrease in sales volume. Average selling prices increased to $498 per ton in 2021 compared to $271 per ton in 2020. The increase in average selling prices was due primarily to the impact of a tighter global nitrogen supply and demand balance. Sales volume was lower in 2021 due primarily to lower supply availability resulting from reduced inventory and production due to plant turnaround and maintenance activity and from weather-related outages, including the impact of Winter Storm Uri and Hurricane Ida.

Cost of Sales. Cost of sales in our ammonia segment averaged $324 per ton in 2021, a 43% increase from $226 per ton in 2020. The increase is due primarily to higher realized natural gas costs, higher costs related to plant turnaround, maintenance and repair activity, and higher costs for ammonia purchased from our joint venture in Trinidad, partially offset by the impact of the $112 million gain on the net settlement of certain natural gas contracts in February 2021. See “Market Conditions and Current Developments” above, for additional information on the operational impact of Winter Storm Uri.

Gross Margin.  Gross margin in our ammonia segment increased by $455 million to $625 million in 2021 from $170 million in 2020, and our gross margin percentage was 35.0% in 2021 compared to 16.7% in 2020. The increase in gross margin was due primarily to an 84% increase in average selling prices, which increased gross margin by $792 million, and the $112 million gain on the net settlement of certain natural gas contracts in February 2021. These factors were partially offset by a $254 million net increase in manufacturing, maintenance and other costs, an increase in realized natural gas costs, which decreased gross margin by $194 million, and a 5% decrease in sales volume, which decreased gross margin by $8 million. Gross margin also includes the impact of a $7 million unrealized net mark-to-market loss on natural gas derivatives in 2021 compared to a $2 million gain in 2020.

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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, Louisiana; Medicine Hat, Alberta; and Port Neal, Iowa nitrogen complexes.

The following table presents summary operating data for our granular urea segment:

______________________________________________________________________________

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, 2021 Compared to Year Ended December 31, 2020

Net Sales. Net sales in our granular urea segment increased $632 million, or 51%, to $1.88 billion in 2021 compared to $1.25 billion in 2020 due primarily to an 81% increase in average selling prices, partially offset by a 17% decrease in sales volume. Average selling prices increased to $438 per ton in 2021 compared to $242 per ton in 2020. The increase was due primarily to the impact of a tighter global nitrogen supply and demand balance. Sales volume was lower due primarily to lower supply availability resulting from reduced production due to plant turnaround, maintenance and repair activity and the impact of weather-related outages. Due to the reduced production, we purchased granular urea in 2021, which we sold for $68 million, to meet customer obligations.

Cost of Sales. Cost of sales in our granular urea segment averaged $231 per ton in 2021, a 41% increase from $164 per ton in 2020, due primarily to higher realized natural gas costs and higher costs related to plant turnaround, maintenance and repair activity due primarily to weather-related outages. In addition, we purchased $71 million of granular urea in 2021 to meet customer obligations.

Gross Margin.  Gross margin in our granular urea segment increased by $487 million to $888 million in 2021 from $401 million in 2020, and our gross margin percentage was 47.2% in 2021 compared to 32.1% in 2020. The increase in gross margin was driven by an 81% increase in average selling prices, which increased gross margin by approximately $814 million. The impact of higher average selling prices was partially offset by higher realized natural gas costs, which decreased gross margin by $144 million, a 17% decrease in sales volume, which decreased gross margin by $88 million, and an $84 million net increase in manufacturing, maintenance and other costs. In addition, we experienced lower production throughout 2021. As a result, in 2021, we purchased 201,000 tons of granular urea to meet customer obligations, which had the impact of reducing our gross margin percentage in our granular urea segment by 2.0 percentage points. Gross margin includes the impact of a $6 million unrealized net mark-to-market loss on natural gas derivatives in 2021 compared to a $2 million gain in 2020.

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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 nitrogen complexes in Courtright, Ontario; Donaldsonville, Louisiana; Port Neal, Iowa; Verdigris, Oklahoma; Woodward, Oklahoma; and Yazoo City, Mississippi.

The following table presents summary operating data for our UAN segment:

______________________________________________________________________________

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, 2021 Compared to Year Ended December 31, 2020

Net Sales. Net sales in our UAN segment increased $725 million, or 68%, to $1.79 billion in 2021 compared to $1.06 billion in 2020 due primarily to a 75% increase in average selling prices, partially offset by a 4% decrease in sales volume. Average selling prices increased to $272 per ton in 2021 compared to $155 per ton in 2020 due primarily to the impact of a tighter global nitrogen supply and demand balance. The decrease in sales volume was due to lower supply availability from reduced production during the first nine months of 2021 due to plant turnaround and maintenance activity and the impact of weather-related outages.

Cost of Sales. Cost of sales in our UAN segment averaged $170 per ton in 2021, a 23% increase from $138 per ton in 2020, due primarily to the impact of higher realized natural gas costs and higher costs related to plant turnaround, maintenance and repair activity.

Gross Margin.  Gross margin in our UAN segment increased by $555 million to $669 million in 2021 from $114 million in 2020, and our gross margin percentage was 37.4% in 2021 compared to 10.7% in 2020. The increase in gross margin was due to a 75% increase in average selling prices, which increased gross margin by $756 million. The impact of higher average selling prices was partially offset by higher realized natural gas costs, which decreased gross margin by $168 million, a $22 million net increase in manufacturing, maintenance and other costs, and a 4% decrease in sales volume, which decreased gross margin by $4 million. Gross margin includes the impact of a $5 million unrealized net mark-to-market loss on natural gas derivatives in 2021 compared to a $2 million gain in 2020.

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Antidumping and Countervailing Duty Investigations

On June 30, 2021, we filed petitions with the U.S. Department of Commerce (Commerce) and the U.S. International Trade Commission (ITC) requesting the initiation of antidumping and countervailing duty investigations on imports of UAN from Russia and Trinidad. On August 13, 2021, the ITC made an affirmative preliminary determination that there is a reasonable indication that the U.S. UAN industry is materially injured by reason of imports of UAN from Russia and Trinidad.

On November 30, 2021, Commerce announced preliminary countervailing duty determinations finding that UAN imports from Russia are unfairly subsidized at rates ranging from 9.66% to 9.84% and UAN imports from Trinidad are unfairly subsidized at a rate of 1.83%, and imposed preliminary cash deposit requirements on those imports.

On January 27, 2022, Commerce announced preliminary antidumping duty determinations finding that Russian UAN imports are dumped (i.e. sold at less than fair value) into the U.S. market at rates ranging from 9.15% to 127.19%, and that Trinidadian UAN imports are dumped at a rate of 63.08%, and imposed preliminary cash deposit requirements on those imports.

We expect that Commerce will issue final determinations later in 2022 and, if any of Commerce’s final determinations are affirmative, the ITC would make a final determination as to whether the unfairly traded imports materially injure or threaten material injury to the U.S. UAN industry. If the ITC makes affirmative final determinations, then Commerce can impose duties equal to the level of dumping and unfair subsidies it finds. At this time, we cannot predict the outcome of the proceedings, including whether final antidumping or countervailing duties will be imposed on imports from either Russia or Trinidad, or the rate of any such duties.

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 by industrial customers for commercial explosives and blasting systems. AN is produced at our nitrogen complexes in Yazoo City, Mississippi and Ince and Billingham, United Kingdom.

The following table presents summary operating data for our AN segment:

_______________________________________________________________________________

N/M—Not Meaningful

(1)AN represents between 29% and 35% of nitrogen content. Nutrient tons represent the tons of nitrogen within the product tons.

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

On September 15, 2021, we announced the halt of operations at both our Ince and Billingham manufacturing facilities in the United Kingdom due to negative profitability driven by the high cost of natural gas. Shortly thereafter, we restarted production at our Billingham facility; however, production continues to be idled at our Ince facility. See the discussion under “Market Conditions and Current Developments—United Kingdom Energy Crisis,” above, for further information.

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Net Sales. Net sales in our AN segment increased $55 million, or 12%, to $510 million in 2021 from $455 million in 2020 due primarily to a 45% increase in average selling prices, partially offset by a 22% decrease in sales volume. Average selling prices increased to $297 per ton in 2021 compared to $205 per ton in 2020 due primarily to the impact of a tighter global nitrogen supply and demand balance. Sales volume decreased due primarily to lower supply availability as a result of reduced production due to plant turnaround and maintenance activity and idled operations at our Ince facility.

Cost of Sales. Cost of sales in our AN segment averaged $277 per ton in 2021, a 57% increase from $176 per ton in 2020, due primarily to higher realized natural gas costs and higher costs related to plant turnaround and maintenance activity, including the impact of the idled Ince facility. Natural gas costs increased significantly in both the United States and the United Kingdom in 2021. See the discussion under “Market Conditions and Current Developments—Natural Gas Prices,” above, for further information.

Gross Margin.  Gross margin in our AN segment decreased by $30 million to $35 million in 2021 from $65 million in 2020, and our gross margin percentage was 6.9% in 2021 compared to 14.3% in 2020. The decrease in gross margin was due to an increase in realized natural gas costs, which decreased gross margin by $97 million, a net increase of $67 million in manufacturing, maintenance and other costs, and a 22% decrease in sales volume, which decreased gross margin by $21 million. These factors were partially offset by a 45% increase in average selling prices, which increased gross margin by $159 million. Gross margin also includes the impact of a $4 million unrealized net mark-to-market loss on natural gas derivatives in 2021.

Other Segment

Our Other segment primarily includes the following products:

•Diesel exhaust fluid (DEF) is an aqueous urea solution typically made with 32.5% or 50% high-purity urea and the remainder deionized water.

•Urea liquor is a liquid product that we sell in concentrations of 40%, 50% and 70% urea as a chemical intermediate.

•Nitric acid is a nitrogen-based mineral acid that is used in the production of nitrate-based fertilizers, nylon precursors and other specialty chemicals.

•Compound fertilizer products (NPKs) are granular fertilizer products for which the nutrient content is a combination of nitrogen, phosphorus and potassium.

The following table presents summary operating data for our Other segment:

_______________________________________________________________________________

N/M—Not Meaningful

(1)Nutrient tons represent the tons of nitrogen within the product tons.

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Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

Net Sales. Net sales in our Other segment increased $235 million, or 70%, to $573 million in 2021 from $338 million in 2020 due to a 69% increase in average selling prices. Average selling prices increased to $247 per ton in 2021 compared to $146 per ton in 2020, due primarily to the impact of a tighter global nitrogen supply and demand balance. Sales volume was essentially unchanged as higher DEF sales volumes were partially offset by lower NPK sales volumes, as a result of idled operations at our Ince facility, and lower urea liquor sales volumes.

Cost of Sales. Cost of sales in our Other segment averaged $174 per ton in 2021, a 40% increase from $124 per ton in 2020, due primarily to higher realized natural gas costs and higher costs related to plant turnaround and maintenance activity, including the impact of the idled Ince facility.

Gross Margin.  Gross margin in our Other segment increased by $119 million to $170 million in 2021 from $51 million in 2020, and our gross margin percentage was 29.7% in 2021 compared to 15.1% in 2020. The increase in gross margin was due to a 69% increase in average selling prices, which increased gross margin by $236 million, and an increase of $13 million due to product mix. These factors were partially offset by a $67 million net increase in manufacturing, maintenance and other costs and an increase in realized natural gas costs, which reduced gross margin by $60 million. Gross margin also includes the impact of a $3 million unrealized net mark-to-market loss on natural gas derivatives in 2021.

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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 and dividends. Our working capital requirements are affected by several factors, including demand for our products, selling prices, raw material costs, freight costs and seasonal factors inherent in the business. 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 March 20, 2021, we redeemed in full all of the remaining $250 million outstanding principal amount of the 2021 Notes, in accordance with the optional redemption provisions in the indenture governing the 2021 Notes. On September 10, 2021, we redeemed $250 million principal amount, representing one-third of the $750 million principal amount outstanding immediately prior to such redemption, of the 2023 Notes, in accordance with the optional redemption provisions in the indenture governing the 2023 Notes. See the discussion under “Debt,” below, for further information.

In 2021, we repurchased approximately 8.6 million shares of CF Holdings common stock under the 2019 share repurchase program for $540 million. See the discussion under “Share Repurchase Programs,” below, for further information.

Our cash and cash equivalents balance was $1.63 billion at December 31, 2021, an increase of $945 million from $683 million at December 31, 2020. At December 31, 2021, we were in compliance with all applicable covenant requirements under our revolving credit agreement and senior notes, and unused borrowing capacity under our revolving credit agreement was $750 million.

United Kingdom Energy Crisis

As discussed under “Market Conditions and Current Developments—United Kingdom Energy Crisis,” above, during the third quarter of 2021, the United Kingdom began experiencing an energy crisis that included a substantial increase in the price of natural gas, which impacted our U.K. operations. Management continues to assess these volatile market conditions in the United Kingdom. The factors that could lead to the resolution of the U.K. energy crisis, and the timing of any such resolution, are unknown to us. Production continues to be idled at our Ince facility, while the Billingham facility is currently operating. There remains significant uncertainty regarding future plans for these sites pending greater clarity as to the future cost of natural gas and electricity, selling prices for the products we produce in the United Kingdom and U.K. government policy. Persistence of the current levels of energy costs and product prices facing our U.K. operations could lead to the continued idling or shutting down of our U.K. facilities. This could result in, among other things, additional funding to support the cash needs of the U.K. operations and recognition of further losses or further asset impairment charges related to our U.K. operations. Each of these actions could have a material adverse impact on our results of operations and cash flows.

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.

Share Repurchase Programs

On February 13, 2019, our Board of Directors (the Board) authorized the repurchase of up to $1 billion of CF Holdings common stock through December 31, 2021 (the 2019 Share Repurchase Program). Repurchases under our share repurchase programs may be made from time to time in the open market, through privately negotiated transactions, block transactions 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.

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The following table summarizes the shares repurchased under the 2019 Share Repurchase Program.

Shares repurchased, including those repurchased under share repurchase programs, are retired as approved by the Board. As of December 31, 2021, we held 27,962 shares of treasury stock.

On November 3, 2021, the Board authorized the repurchase of up to $1.5 billion of CF Holdings common stock from January 1, 2022 through December 31, 2024 (the 2021 Share Repurchase Program).

Capital Spending

We make capital expenditures to sustain our asset base, increase our capacity or capabilities, improve plant efficiency and comply with various environmental, health and safety requirements. Capital expenditures totaled $514 million in 2021 compared to $309 million in 2020. The increase in capital expenditures reflects higher capital spending due to maintenance deferred from 2020 as well as activity that was previously planned to occur in 2022, but accelerated into 2021.

Capital expenditures in 2022 are estimated to be in the range of $500 to $550 million, which includes capital expenditures at our Donaldsonville complex related to green and blue ammonia projects. Planned capital expenditures are generally subject to change due to delays in regulatory approvals or permitting, unanticipated increases in cost, changes in scope and completion time, performance of third parties, delays in the receipt of equipment, adverse weather, defects in materials and workmanship, labor or material shortages, transportation constraints, acceleration or delays in the timing of the work and other unforeseen difficulties.

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.

Emission Credit Activity

Our U.K. manufacturing plants are subject to greenhouse gas (GHG) regulations in the United Kingdom. After the United Kingdom’s exit from the European Union, the U.K. government instituted new GHG regulations in 2021, including establishing the U.K. Emission Trading Scheme (UK ETS). The UK ETS replaces the European Union Emissions Trading System for U.K. companies. In conjunction with these changes, the U.K. GHG regulations established a lower emission cap than applied to us under the European GHG regulations. Under the new U.K. requirements, we are required to obtain and surrender emission allowances equivalent to our annual greenhouse gas emissions, although we are also allocated a certain number of free allowances. As a result of the new GHG regulations and the establishment of the UK ETS, our remaining European Union emission credits were no longer applicable for us in the United Kingdom, and we need U.K. emission credits to offset any emissions that are in excess of the number of free allowances allocated to us. Accordingly, in the third quarter of 2021, we sold our remaining EU emission credits for approximately $20 million and recognized a corresponding gain, as the credits were earned by us in prior years due to approved emission abatement actions that we had taken and, therefore, did not have a recognized cost associated with them. We subsequently purchased approximately 321,000 of U.K. emission credits for approximately $19 million. During the fourth quarter of 2021, as we have estimated that we have sufficient emission credits for our 2021 obligations, we sold the excess U.K. emission credits, including those purchased in the third quarter of 2021, for approximately $46 million, and recognized a corresponding gain of $27 million.

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Canada Revenue Agency Competent Authority Matter

In 2016, the Canada Revenue Agency (CRA) and Alberta Tax and Revenue Administration (Alberta TRA) issued Notices of Reassessment for tax years 2006 through 2009 to one of our Canadian affiliates asserting a disallowance of certain patronage allocations. We filed Notices of Objection with respect to the Notices of Reassessment with the CRA and Alberta TRA and posted letters of credit in lieu of paying the additional tax liability assessed. The letters of credit serve as security until the matter is resolved. In 2018, the matter, including the related transfer pricing topic, was accepted for consideration under the bilateral settlement provisions of the U.S.-Canada tax treaty (the Treaty) by the United States and Canadian competent authorities, and included tax years 2006 through 2011. In the second quarter of 2021, the Company entered the transfer pricing aspect of the matter into the arbitration process under the terms of the Treaty.

In February 2022, we were informed that a decision was reached by the arbitration board regarding the transfer pricing matter with the CRA for tax years 2006 through 2011, as discussed in Note 11—Income Taxes. We are awaiting further details of the results of the arbitration proceedings and the settlement provisions between the United States and Canadian competent authorities. We need to decide whether to accept the decision of the arbitration board or pursue other resolution alternatives, which is expected to occur in the first quarter of 2022.

If we were to accept the decision of the arbitration board, the associated letters of credit would be cancelled and we would owe additional tax and interest to Canada, which would likely be due in the second quarter of 2022. Simultaneously, pursuant to the arbitration determination, the Company would file amended tax returns for the relevant tax years with the United States to request a refund of tax overpaid. The receipt of tax overpaid and any related interest would occur in a period later than the settlement of tax and interest owed. While we are not currently able to estimate the amounts due to, or to be received from, the taxing jurisdictions, each of the individual amounts that would ultimately be paid or received could be material.

Terra Amended Tax Returns

In 2020, we received U.S. federal income tax refunds, including interest, of $110 million relating to amended tax returns that we had filed in 2012 related to prior tax years. See discussion under “Items Affecting Comparability of Results—Terra Amended Tax Returns,” above, for further information.

In 2017, we made a Voluntary Disclosures Program filing with the CRA with respect to the Canadian tax aspects of the amended U.S. tax returns and paid additional Canadian taxes due. In late 2020, the CRA settled with us the voluntary disclosure matter, and, in the first quarter of 2021, we received approximately $20 million of withholding tax refunds, including interest, from the CRA. These amounts were previously recorded in our consolidated balance sheet as of December 31, 2020.

Repatriation of Foreign Earnings and Income Taxes

We have operations in Canada, the United Kingdom and a 50% interest in a joint venture in the Republic of Trinidad and Tobago. Historically, the estimated additional U.S. and foreign income taxes due upon repatriation of the earnings of these foreign operations to the U.S. 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, 2021, approximately $205 million of our consolidated cash and cash equivalents balance of $1.63 billion was held by our Canadian and United Kingdom subsidiaries. Historically, and for the current year, the cash balance held by the Canadian subsidiaries represented accumulated earnings of our foreign operations that were not considered to be permanently reinvested. As of December 31, 2021, we would not expect any additional cash tax cost to repatriate the Canadian and United Kingdom cash balances if we were to repatriate this cash in the future, other than foreign withholding tax.

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Debt

Revolving Credit Agreement

We have a senior unsecured revolving credit agreement (the Revolving Credit Agreement), which provides for a revolving credit facility of up to $750 million with a maturity of December 5, 2024. The Revolving Credit Agreement includes a letter of credit sub-limit of $125 million. Borrowings under the Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions, share repurchases and other general corporate purposes.

Borrowings under the Revolving Credit Agreement may be denominated in U.S. dollars, Canadian dollars, euros and British pounds, and bear interest at a per annum rate equal to an applicable eurocurrency rate or base rate plus, in either case, a specified margin. We are required to pay an undrawn commitment fee on the undrawn portion of the commitments under the Revolving Credit Agreement and customary letter of credit fees. The specified margin and the amount of the commitment fee depend on CF Holdings’ credit rating at the time.

CF Industries is the lead borrower, and CF Holdings is the sole guarantor, under the Revolving Credit Agreement.

The Revolving Credit Agreement contains representations and warranties and affirmative and negative covenants customary for a financing of this type. The financial covenants applicable to CF Holdings and its subsidiaries in the Revolving Credit Agreement:

(i) require that the interest coverage ratio (as defined in the Revolving Credit Agreement) be not less than 2.75:1.00 as of the last day of each fiscal quarter and

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

As of December 31, 2021, we were in compliance with all covenants under the Revolving Credit Agreement.

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, 2021, we had unused borrowing capacity under the Revolving Credit Agreement of $750 million and no outstanding letters of credit. In addition, there were no borrowings outstanding under the Revolving Credit Agreement as of December 31, 2021 or 2020, or during the year ended December 31, 2021.

In March 2020, we borrowed $500 million under the Revolving Credit Agreement to ensure we maintained ample financial flexibility in light of the uncertainty in the global markets, including the financial credit markets, caused by the COVID-19 pandemic. In April 2020, due to confidence in the functioning of the credit markets and strong nitrogen fertilizer business conditions, we repaid the $500 million of borrowings that were outstanding under the Revolving Credit Agreement as of March 31, 2020, which returned our unused borrowing capacity under the Revolving Credit Agreement to $750 million. Maximum borrowings under the Revolving Credit Agreement during 2020 were $500 million. The weighted-average annual interest rate of borrowings under the Revolving Credit Agreement during 2020 was 2.05%.

Letters of Credit

In addition to the letters of credit that may be issued under the Revolving Credit Agreement, as described above, we have also entered into a bilateral agreement with capacity to issue letters of credit up to $250 million. As of December 31, 2021, approximately $223 million of letters of credit were outstanding under this agreement.

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Senior Notes

Long-term debt presented on our consolidated balance sheets as of December 31, 2021 and 2020 consisted of the following debt securities issued by CF Industries:

_______________________________________________________________________________

(1)Carrying amount is net of unamortized debt discount and deferred debt issuance costs. Total unamortized debt discount was $8 million and $9 million as of December 31, 2021 and 2020, respectively, and total deferred debt issuance costs were $27 million and $30 million as of December 31, 2021 and 2020, respectively.

(2)Effective August 23, 2021, these notes are no longer secured, in accordance with the terms of the applicable indenture.

Public Senior Notes

Under the indentures (including the applicable supplemental indentures) governing our senior notes due 2023, 2034, 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.

On September 10, 2021, we redeemed $250 million principal amount, representing one-third of the $750 million principal amount outstanding immediately prior to such redemption, of the 2023 Notes, in accordance with the optional redemption provisions in the indenture governing the 2023 Notes. The total aggregate redemption price paid in connection with the redemption of the 2023 Notes, which was funded with cash on hand, was approximately $265 million, including accrued interest. As a result, we recognized a loss on debt extinguishment of $13 million in the third quarter of 2021, consisting primarily of the premium paid on the redemption of the $250 million principal amount of the 2023 Notes prior to their scheduled maturity.

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

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Notes, constitute change of control repurchase events. Upon the occurrence of a change of control repurchase event with respect to a series of Public Senior Notes, unless CF Industries has exercised its option to redeem such Public Senior Notes, CF Industries will be required to offer to repurchase them at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but not including, the date of repurchase.

Senior Secured Notes

On March 20, 2021, we redeemed in full all of the remaining $250 million outstanding principal amount of the 2021 Notes in accordance with the optional redemption provisions in the indenture governing the 2021 Notes. The total aggregate redemption price paid in connection with the redemption of the 2021 Notes was $258 million, including accrued interest. As a result, we recognized a loss on debt extinguishment of $6 million in the first quarter of 2021, consisting primarily of the premium paid on the redemption of the 2021 Notes prior to their scheduled maturity.

Under the terms of the indenture governing the 4.500% senior secured notes due 2026 (the 2026 Notes), the 2026 Notes are guaranteed by CF Holdings. Until August 23, 2021, the 2026 Notes were guaranteed by certain subsidiaries of CF Industries. The requirement for subsidiary guarantees of the 2026 Notes was eliminated, and all subsidiary guarantees were automatically released, as a result of an investment grade rating event under the terms of the indenture governing the 2026 Notes on August 23, 2021. Prior to the investment grade rating event, subject to certain exceptions, the obligations under the 2026 Notes and related guarantees were secured by a first priority security interest in collateral consisting of substantially all of the assets of CF Industries, CF Holdings and the subsidiary guarantors. As a result of the investment grade rating event, the liens on the collateral securing the obligations under the 2026 Notes and related guarantees were automatically released on August 23, 2021, and the indenture covenant that had limited dispositions of assets constituting collateral no longer applies.

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

Under the indenture governing the 2026 Notes, specified changes of control involving CF Holdings or CF Industries, when accompanied by a ratings downgrade, as defined with respect to the 2026 Notes, constitute change of control repurchase events. Upon the occurrence of a change of control repurchase event with respect to the 2026 Notes, unless CF Industries has exercised its option to redeem such notes, CF Industries will be required to offer to repurchase them at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but not including, the date of repurchase.

The indentures governing the 2026 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. The indenture governing the 2026 Notes provides for customary events of default, which include (subject in certain cases to customary grace and cure periods), among others, nonpayment of principal or interest of the 2026 Notes; failure to comply with other covenants or agreements under the indenture; certain defaults on other indebtedness; the failure of CF Holdings’ guarantee of the 2026 Notes to be enforceable; and specified events of bankruptcy or insolvency. Under the indenture governing the 2026 Notes, in the case of an event of default arising from one of the specified events of bankruptcy or insolvency, the 2026 Notes would become due and payable immediately, and, in the case of any other event of default (other than an event of default related to CF Industries’ and CF Holdings’ reporting obligations), the trustee or the holders of at least 25% in aggregate principal amount of the 2026 Notes then outstanding may declare all of such notes to be due and payable immediately.

Forward Sales and Customer Advances

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 nitrogen 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, 2021 and 2020, we had $700 million and $130 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 and our customers’ outlook of future market fundamentals. During periods of declining prices, customers tend to delay purchasing fertilizer in anticipation that prices in the future will be lower than the

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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.

Natural Gas

Natural gas is the principal raw material used to produce nitrogen products. We use natural gas both as a chemical feedstock and as a fuel to produce ammonia, granular urea, UAN, AN and other products. Expenditures on natural gas are a significant portion of our production costs, representing approximately 40% of our total production costs in 2021. As a result of these factors, natural gas prices have a significant impact on our operating expenses and can thus affect our liquidity.

We enter into agreements for a portion of our future natural gas supply and related transportation. As of December 31, 2021, our natural gas purchase agreements have terms that range from one to two years and a total minimum commitment of approximately $780 million, and our natural gas transportation agreements have terms that range from one to ten years and a total minimum commitment of approximately $165 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.

Because most of our nitrogen manufacturing facilities are located in the United States and Canada, the price of natural gas in North America directly impacts a substantial portion of our operating expenses. Due to increases in natural gas production resulting from the rise in production from shale gas formations, natural gas prices in North America have declined in the last decade, but are subject to volatility. During 2021, the daily closing price at the Henry Hub, the most heavily-traded natural gas pricing point in North America, reached a low of $2.36 per MMBtu on April 7, 2021 and a high of $23.61 per MMBtu on February 18, 2021. During the three-year period ended December 31, 2021, the daily closing price at the Henry Hub reached a low of $1.34 per MMBtu on September 22, 2020 and three consecutive days in October 2020 and a high of $23.61 per MMBtu on February 18, 2021.

We also have manufacturing facilities located in the United Kingdom. These facilities are subject to fluctuations associated with the price of natural gas in Europe. The major natural gas trading point for the United Kingdom is the National Balancing Point (NBP). During 2021, the daily closing price at NBP reached a low of $5.58 per MMBtu on February 23, 2021 and a high of $60.10 per MMBtu on December 22, 2021. During the three-year period ended December 31, 2021, the daily closing price at NBP reached a low of $1.04 per MMBtu on May 22, 2020, and a high of $60.10 per MMBtu on December 22, 2021.

Natural gas costs in our cost of sales, including the impact of realized natural gas derivatives, increased 88% to $4.21 per MMBtu in 2021 from $2.24 per MMBtu in 2020.

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 our 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 2021 and 2020, we recognized an unrealized net mark-to-market loss (gain) on natural gas derivatives of $25 million and $(6) million, respectively, 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

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net settlement of certain derivative trades or may require us to collateralize derivatives in a net liability position. As of December 31, 2021 and 2020, the aggregate fair value of the derivative instruments with credit-risk-related contingent features in net liability positions was $31 million and $6 million, respectively, which also approximates the fair value of the assets that may be needed to settle the obligations if the credit-risk-related contingent features were triggered at the reporting dates.

As of December 31, 2021, our open natural gas derivative contracts consisted of natural gas fixed price swaps, basis swaps and options for 60.0 million MMBtus. As of December 31, 2020, we had open natural gas derivative contracts consisting of natural gas fixed price swaps and basis swaps for 34.1 million MMBtus. At both December 31, 2021 and 2020, 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.

Embedded Derivative Liability

Under the terms of our strategic venture with CHS, if our credit rating as determined by two of three specified credit rating agencies is below certain levels, we are required to make a non-refundable yearly payment of $5 million to CHS. Since 2016, our credit ratings have been below certain levels and, as a result, we made an annual payment of $5 million to CHS in the fourth quarter of each year. These payments will continue on a yearly basis until the earlier of the date that our credit rating is upgraded to or above certain levels by two of three specified credit rating agencies or February 1, 2026. This obligation is recognized on our consolidated balance sheets as an embedded derivative. As of December 31, 2021 and 2020, the embedded derivative liability was $15 million and $18 million, respectively. See Note 10—Fair Value Measurements for additional information.

Defined Benefit Pension Plans

We contributed $40 million to our pension plans in 2021. In 2022, we expect to contribute approximately $29 million to our pension plans. In addition, we expect to contribute a total of approximately $68 million to our U.K. plans in the three-year period from 2023 to 2025, as agreed with the plans’ trustees.

Distributions on Noncontrolling Interest in CFN

The CFN Board of Managers approved semi-annual distribution payments for the years ended December 31, 2021, 2020 and 2019, in accordance with CFN’s limited liability company agreement, as follows:

Cash Flows

Operating Activities

Net cash provided by operating activities in 2021 was $2.87 billion as compared to $1.23 billion in 2020, an increase of $1.64 billion. The increase in cash flow from operations was due primarily to higher net earnings and favorable changes in net working capital. Net earnings in 2021 was $1.26 billion compared to $432 million in 2020. The increase in net earnings was due primarily to higher average selling prices and a $112 million gain on the net settlement of certain natural gas contracts with our suppliers in February 2021, partially offset by higher costs related to manufacturing, maintenance and repair activity. During 2021, net changes in working capital increased cash flow from operations by $448 million, while in 2020 net changes in working capital contributed $12 million to cash flow from operations. The increased cash flow from working capital changes was primarily driven by an increase in customer advances and accounts payable and accrued expenses, partially offset by changes in accounts receivable and inventory.

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Investing Activities

Net cash used in investing activities was $466 million in 2021 compared to $299 million in 2020, or an increase of $167 million. This increase was due primarily to higher capital expenditures. During 2021, capital expenditures totaled $514 million compared to $309 million in 2020.

Financing Activities

Net cash used in financing activities was $1.46 billion in 2021 compared to $542 million in 2020. In 2021, we paid $518 million in connection with the redemption of the 2021 Notes and the partial redemption of the 2023 Notes. In 2021, we repurchased shares of common stock for $540 million, of which $1 million was accrued and unpaid as of December 31, 2021, compared to share repurchases of $100 million in 2020. Dividends paid on common stock in 2021 and 2020 were $260 million and $258 million, respectively. Distributions to noncontrolling interest totaled $194 million in 2021 as compared to $174 million in 2020.

Critical Accounting Estimates

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with U.S. GAAP. 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 prices, raw material costs, operating rates, operating expenses, inflation, discount rates, exchange rates, tax rates and capital spending. 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 business. 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 can begin 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 identified no goodwill impairment in 2020 or 2019.

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During the third quarter of 2021, in light of the unprecedented increase in natural gas prices in the United Kingdom and its estimated impact on our U.K. operations, we identified a triggering event indicating possible impairment of goodwill within our U.K. Ammonia, U.K. AN and U.K. Other reporting units. Due to the triggering event, we performed an interim quantitative goodwill impairment analysis as of September 30, 2021 for our U.K. Ammonia, U.K. AN and U.K. Other reporting units. We estimated the fair value of the reporting units using the income approach described in Note 6—United Kingdom Energy Crisis and Impairment Charges. Based on the evaluation performed, we determined that the carrying value of all three reporting units exceeded their fair value, which resulted in a goodwill impairment charge totaling $259 million in the third quarter of 2021. The goodwill impairment was calculated as the amount that the carrying value of the reporting unit, including any goodwill, exceeded its fair value. The continued impacts of the U.K. energy crisis in the fourth quarter of 2021 triggered an additional impairment test, and we recognized an additional goodwill impairment charge of $26 million. In 2021, we recognized total goodwill impairment charges of $285 million. As of December 31, 2021, after the recognition of the $285 million of goodwill impairment charges noted above, we have no remaining goodwill related to our U.K. operations. As of December 31, 2021, the carrying value of our goodwill was $2.09 billion. Our annual evaluation of impairment in the fourth quarter of 2021 included a qualitative assessment for our North America reporting units, where the remaining goodwill is allocated, and resulted in no indication of impairment.

As a result of the triggering event described above, we also performed a recoverability test on our long-lived assets within the U.K. Ammonia, U.K. AN and U.K. Other asset groups, including our definite-lived intangible assets, as of September 30, 2021. The recoverability test was based on forecasts of undiscounted cash flows, as described in Note 6—United Kingdom Energy Crisis and Impairment Charges. The results of the recoverability test indicated that the long-lived assets within our U.K. Ammonia, U.K. AN and U.K. Other asset groups were not fully recoverable, and, as a result, long-lived asset impairment charges, inclusive of the definite-lived intangible assets, of $236 million were recorded. That impairment was allocated to each of the underlying assets, of which $50 million was allocated to definite-lived intangible assets. As of December 31, 2021 and 2020, the carrying value of our intangible assets was $45 million and $104 million, respectively.

As discussed above, the results of our fourth quarter 2021 long-lived asset impairment test indicated that no additional long-lived asset impairment should be recorded as the undiscounted cash flows were in excess of the carrying values for each of the U.K. asset groups. Of the factors discussed above, the assumptions for product selling prices and natural gas costs included in the expected cash flows utilized in the long-lived asset impairment test were more sensitive than others. Assuming that all other assumptions utilized in our expected cash flows and the other inputs used in our long-lived asset test remained unchanged, a decrease of $5.00 per product ton in the average selling price or an increase of $0.50 per MMBtu in the cost of natural gas would have resulted in long-lived asset impairment for certain of the U.K. asset groups as the undiscounted cash flows would have been lower than their carrying values, and the resulting long-lived asset impairment charges for the fourth quarter of 2021 would have been as follows:

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(1)The sensitivity impact of a $0.50/MMBtu increase or decrease in the cost of natural gas includes any corresponding impact to selling prices from contractually stipulated sales provisions.

See “Items Affecting Comparability of Results—U.K. energy crisis impacts,” “Liquidity and Capital Resources—United Kingdom Energy Crisis,” above, Note 6—United Kingdom Energy Crisis and Impairment Charges, Note 7—Property, Plant and Equipment—Net and Note 8—Goodwill and Other Intangible Assets for further information.

PLNL is our joint venture investment in the Republic of Trinidad and Tobago and operates an ammonia plant that relies on natural gas supplied, under a Gas Sales Contract (the NGC Contract), by the National Gas Company of Trinidad and Tobago Limited (NGC). The joint venture is accounted for under the equity method. The joint venture experienced past curtailments in the supply of natural gas from NGC, which reduced the ammonia production at PLNL. The NGC Contract had an initial expiration date of September 2018 and was extended on the same terms until September 2023. Any NGC commitment to supply gas beyond 2023 will be based on new agreements. If NGC does not make sufficient quantities of natural gas available to PLNL at prices that permit profitable operations, PLNL may cease operating its facility and we would write off the remaining investment in PLNL. The carrying value of our equity method investment in PLNL at December 31, 2021 is $82 million.

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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).

The December 31, 2021 PBO was computed based on a weighted-average discount rate of 2.8% for our North America plans and 2.0% for our United Kingdom plans, which were based on yields for high-quality (AA rated or better) fixed income debt securities that match the timing and amounts of expected benefit payments as of the measurement date of December 31, 2021. Declines in comparable bond yields would increase our PBO. For our United Kingdom plans, the 3.3% RPI used to calculate our PBO is developed using the Bank of England implied retail price inflation curve, which is based on the difference between yields on fixed interest government bonds and index-linked government bonds.

For North America qualified pension plans, our PBO was $841 million as of December 31, 2021, which was $11 million higher than pension plan assets. For our United Kingdom pension plans, our PBO was $590 million as of December 31, 2021, which was $85 million higher than pension plan assets. The tables below estimate the impact of a 50 basis point increase or decrease in the key assumptions on our December 31, 2021 PBO:

See Note 12—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. 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.

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.

Recent Accounting Pronouncements

See Note 3—New Accounting Standards for a discussion of recent accounting pronouncements.

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