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Item 7. Management’s Discussion and Analysis

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Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition, results of operations and cash flow should be read in conjunction with our consolidated financial statements and related notes and with the statistical information and financial data included elsewhere in this Report.

The following discussion and analysis of our financial condition, results of operations and cash flows should be read in conjunction with our consolidated financial statements and related notes and with the statistical information and financial data included elsewhere in this Report, as well as Part I, Item 1, “Business” and Part I, Item 1A, “Risk Factors” of this Report.

References to “CVR Energy”, “CVR”, the “Company”, “we”, “us”, and “our” may refer to consolidated subsidiaries of CVR Energy, including CVR Partners, as the context may require.

This discussion and analysis covers the years ended December 31, 2023 and 2022 and discusses year-to-year comparisons between such periods.

The discussions of the year ended December 31, 2021 and year-to-year comparisons between the years ended December 31, 2022 and 2021 that are not included in this Annual Report on Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2022 filed on February 22, 2023, and such discussions are incorporated by reference into this Report.

With the exception of the Renewables Segment, as defined below, which discusses year-to-year comparisons between all periods presented, this discussion and analysis covers the years ended December 31, 2024 and 2023 and includes year-to-year

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comparisons between such periods.

The discussions of the year ended December 31, 2022 and year-to-year comparisons between the years ended December 31, 2023 and 2022 are not included in this Report but can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2023 filed on February 21, 2024 , and such discussions are incorporated by reference into this Report.

Reflected in this discussion and analysis is how management views the Company’s current financial condition and results of operations, along with key external variables and management’s actions that may impact the Company.

Understanding significant external variables, such as market conditions, weather, and seasonal trends, among others, and management actions taken to manage the Company, address external variables, among others, which will increase users’ understanding of the Company, its financial condition and results of operations.

This discussion may contain forward-looking statements that reflect our plans, estimates and beliefs.

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Company Overview

CVR Energy is a diversified holding company primarily engaged in the petroleum refining and marketing industry (the “Petroleum Segment”) and the nitrogen fertilizer manufacturing industry through its interest in CVR Partners, LP, a publicly traded limited partnership (the “Nitrogen Fertilizer Segment” or “CVR Partners”).

CVR Energy is a diversified holding company primarily engaged in the petroleum refining and marketing industry (the “Petroleum Segment”), the renewable fuels industry (the “Renewables Segment”), and the nitrogen fertilizer manufacturing industry through its interest in CVR Partners, LP, a publicly traded limited partnership (the “Nitrogen Fertilizer Segment” or “CVR Partners”).

The Petroleum Segment is an “independent petroleum refiner”, in that it does not have crude oil exploration or production operations and is a marketer of high value transportation fuels primarily in the form of gasoline and diesel fuels.

The Renewables Segment refines feedstocks, including soybean oil, corn oil, and other related renewable feedstocks, into renewable diesel.

CVR Partners produces and markets nitrogen fertilizers primarily in the form of urea ammonium nitrate (“UAN”) and ammonia.

CVR Energy also produces and markets renewable diesel.

Our renewable diesel operations are not allocated or aggregated to our reportable segments discussed within this Report, but are reflected in our consolidated results of operations.

We operate under two reportable segments:

petroleum and nitrogen fertilizer, which are referred to in this document as our “Petroleum Segment” and our “Nitrogen Fertilizer Segment”, respectively.

Renewables Business

Since 2022, we have focused significant efforts on decarbonization initiatives including but not limited to the completion of the renewable diesel unit (“RDU”) project at the Wynnewood Refinery, the creation of an Environmental, Social and Governance (“ESG”) committee and the publication of multiple ESG reports.

In February 2023, we completed the transfer of various assets to one or more new entities primarily formed in 2022 to, among other purposes, better align our organizational structure with management and financial reporting.

We also achieved mechanical completion of the renewable feedstock pretreater project at the Wynnewood Refinery at the end of 2023.

We currently expect to continue to explore options to decarbonize our business in areas with attractive economics, low risk of government subsidies, and in ways intended to support our Mission and Values.

We operate under three reportable segments:

petroleum, renewables, and nitrogen fertilizer, which are referred to in this document as our “Petroleum Segment”, our “Renewables Segment”, and our “Nitrogen Fertilizer Segment”, respectively.

Strategy and Goals

The Company has adopted Mission and Values, which articulate the Company’s expectations for how it and its employees do business each and every day.

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Mission and Core Values

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We use defined work practices for consistency, efficiency and to create value across the organization.

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Our core Values are driven by our people, inform the way we do business each and every day and enhance our ability to accomplish our mission and related strategic objectives.

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• Financial Discipline - We strive to be as efficient as possible by maintaining low operating costs and disciplined deployment of capital.

Following good faith bargaining by East Dubuque Nitrogen Fertilizer, LLC, the United Automobile Workers Union and its Local 1391 representing approximately 90 employees at the Nitrogen Fertilizer Segment’s facility in East Dubuque, Illinois (the “East Dubuque Fertilizer Facility”) went on strike on October 18, 2023 after its collective bargaining agreement expired the previous day.

The East Dubuque Fertilizer Facility has continued to operate and is currently expected to continue normal operations during the strike.

Potential Strategic Transactions

As previously disclosed in a Schedule 13D amendment filed on March 18, 2024, Icahn Enterprises L.P.

and its affiliates (“IEP”) and the Company are considering potential strategic transactions available to the Company and our subsidiaries, which may include the acquisition of additional entities, assets or businesses, including the acquisition of material amounts of refining assets through negotiated mergers or stock or asset purchase agreements by the Company or our subsidiaries.

IEP may participate in such acquisitions, including by providing financing to us or our subsidiaries through the acquisition of additional equity of us or our subsidiaries, providing loans to us or our subsidiaries or otherwise.

In addition, IEP and the Company are considering strategic options involving CVR Partners, which may include the acquisition by IEP, the Company, a combination of IEP and the Company or other affiliated entities of some or all of the outstanding common units of CVR Partners not already indirectly owned by the Company (the “public common units”), the sale of CVR Partners or the Company’s interest therein, or other transactions.

Any such acquisition, sale or transaction could be effectuated through open market purchases, tender or exchange offers, exercise of the limited call right contained in CVR Partners’ limited partnership agreement, value enhancing partnerships, negotiated merger transactions, privately negotiated transactions, sale transactions or otherwise.

At this time, there can be no assurance that IEP or the Company will pursue any such potential strategic transactions or that any transactions, if pursued, will be completed on attractive terms or at all.

Recent Events

As described further below, volatile commodity pricing and higher industry utilization and oversupply have had an unfavorable impact on our business and have negatively impacted our cash from operating activities and liquidity.

As a result, the Board elected to suspend payment of the cash dividend, defer new growth capital spending, and reduce certain expected capital expenditures, as further discussed in Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” of this Report.

On December 19, 2024, certain of the Company’s subsidiaries entered into a senior secured term loan facility in the amount of $325 million (the “Term Loan”), which was borrowed in full on the closing date.

On December 23, 2024, a subsidiary of the Company sold the 50% limited liability company interest (the “Membership Interests”) it owned in Midway Pipeline LLC (“Midway”) to Plains Pipeline, L.P.

pursuant to an Assignment and Assumption of Units in exchange for cash consideration of approximately $90 million.

Midway operates a crude oil pipeline that connects the Broome Station facility to Cushing, Oklahoma.

In connection with the sale of the Membership Interests, a subsidiary of the

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Environmental, Social & Governance (“ESG”) Highlights

In the past year, we achieved numerous milestones through our commitment to ESG initiatives, including environmental and safety stewardship, diversity and inclusion, community outreach and sound corporate governance.

In December 2023, we published our 2022 Environmental, Social & Governance Report (“2022 ESG Report”) which is based on the Sustainability Accounting Standards Board standards and is available at CVR Energy’s website at www.CVREnergy.com.

Company entered into a pipeline transportation agreement with Midway that allows the Company to deliver a variety of crude oils from Cushing, Oklahoma to the Coffeyville Refinery over the long-term.

In January 2025, we published our 2023 Environmental, Social & Governance Report (“2023 ESG Report”), which continues to benchmark our Company’s performance against specific Sustainability Accounting Standards Board metrics and is available at CVR Energy’s website at www.CVREnergy.com.

Our 2023 ESG Report does not constitute a part of, and is not incorporated by reference into, this Annual Report on Form 10-K or any other report we file with (or furnish to) the SEC, whether made before or after the date of this Annual Report on Form 10-K.

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General Business Environment

Geopolitical Matters - The conflict between Israel and Hamas, which began in October 2023, and the ongoing Russia-Ukraine war, can significantly impact global oil, fertilizer, and agriculture markets.

These conflicts pose significant geopolitical risks to global markets, raise concerns of major implications, such as the enforcement of sanctions, and could contribute to further oil inventory tightening and price volatility, and disrupt the production and trade of fertilizer, grains, and feedstock through several means, such as trade restrictions.

The ultimate outcome of these conflicts and any associated market disruptions are difficult to predict and may affect our business, operations, and cash flows in unforeseen ways.

Geopolitical Matters - The Middle East conflict, which began in October 2023 and impacted global oil, fertilizer, and agriculture markets, alongside other conflicts, like the ongoing Russia-Ukraine war, continue to present significant geopolitical risks to global markets as does the potential for future trade wars and the potential changes in U.S.

economic trade policy.

These concerns, including the enforcement of sanctions, could lead to further oil price volatility and disruptions in the production and trade of fertilizer, grains, and feedstock through various means, such as trade restrictions.

The ultimate outcome of these conflicts and/or economic policy, or further escalation or expansion thereof, and any associated market disruptions are difficult to predict and may affect our business, operations, and cash flows in unforeseen ways.

Regulatory Environment - In addition to existing regulations like the Renewable Fuel Standard (“RFS”) of the Clean Air Act, which significantly impacts our business, there have been several proposed and enacted climate-related rules and compliance requirements at federal, state, and international levels.

While the Biden Administration had advanced significant climate-related initiatives, including stricter EPA emissions standards and the SEC’s proposed climate risk disclosure rule, recent changes under the Trump Administration following the 2024 U.S.

presidential election has begun to and may further shift regulatory priorities.

Through executive orders and regulatory rollbacks, certain of these initiatives have been curtailed or reevaluated and incentives to increase fossil fuel production have been promoted, creating a more uncertain regulatory landscape which may materially impact our business, operations, feedstock and compliance costs, results and market stability.

Petroleum Segment

The earnings and cash flows of the Petroleum Segment are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks that are processed and blended into refined products together with the cost of refinery compliance, including the cost of compliance with Renewable Fuel Standard (“RFS”) regulations.

The cost to acquire crude oil and other feedstocks and the price for which refined products are ultimately sold depends on factors beyond the Petroleum Segment’s control, including the supply of and demand for crude oil, as well as gasoline, distillate, and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, driving habits, weather conditions, domestic and foreign political affairs, production levels, the availability or permissibly of imports and exports, the marketing of competitive fuels, and the extent of government regulations.

Because the Petroleum Segment applies first-in, first-out (“FIFO”) accounting to value its inventory, crude oil price movements may impact net income as a result of changes in the value of its unhedged inventory.

The effect of changes in crude oil prices on the Petroleum Segment’s results of operations is partially influenced by the rate at which the processing of refined products adjusts to reflect these changes.

Because the Petroleum Segment applies first-in, first-out (“FIFO”) accounting to value its inventory, crude oil and refined product price movements may impact margin as a result of changes in the value of its unhedged inventory.

The effect of changes in crude oil prices on the Petroleum Segment’s results of operations is also influenced by the rate at which the processing of refined products adjusts to reflect these changes.

The prices of crude oil and other feedstocks and refined products are also affected by other factors, such as product pipeline capacity, system inventory, local and regional market conditions, inflation, and the operating levels of other refineries.

Crude oil costs and the prices of refined products have historically been subject to wide fluctuations.

Widespread expansion or upgrades of third-party facilities, price volatility, international political and economic developments, and other factors are likely to continue to play an important role in refining industry economics.

Widespread expansion or upgrades of third-party facilities, shutdowns, price volatility, international political and economic developments, and other factors are likely to continue to play an important role in refining industry economics.

These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins.

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Specific factors impacting the Company’s operations are outlined below:

Current Market Outlook

• After substantial declines in demand for gasoline and diesel due to the COVID-19 pandemic in 2020, the combination of improving demand, declining inventories, loss of domestic and foreign operating refining capacities, and conversions to renewable diesel facilities led to an increase in refined products prices and crack spreads during 2022 and 2023.

While the refining market has largely recovered since the pandemic, refined product demand declined 3% nationwide in the fourth quarter of 2023 from the pre-pandemic fourth quarter of 2019.

Group 3 demand has been relatively strong compared to other parts of the country following the pandemic;

however, high regional refinery utilization through the second half of 2023 and typical seasonal inventory builds have pressured the prompt crack spreads.

We would characterize the current NYMEX crack spread environment as above mid-cycle;

however, the Group 3 basis is historically wide and the current forward curves for Group 3 crack spreads remain near or below mid-cycle levels.

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• Winter 2022/2023 weather was warmer than average in Europe and when combined with natural gas conservation measures caused demand and prices for natural gas to fall significantly in the region, which contributed to the flattening of the global cost curve and has reduced the U.S.

Current Market Outlook

• We characterize current crack spreads as below mid-cycle levels.

This is due to a combination of the refined products market being oversupplied, as refinery utilization has been above the 5-year history for most of 2024, improved fleet mileage, and reduced manufacturing activity which has lead to weak gas and diesel demand.

• Winter 2023/2024 weather was warmer than average in North America and Europe and, when combined with natural gas conservation measures, has caused demand and prices for natural gas to fall significantly, which contributed to the flattening of the global cost curve and has reduced the U.S.

refiners’ advantage compared to refiners in Europe.

• Contributing to the ultra-low sulfur diesel (“ULSD”) supply constraints is the International Maritime Organization’s limit on the sulfur content in the fuel oil used on board ships (“bunker fuel”) effective January 1, 2020, which lowered the sulfur limit of bunker fuel from 3.5% to 0.5% (the “IMO 2020 Regulations”), which necessitated blending ULSD into bunker fuel to meet the new specifications.

The resulting reduction of supply for traditional ULSD demand was initially muted by the pandemic-induced demand contraction.

• In the second half of 2023, industrial production slowed and truck, rail, and ship tonnage and freight volumes were reduced, which reduced distillate pricing heading into the fourth quarter of 2023.

Gasoline and distillate pricing declined significantly through the end of the quarter.

If similar conditions are experienced during the 2024/2025 winter, these impacts could persist into 2025.

• Industrial production slowed in 2024, and truck, rail, and ship tonnage and freight volumes were reduced, which lowered distillate pricing into 2025.

In addition, distillate crack spreads continue to be pressured by the low price levels of natural gas causing a lack of distillate demand to generate electricity around the world.

Moreover, new liquid natural gas (“LNG”) projects coming online and expansion of export capacity in the United States has contributed to the increase of global supply of natural gas and thus downward pressure on prices, and may also support fleet shifting from diesel to LNG.

Gasoline and distillate pricing has continued to decline into 2025.

• Shale oil production continues to increase in the shale oil basins, albeit at a slower pace than in prior years, including in the Anadarko Basin.

Crude oil exports have continued above the 4 million bpd rate, and we believe our Petroleum Segment benefits from these exports through the Brent crude differential to WTI, as do all refineries in PADD II.

• Significant refining capacity additions are expected in 2024, headlined by major projects scheduled to start up in the Middle East, Asia, Mexico, and Africa.

Some of the capacity additions could be offset by renewable diesel conversions and planned shutdowns, but refined product consumption is slowing in the United States and remains weak in Europe.

• Renewable identification number (“RIN”) prices continued to decline in the fourth quarter of 2023.

This decline was partly due to higher distillate prices and higher biomass based diesel RIN (“D4”) production rates.

We expect D4 production to exceed the renewable volume obligation (“RVO”) significantly going forward, creating a RIN surplus.

Crude oil exports have sustained a 4 million bpd rate, and we believe the Petroleum Segment benefits from these exports through the Brent crude differential to WTI, as do all refineries in PADD II.

• Refining capacity has increased around the world over the past two years, with major projects being completed in the Middle East, Asia, Mexico, and Africa.

Refining capacity in the United States has also increased approximately 500,000 bpd from post-pandemic levels, mainly due to the completion of expansion projects that were underway pre-pandemic, and capacity creep.

While these ongoing projects may encounter various challenges and come to market slower than anticipated, they have begun to and should have a growing impact on global oil and refined product flows.

At the same time, these capacity expansions could be offset by additional conversions to renewable fuels production and further refinery fleet rationalization through planned shutdowns, or currently unplanned shutdowns due to future economic constraints given refined product consumption is slowing in the United States and remains weak in Europe.

Currently announced refinery closures in the U.S.

and Europe account for nearly 800,000 bpd of capacity expected to be shut in by the end of 2025.

• While renewable identification number (“RIN”) prices increased slightly during the fourth quarter of 2024, they are still lower than the fourth quarter of 2023.

Production of renewable fuels in the United States continues to increase as new plants start up, which may continue through 2025.

We also expect biomass based diesel RIN (“D4”) production to exceed the renewable volume obligation (“RVO”) significantly going forward, creating a RIN surplus.

In June 2023, the Environmental Protection Agency (“EPA”) set the D4 RVO for 2024 and 2025 at 3.04 and 3.35 billion gallons, respectively.

• Electric vehicle penetration of new vehicle sales in the U.S.

light vehicle market has increased significantly, up approximately 30 percent from the prior year.

The EPA released a unified agenda during spring 2024 delaying finalization of the 2026 RFS rule until December 2025.

• In the fourth quarter of 2024, new electric vehicle sales in the United States increased approximately 15.2% from the fourth quarter of 2023.

In 2023, miles per gallon of the new auto fleet continued to increase, averaging 27.1 miles per gallon (“MPG”).

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We expect this trend to continue.

Based on 9.2 billion miles traveled per day, a 1 MPG change in fuel efficiency represents approximately 300,000 bpd of gasoline demand.

• Asian refiners appear to be benefiting from discounted crude oil offered by sanctioned countries like Russia and Iran, adding product to an oversupplied global market.

• While the Chinese government has taken several steps to spur economic activity, the Chinese economy is still weighed by a weak property sector and lower domestic demand for transportation fuels.

China has seen a significant increase in EV sales as well as the conversion of heavy trucks to LNG.

Any lasting effects of these factors remains to be seen.

Regulatory Environment

We continue to be impacted by significant volatility and costs associated with current and proposed laws, rules, regulations and policies relating to climate change, the RFS, energy transition and related matters.

We continue to be impacted by significant volatility and costs associated with current and proposed laws, rules, regulations and policies, including the reinterpretation and amplification thereof, relating to climate change, the RFS, energy transition and related matters.

• Certain of the Petroleum Segment’s subsidiaries are subject to the RFS (collectively, the “obligated-party subsidiaries”), which, each year, absent exemptions or waivers, requires such obligated-party subsidiaries to blend renewable fuels with transportation fuels, purchase RINs in lieu of blending, or otherwise face liability.

Our cost to comply with the RFS is dependent upon a variety of factors, which include but are not limited to the availability of ethanol and biodiesel for blending at our refineries and downstream terminals or RINs for purchase, the actions of RIN market participants including non-obligated parties, the price at which RINs can be purchased, transportation fuel and renewable diesel production levels and pricing including potential discounts thereto related to the RFS, the mix of our products, our refining margins and other factors, all of which can vary significantly from period to period, as well as certain waivers or exemptions to which we may be entitled.

Our costs to comply with the RFS further depend on the consistent, timely, and legal administration of the RFS program by the EPA, including the EPA’s unlawful failure to establish the RVOs by their statutory deadlines, its subsequent promulgation of RVOs exceeding the blendwall, its delay in issuing decisions on pending small refinery exemption (“SRE”) petitions, its subsequent denial of those SRE petitions and its failure to designate blenders as obligated parties under the RFS.

Our costs to comply with the RFS are also impacted by, and dependent upon the outcome of, the numerous lawsuits filed by multiple refiners including our obligated-party subsidiaries, biofuels groups and others.

Refer to Part II, Item 8, Note 14 (“Commitments and Contingencies”).

Wynnewood Refining Company, LLC filed its SRE petition for 2023, which has not yet been ruled on by the EPA.

As a result, our costs to comply with RFS (excluding the impacts of any exemptions or waivers to which the Petroleum Segment’s obligated-party subsidiaries may be entitled) increased significantly throughout 2022, remained significant in 2023 and is expected to remain significant through 2024 and beyond.

• In April 2023, the EPA issued new proposed federal vehicle emissions standards for light-, medium-, and heavy-duty vehicles for model year 2027 and beyond, under which automakers are expected to produce 60% EVs by 2030 and

Our cost to comply with the RFS is dependent upon a variety of factors, which include but are not limited to the availability of

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67% by 2032 to meet the requirements.

ethanol and biodiesel for blending at our refineries and downstream terminals or RINs for purchase, the actions of RIN market participants including non-obligated parties, the price at which RINs can be purchased, transportation fuel and renewable diesel production levels and pricing including potential discounts thereto related to the RFS, the mix of our products, our refining margins and other factors, all of which can vary significantly from period to period, as well as certain waivers or exemptions to which we may be entitled.

Our costs to comply with the RFS further depend on the consistent, timely, and legal administration of the RFS program by the EPA, including the EPA’s unlawful failure to establish the RVOs by their statutory deadlines, its subsequent promulgation of RVOs exceeding the blendwall, its delay in issuing and refusal to issue decisions on pending small refinery exemption (“SRE”) petitions, its subsequent denial of those SRE petitions, most of which have been overturned by courts, and its enabling non-obligated parties to generate, hoard and sell RINs.

Refer to Part II, Item 8, Note 14 (“Commitments and Contingencies”) in this Report.

As a result, our costs to comply with RFS (excluding the impacts of any exemptions or waivers to which the Petroleum Segment’s obligated-party subsidiaries may be entitled) increased significantly throughout 2022, remained significant through 2024 and is expected to remain significant through 2025 and beyond.

• In March 2024, the EPA finalized new motor vehicle emissions standards for light-, medium-, and heavy-duty vehicles for model year 2027 and beyond.

As a result of these new standards, the EPA is expected to propose new automobile limits requiring at least 50% of new vehicles sold to be EVs by 2030.

In the United States in 2024, approximately 8.1% of new-vehicle sales were EVs.

• During 2024, multiple bills were introduced in Congress that would extend the Biodiesel Blenders’ Tax Credit (“BTC”).

While extensions of this tax incentive have been passed by Congress and signed into law close to, and even after, expiration dates in the past, we believe provisions of the Inflation Reduction Act that created the Clean Fuel Production Credit (“PTC”) could signal the end of the BTC, and if not renewed, would likely affect RIN prices.

Company Initiatives

• In November 2021, the Board approved the pretreater project at the Wynnewood Refinery, which was mechanically completed in the fourth quarter of 2023 at a cost of $94 million.

Once operational, the pretreatment unit should lower our feedstock costs and enable us to process a wider variety of renewable diesel feedstocks at the Wynnewood Refinery, most of which have a lower carbon intensity than soybean oil and generate additional LCFS credits.

With our existing renewable diesel production, this could effectively mitigate a substantial majority, if not all, of our future RFS exposure, assuming we receive SREs for our Wynnewood Refinery for its transportation fuels, which we believe we are legally entitled to and are pursuing in the courts.

However, impacts from recent climate change initiatives under the Biden Administration, actions taken by the courts, resulting administration actions under the RFS, and market conditions, could significantly impact the amount by which our renewable diesel business mitigates our costs to comply with the RFS, if at all.

The renewable diesel unit at the Wynnewood Refinery has the flexibility to be returned to hydrocarbon processing service primarily through a catalyst change or sustainable aviation fuel with additional capital outlays;

depending on market conditions including but not limited to renewable diesel margins, contractual obligations and other factors, the Company could seek to return the unit to hydrocarbon processing service in the future.

• The Company is evaluating a potential renewables project near its Coffeyville location, the approval of which would be subject to numerous conditions and requirements including but not limited to approval of our Board, regulators, and potential other third parties.

This project, if approved and pursued, could enable the capture of synergies with the Petroleum Segment as our refinery in Coffeyville, Kansas (“Coffeyville Refinery”) has excess hydrogen capacity as well as potential access to third-party carbon capture use and storage.

• The Company is installing a fuel by rail facility at its Coffeyville Refinery which will allow the Company to load gasoline, jet, and additional diesel into rail cars.

This system will allow the Company to ship refined products to high priced markets in PADD IV.

• The Company has decided to replace the hydrofluoric acid catalyst alky unit at its Wynnewood Refinery with a fixed bed catalyst system which will expand the alkylation unit by approximately 2,500 bpd, increasing product capture by reducing propylene production and increasing production of premium gasoline, and eliminate hydrofluoric acid inventory onsite.

The capital investment is estimated at $136 million and the project eliminates the need for a hydrofluoric acid mitigation system which would have a cost of approximately $45 million.

As of December 31, 2023, we have an estimated liability of $329 million for the Petroleum Segment’s obligated-party subsidiaries’ compliance with the RFS for 2020, 2021, 2022 and 2023, which consists of approximately 362 million RINs, excluding open, fixed-price commitments to sell a net 11 million RINs.

• During 2024, the Company installed a fuel by rail facility at its Coffeyville Refinery which allows the Company to load gasoline, jet, and additional diesel into rail cars.

This system allows the Company to ship refined products to high priced markets in PADD IV.

• The Company has undertaken a project to replace the hydrofluoric acid catalyst alkylation unit at the refinery in Wynnewood, Oklahoma (the “Wynnewood Refinery”) with a fixed bed catalyst system, which should expand the alkylation unit by approximately 2,500 bpd, increase product capture by reducing propylene production/sales and increase production of premium gasoline, and eliminate hydrofluoric acid inventory onsite.

The capital investment is estimated at $136 million, and the unit is expected to become operational by the second quarter of 2027.

• In April 2024, the Board approved a distillate yield improvement project at the Wynnewood Refinery to modify one of the vacuum towers, which may increase distillate production at the refinery by up to approximately 4,000 bpd.

Final completion is currently expected in 2027 at a capital cost of less than $15 million.

The Company is also studying a similar project at the Coffeyville Refinery which will be installed in phases.

Modification to the crude tower will be made in early 2025 during the scheduled turnaround.

• In connection with our settlement with the EPA on certain environmental issues at the Coffeyville Refinery, the Company plans to install a flare gas recovery system at a cost of approximately $50 million, which is expected to be operational in late 2026.

As of December 31, 2024, we have an estimated liability of $323 million for the Petroleum Segment’s obligated-party subsidiaries’ compliance with the RFS for 2020 through 2024, which consists of approximately 487 million RINs, excluding open, fixed-price commitments to purchase a net 7 million RINs.

The Company’s open RFS position, which does not consider open commitments expected to settle in future periods, is marked-to-market each period and thus significant market volatility, as experienced in late 2023 and 2024, could impact our RFS expense from period to period.

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The pricing differences between other crude oils and WTI, known as differentials, show how the market for other crude oils, such as WCS, White Cliffs (“Condensate”), Brent Crude (“Brent”), and Midland WTI (“Midland”), are trending.

Due to the COVID-19 pandemic, the Russia-Ukraine war, the Israel-Hamas conflict, and, in each case, actions taken by governments and others in response thereto, refined product prices have experienced extreme volatility.

As a result of the current environment, refining margins have been and should continue to be volatile.

As a performance benchmark and a comparison with other industry participants, we utilize NYMEX and Group 3 crack spreads.

Due to geopolitical events, such as the Russia-Ukraine war and the conflict in the Middle East, and, in each case, actions taken by governments and

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others in response thereto, refined product prices have experienced extreme volatility.

As a result of the current environment, refining margins have been and will likely continue to be volatile.

We utilize NYMEX and Group 3 crack spreads as a performance benchmark and a comparison with other industry participants.

These crack spreads are a measure of the difference between market prices for crude oil and refined products and are a commonly used proxy within the industry to estimate or identify trends in refining margins.

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The Group 3 2-1-1 crack spread is calculated using two barrels of WTI crude oil producing one barrel of Group 3 sub-octane gasoline and one barrel of Group 3 ultra-low sulfur diesel.

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Both NYMEX 2-1-1 and Group 3 2-1-1 crack spreads decreased during 2024 compared to 2023.

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Crude Oil Differentials against WTI (1)(2)

NYMEX Crack Spreads (2)

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NYMEX Crack Spreads (2)

PADD II Group 3 Product Crack

Spread and RIN Pricing (2)(3) ( $/bbl )

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Group 3 Product Differential against NYMEX

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(3) PADD II is the Midwest Petroleum Area for Defense District (“PADD”), which includes Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee, and Wisconsin.

Renewables Segment

The earnings and cash flows of the Renewables Segment are primarily affected by the relationship between renewable fuel prices, the prices for Vegetable oils and other feedstocks that are processed and blended into renewable fuels, as well as the prices of various credits generated by the production of renewable fuels together with the cost of operating the renewable diesel unit, including the pre-treatment unit.

The cost to acquire Vegetable oils and other feedstocks and the price for which renewable fuels are ultimately sold depends on factors beyond the Renewables Segment’s control, including the supply of and demand for Vegetable oil and other feedstocks, as well as renewable diesel and other renewable fuels which, in turn, depend on, among other factors, changes in domestic and foreign economies, driving habits, weather conditions, domestic and foreign political affairs, production levels, the availability or permissibly of imports and exports, the marketing of competitive fuels, and the extent of government regulations.

Similar to the Petroleum Segment, the Renewables Segment applies FIFO accounting to value its inventory, and product price movements may thus impact margin as a result of changes in the value of its unhedged inventory.

The effect of changes in product prices on the Renewables Segment’s results of operations is partially influenced by the rate at which the processing of renewable fuels adjusts to reflect these changes.

The prices of Vegetable oils and other feedstocks and renewable fuels are also affected by other factors, such as Vegetable oil production capacity, system inventory, local and regional market conditions, inflation, and the operating levels of other facilities.

Vegetable oil costs and the prices of renewable fuels have historically been subject to wide fluctuations.

These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins.

Specific factors impacting the Company’s operations are outlined below:

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Current Market Outlook

• The near-term outlook for the renewables market is likely to be heavily influenced by U.S.

government policies, particularly as related to the recently expired BTC and PTC, which is awaiting formal IRS rule making, along with the RVO levels to be set for 2026 and the resulting potential impacts on RINs prices.

• The $1 per gallon BTC expired on December 31, 2024, and formal IRS rule making for he PTC has not been issued.

With the loss of the BTC there could be additional volatility in pricing for renewables fuels feedstocks, as well as in prices of other credits generated by renewable fuels production, particularly RINs prices and Low Carbon Fuel Standard (“LCFS”) credit prices.

• After a substantial build-out of renewable diesel production capacity in the United States over the past four years, where capacity increased from less than 900 million gallons per year in January 2021 to over 4.5 billion gallons per year in October 2024, further renewable diesel production capacity expansion is expected to slow significantly due to the uncertainties around U.S.

government policies and support of renewables businesses.

Regulatory Environment

• Profitability in the Renewables Segment is highly dependent on the prices of government credits, particularly RINs prices, LCFS credit prices, and the BTC.

RINs prices are mainly influenced by supply and demand dynamics, with the demand being heavily impacted by the annual RVO levels established by the EPA.

Current market prices for renewable feedstocks are significantly higher than the prices for renewable fuels.

Without sufficient government support to stabilize prices for credits generated by renewable fuels production, many renewable fuel producers may not be able to generate profits.

Company Initiatives

• The Company is evaluating a potential project to convert the Wynnewood Renewable Diesel Unit to produce sustainable aviation fuel (“SAF”), which approval would be subject to numerous conditions and requirements, such as approval of our Board, regulators, and potential other parties.

This project, if approved and pursued, could reduce the risks associated with government credits through an off-take structure with potential counterparties, by potentially shifting the exposure of those credit prices to the fuel purchaser.

• The renewable diesel unit at the Wynnewood Refinery has the flexibility to be returned to hydrocarbon processing service primarily through a catalyst change, or to sustainable aviation fuel with additional capital outlays;

depending on market conditions, such as renewable diesel margins, governmental regulations, contractual obligations and other factors, the Company could seek to return the unit to hydrocarbon processing service in the future.

• The Company is also evaluating a potential renewables project near its Coffeyville Refinery, which approval would be subject to numerous conditions and requirements, including but not limited to, approval of our Board, regulators, and potential other third parties.

This project, if approved and pursued, could enable the capture of synergies with the Petroleum Segment, such as the use of excess hydrogen capacity of our Coffeyville Refinery and potential access to third-party carbon capture use and storage.

Market Indicators

Chicago Board of Trade (“CBOT”) soybean oil is an industry wide benchmark that is utilized in the pricing of renewable fuel feedstocks.

The pricing differences between CBOT soybean oil and other renewable feedstocks such as distiller’s corn oil, used cooking oil and animal fats is typically driven by the carbon intensity (“CI”) score related to each feedstock along, with overall supply and demand in the market for various feedstocks.

Feedstock CI scores play a significant role in the generation of Low Carbon Fuel Standard (“LCFS”) credits, where lower CI score feedstocks generate higher credit values than higher CI score feedstocks.

The PTC that is intended to replace the BTC would also be calculated based on CI scores, with lower CI scores generating higher credit values.

Approximately 60% of combined biodiesel and renewable diesel production in 2023 was produced from Vegetable oils, with animal fats comprising the remaining 40%.

Of the Vegetable oils consumed, soybean oil comprised over 60%, making it one of the primary feedstock pricing benchmarks in the renewables market.

As a performance benchmark and a comparison with other industry participants, we utilize the HOBO spread and a Benchmark Renewable Diesel Margin that incorporates the HOBO spread along with RINs, LCFS credits, and BTCs generated by renewable diesel production.

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The HOBO spread tightened during 2024 compared to 2023, primarily as a result of declining soybean oil pricing in 2024 more than offsetting a decline in ULSD prices.

The HOBO spread averaged $(0.90) per gallon in 2024 compared to $(1.50) per gallon in 2023.

Despite the improvement in the HOBO spread in 2024, the Benchmark Renewable Diesel Margin declined in 2024 compared to 2023, primarily due to declines in prices for RINs and LCFS credits.

The Benchmark Renewable Diesel Margin averaged $1.82 per gallon in 2024, compared to $2.53 per gallon in 2023.

Average monthly prices for RINs decreased 56% during 2024 compared to 2023, while LCFS credit prices decreased 17% during 2024 compared to 2023.

The tables below are presented by month through December 31, 2024:

Benchmark Renewable Diesel Margins (1) (2) (3)

LCFS Credit Price and D4 RIN Market Pricing (1)

Soybean Oil and LA/SF CARB Market Pricing (1)

(1) Information used within these charts was obtained from reputable market sources, including the New York Mercantile Exchange (“NYMEX”), CBOT, and Argus Media, among others.

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(2) Renewable Diesel Indicator Margin calculated as follows:

(OPIS CARB ULSD + (D4 RIN * 1.7x) + BTC + LCFS Credit(65CI) + CAR + LCFS Fee) - (CBOT Soybean Oil * 7.6 lbs/gal).

(3) HOBO spread represents the Heating Oil – Bean Oil Spread and is calculated as CARB ULSD price per gallon less CBOT Soybean Oil price per gallon.

Nitrogen Fertilizer Segment

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Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products.

Certain governmental regulations and incentives associated with the automobile transportation and agricultural industries, including the ones related to corn-based ethanol and sustainable aviation fuel production or consumption can directly impact our business.

In August 2022, the Inflation Reduction Act was passed and introduced the Clean Fuel Production Credit incentivizing lower Carbon Intensity feedstocks, including corn oil, which may increase demand for corn planting.

In June 2023, the EPA announced the renewable volume obligations for 2023, 2024, and 2025 which maintained the ethanol blending level at 15 billion gallons.

In June 2023, the EPA announced the renewable volume obligations for 2023, 2024, and 2025 which maintained the conventional biofuel blending level at 15 billion gallons.

These actions lead us to believe that the demand on food, in particular corn, for fuel will remain strong for the foreseeable future and support farmer economics that incentivize the use of nitrogen-based fertilizers.

In contrast, in April 2023, the EPA announced the proposed federal vehicle emission standards for 2027 through 2032, which, if finalized as proposed, would significantly reduce the use of internal combustion engine vehicles and the demand for liquid fuels including ethanol.

In contrast, in March 2024, the EPA finalized new motor vehicle emission standards for light-, medium-, and heavy-duty vehicles for model year 2027 and beyond, which could significantly reduce the use of internal combustion engine vehicles and the demand for liquid fuels, including ethanol.

New heavy-truck requirements are also being proposed.

In 2023, production of ethanol consumed approximately 37% of the annual United States corn crop used by the market.

CVR Partners Initiatives

CVR Partners has been conducting engineering studies on the potential to utilize natural gas as an optional feedstock to pet coke at its Coffeyville Fertilizer Facility.

Based on these studies, CVR Partners subsidiaries could utilize either natural gas or pet coke to produce nitrogen fertilizer by making certain modifications to the plant.

If this project is approved by the board of directors of CVR Partners’ general partner (the “UAN GP Board”) and successfully implemented, it could allow CVR Partners to choose the lowest cost feedstock for production and would make the Coffeyville Fertilizer Facility the only nitrogen fertilizer plant in the U.S.

with that feedstock flexibility.

Market Indicators

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As such, upon harvesting of soybeans, the soil retains a certain amount of nitrogen which results in lower demand for nitrogen fertilizer for the following corn planting cycle.

Due to these factors, nitrogen fertilizer consumers generally operate a balanced corn-soybean rotational planting cycle as shown by the chart presented below for 2023, 2022, and 2021.

Due to these factors, nitrogen fertilizer consumers generally operate a balanced corn-soybean rotational planting cycle as shown by the chart presented below.

The relationship between the total acres planted for both corn and soybeans has a direct impact on the overall demand for nitrogen products, as the market and demand for nitrogen increases with increased corn acres and decreases with increased soybean acres.

Additionally, an estimated 12.8 billion pounds of soybean oil is expected to be used in producing cleaner

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renewable fuels in marketing year 2023/2024.

Additionally, an estimated 14 billion pounds of soybean oil is expected to be used in producing cleaner renewable fuels in marketing year 2024/2025.

Multiple refiners have announced renewable diesel expansion projects for 2025 and beyond, which should only increase the demand for soybeans and potentially for corn and canola.

The USDA data shows that in spring 2023 farmers planted 94.6 million corn acres, representing an increase of 6.8% as compared to 88.6 million corn acres in 2022.

Planted soybean acres for spring 2023 are 83.6 million, representing a decrease of 4.5% as compared to 87.5 million soybean acres in 2022.

The combined corn and soybean planted acres of 178.2 million in 2023 is an increase of 1.2% compared to the acreage planted in 2022.

Due to lower input costs in 2023 for corn planting and the relative grain prices of corn versus soybeans, economics favored planting corn compared to soybeans in 2023.

Lower inventory levels of corn and soybeans are expected to be supportive of grain prices into the spring of 2024.

The USDA data estimates that in spring 2024 farmers planted 90.7 million corn acres, representing a decrease of 4.1% as compared to 94.6 million corn acres in 2023.

Planted soybean acres for spring 2024 are 87.1 million, representing an increase of 4.2% as compared to 83.6 million soybean acres in 2023.

The combined corn and soybean planted acres of 177.8 million in 2024 is in line with the acreage planted in 2023.

Due to lower input costs in 2024 for corn planting and the relative grain prices

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of corn versus soybeans, economics favored planting corn compared to soybeans in 2024.

Inventory levels of corn and soybeans are expected to be supportive of grain prices into the spring of 2025.

Ethanol is blended with gasoline to meet RFS requirements and for its octane value.

Ethanol production has historically consumed approximately 37% of the U.S.

Since 2010, ethanol production has historically consumed approximately 37% of the U.S.

corn crop used by the market, so demand for corn generally rises and falls with ethanol demand, as shown by the charts below, through December 31, 2024.

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Weather continues to be a critical variable for crop production.

Even with high planted acres and trendline yields per acre in the U.S., global inventory levels for corn and soybeans remain below historical levels and prices have remained elevated.

With tight grain and fertilizer inventory levels driven by the conflict in Ukraine, prices for grains remained elevated through 2023, although below the elevated prices experienced in the spring of 2022.

Demand for nitrogen fertilizer, as well as other crop inputs, was strong for the spring 2023 planting season and fall 2023 ammonia application, primarily due to elevated grain prices and favorable weather conditions for planting and fertilizer application.

Even with high planted acres and above trendline yields per acre for corn in the United States, global inventory levels for corn and soybeans remain near historical 10-year averages and prices have remained elevated.

Demand for nitrogen fertilizer, as well as other crop inputs, was strong for the spring 2024 planting season, primarily due to elevated grain prices and favorable weather conditions for planting.

Fertilizer input costs have been volatile since the fall of 2021.

Natural gas prices were elevated in the fall of 2022 due to shortages in Europe and demand being driven by building natural gas storage for winter.

Winter 2022/2023 weather was warmer than average in Europe and when combined with natural gas conservation measures, caused demand and prices for natural gas in Europe to fall significantly in the first quarter of 2023 and remain below the 2021/2022 price levels.

The decline in natural gas prices has led to a significant reduction in the price for nitrogen fertilizer globally due to lower input costs.

While we expect that natural gas prices might remain below the elevated levels experienced in 2022 in the near term, we believe that the structural shortage of natural gas in Europe will continue to be a source of volatility into 2024.

Although pet coke prices remain elevated compared to historical levels, third-party pet coke prices have declined into 2024.

Winter 2023/2024 weather was warmer than average in Europe and when combined with natural gas conservation measures caused demand and prices for natural gas in Europe to fall significantly in the first quarter of 2024 and remain below the 2021/2022 price levels throughout 2024.

The decline in natural gas prices, and the resulting reversal of capacity curtailments, among other factors, has led to a significant reduction in the price for nitrogen fertilizer from peak prices.

Although pet coke prices had been elevated since 2021 due to higher natural gas prices compared to historical levels, as natural gas prices remained low in 2024, third-party pet coke prices declined into 2024 and fell further into 2025.

CVR Partners Initiatives

CVR Partners has been conducting engineering studies on the potential to utilize natural gas as an optional feedstock to pet coke at its facility in Coffeyville, Kansas (the “Coffeyville Fertilizer Facility”).

Based on these studies, CVR Partners believes the Coffeyville Fertilizer Facility could utilize either natural gas or pet coke to produce nitrogen fertilizer by making certain modifications to the plant.

If this project is approved by the board of directors of CVR Partners’ general partner (the “UAN GP Board”) and successfully implemented, it could allow CVR Partners to choose the optimal feedstock mix for production and would make the Coffeyville Fertilizer Facility the only nitrogen fertilizer plant in the United States with that feedstock flexibility.

As part of growth capital projects, CVR Partners has undertaken several initiatives to continually improve reliability of its Facilities.

In December 2024, an additional piece of oxygen equipment was installed to provide better reliability of a third-party

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air separation plant which supplies contract volumes of oxygen, nitrogen, and compressed dry air to the Coffeyville Fertilizer Facility gasifiers.

The charts below show relevant market indicators for the Nitrogen Fertilizer Segment by month through December 31, 2024:

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Results of Operations

The following sections should be read in conjunction with the information outlined within the previous sections of this Part II, Item 7 and the consolidated financial statements and related notes thereto in Part II, Item 8 of this Report.

Our consolidated results of operations include renewable fuels, certain other unallocated corporate activities, and the elimination of intercompany transactions and, therefore, do not equal the sum of the operating results of the Petroleum and Nitrogen Fertilizer Segments.

Effective with this Annual Report on Form 10-K for the year ended December 31, 2024 and due to the prominence of the renewables business relative to the Company’s overall 2024 performance, we have revised our reportable segments to reflect a new reportable segment – Renewables.

The Renewables Segment includes the operations of the renewable diesel unit and

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renewable feedstock pretreater at the Wynnewood Refinery.

Results of the Renewables Segment were not previously included within our reportable segments discussed below, rather included within “Other”.

Prior period segment information has been retrospectively adjusted to reflect the current segment presentation, and year-to-year comparisons between all periods presented for the Renewables Segment are discussed herein.

Our consolidated results of operations include certain unallocated corporate activities and the elimination of intercompany transactions and, therefore, do not equal the sum of the operating results of the Petroleum, Renewables, and Nitrogen Fertilizer Segments.

Consolidated Financial Highlights

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(1) See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measure shown above.

Overview - The Company’s operating income and net income were $1,123 million and $878 million, respectively, for the year ended December 31, 2023, increases of $160 million and $234 million, respectively, compared to operating income and net income of $963 million and $644 million, respectively, for the year ended December 31, 2022.

These increases were driven by an improvement in operating income of $263 million within the Petroleum Segment, partially offset by a decline in operating income of $119 million within the Nitrogen Fertilizer Segment, for the year ended December 31, 2023 compared to the year ended December 31, 2022.

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Overview - For the year ended December 31, 2024, the Company’s operating income and net income were $58 million and $45 million, respectively, compared to operating income and net income of $1.1 billion and $878 million, respectively, for the year ended December 31, 2023.

Refer to our discussion of each segment’s results of operations below for further information.

Other Income (Expense), Net - The Company’s Other income (expense), net, was $38 million for the year ended December 31, 2024 compared to $14 million for the year ended December 31, 2023.

The change was primarily attributable to a litigation settlement that occurred during 2022.

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Income Tax Expense - The income tax expense for the year ended December 31, 2023 was $207 million, or 19.1% of income before income taxes, as compared to income tax expense for the year ended December 31, 2022 of $157 million, or 19.6% of income before income taxes.

The increase in income tax expense was due primarily to an increase in overall pretax earnings, partially offset by decreases in state tax rates and an increase in tax credits and incentives generated for the year ended December 31, 2023 compared to the year ended December 31, 2022.

In addition, the change in the effective tax rate was due primarily to changes in pretax earnings attributable to noncontrolling interests, decreases in state tax rates and an increase in tax credits and incentives generated for the year ended December 31, 2023 compared to the year ended December 31, 2022.

The change was primarily attributable to the gain on the Company’s sale of its Membership Interests in December 2024.

Income Tax (Benefit) Expense - Income tax benefit for the year ended December 31, 2024 was $26 million, or (137.2)% of income before income taxes, compared to income tax expense for the year ended December 31, 2023 of $207 million, or 19.1% of income before income taxes.

The decrease in income tax expense was due primarily to a decrease in overall pretax earnings.

In addition, the change in the effective tax rate was due primarily to changes in pretax earnings attributable to noncontrolling interests and the impact of federal and state tax credits and incentives generated in relation to overall pretax earnings for the year ended December 31, 2024 compared to the year ended December 31, 2023.

Petroleum Segment

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(in bpd) 2024 2023 2022

Regional crude 62,859 53,237 28,270

WTI 27,283 38,265 62,695

WTL 731 407 511

Midland WTI — 642 452

Gathered crude 71,382 62,263 53,237

Other domestic 39,360 49,930 55,383

Canadian 7,304 3,265 6,847

Condensate 3,177 7,566 12,159

Heavy Canadian 3,265 6,847 3,695

DJ Basin 20,342 15,607 17,980

Bakken 978 — —

Other crude oil 2,546 — —

Other feedstocks and blendstocks 12,511 13,490 11,556

Regional crude 50,900 46,159 60,287

WTL 1,975 2,323 3,430

WTS — 143 202

Midland WTI 137 1,073 2,107

Gathered crude 46,185 50,900 46,160

Other domestic 980 2,112 3,538

Condensate 9,165 15,228 13,283

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Total production 194,931 206,959 204,511

Light product yield (as % of crude throughput) (1)

Light product yield (as % of total crude throughput) (1)

100.2 % 100.2 % 99.3 %

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96.9 % 97.4 % 97.3 %

Distillate yield (as % of crude throughput) (3)

Distillate yield (as % of total crude throughput) (3)

43.1 % 43.3 % 42.9 %

(1) Total Gasoline and Distillate divided by total Regional crude, WTI, WTL, Midland WTI, WTS, Condensate, Heavy Canadian, DJ Basin, and Bakken throughput.

(1) Total Gasoline and Distillate divided by total Gathered crude, Other domestic, Canadian, and Condensate throughput (collectively, “Total Crude Throughput”).

(2) Total Gasoline, Distillate, and Other liquid products divided by total throughput.

(3) Total Distillate divided by total Regional crude, WTI, WTL, Midland WTI, WTS, Condensate, Heavy Canadian, DJ Basin, and Bakken throughput.

(3) Total Distillate divided by Total Crude Throughput.

Petroleum Segment Financial Highlights

Overview - The Petroleum Segment’s operating income and net income for the year ended December 31, 2023 were $982 million and $1,071 million, respectively, representing an improvement of $263 million and $312 million, respectively, compared to an operating income and net income of $719 million and $759 million, respectively, for the year ended December 31, 2022.

The improvement in both operating income and net income compared to the prior period was primarily due to lower RFS related expense and a favorable derivatives impact in the current year.

Net Sales Operating Income (Loss)

Overview - For the year ended December 31, 2024, the Petroleum Segment’s operating income and net income were $12 million and $70 million, respectively, compared to operating income and net income of $982 million and $1.1 billion, respectively, for the year ended December 31, 2023.

The decline in both operating income and net income compared to the prior period was primarily due to decreases in gasoline and distillate crack spreads in 2024, decreased production and increased maintenance resulting from the fire at the Wynnewood Refinery during the second quarter of 2024 (the “Wynnewood Fire”) and unplanned downtime at the Coffeyville Refinery (together with the Wynnewood Fire, the “Petroleum Unplanned Outages”), and increased RFS-related expense in 2024.

Net Sales Operating Income

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(1) See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measure shown above.

Net Sales - For the year ended December 31, 2023, net sales for the Petroleum Segment decreased by $1.6 billion when compared to the year ended December 31, 2022.

Net Sales - For the year ended December 31, 2024, net sales for the Petroleum Segment was $6.9 billion compared to $8.3 billion for the year ended December 31, 2023.

The decrease in net sales was due to decreased refined product prices resulting from declining demand and increasing inventory levels for the year ended December 31, 2024 compared to the year ended December 31, 2023.

Further, higher net sales in 2022 were due to increased prices resulting from tight inventory levels and the Russia-Ukraine war.

Further, higher net sales in 2023 were due to increased prices resulting from tight inventory levels and uncertainty caused by the Russia-Ukraine war.

Refining Margin (1)

Refining Margin (excluding Inventory Valuation Impacts (1)

(1) See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown above.

Refining Margin - For the year ended December 31, 2023, refining margin was $1.7 billion, or $21.82 per throughput barrel, compared to $1.4 billion, or $19.09 per throughput barrel, for the year ended December 31, 2022.

The primary factors contributing to the $227 million increase in refining margin were:

• A decline in RFS-related expense of $483 million, which includes a reduction in RINs revaluation impact of $419 million;

Refining Margin - For the year ended December 31, 2024, refining margin was $684 million, or $9.53 per throughput barrel, compared to $1.7 billion, or $21.82 per throughput barrel, for the year ended December 31, 2023.

The primary factors contributing to the $974 million decrease in refining margin were:

• A decrease in the Group 3 2-1-1 crack spread of $14.22 per barrel, driven by a tightening of gasoline and distillate crack spreads primarily due to increased inventory levels and lower demand in the current year;

• Unfavorable sales volume impacts related to the Petroleum Unplanned Outages;

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• Favorable derivative impacts of $61 million from gains on open crack spread swap positions in the current period and wider margins on Canadian crude oil forward purchases and sales compared to the prior period;

• A decrease in the Group 3 2-1-1 crack spread of $5.91 per barrel, driven by a tightening distillate crack spread primarily due to strong utilization of the U.S.

refining fleet during the winter and slowing demand trends;

• Unfavorable inventory valuation impacts of $32 million in 2023 compared to favorable inventory valuation impacts of $22 million in 2022, primarily due to decreased crude oil prices in the current period.

• An increase in RFS-related expense, net of RINs sales, of $42 million, which includes unfavorable RINs revaluation adjustments of $195 million as a result of a smaller decrease in RINs prices in the current period compared to the previous period.

Factors partially offsetting the decrease in refining margin were:

• Unfavorable inventory valuation impacts of $6 million in 2024 compared to unfavorable inventory valuation impacts of $32 million in 2023, primarily due to a smaller decrease in crude oil prices for the current period as compared to the prior period.

Direct Operating Expenses (1)

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Direct Operating Expenses (Exclusive of Depreciation and Amortization) - For the year ended December 31, 2024, direct operating expenses (exclusive of depreciation and amortization) were $421 million compared to $406 million for the year ended December 31, 2023.

The decrease in the current period was primarily due to lower costs for electricity and natural gas.

On a total throughput barrel basis, direct operating expenses decreased to $5.34 per barrel from $5.68 per barrel, as a function of the decreased expense in 2023, combined with the increase in total throughput in 2023 compared to 2022.

Depreciation and Amortization Expense Selling, General, and Administrative

Expenses, and Other

Depreciation and Amortization Expense - For the year ended December 31, 2023, depreciation and amortization expense increased $2 million compared to the year ended December 31, 2022, primarily due to turnaround asset additions in 2023.

The increase in the current period was primarily due to increased repairs and maintenance costs and increased personnel costs as a result of the Petroleum Unplanned Outages, partially offset by lower costs for electricity and natural gas.

On a total throughput barrel basis, direct operating expenses increased to $5.86 per barrel from $5.34 per barrel, as a function of the increased expense in 2024, combined with the decrease in total throughput in 2024 compared to 2023.

Depreciation and Amortization Expense Selling, General, and

Administrative Expenses

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Selling, General, and Administrative Expenses, and Other - For the year ended December 31, 2023, selling, general and administrative expenses and other was $81 million compared to $99 million for the year ended December 31, 2022.

The decrease was primarily a result of lower personnel costs driven by decreased share-based compensation due to a decline in the market price of CVR Energy’s common stock, and greater loss on asset disposals in 2022 as compared to 2023.

Depreciation and Amortization Expense - For the year ended December 31, 2024, depreciation and amortization expense was $174 million compared to $189 million for the year ended December 31, 2023.

The decrease was primarily attributable to certain assets being retired or fully depreciated during the 2024 turnaround, partially offset by fixed asset additions during the 2024 turnaround.

Selling, General, and Administrative Expenses - For the year ended December 31, 2024, selling, general and administrative expenses was $77 million compared to $81 million for the year ended December 31, 2023.

The decrease was primarily a result of lower personnel costs driven by decreased share-based compensation due to a decline in the market price of CVR Energy’s common stock.

Renewables Segment

The Renewables Segment utilizes certain inputs within its refining operations.

These inputs include corn oil, soybean oil, and other vegetable oils (these are also known as “throughputs”).

Renewables Throughput and Production Data

Throughput Data Year Ended December 31,

(in gallons per day) 2024 2023 2022

Corn Oil 52,807 53,661 20,501

Soybean Oil 98,439 172,297 96,014

Other feedstocks and blendstocks 58,730 51,039 34,122

Total throughput 209,976 276,997 150,637

Production Data Year Ended December 31,

(in gallons per day) 2024 2023 2022

Renewable diesel 134,399 200,015 101,362

Renewable naphtha 17,101 34,099 20,160

Renewable light ends 62,424 92,802 54,804

Other 41,064 45,552 26,961

Total production 254,988 372,468 203,287

Renewable diesel yield (as % of corn and soybean oil throughput) 89.2 % 88.5 % 87.0 %

Renewables Segment Financial Highlights

Overview - The Renewables Segment’s operating loss and net loss for the year ended December 31, 2024 were $22 million and $21 million, respectively, compared to operating loss and net loss of $37 million and $36 million, respectively, for the year ended December 31, 2023.

The improvement in both operating loss and net loss compared to the prior period was primarily due to an overall feedstock price decrease.

Operating loss and net loss for the year ended December 31, 2023 improved compared to operating loss and net loss of $47 million and $47 million, respectively, for the year ended December 31, 2022 primarily due to having a full year of operations in 2023 compared to operations beginning in April of 2022, as well as a better margin environment in 2023 compared to 2022.

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Net Sales Operating Loss

(1) See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measure shown above.

Net Sales - For the year ended December 31, 2024, net sales for the Renewables Segment was $289 million compared to $559 million for the year ended December 31, 2023.

The decrease in net sales was due to reduced production and sales volumes coupled with decreased biodiesel RIN prices resulting from increased renewable diesel supply in the market for the year ended December 31, 2024 compared to the year ended December 31, 2023.

Net sales for the year ended December 31, 2023 increased compared to net sales of $338 million for the year ended December 31, 2022 primarily due to having a full year of operations in 2023 compared to operations beginning in April of 2022, partially offset by decreased biodiesel RINs prices resulting from increased renewable diesel supply in the market for the year ended December 31, 2023 compared to the year ended December 31, 2022.

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Renewables Margin (1)

(1) See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown above.

Renewables Margin - For the year ended December 31, 2024, renewables margin was $44 million, or $0.80 per Vegetable oil throughput gallon, compared to $22 million, or $0.27 per Vegetable oil throughput gallon, for the year ended December 31, 2023.

The primary factors contributing to the $22 million increase in renewables margin were:

• Favorable cost of sales of $284 million due to lower Vegetable oil feedstock prices;

• An increase in the HOBO spread of $0.59 per gallon, driven by a decrease in soybean oil prices of $0.14 per pound due to increased U.S.

soybean oil inventories resulting from higher production levels;

• An increase in renewable diesel yield due to improved catalyst performance in the current year.

For the year ended December 31, 2022, renewables margin was $(4) million, or $(0.10) per Vegetable oil throughput gallon.

The primary factors contributing to the $26 million increase in renewables margin compared to the year ended December 31, 2023 were:

• A full year of operations in 2023 compared to beginning in April 2022;

• An increase in the HOBO spread of $0.37 per gallon, driven by a decrease in soybean oil prices of $0.13 per pound due to increased global supply and decreased demand.

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Direct Operating Expenses (1)

(1) Exclusive of depreciation and amortization expense.

Direct Operating Expenses (Exclusive of Depreciation and Amortization) - For the year ended December 31, 2024, direct operating expenses (exclusive of depreciation and amortization) were $31 million compared to $28 million for the year ended December 31, 2023.

The increase in the current period was primarily due to higher costs for insurance and chemicals used in the production process.

On a Vegetable oil throughput gallon basis, direct operating expenses increased to $0.57 per gallon from $0.35 per gallon, as a function of the increased expense in 2024, partially offset by the decline in total Vegetable oil throughput in 2024 compared to 2023.

Direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 2023 increased compared to $24 million for the year ended December 31, 2022 due primarily to higher costs for catalysts and electricity.

On a Vegetable oil throughput gallon basis, direct operating expenses decreased to $0.35 per gallon from $0.55 per gallon, primarily due to the increased throughput in 2023 as compared to 2022, partially offset by the increased expense in 2023.

Nitrogen Fertilizer Segment

Utilization and Production Volumes - The following tables summarize the consolidated ammonia utilization from the Nitrogen Fertilizer Segment’s facilities in Coffeyville, Kansas (the “Coffeyville Fertilizer Facility”) and the East Dubuque Fertilizer Facility.

Utilization is an important measure used by management to assess operational output at each of the Nitrogen Fertilizer Segment’s facilities.

Utilization and Production Volumes - The following tables summarize the ammonia utilization rates on a consolidated basis for the Nitrogen Fertilizer Segment’s facilities in Coffeyville, Kansas (the “Coffeyville Fertilizer Facility”, and together with the East Dubuque Fertilizer Facility, the “Facilities”) and the East Dubuque Fertilizer Facility.

Utilization is an important measure used by management to assess operational output at each of the Facilities.

Utilization is calculated as actual tons of ammonia produced divided by capacity.

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Gross tons of ammonia represent the total ammonia produced, including ammonia produced that was upgraded into other fertilizer products.

Net tons available for sale represents the ammonia available for sale that was not upgraded into other fertilizer products.

Net tons available for sale represents the ammonia available for sale that was not upgraded into other

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fertilizer products.

The table below presents all of these Nitrogen Fertilizer Segment metrics for the years ended December 31, 2024, 2023, and 2022:

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2024 2023 2022

Consolidated Ammonia Utilization 100 % 81 % 92 %

Ammonia utilization rate 96 % 100 % 81 %

Production Volumes (in thousands of tons)

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UAN 1,273 1,369 1,140

On a consolidated basis, the Nitrogen Fertilizer Segment’s utilization increased 19% to 100% for the year ended December 31, 2023 compared to the year ended December 31, 2022.

This increase was primarily due to reduced production volumes and utilization during the planned turnarounds at both fertilizer facilities in the third quarter of 2022, which subsequently improved operational reliability.

In addition, there was increased unplanned downtime in 2022 associated with the third-party air separation plant operated by Messer LLC (the “Messer Outages”) at the Coffeyville Fertilizer Facility and various pieces of equipment being down at the East Dubuque Fertilizer Facility.

On a consolidated basis, the Nitrogen Fertilizer Segment’s utilization decreased 4% to 96% for the year ended December 31, 2024 as compared to the year ended December 31, 2023, primarily due to the 14-day planned outage at the Coffeyville Fertilizer Facility during the first quarter of 2024 and other minor unplanned outages at the Facilities (the “2024 Outages”) in the current period.

Sales and Pricing per Ton - Two of the Nitrogen Fertilizer Segment’s key operating metrics are total sales volumes for ammonia and UAN, along with the product pricing per ton realized at the gate.

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2024 2023 2022

Consolidated sales (thousand tons)

Consolidated sales volumes (thousand tons)

Ammonia 271 281 195

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UAN 248 309 486

For the year ended December 31, 2024, total product sales volumes were unfavorable, compared to the year ended December 31, 2023 driven by reduced production volumes resulting from the 2024 Outages in the current period.

For the year ended December 31, 2024, total product sales were unfavorable driven by sales price decreases of 16% for ammonia and 20% for UAN during the year.

Ammonia and UAN sales prices were unfavorable primarily due to lower natural gas prices reducing input costs and lower planted acres of corn in the U.S.

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For the year ended December 31, 2023, total product sales volumes were favorable, driven by reduced production volumes and utilization during the planned turnarounds at both fertilizer facilities in the third quarter of 2022, which subsequently improved operational reliability.

In addition, the fertilizer facilities experienced minimal unplanned downtime in 2023 compared to 2022 due to the Messer Outages at the Coffeyville Fertilizer Facility and various pieces of equipment being down at the East Dubuque Fertilizer Facility in 2022.

For the year ended December 31, 2023, total product sales were unfavorable driven by sales price decreases of 44% for ammonia and 36% for UAN.

Ammonia and UAN sales prices were unfavorable primarily due to lower natural gas prices and increased global supplies of nitrogen fertilizers.

Feedstock - Our Coffeyville Fertilizer Facility utilizes a pet coke gasification process to produce nitrogen fertilizer.

Our East Dubuque Fertilizer Facility uses natural gas in its production of ammonia.

The table below presents these feedstocks for both fertilizer facilities within the Nitrogen Fertilizer Segment for the years ended December 31, 2023, 2022, and 2021:

The table below presents these feedstocks for the Facilities for the years ended December 31, 2024, 2023, and 2022:

Year Ended December 31,

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Nitrogen Fertilizer Segment Financial Highlights

Overview - The Nitrogen Fertilizer Segment’s operating income and net income for the year ended December 31, 2023 were $201 million and $172 million, respectively, representing declines of $119 million and $115 million, respectively, compared to operating income and net income of $320 million and $287 million, respectively, for the year ended December 31, 2022.

These variances were primarily driven by decreased product sales prices, offset by increased production and sales volumes, compared to 2022.

Overview - For the year ended December 31, 2024, the Nitrogen Fertilizer Segment’s operating income and net income were $90 million and $61 million, respectively, compared to operating income and net income of $201 million and $172 million, respectively, for the year ended December 31, 2023.

These decreases were driven primarily by lower product sales prices attributable to natural gas prices reducing input costs and driving an overall decrease in market prices and unfavorable product sales volume driven by reduced production volumes resulting from the 2024 Outages in the current period, partially offset by favorable utility costs due to lower natural gas and electricity prices.

Net Sales Operating Income

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(1) See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown above.

Net Sales - The Nitrogen Fertilizer Segment’s net sales decreased by $155 million to $681 million for the year ended December 31, 2023 compared to the year ended December 31, 2022.

This decrease was primarily due to unfavorable UAN and ammonia pricing conditions which reduced revenue by $374 million, partially offset by increased sales volumes which contributed $210 million in higher revenue compared to the year ended December 31, 2022.

Net Sales - For the year ended December 31, 2024, net sales for the Nitrogen Fertilizer Segment was $525 million compared to $681 million for the year ended December 31, 2023.

This decrease was primarily due to unfavorable UAN and ammonia pricing conditions and sales volume which lowered revenues by $104 million and $47 million, respectively.

For the years ended December 31, 2024 and 2023, net sales included $36 million and $42 million in freight revenue and $16 million and $18 million in other revenue, respectively.

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Ammonia (26) (5)

For the year ended December 31, 2023 compared to the year ended December 31, 2022, ammonia and UAN sales prices were unfavorable primarily due to lower natural gas prices and increased global supplies of nitrogen fertilizers in the current year.

Total product sales volumes were favorable driven by reduced production volumes and utilization during the planned turnarounds at both fertilizer facilities in the third quarter of 2022, which subsequently improved operational reliability.

In addition, there was minimal unplanned downtime in 2023 compared to 2022 due to the Messer Outages at the Coffeyville Fertilizer Facility and various pieces of equipment being down at the East Dubuque Fertilizer Facility in 2022.

Cost of Materials and Other - Cost of materials and other for the year ended December 31, 2023 was $134 million, compared to $131 million for the year ended December 31, 2022.

The $3 million increase was driven primarily by higher third-party pet coke feedstock costs, partially offset by lower natural gas feedstock costs in the current period.

For the year ended December 31, 2024 compared to the year ended December 31, 2023, ammonia and UAN sales prices were unfavorable primarily due to lower natural gas prices reducing input costs and driving an overall decrease in market prices, paired with lower planted corn acres in the U.S.

Total product sales volumes were unfavorable driven by reduced production volumes resulting from the 2024 Outages in the current period.

Cost of Materials and Other - For the year ended December 31, 2024, cost of materials and other was $104 million compared to $134 million for the year ended December 31, 2023.

The decrease was driven primarily by lower pet coke and natural gas feedstock costs combined with favorable inventory impacts in the current period.

Direct Operating Expenses (exclusive of depreciation and amortization) - For the year ended December 31, 2024, direct operating expenses (exclusive of depreciation and amortization) were $214 million compared to $235 million for the year ended December 31, 2023.

The $35 million variance was primarily due to turnaround expenses in the prior period associated with the planned turnarounds taking place at both fertilizer facilities in the third quarter of 2022, coupled with decreased personnel costs from share-based compensation and lower natural gas and electricity costs in the current period.

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The decrease was primarily due to favorable utility costs due to lower natural gas and electricity prices combined with favorable inventory impacts in the current period.

Non-GAAP Measures

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These non-GAAP financial measures are important factors in assessing our operating results and profitability and include the performance and liquidity measures defined below.

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The following are non-GAAP measures we present for the years ended December 31, 2024, 2023, and 2022:

EBITDA - Consolidated net income (loss) before (i) interest expense, net, (ii) income tax expense (benefit) and (iii) depreciation and amortization expense.

Petroleum EBITDA and Nitrogen Fertilizer EBITDA - Segment net income (loss) before segment (i) interest expense, net, (ii) income tax expense (benefit), and (iii) depreciation and amortization.

Petroleum EBITDA, Renewables EBITDA, and Nitrogen Fertilizer EBITDA - Segment net income (loss) before segment (i) interest expense, net, (ii) income tax expense (benefit), and (iii) depreciation and amortization.

Refining Margin - The difference between our Petroleum Segment net sales and cost of materials and other.

Refining Margin, adjusted for Inventory Valuation Impacts - Refining Margin adjusted to exclude the impact of current period market price and volume fluctuations on crude oil and refined product inventories purchased in prior periods and lower of cost or net realizable value adjustments, if applicable.

We record our commodity inventories on the first-in-first-out basis.

As a result, significant current period fluctuations in market prices and the volumes we hold in inventory can have favorable or unfavorable impacts on our refining margins as compared to similar metrics used by other publicly-traded companies in the refining industry.

Refining Margin and Refining Margin adjusted for Inventory Valuation Impacts, per Throughput Barrel - Refining Margin and Refining Margin adjusted for Inventory Valuation Impacts divided by the total throughput barrels during the period, which is calculated as total throughput barrels per day times the number of days in the period.

Refining Margin per Throughput Barrel - Refining Margin divided by the total throughput barrels during the period, which is calculated as total throughput barrels per day times the number of days in the period.

Direct Operating Expenses per Throughput Barrel - Direct operating expenses for our Petroleum Segment divided by total throughput barrels for the period, which is calculated as total throughput barrels per day times the number of days in the period.

Adjusted EBITDA, Petroleum Adjusted EBITDA and Nitrogen Fertilizer Adjusted EBITDA - EBITDA, Petroleum EBITDA and Nitrogen Fertilizer EBITDA adjusted for certain significant noncash items and items that management believes are not attributable to or indicative of our on-going operations or that may obscure our underlying results and trends.

Renewables Margin - The difference between our Renewables Segment net sales and cost of materials and other.

Renewables Margin per Vegetable Oil Throughput Gallon - Renewables Margin divided by the total Vegetable oil throughput gallons for the period, which is calculated as total Vegetable oil throughput gallons per day times the number of days in the period.

Direct Operating Expenses per Vegetable Oil Throughput Gallon - Direct operating expenses for our Renewables Segment divided by total Vegetable oil throughput gallons for the period, which is calculated as total Vegetable oil throughput gallons per day times the number of days in the period.

Adjusted EBITDA, Petroleum Adjusted EBITDA, Renewables Adjusted EBITDA, and Nitrogen Fertilizer Adjusted EBITDA - EBITDA, Petroleum EBITDA , Renewables EBITDA , and Nitrogen Fertilizer EBITDA adjusted for certain significant noncash items and items that management believes are not attributable to or indicative of our on-going operations or that may obscure our underlying results and trends.

We present these measures because we believe they may help investors, analysts, lenders and ratings agencies analyze our results of operations and liquidity in conjunction with our U.S.

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Petroleum Segment

Our results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future due to capitalized expenditures as part of planned turnarounds.

Major Scheduled Turnaround Activities - Our results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future due to capitalized expenditures as part of planned turnarounds.

Total capitalized expenditures were $58 million, $60 million, and $81 million during the years ended December 31, 2024, 2023, and 2022, respectively.

The next planned turnarounds are currently scheduled to take place in the spring of 2024 at the Wynnewood Refinery at an estimated cost of $44 million and in 2025 at the Coffeyville Refinery.

The next planned turnaround is currently scheduled to commence in the first quarter of 2025 at the Coffeyville Refinery.

Midway Disposition - On December 23, 2024, a subsidiary of the Company sold the 50% Membership Interests it owned in Midway to Plains Pipeline, L.P.

in exchange for cash consideration of approximately $90 million.

The sale resulted in a gain of $24 million within Other income (expense), net in the Company’s Consolidated Statements of Operations.

December 31, 2024 | 75

Nitrogen Fertilizer Segment

Our results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future due to expenses incurred as part of planned turnarounds.

We incurred turnaround expenses of $2 million, $33 million, and $3 million during the years ended December 31, 2023, 2022, and 2021, respectively.

The next planned turnarounds are currently scheduled to take place in 2025 at the Coffeyville Fertilizer Facility and in 2026 at the East Dubuque Fertilizer Facility.

We incurred turnaround expenses of less than $1 million, $2 million, and $33 million during the years ended December 31, 2024, 2023, and 2022, respectively.

The next planned turnarounds are currently scheduled to commence in the fourth quarter of 2025 at the Coffeyville Fertilizer Facility and in 2026 at the East Dubuque Fertilizer Facility.

Non-GAAP Reconciliations

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Interest expense, net 77 52 85

Income tax expense (benefit) 207 157 (8)

Income tax (benefit) expense (26) 207 157

Depreciation and amortization

EBITDA 394 1,435 1,174

Revaluation of RFS liability (284) 135 63

Gain on marketable securities — — (81)

Unrealized (gain) loss on derivatives, net (32) 5 (16)

Revaluation of RFS liability, (favorable) unfavorable (89) (284) 135

Unrealized loss (gain) on derivatives, net 22 (32) 5

Inventory valuation impacts, unfavorable (favorable)

45 (24) (127)

Gain on sale of equity method investment (24) — —

Call Option Lawsuits settlement — — 79

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Petroleum EBITDA 223 1,185 905

Revaluation of RFS liability (284) 135 63

Unrealized (gain) loss on derivatives, net (30) 3 (16)

Revaluation of RFS liability, (favorable) unfavorable (89) (284) 135

Unrealized loss (gain) on derivatives, net 22 (30) 3

Inventory valuation impacts, unfavorable (favorable) (1)

32 (22) (127)

Gain on sale of equity method investment (24) — —

Petroleum Adjusted EBITDA $ 138 $ 903 $ 1,021

(1) The Petroleum Segment’s basis for determining inventory value under GAAP is FIFO.

Changes in crude oil prices can cause fluctuations in the inventory valuation of crude oil, work in process and finished goods, thereby resulting in a favorable inventory valuation impact when crude oil prices increase and an unfavorable inventory valuation impact when crude oil prices decrease.

The inventory valuation impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period.

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Reconciliation of Petroleum Segment Gross Profit to Refining Margin and Refining Margin Adjusted for Inventory Valuation Impact

Reconciliation of Petroleum Segment Gross Profit to Refining Margin

Year Ended December 31,

(in millions) 2023 2022 2021

(in millions, except throughput data) 2024 2023 2022

Net sales $ 6,920 $ 8,287 $ 9,919

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Refining margin $ 684 $ 1,658 $ 1,431

Inventory valuation impacts, unfavorable (favorable) (1)

32 (22) (127)

Refining margin, adjusted for inventory valuation impacts

$ 1,690 $ 1,409 $ 494

(1) The Petroleum Segment’s basis for determining inventory value under GAAP is FIFO.

The inventory valuation impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period.

In order to derive the inventory valuation impact per total throughput barrel, we utilize the total dollar figures for the inventory valuation impact and divide by the number of total throughput barrels for the period.

Reconciliation of Petroleum Segment Total Throughput Barrels and Metrics per Total Throughput Barrel

Year Ended December 31,

2023 2022 2021

Total throughput barrels per day 196,278 208,219 205,288

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Total throughput barrels 71,837,644 75,999,905 74,930,140

(in millions, except per total throughput barrel)

Refining margin $ 1,658 $ 1,431 $ 621

Refining margin per total throughput barrel $ 9.53 $ 21.82 $ 19.09

Refining margin, adjusted for inventory valuation impact $ 1,690 $ 1,409 $ 494

Refining margin adjusted for inventory valuation impact per total throughput barrel $ 22.24 $ 18.80 $ 6.48

Direct operating expenses (exclusive of depreciation and amortization) $ 406 $ 426 $ 369

Direct operating expenses per total throughput barrel 5.86 5.34 5.68

Reconciliation of Renewables Segment Net Loss to EBITDA and Adjusted EBITDA

Year Ended December 31,

(in millions) 2024 2023 2022

Renewables net loss $ (21) $ (36) $ (47)

Interest expense, net (1) (1) —

Depreciation and amortization 25 20 16

Renewables EBITDA 3 (17) (31)

Unrealized (gain) loss on derivatives, net — (2) 2

Inventory valuation, (favorable) unfavorable (1) (2)

Renewables Adjusted EBITDA $ 10 $ (5) $ (31)

(1) The Renewables Segment’s basis for determining inventory value under GAAP is FIFO.

Changes in renewable diesel and renewable feedstock prices can cause fluctuations in the inventory valuation of renewable diesel, work in process and finished goods, thereby resulting in a favorable inventory valuation impact when renewable diesel prices increase and an unfavorable inventory valuation impact when renewable diesel prices decrease.

The inventory valuation impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period.

(2) Includes an inventory valuation charge of $5 million and $4 million recorded in the fourth quarters of 2024 and 2023, respectively, as inventories were reflected at the lower of cost or net realizable value.

No adjustment was necessary for any other period in 2024, 2023, or 2022.

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Reconciliation of Renewables Segment Gross Loss to Renewables Margin

Year Ended December 31,

(in millions, except throughput data) 2024 2023 2022

Net sales $ 289 $ 559 $ 338

Cost of materials and other (245) (537) (342)

Direct operating expenses (exclusive of depreciation and amortization) (31) (28) (24)

Depreciation and amortization (25) (20) (16)

(12) (26) (44)

Direct operating expenses (exclusive of depreciation and amortization) 31 28 24

Depreciation and amortization 25 20 16

Renewables margin $ 44 $ 22 $ (4)

Total Vegetable oil throughput gallons per day 151,278 225,957 116,515

Days in the period 366 365 365

Total Vegetable oil throughput gallons 55,367,620 82,474,473 42,527,847

Renewables margin per Vegetable oil throughput gallon $ 0.80 $ 0.27 $ (0.10)

Direct operating expenses per Vegetable oil throughput gallon 0.57 0.35 0.55

Reconciliation of Nitrogen Fertilizer Segment Net Income to EBITDA and Adjusted EBITDA

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Our principal source of liquidity has historically been cash from operations.

Our principal uses of cash are for working capital, capital expenditures, funding our debt service obligations, and paying dividends to our stockholders, as further discussed below.

T he demand for refined products has returned to pre-COVID levels, and the supply impacts of refinery closures in the United States and globally have kept inventories of refined products at or below five-year average levels.

However, current geopolitical matters, such as the conflict between Israel and Hamas and the ongoing Russia-Ukraine war, pose significant risks to global markets and could contribute to further oil inventory tightening and price volatility, and disrupt the production and trade of fertilizer, grains, and feedstock supply through several means, including trade restrictions and supply chain disruptions.

While the volatility in commodity pricing has had a favorable impact on our business and has not significantly impacted our primary source of liquidity, there is still uncertainty on the horizon due to the potential for recession driven demand destruction and any potential implications of geopolitical matters.

We continue to maintain our focus on safe and reliable operations, maintain an appropriate level of cash to fund ongoing operations, and protect our balance sheet.

As a result of these factors, the Board elected to declare cash dividends of $0.50 per share for the first, second, third and fourth quarters of 2023 and special dividends equal to $1.00 and $1.50 per share for the second and third quarters of 2023, respectively.

These decisions support the Company’s continued focus on financial discipline through a balanced approach of evaluation of strategic investment opportunities and stockholder dividends while maintaining adequate capital requirements for ongoing operations throughout this environment of uncertainty.

The Board will continue to evaluate the economic environment, the Company’s cash needs, optimal uses of cash, and other applicable factors, and may elect to make additional changes to the Company’s dividend (if any) in future periods.

Additionally, in executing financial discipline, we have successfully implemented and are maintaining the following measures:

• Focused on maintaining adequate liquidity to help mitigate the potential impact of adverse government actions such as the EPA unlawfully denying SREs;

• Focused refining maintenance capital expenditures to only include those projects which are a priority to support continuing safe and reliable operations, or which we consider required to support future activities;

• Focused future capital allocation to high-return assets and opportunities that advance participation in the energy industry transformation;

• Continued to focus on disciplined management of operational and general and administrative costs.

When considering the market conditions and actions outlined above, we currently believe that our cash from operations and existing cash and cash equivalents, along with borrowings, as necessary, will be sufficient to satisfy anticipated cash requirements associated with our existing operations for at least the next 12 months.

However, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors including, but not limited to, rising material and labor costs, the costs associated with complying with the RFS’s outcome of litigation and other factors.

Additionally, our ability to generate sufficient cash from our operating activities and secure additional financing depends on our future operational performance, which is subject to general economic, political, financial, competitive, and other factors, some of which may be beyond our control.

Depending on the needs of our business, contractual limitations and market conditions, we may from time to time seek to issue equity securities, incur additional debt, issue debt securities, or redeem, repurchase, refinance, or retire our outstanding debt through privately negotiated transactions, open market repurchases, redemptions, exchanges, tender offers or otherwise,

As further discussed below, our principal uses of cash are for working capital, capital expenditures, funding our debt service obligations, and paying dividends to our stockholders.

We may also seek to secure additional liquidity to help mitigate the potential impact of adverse government actions such as the EPA denial of SREs.

Certain external factors, such as volatile commodity pricing, higher industry utilization, and oversupply have had an unfavorable impact on our business, especially on our Petroleum segment, and have negatively impacted cash from operations, our primary source of liquidity.

Operational issues at our facilities, including the fire incident at the Wynnewood Refinery in the second quarter of 2024 and weather-related external power outages at both refineries in the third quarter of 2024, have also contributed to the negative impact on our cash from operations.

In addition, uncertainty remains due to the potential for further demand destruction, increased supply of refined products from the startup of new refineries worldwide, the impacts of increasing electric vehicles and liquid natural gas and other improvements in fuel efficiencies, and potential implications of geopolitical matters and government regulatory actions.

The planned turnaround at the Coffeyville Refinery that started in January 2025 and is currently expected to be completed in approximately 45 days from commencement is an event that is scheduled to occur once every five years and supports our continued focus on safe and reliable operations, with a total estimated cash outlay of $175 million to $200 million.

As a result of these factors, the Board elected to suspend payment of the cash dividend in October 2024 and has implemented and are maintaining the following measures:

(1) The deferment of new growth capital spending;

December 31, 2024 | 78

but we are under no obligation to do so.

There can be no assurance that we will seek to do any of the foregoing or that we will be able to do any of the foregoing on terms acceptable to us or at all.

On September 26, 2023, CVR Partners and certain of its subsidiaries entered into Amendment No.

1 to the Credit Agreement (the “CVR Partners ABL Amendment”) with Wells Fargo Bank, National Association, a national banking associate (“Wells Fargo”), as administrative agent, collateral agent and a lender.

The CVR Partners ABL Amendment amended that certain Credit Agreement, dated as of September 30, 2021 (as amended by the CVR Partners ABL Amendment, the “CVR Partners ABL”), by and among the credit parties thereto and Wells Fargo, as administrative agent, collateral agent and a lender, to, among other things, (i) increase the aggregate principal amount available under the credit facility by an additional $15 million to a total of $50 million in the aggregate, with an incremental facility of an additional $15 million in the aggregate subject to additional lender commitments and certain other conditions, and (ii) extend the maturity date by an additional four years to September 26, 2028.

On December 21, 2023, CVR Energy completed the issuance of $600 million in aggregate principal amount of 8.50% Senior Notes due 2029 (the “2029 Notes”), which mature on January 15, 2029, unless earlier redeemed or purchased.

Interest on the 2029 Notes is payable semi-annually in arrears on February 15 and August 15 each year, commencing on February 15, 2024.

As of December 31, 2023, the net proceeds of the offering were reserved to fund the redemption of the Company’s outstanding 5.25% Senior Notes due 2025 (the “2025 Notes”).

On February 15, 2024, CVR Energy redeemed the outstanding 2025 Notes, at par, and settled accrued interest of approximately $16 million to the date of redemption.

(2) A reduction in capital expenditures for the fourth quarter of 2024 and certain capital expenditures through 2025 to only include those projects critical to continuing safe and reliable operations, environmental compliance projects or are required to support future activities.

Concurrently, the Company took the following actions to further enhance the Company’s liquidity:

(1) Entered into the Term Loan in the amount of $325 million, which has scheduled quarterly principal amortization payments in an amount equal to 0.25% of the aggregate principal amount of the initial term loans and maturity on December 30, 2027.

Refer to Part II, Item 8, Note 8 (“Long-Term Debt and Finance Lease Obligations”) of this Report for further discussion;

The Company and its subsidiaries were in compliance with all applicable covenants under their respective debt instruments as of December 31, 2023 and through the date of filing, as applicable.

We do not have any “off-balance sheet arrangements” as such term is defined within the rules and regulations of the SEC.

(2) Sold the 50% Membership Interests it owned in Midway for cash consideration of approximately $90 million;

(3) Entered into an Incremental Commitment Agreement for an amount of $70 million, which increased the total aggregate principal amount available under the CVR Energy ABL from $275 million to $345 million;

(4) Explored additional efforts to control costs.

These decisions support the Company’s focus on financial discipline to maintain adequate capital for ongoing operations throughout this environment of uncertainty.

The Board will continue to evaluate the economic environment, the Company’s cash needs, optimal uses of cash, payment of dividends (if any), and other applicable factors, and may elect to make additional changes to the Company’s capital allocation in future periods.

Depending on the needs of our business, contractual limitations, and market conditions, we may, from time to time, seek to issue equity securities, incur additional debt, issue debt securities, or redeem, repurchase, refinance, or retire our outstanding debt through privately negotiated transactions, open market repurchases, redemptions, exchanges, tender offers or otherwise.

There can be no assurance that we will seek to do any of the foregoing or that we will be able to do any of the foregoing on terms acceptable to us or at all.

We closely monitor the amounts and timing of our sources and uses of funds and the availability and borrowings, if any, under the CVR Energy ABL.

Our ability to incur additional indebtedness could be restricted by the terms of our existing Senior Notes, the CVR Energy ABL, as defined below, or the Term Loan.

Considering the market conditions and actions outlined above, we believe that our cash from operations and existing cash and cash equivalents, along with borrowings, as necessary, will be sufficient to satisfy anticipated cash requirements associated with our existing operations for at least the next 12 months.

Our future expenditures for turnaround, capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors including, but not limited to, rising material and labor costs, the costs associated with complying with the RFS and the outcome of litigation and other factors.

Additionally, our ability to generate adequate cash from our operating activities in the current commodity price environment, sell non-core assets, access capital markets, incur additional debt or take any other action to improve our liquidity is subject to the risks discussed above and elsewhere in our periodic reports and the other risks and uncertainties that exist in our industry, and depends on our future operational performance, which is subject to general economic, political, financial, competitive, and other factors, some of which may be beyond our control.

The Company and its subsidiaries were in compliance with applicable financial covenants under their respective debt instruments as of December 31, 2024 and through the date of filing of this Report, as applicable.

Cash Balances and Other Liquidity

As of December 31, 2023, we had total liquidity of approximately $869 million, not considering the $598 million of reserved funds to be utilized for the repayment of the 2025 Notes.

As of December 31, 2024, we had total liquidity of approximately $1.3 billion.

Total liquidity consists of $987 million of consolidated cash and cash equivalents, $238 million available under CVR Energy’s Amended and Restated ABL Credit Agreement (the “CVR Energy ABL”), and $39 million available under the CVR Partners ABL.

As of December 31, 2022, we had $510 million in cash and cash equivalents.

As of December 31, 2023, we had total liquidity of approximately $869 million, not considering the $598 million of reserved funds that were utilized for the repayment of CVR Energy’s 5.25% Senior Notes, due 2025 (the “2025 Notes”).

Total liquidity consisted of $581 million in cash and cash equivalents, $249 million available under the CVR Energy ABL, and $39 million available under the CVR Partners ABL.

December 31, 2024 | 79

Long-term debt consisted of the following:

(in millions) December 31, 2023 December 31, 2022

5.25% Senior Notes, due February 2025, net of current portion (1)

5.75% Senior Notes, due February 2028

(in millions) 2024 2023

8.50% Senior Notes, due January 2029

5.75% Senior Notes, due February 2028

Unamortized debt issuance costs (4) (5)

Total CVR Energy debt 996 995

Petroleum Segment:

Term Loan 322 —

Unamortized debt discount and debt issuance costs (8) —

Total Petroleum Segment debt

Nitrogen Fertilizer Segment:

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Total long-term debt, including current portion $ 1,861 $ 2,141

(1) On December 21, 2023, the Company delivered a notice of redemption to the holders of its 2025 Notes, that all outstanding amounts of the 2025 Notes, plus any accrued and unpaid interest to the redemption date, would be redeemed on February 15, 2024.

December 31, 2023 | 67

outstanding balance of the $600 million principal amount of the 2025 Notes was classified as short-term as of December 31, 2023.

On February 15, 2024, the 2025 Notes were paid in full, at par, plus accrued and unpaid interest to the redemption date.

As of December 31, 2023, CVR Energy has the 2025 Notes, the 5.75% Senior Notes, due 2028 (the “2028 Notes”), the 2029 Notes, and the CVR Energy ABL, the net proceeds of which may be used for general corporate purposes, which may include funding acquisitions, working capital and capital expenditures, share repurchases or distributions to our stockholders.

Refer to Part II, Item 8, Note 8 (“Long-Term Debt and Finance Lease Obligations”) of this Report for further discussion.

(1) On February 15, 2024, CVR Energy’s 5.25% Senior Notes, due 2025 (the “2025 Notes”) were redeemed in full, at par, plus accrued and unpaid interest to the redemption date.

As of December 31, 2024, CVR Energy has the 5.75% Senior Notes, due 2028 (the “2028 Notes”) and the 8.50% Senior Notes, due 2029 (the “2029 Notes”), the net proceeds of which may be used for general corporate purposes, which may include funding acquisitions, working capital and capital expenditures, share repurchases or distributions to our stockholders.

Petroleum Segment

As of December 31, 2024, the Petroleum Segment has the Term Loan and the CVR Energy ABL.

The net proceeds from the Term Loan will be used to fund capital expenditures, including turnaround initiatives.

The CVR Energy ABL supports working capital needs and liquidity for daily operations.

Nitrogen Fertilizer Segment

As of December 31, 2023, the Nitrogen Fertilizer Segment has the 6.125% Senior Secured Notes, due June 2028 (the “2028 UAN Notes”) and the CVR Partners ABL, the proceeds of which may be used to fund working capital and capital expenditures and for other general corporate purposes.

Refer to Part II, Item 8, Note 8 (“Long-Term Debt and Finance Lease Obligations”) of this Report for further discussion.

As of December 31, 2024, the Nitrogen Fertilizer Segment had outstanding its 6.125% Senior Secured Notes, due June 2028 (the “2028 UAN Notes”) and the CVR Partners ABL, the proceeds of which may be used to fund working capital and capital expenditures and for other general corporate purposes.

Refer to Part II, Item 8, Note 8 (“Long-Term Debt and Finance Lease Obligations”) of this Report for further discussions of these debt instruments.

Capital Spending

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Maintenance capital spending includes non-discretionary maintenance projects and projects required to comply with environmental, health, and safety regulations.

Growth capital projects generally involve an expansion of existing capacity and/or a reduction in direct operating expenses.

We undertake growth capital spending based on the expected return on incremental capital employed.

In November 2021, the Board approved the renewable feedstock pretreater project at the Wynnewood Refinery, which was mechanically completed in the fourth quarter of 2023 at a cost of $94 million.

Growth capital projects generally involve an expansion of existing capacity, reliability improvements, and/or a reduction in direct operating expenses.

We undertake growth capital spending based on the expected return on incremental capital employed, which is typically funded by reserves taken in prior years.

December 31, 2024 | 80

Our total capital expenditures for the year ended December 31, 2024, along with our estimated expenditures for 2025, by segment, are as follows:

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Petroleum $ 90 $ 38 $ 128 $ 70 $ 80 $ 35 $ 45 $ 105 $ 125

Renewables 3 8 11 3 5 1 2 4 7

Nitrogen Fertilizer 30 7 37 35 45 20 25 55 70

6 54 60 8 10 9 14 17 24

Other 4 1 5 — 2 1 1 1 3

Total $ 127 $ 54 $ 181 $ 108 $ 132 $ 57 $ 73 $ 165 $ 205

(1) Includes renewables spending for the Wynnewood Refinery’s renewable feedstock pretreater project.

As of December 31, 2023, Renewables does not meet the definition of a reportable segment as defined under Accounting Standards Codification Topic 280.

Our estimated capital expenditures are subject to change due to changes in the cost, scope, and completion time for capital projects.

For example, we may experience changes in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of the refineries or facilities.

We may also accelerate or defer some capital expenditures from time to time.

Capital spending for CVR Partners is determined by the UAN GP Board.

Our estimated capital expenditures are subject to further change due to changes in capital projects’ cost, scope, and completion time.

For example, we may experience labor or equipment cost changes necessary to comply with government regulations or to complete projects that sustain the operations of the refineries or facilities.

The UAN GP Board determines CVR Partners’ capital spending.

We will continue to monitor market conditions and make adjustments, if needed, to our current capital spending or turnaround plans.

We may also accelerate or defer some capital expenditures from time to time.

For example, as described further above, volatile commodity pricing and higher industry utilization and oversupply have had an unfavorable impact on our business and have negatively impacted our cash from operating activities and liquidity.

As a result, in October 2024, the Board elected to suspend payment of the cash dividend, defer new growth capital spending, and reduce certain expected capital expenditures, as further discussed under “Liquidity and Capital Resources” above.

The Petroleum Segment’s planned turnaround at the Wynnewood Refinery commenced in February 2024 and was completed in March 2024.

The planned turnaround at the Coffeyville Refinery commenced in January 2025 and is expected to be completed 45 days from commencement.

The Petroleum Segment’s total capitalized expenditures were $58 million, $60 million, and $81 million during the years ended December 31, 2024, 2023, and 2022, respectively.

The next planned turnarounds are currently scheduled to take place in the spring of 2024 at the Wynnewood Refinery at an estimated cost of $44 million and in 2025 at the Coffeyville Refinery.

The Nitrogen Fertilizer Segment incurred turnaround expenses of $2 million, $33 million, and $3 million during the years ended December 31, 2023, 2022, and 2021, respectively.

The next planned turnarounds are currently scheduled to take place in 2025 at the Coffeyville Fertilizer Facility and in 2026 at the East Dubuque Fertilizer Facility.

December 31, 2023 | 68

The Nitrogen Fertilizer Segment incurred turnaround expenses of less than $1 million, $2 million, and $33 million during the years ended December 31, 2024, 2023, and 2022, respectively.

The next planned turnarounds are currently scheduled to commence in the fourth quarter of 2025 at the Coffeyville Fertilizer Facility and in 2026 at the East Dubuque Fertilizer Facility.

Cash Requirements

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Finance lease obligations (3)

Other long-term liabilities (4)

Purchase commitments (5)

1 unchanged sentence

Total cash requirements $ 295 $ 3,323 $ 3,618

(1) Debt obligations consist of the 2025 Notes, 2028 Notes, 2029 Notes, and 2028 UAN Notes as of December 31, 2023.

On February 15, 2024, the 2025 Notes were redeemed in full, at par, plus accrued and unpaid interest to the redemption date.

(1) Debt obligations consist of the Term Loan, 2028 Notes, 2029 Notes, and 2028 UAN Notes as of December 31, 2024.

(2) Interest payments related to debt obligations consist of interest payments for our long-term debt outstanding as of December 31, 2024 and commitment fees on the unutilized commitments of the CVR Energy ABL and the CVR Partners ABL.

(3) Operating lease liabilities and finance lease obligations are described in Part II, Item 8, Note 6 (“Leases”) of this Report.

(4) Consists primarily of purchase obligations for pipeline storage and capacity, the supply of pet coke and other feedstocks, and water and utilities usage.

(4) Other long-term liabilities include obligations related to environmental liabilities.

Environmental liabilities represents our estimated payments required by federal and/or state environmental agencies.

See Part I, Item 1, “Environmental Matters”.

(5) Consists primarily of purchase obligations for pipeline storage and capacity, the supply of pet coke, oxygen, nitrogen, and other feedstocks, and water and utilities usage.

December 31, 2024 | 81

(6) Includes purchase obligations related to the transportation of feedstocks.

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IEP, through its ownership of the Company’s common stock, is entitled to receive dividends that are declared and paid by the Company based on the number of shares held at each record date.

The following tables present quarterly and special dividends paid to the Company’s stockholders, including IEP, during 2023 and 2022 (amounts presented in table below may not add to totals presented due to rounding):

The following table presents quarterly and special dividends paid to the Company’s stockholders, including IEP, during 2024, 2023, and 2022 (amounts presented in the table below may not add to totals presented due to rounding):

Quarterly Dividends Paid ( in millions )

7 unchanged sentences

August 19, 2024 0.50 17 33 50

Total 2024 quarterly dividends

$ 1.50 $ 51 $ 100 $ 151

2022 - 4th Quarter

March 13, 2023 $ 0.50 $ 15 $ 36 $ 50

2023 - 1st Quarter

May 22, 2023 0.50 15 36 50

2023 - 2nd Quarter

August 21, 2023 0.50 15 36 50

2023 - 3rd Quarter

2 unchanged sentences

$ 2.00 $ 61 $ 140 $ 201

Special Dividends Paid ( in millions )

Related Period Date Paid Special Dividends

Per Share Public Stockholders IEP Total

2023 - 2nd Quarter August 21, 2023 $ 1.00 $ 29 $ 71 $ 101

2023 - 3rd Quarter November 20, 2023 1.50 51 100 151

Total 2023 special dividends

$ 2.50 $ 80 $ 171 $ 251

December 31, 2023 | 69

Quarterly Dividends Paid ( in millions )

Related Period Date Paid Quarterly Dividends

Per Share Public Stockholders IEP Total

2022 - 1st Quarter

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$ 2.50 $ 80 $ 171 $ 251

There were no quarterly dividends declared or paid during the first quarter of 2022 related to the fourth quarter of 2021, and there were no quarterly dividends declared or paid during 2021 related to the first, second, and third quarters of 2021 and fourth quarter of 2020.

On May 26, 2021, the Company announced a special dividend of approximately $492 million, or equivalent to $4.89 per share of the Company’s common stock, to be paid in a combination of cash (the “Cash Distribution”) and the common stock of Delek US Holdings, Inc.

(“Delek”) held by the Company (the “Stock Distribution”).

On June 10, 2021, the Company distributed an aggregate amount of approximately $241 million, or $2.40 per share of the Company’s common stock, pursuant to the Cash Distribution, and approximately 10,539,880 shares of Delek common stock, which represented approximately 14.3% of the outstanding shares of Delek common stock, pursuant to the Stock Distribution.

IEP received approximately 7,464,652 shares of common stock of Delek and $171 million in cash.

The Stock Distribution was recorded as a reduction to equity through a derecognition of our investment in Delek, and the Company recognized a gain of $112 million from the initial investment in Delek through the date of the Stock Distribution.

For the fourth quarter of 2023, the Company, upon approval by the Board on February 20, 2024, declared a cash dividend of $0.50 per share, or $50 million, which is payable March 11, 2024 to shareholders of record as of March 4, 2024.

Of this amount, IEP will receive $33 million due to its ownership interest in the Company’s shares.

2022 - 2nd Quarter August 22, 2022 $ 2.60 $ 76 $ 185 $ 261

2022 - 3rd Quarter November 21, 2022 1.00 29 71 101

Total 2022 special dividends

$ 3.60 $ 106 $ 256 $ 362

There were no quarterly dividends declared or paid during the fourth quarter of 2024 related to the third quarter of 2024, and there were no quarterly dividends declared or paid during the first quarter of 2022 related to the fourth quarter of 2021.

No dividends were declared for the fourth quarter of 2024.

Distributions to CVR Partners ’ Unitholders

Distributions, if any, including the payment, amount and timing thereof, and UAN GP Board’s distribution policy, including the definition of available cash, are subject to change at the discretion of the UAN GP Board.

The following tables present quarterly distributions paid by CVR Partners to CVR Partners’ unitholders, including amounts received by the Company, as of December 31, 2023 and 2022 (amounts presented in tables below may not add to totals presented due to rounding):

The following tables

December 31, 2024 | 82

present quarterly distributions paid by CVR Partners to CVR Partners’ unitholders, including amounts received by the Company, during 2024, 2023, and 2022 (amounts presented in the table below may not add to totals presented due to rounding):

Quarterly Distributions Paid (in millions)

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$ 6.69 $ 44 $ 26 $ 71

December 31, 2023 | 70

Quarterly Distributions Paid (in millions)

Related Period Date Paid Quarterly Distributions

Per Common Unit Public Unitholders CVR Energy Total

2022 - 4th Quarter

8 unchanged sentences

$ 26.62 $ 178 $ 104 $ 281

Quarterly Distributions Paid (in millions)

Related Period Date Paid Quarterly Distributions

Per Common Unit Public Unitholders CVR Energy Total

2021 - 4th Quarter

March 14, 2022 $ 5.24 $ 36 $ 20 $ 56

2022 - 1st Quarter

May 23, 2022 2.26 15 9 24

2022 - 2nd Quarter

4 unchanged sentences

$ 19.32 $ 129 $ 75 $ 205

There were no quarterly distributions declared or paid by CVR Partners related to the first quarter of 2021 and the fourth quarter of 2020.

For the fourth quarter of 2024, CVR Partners, upon approval by the UAN GP Board on February 18, 2025, declared a distribution of $1.75 per common unit, or $18 million, which is payable March 10, 2025 to unitholders of record as of March 3, 2025.

Of this amount, CVR Energy will receive approximately $7 million, with the remaining amount payable to public unitholders.

Of this amount, CVR Energy and IEP will receive approximately $7 million and less than $1 million, with the remaining amount payable to public unitholders.

Capital Structure

On October 23, 2019, the Board authorized a stock repurchase program (the “Stock Repurchase Program”), which authorized the Company to repurchase up to $300 million of the Company’s common stock.

Repurchases under the Stock Repurchase Program could have been made from time-to-time through open market transactions, block trades, privately negotiated transactions or otherwise in accordance with applicable securities laws.

The timing, price and amount of repurchases (if any) were to be made at the discretion of management and were subject to market conditions as well as corporate, regulatory and other considerations.

The Stock Repurchase Program expired, in accordance with its terms, on October 22, 2023.

We did not repurchase any of our common stock under the Stock Repurchase Program.

On May 6, 2020, CVR Partners announced that the UAN GP Board, on behalf of CVR Partners, authorized a unit repurchase program (the “Unit Repurchase Program”), which was increased on February 22, 2021.

The Unit Repurchase Program, as increased, authorized CVR Partners to repurchase up to $20 million of CVR Partners’ common units.

During the year ended December 31, 2023, CVR Partners did not repurchase any common units.

During the years ended December 31, 2022 and 2021, CVR Partners repurchased 111,695 and 24,378 common units, respectively, on the open market in accordance with a repurchase agreement under Rules 10b5-1 and 10b-18 of the Securities Exchange Act of 1934, as amended, at a cost of $12 million and $1 million, respectively, exclusive of transaction costs, or an average price of $110.98 and $21.69 per common unit, respectively.

As of December 31, 2023, considering all repurchases made since inception of the Unit Repurchase Program, CVR Partners had a nominal authorized amount remaining under the Unit Repurchase Program.

This Unit Repurchase Program does not obligate CVR Partners to acquire any common units and may be cancelled or terminated by the UAN GP Board at any time.

On May 6, 2020, CVR Partners announced that the UAN GP Board, on behalf of CVR Partners, authorized a unit repurchase program, which was increased on February 22, 2021 (the “Unit Repurchase Program”).

The Unit Repurchase Program authorized CVR Partners to repurchase up to $20 million of CVR Partners’ common units.

On February 20, 2024, the UAN GP Board, on behalf of CVR Partners, terminated the nominal authority remaining under the Unit Repurchase Program.

From authorization through March 2022, CVR Partners repurchased, on a split-adjusted basis, 759,250 common units on the open market in accordance with a repurchase agreement under Rules 10b5-1 and 10b-18 of the Securities Exchange Act of 1934, as amended, at a cost of $20 million, exclusive of transaction costs, or an average price of $26.33 per common unit.

Prior to the termination of the Unit Repurchase Program in 2024 and for the year ended December 31, 2023, CVR Partners did not repurchase any common units.

December 31, 2024 | 83

6 unchanged sentences

Financing activities (482) (40) (696)

Net increase (decrease) in cash, cash equivalents, reserved funds and restricted cash $ 669 $ — $ (157)

Net (decrease) increase in cash, cash equivalents, reserved funds and restricted cash $ (199) $ 669 $ —

Operating Activities

The change in net cash provided by operating activities for the year ended December 31, 2023 compared to the year ended December 31, 2022 was driven primarily by a decrease in working capital of $262 million primarily associated with decreases in accrued liabilities, resulting from reduced RFS costs associated with decreased RINs prices coupled with increased RINs generation from ethanol and biodiesel blending, and accounts payable, partially offset by increases in inventory, primarily from temporary purchases due to changing the crude oil purchasing intermediary, and accounts receivable.

This variance was partially offset by a $234 million increase in net income during 2023 as a result of decreases in RFS compliance and utility costs offset by commodity price fluctuations, a litigation settlement expense in 2022, as well as a decrease in asset disposals of $9 million.

The change in net cash provided by operating activities for the year ended December 31, 2024 compared to the year ended December 31, 2023 was driven primarily by lower income from operations, offset by an increase in net changes from working capital items.

The decrease of $833 million in net income was primarily due to decreases in gasoline and distillate crack spreads, as well as decreased production caused by the Petroleum Unplanned Outages in 2024.

The lower activity in the current period was offset by favorable working capital changes of $403 million which were substantially attributable to the volatility in the RFS obligation in the prior period.

Investing Activities

The change in net cash used in investing activities for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to a decrease in our turnaround expenditures of $26 million in 2023 compared to 2022 related to the planned turnaround at the Wynnewood Refinery completed in 2022 and distributions from the CVR Partners’ equity method investment of $19 million associated with the 45Q Transaction.

This was partially offset by an increase in capital expenditures of $14 million resulting from fixed asset additions.

The change in net cash used in investing activities for the year ended December 31, 2024 compared to the year ended December 31, 2023 was primarily due to proceeds received from the sale of the Membership Interests contributing approximately $90 million, a decrease in capital expenditures of $26 million, received insurance proceeds of $10 million related to the Wynnewood Fire in the second quarter of 2024, and a decrease in turnaround expenditures of $4 million in 2024 compared to 2023.

This was partially offset by lower distributions from the CVR Partners’ equity method investment of $13 million associated with the 45Q Transaction during 2024.

Financing Activities

The change in net cash used in financing activities for the year ended December 31, 2023 compared to the year ended December 31, 2022 was primarily due to the Company’s December 2023 offering of $600 million principal amount of the 2029 Notes, decreases of $65 million and $12 million used for the redemption of the remaining balance of CVR Partners’ 9.25% Senior Notes due 2023 and unit repurchases of CVR Partners’ common units in 2022, respectively, with no corresponding amounts in 2023, and a decrease in dividends paid to CVR Energy stockholders of $30 million.

These changes were partially offset by an increase in distributions paid to CVR Partners’ noncontrolling interest holders of $49 million during 2023 compared to 2022.

The change in net cash used in financing activities for the year ended December 31, 2024 compared to the net cash used in financing activities for the year ended December 31, 2023 was primarily due to the $600 million redemption of the 2025 Notes in 2024 and the decrease in proceeds of $275 million from issuance of the Term Loan in 2024 compared to the 2029 Notes in 2023.

This was partially offset by a decrease in dividends paid to CVR Energy stockholders of $302 million and a decrease in distributions paid to CVR Partners’ noncontrolling interest holders of $134 million during 2024 compared to 2023.

Recent Accounting Pronouncements

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We compare the estimated realizable value of inventories to their cost by product at each of our facilities.

In our refining and renewables businesses, to determine the net realizable value of our inventories, we assume that crude oil and other feedstocks are converted into refined products, which requires us to make estimates regarding the refined products expected to be produced from those feedstocks and the conversion costs required to convert those feedstocks into refined products.

We also estimate the usual and customary transportation costs required to move the inventory from our plants to the appropriate points of sale, if material.

In our Petroleum and Renewables Segments, to determine the net realizable value of our inventories, we assume that crude oil and other feedstocks are converted into refined products, which requires us to make estimates regarding the refined products expected to be produced from those feedstocks and the costs required to convert those feedstocks into refined products.

We also estimate the usual and customary transportation costs required to move the inventory from our facilities to the appropriate points of sale, if material.

We then apply an estimated selling price to our inventories based primarily on actual prices observed subsequent to the end of the reporting period with any remaining volumes’ selling price estimated using indicative market pricing available as of the time the estimate is made.

For our nitrogen fertilizer business, depending on inventory levels, the per-ton realizable value of our fertilizer products is estimated using pricing on in-transit orders, pricing for open, fixed-price orders that have not shipped, and, if volumes remain unaccounted for, current management pricing estimates for fertilizer products.

Management’s estimate for current pricing reflects up-to-date pricing in each facility’s market as of the end of each reporting period.

In our Nitrogen Fertilizer Segment, depending on inventory levels, the per-ton realizable value of our fertilizer products is estimated using pricing on in-transit orders, pricing for open, fixed-price orders that have not shipped, and, if volumes remain unaccounted for, current management pricing estimates for fertilizer products.

Management’s estimate for current pricing reflects up-to-date pricing in each business’s market as of the end of each reporting period.

Reductions to selling prices for unreimbursed freight costs are included to arrive at net realizable value, as applicable.

If the net realizable value is less than cost, we recognize a loss for the difference in our statements of operations in the period in which it occurs.

During the year ended December 31, 2023, we recognized losses on inventory of $4 million to reflect net realizable value associated with our renewables business.

No amounts were recognized in 2022 and 2021.

During the years ended December 31, 2024 and December 31, 2023, we recognized losses on inventory of $5 million and $4 million to reflect net realizable value associated with our Renewables Segment.

No amounts were recognized in 2022.

Due to the amount and variability in volume of inventories maintained, changes in production costs, and the volatility of market pricing for our products, losses recognized to reflect inventories at the lower of cost or net realizable value could have a material impact on the Company’s results of operations.

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Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future expected cash flows.

If the sum of the undiscounted expected future cash flows of an asset group is less than the carrying value, including applicable liabilities, the carrying value is written down to its estimated fair value.

Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other assets (for example, at a refinery or fertilizer facility level).

If the sum of the undiscounted expected future cash flows of an asset group is less than the carrying value, including applicable liabilities, the carrying value may be written down to its estimated fair value.

In addition, when preparing the expected future cash flows or estimating the fair value of impaired assets, we make several estimates that include subjective assumptions related to future sales volumes, commodity prices, operating costs, discount rates, and capital expenditures, among others.

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

What changed 10-K

Item 7. Management’s Discussion and Analysis