What changed in this filing

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Item 7. Management’s Discussion and Analysis

2024-02-21 compared with 2023-02-22 · 339 added, 413 removed, 400 unchanged (65% of the section changed)

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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”).

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

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.

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

We also produce and market renewable diesel.

Our renewable diesel operations are not part of our reportable segments discussed below.

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:

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Renewables Business

Effective February 1, 2023, in connection with our growing focus on decarbonization, we transformed our business to segregate our renewables business.

As part of this transformation, in the first quarter of 2022, we formed 16 new indirect, wholly-owned subsidiaries (“NewCos”) of CVR Energy.

In addition, in April 2022, in connection with our Corporate Master Service Agreement effective January 1, 2020, by and among our wholly-owned subsidiary, CVR Services, LLC (“CVR Services”), and certain other of our subsidiaries, including but not limited to CVR Partners and its subsidiaries, pursuant to which CVR Services provides the service recipients thereunder with management and other professional services (the “Corporate MSA”), the NewCos were joined as service recipients under the Corporate MSA.

The Company also transferred certain assets to these NewCos to, among other purposes, better align our organizational structure with management, financial reporting, and our goal to maximize our renewables focus.

Potential Spin-Off of Nitrogen Fertilizer Business

On November 21, 2022, we announced that CVR Energy’s board of directors (the “Board”) had authorized management to explore a potential spin-off of our interest in the nitrogen fertilizer business into a newly created and separately traded public

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If completed, upon effectiveness of the potential spin-off transaction, CVR Energy stockholders would own shares of both CVR Energy, holding the refinery and renewables businesses, and a holding company, holding CVR Energy’s current ownership of the general partner interest in, and approximately 37% of the common units (representing limited partner interests) of CVR Partners.

If we proceed with the spin-off, it would be intended to be structured as a tax-free, pro-rata distribution to all of CVR Energy’s stockholders as of a record date to be determined by the Board.

Completion of any potential spin-off would be subject to various conditions, including final approval of our Board, and there can be no assurance that the potential spin-off will be completed in the manner described above, or at all.

We expect to incur significant costs in connection with exploring the potential spin-off transaction of our nitrogen fertilizer business into a newly created and separately traded public company.

Spin-off exploration costs include legal, accounting, and advisory fees, implementation and integration costs, duplicative costs for subscriptions and information technology systems, employee and contractor costs, and other incremental separation costs related to the potential spin-off of the nitrogen fertilizer business.

The potential spin-off transaction results in operating expenses that would not otherwise have been incurred by us in the normal course of our organic business operations, and we expect to incur additional spin-off exploration costs in future periods.

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.

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 have outlined the following strategic objectives to drive the accomplishment of our mission:

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• Environmental, Health & Safety (“EH&S”) - We aim to achieve continuous improvement in all EH&S areas through ensuring our people’s commitment to environmental, health and safety comes first, the refinement of existing policies, continuous training, and enhanced monitoring procedures.

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

From the beginning of the fiscal year through the date of filing, we successfully executed a number of achievements in support of our strategic objectives shown below:

Safety Reliability Market Capture Financial Discipline

Achieved reduction in total recordable incident rate of 63% compared to 2021

Declared a quarterly cash dividend of $0.50 per share for the fourth quarter of 2022, bringing total dividends declared, including special dividends, to date of $5.30 per share related to 2022

Completed plan to transform our business to segregate our renewables operations ü ü

Safely completed the conversion of the Wynnewood hydrocracker to renewable diesel service ü ü ü

Began the exploration of a potential spin-off of our Nitrogen Fertilizer business ü ü

Published our first external ESG Report for 2021 ü ü

Petroleum Segment:

Achieved a reduction in total recordable incident rate of 20% and maintained a level number of environmental events compared to 2021

Operated our refineries safely and reliably ü ü

Safely completed the planned turnaround at the refinery in Wynnewood, Oklahoma (the “Wynnewood Refinery”) on time and on budget

Completed an amendment and extension of the CVR Refining, LP (“CVR Refining”) Asset Based Credit Agreement in June 2022 ü

Achieved record truck-gathered crude oil volumes in the third quarter of 2022

Nitrogen Fertilizer Segment:

Achieved reductions in process safety management tier 1 incidents and total recordable incident rate of 37% and 86%, respectively, compared 2021

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.

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Safety Reliability Market Capture Financial Discipline

Safely completed the planned turnarounds at both fertilizer facilities on time and on budget, as well as inspected, repaired and replaced major equipment as necessary during this downtime ü ü ü ü

Achieved record UAN production volumes at the Coffeyville Fertilizer Facility in March 2022

Achieved record ammonia production at the East Dubuque Fertilizer Facility in December 2022

Completed transaction intended to monetize 45Q tax credits and received an initial upfront payment, net of expenses, of $18 million in January 2023

Declared cash distribution of $10.50 per common unit for the fourth quarter of 2022, bringing cumulative distributions declared to date of $24.58 per common unit related to 2022

Achieved average reduction in CO 2 e emissions of over 1 million metric tons per year since 2020 for CVR Partners

Completed CVR Partners’ targeted $95 million debt reduction plan with the repayment of the remaining $65 million balance of its 9.25% Senior Secured Notes, due 2023 (the “2023 UAN Notes”) in the first quarter of 2022 for a total reduction in annual cash interest expense of approximately $9 million

Repurchased over 111,000 CVR Partners common units for $12 million

Environmental, Social & Governance (“ESG”) Highlights

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

In December 2022, we published our first public report based on the Sustainability Accounting Standards Board standards.

Our 2021 Environmental, Social & Governance Report (“2021 ESG Report”) is available at CVR Energy’s website at www.CVREnergy.com.

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.

Our 2022 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

Russia-Ukraine Conflict and Global Market Conditions - In February 2022, Russia invaded Ukraine, disrupting the global oil, fertilizer, and agriculture markets, and leading to heightened uncertainty in the worldwide economy recovering from the COVID-19 pandemic.

In response, many countries have formally or informally adopted sanctions on a number of Russian exports, including Russian oil and natural gas, and individuals affiliated with Russian government leadership.

These sanctions resulted in oil price volatility and elevated natural gas prices during 2022, and should continue to impact commodity prices in the near-term, which could have a material effect on our financial condition, cash flows, or results of operations.

A global recession stemming from market volatility and higher price levels could result in demand destruction.

The ultimate outcome of the Russia-Ukraine conflict and any associated market disruptions, as well as the potential for high inflation and/or economic recession, are difficult to predict and may materially affect our business, operations, and cash flows in unforeseen ways.

COVID-19 - The economic effects from the COVID-19 pandemic on our business were and may again be significant.

Although our business has recovered since the onset of the pandemic in March 2020, there continues to be uncertainty and unpredictability about the lingering impacts to the worldwide economy, including in connection with the spread of variants of COVID-19 and resulting restrictions, that could negatively affect our business, financial condition, results of operations , and liquidity in future periods.

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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.

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.

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 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 regulation.

Because the Petroleum Segment applies first-in first-out accounting to value its inventory, crude oil price movements may impact net income because of changes in the value of its unhedged inventory.

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.

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• 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, refined product demand declined 5% nationwide in January 2023 from the 2022 average.

However, distillate crack spreads have remained elevated to date in 2023.

• Warmer winter weather in Europe has significantly reduced natural gas prices in the region from December 2022 to January 2023, which has flattened the global cost curve and has hurt U.S.

refiners’ advantage.

• Contributing to the ultra-low sulfur diesel (“ULSD”) supply constraints is the International Maritime Organization’s new 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.

• Due to the IMO 2020 Regulations, heavy crude differentials have widened, particularly for WCS.

However, the expansion of the Trans Mountain Pipeline currently expected to be completed in 2023 should potentially narrow this differential going forward.

• Shale oil production continues to increase in the shale oil basins, including the Anadarko Basin.

Crude oil exports peaked in the fourth quarter of 2022 at over 5 million bpd, and we believe the Petroleum Segment benefits from these exports through the Brent crude differential to WTI, as well as all refineries in PADD II.

• Drilled but uncompleted wells inventory in the United States has decreased significantly as a result of decreased drilling activity in 2022.

• Significant capacity additions are expected in 2023, headlined by major projects scheduled to start up in the Middle East, Asia, and Africa.

Some of the capacity additions could be offset with a likely economic rebound in China amid easing COVID-19 restrictions but refined product consumption is slowing in the United States and remains weak in Europe.

• The Russia-Ukraine conflict creates additional uncertainty, as sanctions on Russian oil exports, specifically diesel exports, have significantly influenced commodity markets in 2022 and into 2023.

Resolution of this conflict could continue to affect markets going forward.

Based on these factors, current inventory levels have remained low, particularly for distillate, with the days of supply for distillate and jet fuel at approximately 3.8 and 6.1 days,

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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respectively, below the seasonally adjusted five-year averages.

Furthermore, planned and unplanned outages at domestic refineries are continuing to contribute to further inventory tightening and volatility.

• 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.

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.

• 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.

In June 2023, the Environmental Protection Agency (“EPA”) set the D4 RVO for 2023, 2024, and 2025 at 2.82, 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.

In 2022, miles per gallon of the new auto fleet continued to increase, averaging 26 miles per gallon (“MPG”).

The EPA expects the new fleet average to increase in 2023 by approximately 1 MPG.

Vehicle miles traveled continues to increase but the effect of electric vehicle (“EV”) penetration in the fleet is clear and present.

We expect this trend to continue.

Regulatory Environment

• We continue to be impacted by significant volatility and excessive RIN prices related to compliance requirements under the Renewable Fuel Standard (“RFS”), proposed climate change laws, and regulations.

Coffeyville Resources & Marketing, LLC (“CRRM”) and Wynnewood Refining Company, LLC (“WRC” and, together with CRRM, the “obligated-party subsidiaries”), are subject to the RFS, which, each year, absent exemptions or waivers, requires blending “renewable fuels” with transportation fuels or purchasing renewable identification numbers (“RINs”), in lieu of blending, or otherwise be subject to penalties.

Our cost to comply with the RFS is dependent upon a variety of factors, which include the availability of ethanol and biodiesel for blending at our refineries and downstream terminals or RINs for purchase, the price at which RINs can be purchased, transportation fuel and renewable diesel production levels, and the mix of our products, 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 depend on the consistent and timely application of the program by the Environmental Protection Agency (“EPA”), such as timely establishment of the annual renewable volume obligation (“RVO”).

RIN prices have been highly volatile and remain high due in large part to the EPA’s unlawful failure to establish the 2021, 2022, and 2023 RVOs by their respective statutory deadlines, the EPA’s delay in issuing decisions on pending small refinery hardship petitions, and subsequent denial thereof.

The price of RINs has also been impacted by market factors and the depletion of the carryover RIN bank, as demand destruction during the COVID-19 pandemic resulted in reduced ethanol blending and RIN generation that did not keep pace with mandated volumes, requiring carryover RINs from the RIN bank to be used to settle blending obligations.

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 2021 and remained significant in 2022.

• In April 2022, the EPA denied 36 small refinery exemptions (“SRE”) for the 2018 compliance year, many of which had been previously granted by the EPA, and also issued an alternative compliance demonstration approach for certain small refineries (the “Alternate Compliance Ruling”) under which they would not be required to purchase or redeem additional RINs as a result of the EPA’s denial.

On June 3, 2022, the EPA revised the 2020 RVO and finalized the 2021 and 2022 RVOs.

The EPA also denied 69 petitions from small refineries seeking SREs, including those submitted by WRC for 2017 through 2021, and applied the Alternate Compliance Ruling to three such petitions.

The price of RINs did not respond to the EPA announcement and continues to remain elevated, and as a result, we continue to expect significant volatility in the price of RINs during 2023 and such volatility could have material impacts on the Company’s results of operations, financial condition and cash flows.

• In December 2022, the EPA announced proposed RVO’s for 2023, 2024, and 2025 which mandated biodiesel RINs production to comply with ethanol RINs mandates.

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.

• 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.

• 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

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67% by 2032 to meet the requirements.

In the United States in 2023, approximately 7.6% of new-vehicle sales were EVs.

Company Initiatives

• In April 2022, we completed the renewable diesel project at our Wynnewood Refinery by converting the Wynnewood Refinery’s hydrocracker to a RDU, at a total cost of $179 million, which is capable of producing approximately 100 million gallons of renewable diesel per year and generating approximately 170 to 180 million RINs annually.

The production of renewable diesel is expected to significantly reduce our future net exposure to the RFS.

Further, the RDU has enabled us to capture additional benefits associated with the existing blenders’ tax credit, which has been extended to the end of 2024, and growing Low Carbon Fuel Standard (“LCFS”) programs across the country, with programs in place in California and Oregon and new programs anticipated to be implemented over the coming years.

• In November 2021, the Board approved the pretreater project at the Wynnewood Refinery, which is currently expected to be completed in the third quarter of 2023 at an estimated cost of $95 million.

The pretreatment unit should 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.

When completed, the collective renewable diesel efforts could effectively mitigate a substantial majority, if not all, of our future RFS exposure, assuming we receive SREs for our Wynnewood Refinery which we believe we are legally entitled to and are pursuing in the courts.

• 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.

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As of December 31, 2022, we have an estimated open position (excluding the impacts of any exemptions or waivers to which we may be entitled) under the RFS for 2020, 2021 and 2022 of approximately 397 million RINs, excluding approximately 34 million of net open, fixed-price commitments to purchase RINs, resulting in a potential liability of $692 million.

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.

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 2022 and 2023, could impact our RFS expense from period to period.

We recognized expense of approximately $435 million, net of the RINs generated from our renewable diesel operations of $103 million, and $435 million for the years ended December 31, 2022 and 2021, respectively, for the Company’s obligated-party subsidiaries compliance with the RFS.

The increase in 2022 compared to 2021 was driven by an increase in RINs pricing through the fourth quarter of 2022.

Of the expense recognized during the years ended December 31, 2022 and 2021, an expense of $135 million and $63 million relates to the revaluation of our net RVO position as of December 31, 2022 and 2021, respectively.

The revaluation represents the summation of the prior period obligation and current period commercial activities, marked at the period end market price.

Based upon recent market prices of RINs in January 2023, current estimates related to other variable factors, including our anticipated blending and purchasing activities, and the impact of the open RFS positions and resolution thereof, our estimated consolidated cost to comply with the RFS (without regard to any SREs the obligated-party subsidiaries may receive) is $230 to $240 million for 2023, net of the estimated RINs generation from our renewable diesel operations of $240 to $250 million.

Market Indicators

NYMEX WTI crude oil is an industry wide benchmark that is utilized in the market pricing of a barrel of crude oil.

The pricing differences between other crudes 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 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 will continue to be volatile.

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.

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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.

Both NYMEX 2-1-1 and Group 3 2-1-1 crack spreads increased during 2022 compared to 2021.

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Both NYMEX 2-1-1 and Group 3 2-1-1 crack spreads decreased during 2023 compared to 2022.

The NYMEX 2-1-1 crack spread averaged $34.24 per barrel in 2023 compared to $42.60 per barrel in 2022.

The Group 3 2-1-1 crack spread averaged $32.27 per barrel in 2023 compared to $38.18 per barrel in 2022.

Average monthly prices for RINs increased 12.4% during 2022 compared to 2021.

Average monthly prices for RINs decreased 7.8% during 2023 compared to 2022.

On a blended barrel basis (calculated using applicable RVO percentages), RINs approximated $6.95 per barrel during 2023 compared to $7.54 per barrel during 2022.

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The tables below are presented, on a per barrel basis, by month through December 31, 2023:

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

Group 3 Differential against NYMEX

WTI (1)(2) ( $/bbl )

Group 3 Product Differential against NYMEX

Products (1)(2) ( $/bbl )

(1) The change over time in NYMEX - WTI, as reflected in the charts above, is illustrated below.

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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.

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Nitrogen Fertilizer Segment

Within the Nitrogen Fertilizer Segment, earnings and cash flows from operations are primarily affected by the relationship between nitrogen fertilizer product prices, utilization, and operating costs and expenses, including pet coke and natural gas feedstock costs.

The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the global supply and demand for nitrogen fertilizer products which, in turn, depends on, among other factors, world grain demand and production levels, inflation, global supply disruptions, changes in world population, the cost and availability of fertilizer transportation infrastructure, local market conditions, operating levels of competing facilities, weather conditions, the availability of imports, the availability and price of feedstocks to produce nitrogen fertilizer, impacts of foreign imports and foreign subsidies thereof, and the extent of government intervention in agriculture markets.

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

The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the global supply and demand for nitrogen fertilizer products, which, in turn, depends on world grain demand and production levels, changes in world population, the cost and availability of fertilizer transportation infrastructure, weather conditions, the availability of imports, the availability and price of feedstocks to produce nitrogen fertilizer, and the extent of government intervention in agriculture markets, among other factors.

These factors can impact, among other things, the level of inventories in the markets, resulting in price and product margin volatility.

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

As a result of the Russian invasion of Ukraine, the Black Sea, a major export point for nitrogen fertilizer and grains from these countries, has been closed to exports, which prompted tightening global supply conditions for nitrogen fertilizer in advance of spring planting and wheat and corn availability, two major exports from this region.

Further, while fertilizers have not been formally sanctioned by countries, many customers are either unwilling to purchase Russian fertilizers or logistics make it too costly to import these fertilizers.

Additionally, natural gas supplied from Russia to Western Europe has been constrained, and natural gas prices have remained elevated since September 2021, causing a significant portion of European nitrogen fertilizer production capacity to be curtailed or costs to be elevated compared to competitors in other regions of the world.

Overall, these events have caused grain and fertilizer prices to rise, and we currently expect these conditions to persist through the spring of 2023.

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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.

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 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

While there is risk of shorter-term volatility given the inherent nature of the commodity cycle, the Company believes the long-term fundamentals for the U.S.

While there is risk of shorter-term volatility given the inherent nature of the commodity cycle and governmental and geopolitical risks, the Company believes the long-term fundamentals for the U.S.

nitrogen fertilizer industry remain intact.

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Corn crops result in the depletion of the amount of nitrogen within the soil in which it is grown, which in turn, results in the need for this nutrient to be replenished after each growing cycle.

Unlike corn, soybeans are able to obtain most of their own nitrogen through a process known as “N fixation.” 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 evident by the chart presented below for 2022, 2021, and 2020.

Unlike corn, soybeans are able to obtain most of their own nitrogen through a process known as “N fixation”.

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.

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 11.6 billion pounds of soybean oil is expected to be used in producing cleaner renewables in marketing year 2022/2023.

Multiple refiners have announced renewable diesel expansion projects for 2023 and beyond, which will only increase the demand for soybeans and potentially for corn and canola.

The United States Department of Agriculture (“USDA”) estimates that in spring 2022 farmers planted 88.6 million acres of corn, representing a decrease of 5.1% in corn acres planted as compared to 93.4 million corn acres in 2021.

Planted soybean acres were estimated to be 87.5 million acres, representing a 0.3% increase in soybean acres planted as compared to 87.2 million soybean acres in 2021.

The estimated combined corn and soybean planted acres of 176.1 million in 2022 is a 2.5% decrease from the total acreage planted in 2021, which was the highest in history.

Due to higher input costs for corn planting and increased demand for soybeans, particularly for renewable diesel production, it was more favorable for farmers to plant soybeans compared to corn.

The lower planted corn acres in 2022 and lower corn production are expected to be supportive of corn prices for 2023.

Ethanol is blended with gasoline to meet renewable fuel standard requirements and for its octane value.

Since 2006, ethanol production has consumed approximately 36% of the U.S.

corn crop, so demand for corn generally rises and falls with ethanol demand, as evidenced in the charts below.

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.

Multiple refiners have announced renewable diesel expansion projects for 2024 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.

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.

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, 2023.

Plant Production of Fuel Ethanol (1)

Corn and Soybean Planted Acres (2)

(1) Information used within this chart was obtained from the EIA through December 31, 2022.

(1) Information used within this chart was obtained from the U.S.

Energy Information Administration (“EIA”) through December 31, 2023.

(2) Information used within this chart was obtained from the USDA, National Agricultural Statistics Services, as of December 31, 2023.

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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 United States, 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 Russia-Ukraine conflict, prices for grains and fertilizers are expected to remain elevated through the spring of 2023.

While the weather conditions were difficult early in spring 2022, farmers were able to complete the crop planting later than normal.

Demand for nitrogen fertilizer, as well as other crop inputs, was strong for the spring 2022 planting season.

During the summer 2022 growing season, severe drought conditions were experienced in Asia, Europe, and parts of the U.S.

As a result, crop yields are projected to be below expectations and grain inventories are projected to be at the low end of historical levels, causing grain prices to rise.

We expect tight grain inventories to positively impact planted acreage for the spring of 2023 and boost the demand for nitrogen fertilizer.

On June 30, 2021, CF Industries Nitrogen, L.L.C., Terra Nitrogen, Limited Partnership, and Terra International (Oklahoma) LLC filed petitions with the U.S.

Department of Commerce (“USDOC”) and the U.S.

International Trade Commission (the “ITC”) requesting the initiation of antidumping and countervailing duty investigations on imports of UAN from Russia and Trinidad and Tobago (“Trinidad”).

On July 18, 2022, the ITC made a negative final injury determination concerning its investigation of imports from Russia and Trinidad despite USDOC’s final determination in June that UAN is subsidized and dumped in the U.S.

market by producers in both countries.

Since the decision in July 2022, we have observed minimal impact on the supply or demand for nitrogen fertilizer as a result of these actions.

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.

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.

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The charts below show relevant market indicators for the Nitrogen Fertilizer Segment by month through December 31, 2023:

Ammonia and UAN Market Pricing (1)

Natural Gas and Pet Coke Market Pricing (1)

Natural Gas Market Pricing (1)

Pet Coke Market Pricing (1)

(1) Information used within these charts was obtained from various third-party sources including Green Markets (a Bloomberg Company), Pace Petroleum Coke Quarterly, and the EIA, amongst others.

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Consolidated Financial Highlights

Operating Income (Loss)

Net Income (Loss) Attributable to CVR Energy Stockholders

Earnings (Loss) per Share

Operating Income

Net Income Attributable to CVR Energy Stockholders

Earnings per Share

(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 $746 million within the Petroleum Segment and $186 million within the Nitrogen Fertilizer Segment for the year ended December 31, 2022 compared to December 31, 2021.

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.

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

Investment Income on Marketable Securities - On June 10, 2021, the Company distributed substantially all of its holdings in Delek US Holdings, Inc.

(“Delek”) (NYSE:

DK), of which the Company was the largest stockholder holding approximately 14.3% of Delek’s outstanding common stock, as part of a special dividend.

On January 18, 2022, the Company divested its remaining nominal holdings in Delek, and as of December 31, 2022, the Company did not hold an investment in other marketable securities of Delek.

There was no dividend income received during the years ended December 31, 2022 and 2021.

The Company did not recognize a gain or loss on the investment during the year ended December 31, 2022 compared to a recognized gain of $81 million for the year ended December 31, 2021.

Other Income (Expense), Net - The Company’s Other income (expense), net, was $14 million for the year ended December 31, 2023 compared to $(77) million for the year ended December 31, 2022.

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

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Other Income (Expense), Net - The Company’s Other (expense) income, net, was an expense of $77 million for the year ended December 31, 2022 compared to income of $15 million for the year ended December 31, 2021.

The change was primarily attributable to the settlement of litigation.

Refer to Part II, Item 8, Note 11 (“Commitments and Contingencies”) of this Report for further discussion of this settlement.

Income Tax Expense (Benefit) - The income tax expense for the year ended December 31, 2022 was $157 million, or 19.6% of income before income taxes, as compared to income tax benefit for the year ended December 31, 2021 of $8 million, or (12.4)% of income before income taxes.

The fluctuation in income tax expense was due primarily to an increase in overall pretax earnings and state income tax expense.

In addition, the change in the effective tax rate was due primarily to the changes in pretax earnings attributable to noncontrolling interests and an increase in state income tax expense.

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.

Petroleum Segment

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DJ Basin 20,342 15,607 17,980

Bakken 978 — —

Other feedstocks and blendstocks 13,490 11,556 10,788

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43.3 % 42.9 % 43.7 %

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

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

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

Petroleum Segment Financial Highlights

Overview - Petroleum Segment operating income and net income for the year ended December 31, 2022 were $719 million and $759 million, respectively, an improvement of $746 million and $755 million, respectively, compared to an operating loss and net income of $27 million and $4 million, respectively, for the year ended December 31, 2021.

The improvement in both operating income and net income compared to the prior period was primarily a result of favorable refining margins resulting from improved crack spreads pricing in the current period, partially offset by increased RFS compliance costs.

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)

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Net Income (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, 2022, net sales for the Petroleum Segment increased by $3.2 billion when compared to the year ended December 31, 2021.

The increase in net sales was due to increased prices resulting from tight inventory levels and the ongoing Russia-Ukraine conflict for the year ended December 31, 2022 compared to the year ended December 31, 2021.

Further, net sales in 2021 were impacted by Winter Storm Uri, resulting in reduced production rates at both refineries.

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.

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, 2023 compared to the year ended December 31, 2022.

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

Refining Margin (1)

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

Refining Margin - For the year ended December 31, 2022, refining margin was $1.4 billion, or $19.09 per throughput barrel, as compared to $621 million, or $8.14 per throughput barrel, for the year ended December 31, 2021.

The increase in refining margin of $810 million was primarily due to an increase in product crack spreads.

The Group 3 2-1-1 crack spread increased by $20.04 per barrel relative to the year ended December 31, 2021 driven by tight inventory levels, increased European demand for diesel, and supply concerns due to the ongoing Russia-Ukraine conflict.

Offsetting these impacts for the year ended December 31, 2022, throughput volumes declined by 3,796 bpd due to the Wynnewood turnaround in the first quarter of 2022, the startup of the RDU limiting crude unit capacity, and minor plant outages during 2022.

This was combined

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;

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with favorable inventory valuation impacts totaling $22 million, or $0.29 per total throughput barrel, compared to favorable inventory valuation impacts of $127 million, or $1.66 per total throughput barrel, in 2021.

While impacts were favorable, the decline in inventory valuation impacts year over year was a result of crude oil price increases in the prior year exceeding crude oil price increases in 2022.

The Petroleum Segment’s obligated-party subsidiaries recognized costs to comply with RFS of $403 million, or $5.38 per throughput barrel, which excludes the RINs revaluation expense impact of $135 million, or $1.80 per total throughput barrel, for the year ended December 31, 2022.

This is compared to RFS compliance costs of $372 million, or $4.87 per throughput barrel, which excludes the RINs revaluation expense impact of $63 million, or $0.83 per total throughput barrel, for the year ended December 31, 2021.

For the year ended December 31, 2022, the Petroleum Segment’s RFS compliance costs included $103 million of RINs purchased from our renewable diesel operations.

The increase in both RFS compliance costs and RINs revaluation in 2022 was primarily related to increased RINs prices for the year ended December 31, 2022 compared to the prior period.

This was combined with derivative losses of $47 million recognized during the year ended December 31, 2022, a result of unfavorable crack spread swaps, partially offset by gains on WCS sales, compared to derivative losses of $45 million recognized during the year ended December 31, 2021, also a result of unfavorable crack spread swaps, partially offset by gains on WCS sales.

• 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.

Direct Operating Expenses (1)

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Direct Operating Expenses (Exclusive of Depreciation and Amortization) - For the year ended December 31, 2023, direct operating expenses (exclusive of depreciation and amortization) were $406 million compared to $426 million for the year ended December 31, 2022.

The increase in the current period was primarily due to personnel costs, repairs and maintenance expense, electricity costs, and natural gas costs.

On a total throughput barrel basis, direct operating expenses increased to $5.68 per barrel from $4.83 per barrel, as a function of the increased expense in 2022, compounded by the decrease in total throughput in 2022 compared to 2021 caused by the Wynnewood turnaround in the first quarter of 2022, the startup of the RDU in the second quarter of 2022, and minor plant outages during 2022.

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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, 2022, depreciation and amortization expense decreased $16 million compared to the year ended December 31, 2021, primarily due to assets being fully depreciated in 2021 and early 2022.

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.

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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 increase was primarily a result of increased personnel costs, driven primarily by increased share-based and incentive-based compensation, and loss on asset disposals in 2022 as compared to 2021.

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.

Nitrogen Fertilizer Segment

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

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

Utilization is presented solely on ammonia production, rather than each nitrogen product, as it provides a comparative baseline against industry peers and eliminates the disparity of facility configurations for upgrade of ammonia into other nitrogen products.

Utilization is presented solely on ammonia production, rather than on each nitrogen product, as it provides a comparative baseline against industry peers and eliminates the disparity of facility configurations for upgrade of ammonia into other nitrogen products.

With production primarily focused on ammonia upgrade capabilities, we believe this measure provides a meaningful view of how we operate.

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

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

Production for the year ended December 31, 2022 was impacted by unplanned downtime associated with the Messer air separation plant (the “Messer Outages”) at the Coffeyville Fertilizer Facility and various pieces of equipment at the East Dubuque Fertilizer Facility in 2022, along with the completion of the planned turnarounds at both

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fertilizer facilities during the third quarter of 2022.

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.

The table below presents all of these Nitrogen Fertilizer Segment metrics for the years ended December 31, 2023, 2022, and 2021:

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UAN 1,369 1,140 1,208

On a consolidated basis, the Nitrogen Fertilizer Segment’s utilization decreased 11% to 81% for the year ended December 31, 2022 compared to the year ended December 31, 2021.

This decrease was primarily due to the completion of planned turnarounds at both fertilizer facilities in the third quarter of 2022, along with unplanned downtime in 2022 associated with the Messer Outages at the Coffeyville Fertilizer Facility and various pieces of equipment at the East Dubuque Fertilizer Facility, compared to unplanned downtime at the Coffeyville Fertilizer Facility and the East Dubuque Fertilizer Facility in July and September 2021, respectively, due to externally driven power outages and downtime at the East Dubuque Fertilizer Facility in October 2021 for equipment repair.

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.

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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UAN 309 486 264

For the year ended December 31, 2022, total product sales volumes were unfavorable, driven by lower production at both facilities due to the planned turnarounds in the third quarter of 2022, as well as increased downtime from the Messer Outages at the Coffeyville Fertilizer Facility and various pieces of equipment at the East Dubuque Fertilizer Facility in 2022, as compared to 2021.

For the year ended December 31, 2022, total product sales were favorable driven by sales price increases of 88% for ammonia and 84% for UAN.

Ammonia and UAN sales prices were favorable primarily due to continued tight market conditions due to lower fertilizer supply driven by ongoing impacts from the Russia-Ukraine conflict, including reduced production from Europe as a result of the high energy price environment, and higher crop pricing.

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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 facilities within the Nitrogen Fertilizer Segment for the years ended December 31, 2022, 2021, and 2020:

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:

Year Ended December 31,

2023 2022 2021

Petroleum coke used in production (thousand tons)

Petroleum coke (dollars per ton)

Petroleum coke used in production (thousands of tons)

Petroleum coke used in production (dollars per ton)

$ 78.14 $ 52.88 $ 44.69

Natural gas used in production (thousands of MMBtu) (1)

Natural gas used in production (thousands of MMBtus) (1)

8,462 6,905 8,049

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$ 3.42 $ 6.66 $ 3.95

Natural gas in cost of materials and other (thousands of MMBtu) (1)

Natural gas in cost of materials and other (thousands of MMBtus) (1)

8,671 6,701 7,848

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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, 2022 were $320 million and $287 million, respectively, representing improvements of $186 million and $209 million, respectively, compared to operating income and net income of $134 million and $78 million, respectively, for the year ended December 31, 2021.

These improvements were primarily driven by higher product sales prices for UAN and ammonia in 2022, partially offset by reduced sales volumes, increased costs associated with the two planned turnarounds during the third quarter of 2022, and increased feedstock prices in 2022.

Net Sales Operating Income (Loss)

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.

Net Sales Operating Income

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Net Income (Loss)

(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 increased by $303 million to $836 million for the year ended December 31, 2022 compared to the year ended December 31, 2021.

This increase was primarily due to favorable UAN and ammonia pricing conditions which contributed $348 million in higher revenues, partially offset by decreased sales volumes, which reduced revenues by $54 million compared to the year ended December 31, 2021.

For the years ended December 31, 2022 and 2021, net sales included $35 million and $31 million in freight revenue, respectively, and $11 million and $11 million in other revenue, respectively.

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.

For the years ended December 31, 2023 and 2022, net sales included $42 million and $35 million in freight revenue and $18 million and $11 million in other revenue, respectively.

The following table demonstrates the impact of changes in sales volumes and pricing for the primary components of net sales, excluding urea products, freight, and other revenue, for the year ended December 31, 2023 compared to the year ended December 31, 2022:

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Ammonia (127) 88

For the year ended December 31, 2022 compared to the year ended December 31, 2021, ammonia and UAN sales prices were favorable primarily due to continued tight market conditions due to lower fertilizer supply driven by ongoing impacts from the Russia-Ukraine conflict, including reduced production from Europe as a result of the high energy price environment, and higher crop pricing.

Total product sales volumes were unfavorable driven by lower production due to unplanned downtime associated with the Messer Outages at the Coffeyville Fertilizer Facility and various pieces of equipment at the East Dubuque Fertilizer Facility in 2022, along with the completion of the planned turnarounds at both fertilizer facilities during the third quarter of 2022.

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 $33 million increase was driven primarily by increases in purchases of nitrogen and ammonia of $17 million, increased natural gas costs of $14 million, and higher distribution costs of $4 million.

These increases were partially offset by an inventory build contributing $2 million.

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.

Direct Operating Expenses (exclusive of depreciation and amortization) - For the year ended December 31, 2023, direct operating expenses (exclusive of depreciation and amortization) were $235 million compared to $270 million for the year ended December 31, 2022.

The $72 million variance was primarily due to higher turnaround costs incurred during the planned turnarounds at both fertilizer facilities during 2022, which increased turnaround expenses by $31 million, increased repair and maintenance expenses by $15 million, and increased personnel costs by $3 million.

In addition to these turnaround related increases, there were $14 million of higher prices for natural gas for fuel purposes, $4 million of increased operating materials

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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and office costs, $4 million related to higher electricity pricing, and $3 million of higher insurance costs.

These increases were partially offset by an inventory build contributing $3 million.

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.

The following are non-GAAP measures we present for the year ended December 31, 2022:

The following are non-GAAP measures we present for the years ended December 31, 2023, 2022, and 2021:

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

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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, Adjusted Petroleum EBITDA and Adjusted Nitrogen Fertilizer EBITDA - EBITDA, Petroleum EBITDA and Nitrogen Fertilizer EBITDA adjusted for certain significant non-cash 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.

Adjusted Earnings (Loss) per Share - Earnings (loss) per share adjusted for certain significant non-cash 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.

Free Cash Flow - Net cash provided by (used in) operating activities less capital expenditures and capitalized turnaround expenditures.

Net Debt and Finance Lease Obligations - Net debt and finance lease obligations is total debt and finance lease obligations reduced for cash and cash equivalents.

Total Debt and Net Debt and Finance Lease Obligations to EBITDA Exclusive of Nitrogen Fertilizer - Total debt and net debt and finance lease obligations is calculated as the consolidated debt and net debt and finance lease obligations less the Nitrogen Fertilizer Segment’s debt and net debt and finance lease obligations as of the most recent period ended divided by EBITDA exclusive of the Nitrogen Fertilizer Segment for the most recent twelve-month 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.

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.

GAAP results, including but not limited to our operating performance as compared to other publicly-traded companies in the refining and fertilizer industries, without regard to historical

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cost basis or financing methods and our ability to incur and service debt and fund capital expenditures.

GAAP results, including but not limited to our operating performance as compared to other publicly-traded companies in the refining and fertilizer industries, without regard to historical cost basis or financing methods and our ability to incur and service debt and fund capital expenditures.

Non-GAAP measures have important limitations as analytical tools because they exclude some, but not all, items that affect net earnings and operating income.

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Factors Affecting Comparability of Our Financial Results

Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons discussed below.

Petroleum Segment

Coffeyville Refinery - The next planned turnaround of the refinery in Coffeyville, Kansas (the “Coffeyville Refinery”) is expected to start in the spring of 2023, with pre-planning expenditures of $14 million capitalized for the year ended December 31, 2022.

Wynnewood Refinery - The Wynnewood Refinery began a major scheduled turnaround in late February 2022 that was completed in early April 2022.

We capitalized expenditures of $67 million and $7 million related to turnaround activities for the years ended December 31, 2022 and 2021, respectively.

Nitrogen Fertilizer Segment

Coffeyville Fertilizer Facility - A planned turnaround at the Coffeyville Fertilizer Facility commenced in July 2022 and was completed in mid-August 2022.

For the year ended December 31, 2022, we incurred turnaround expense of $12 million.

For the year ended December 31, 2021, we incurred turnaround expense of less than $1 million related to planning for the Coffeyville Fertilizer Facility’s turnaround completed during the third quarter of 2022.

During the planning and execution of this turnaround, we updated the estimated useful lives of certain assets, which resulted in additional depreciation expense of $6 million during the year ended December 31, 2022.

Additionally, the Coffeyville Fertilizer Facility had planned downtime during the fourth quarter of 2021 at a cost of $2 million.

East Dubuque Fertilizer Facility - A planned turnaround at the East Dubuque Fertilizer Facility commenced in August 2022 and was completed in mid-September 2022.

For the year ended December 31, 2022, we incurred turnaround expense of $21 million.

For the year ended December 31, 2021, we incurred turnaround expense of $1 million related to planning for the East Dubuque Fertilizer Facility’s turnaround completed during the third quarter of 2022.

During the planning and execution of this turnaround, we updated the estimated useful lives of certain assets, which resulted in additional depreciation expense of $6 million and $5 million during the years ended December 31, 2022 and 2021, respectively.

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 $60 million, $81 million, and $8 million during the years ended December 31, 2023, 2022, and 2021, 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.

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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.

Non-GAAP Reconciliations

Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA

Reconciliation of Net Income to EBITDA and Adjusted EBITDA

Year Ended December 31,

(in millions) 2023 2022 2021

Net income (loss) $ 644 $ 74 $ (320)

Net income $ 878 $ 644 $ 74

Interest expense, net 52 85 117

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Gain on marketable securities — — (81)

Unrealized loss (gain) on derivatives, net 5 (16) 9

Inventory valuation impacts, (favorable) unfavorable

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

Inventory valuation impacts, unfavorable (favorable)

45 (24) (127)

Goodwill impairment — — 41

Call Option Lawsuits settlement — 79 —

Adjusted EBITDA $ 1,164 $ 1,369 $ 301

Reconciliation of Basic and Diluted Earnings (Loss) per Share to Adjusted Earnings (Loss) per Share

Year Ended December 31,

2022 2021 2020

Basic and diluted earnings (loss) per share $ 4.60 $ 0.25 $ (2.54)

Revaluation of RFS liability 1.00 0.46 0.43

Gain on marketable securities — (0.59) (0.25)

Unrealized loss (gain) on derivatives, net 0.04 (0.12) 0.07

Inventory valuation impacts, (favorable) unfavorable

(0.18) (0.93) 0.43

Goodwill impairment (3)

Call Option Lawsuits settlement (1)

Adjusted earnings (loss) per share $ 6.04 $ (0.93) $ (1.79)

(1) Refer to Part II, Item 8, Note 11 (“Commitments and Contingencies”) of this Report for further discussion of this settlement.

(2) Amounts are shown after-tax, using the Company’s marginal tax rate, and are presented on a per share basis using the weighted average shares outstanding for each period.

(3) Amount is shown exclusive of noncontrolling interests.

Reconciliation of Net Cash Provided By Operating Activities to Free Cash Flow

Year Ended December 31,

(in millions) 2022 2021 2020

Net cash provided by operating activities $ 967 $ 396 $ 90

Capital expenditures (191) (224) (124)

Capitalized turnaround expenditures (83) (5) (159)

Free cash flow $ 693 $ 167 $ (193)

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Reconciliation of Petroleum Segment Net Income (Loss) to EBITDA and Adjusted EBITDA

Reconciliation of Petroleum Segment Net Income to EBITDA and Adjusted EBITDA

Year Ended December 31,

(in millions) 2023 2022 2021

Petroleum net income (loss) $ 759 $ 4 $ (271)

Petroleum net income $ 1,071 $ 759 $ 4

Interest income, net (75) (41) (21)

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Revaluation of RFS liability (284) 135 63

Unrealized loss (gain) on derivatives, net 3 (16) 9

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

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

Inventory valuation impacts, unfavorable (favorable) (1)

32 (22) (127)

Petroleum Adjusted EBITDA $ 903 $ 1,021 $ 106

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

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

Year Ended December 31,

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Depreciation and amortization (185) (182) (197)

Gross profit (loss) 823 55 (215)

Gross profit 1,067 823 55

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

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Refining margin 1,658 1,431 621

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

Inventory valuation impacts, unfavorable (favorable) (1)

32 (22) (127)

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$ 1,690 $ 1,409 $ 494

(1) The Petroleum Segment’s basis for determining inventory value under GAAP is First-In, First-Out (“FIFO”).

(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.

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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.

(2) Includes an inventory valuation charge of $58 million recorded in the first quarter of 2020, as inventories were reflected at the lower of cost or net realizable value.

No adjustment was necessary during the years ended December 31, 2022 or December 31, 2021 or any other period in 2020.

Reconciliation of Petroleum Segment Total Throughput Barrels

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

Year Ended December 31,

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Total throughput barrels 75,999,905 74,930,140 76,315,701

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Reconciliation of Petroleum Segment Refining Margin per Total Throughput Barrel

Year Ended December 31,

(in millions, except per total throughput barrel)

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

total throughput barrels 75 76 67

Refining margin per total throughput barrel $ 21.82 $ 19.09 $ 8.14

Reconciliation of Petroleum Segment Refining Margin Adjusted for Inventory Valuation Impact per Total Throughput Barrel

Year Ended December 31,

(in millions, except per total throughput barrel) 2022 2021 2020

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

total throughput barrels 75 76 67

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

Reconciliation of Petroleum Segment Direct Operating Expenses per Total Throughput Barrel

Year Ended December 31,

(in millions, except per total throughput barrel) 2022 2021 2020

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

total throughput barrels 75 76 67

Direct operating expenses per total throughput barrel $ 5.34 $ 5.68 $ 4.83

Reconciliation of Nitrogen Fertilizer Segment Net Income (Loss) to EBITDA and Adjusted EBITDA

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

Year Ended December 31,

(in millions) 2023 2022 2021

Nitrogen Fertilizer net income (loss) $ 287 $ 78 $ (98)

Interest expense, net 34 61 63

Depreciation and amortization 82 74 76

Nitrogen Fertilizer EBITDA 403 213 41

Goodwill impairment — — 41

Nitrogen Fertilizer Adjusted EBITDA $ 403 $ 213 $ 82

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Reconciliation of Total Debt and Net Debt and Finance Lease Obligations to EBITDA Exclusive of Nitrogen Fertilizer

(in millions) Year Ended

December 31, 2022

Total debt and finance lease obligations (1)

Nitrogen Fertilizer debt and finance lease obligations (1)

Total debt and finance lease obligations exclusive of Nitrogen Fertilizer 1,044

EBITDA exclusive of Nitrogen Fertilizer $ 771

Total debt and finance lease obligations to EBITDA exclusive of Nitrogen Fertilizer 1.35

Consolidated cash and cash equivalents $ 510

Nitrogen Fertilizer cash and cash equivalents (86)

Cash and cash equivalents exclusive of Nitrogen Fertilizer 424

Net debt and finance lease obligations exclusive of Nitrogen Fertilizer (2)

Net debt and finance lease obligations to EBITDA exclusive of Nitrogen Fertilizer (2)

(1) Amounts are shown inclusive of the current portion of long-term debt and finance lease obligations.

(2) Net debt represents total debt and finance lease obligations exclusive of cash and cash equivalents.

Three Months Ended Year Ended December 31, 2022 (1)

(in millions) March 31, 2022 June 30, 2022 September 30, 2022 December 31,

Net income $ 153 $ 239 $ 80 $ 172 $ 644

Interest expense, net 24 23 19 18 85

Income tax expense 34 66 7 50 157

Depreciation and amortization 67 73 75 73 288

EBITDA $ 278 $ 401 $ 181 $ 313 $ 1,174

Nitrogen Fertilizer

Net income (loss) $ 94 $ 118 $ (20) $ 95 287

Nitrogen Fertilizer net income $ 172 $ 287 $ 78

Interest expense, net 29 34 61

Depreciation and amortization 80 82 74

EBITDA $ 123 $ 147 $ 10 $ 122 $ 403

EBITDA exclusive of Nitrogen Fertilizer $ 155 $ 254 $ 171 $ 191 $ 771

(1) Due to rounding, numbers within this table may not add or equal to totals presented.

December 31, 2022 | 68

Nitrogen Fertilizer EBITDA and Adjusted EBITDA 281 403 213

Liquidity and Capital Resources

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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.

Following the significant declines in demand and pricing for crude oil and refined products in 2020 due to the COVID-19 pandemic, market conditions improved steadily throughout 2021 and into 2022.

In the first quarter of 2022, following the Russian invasion of Ukraine, crude oil and refined product prices increased and have been volatile over concerns of a reduction in global supply of these products due to sanctions placed on Russian exports by the U.S.

and numerous other countries.

Despite the extreme volatility in commodity pricing, the increase in refined product pricing during 2021 and 2022 has had a favorable impact on our business and has not significantly impacted our primary source of liquidity.

While we believe demand for crude oil and refined products has stabilized, there is still uncertainty on the horizon due to the potential for recession driven demand destruction and any potential resolution of the Russia-Ukraine conflict.

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 $0.40 for the first, second, and third quarters of 2022 and $0.50 for the fourth quarter of 2022.

The Board also elected to declare special dividends equal to $2.60 and $1.00 during the second and third quarters of 2022, respectively.

No quarterly dividends were declared for the fourth quarter of 2021.

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 the environment of uncertainty.

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.

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:

• Deferred the majority of our growth capital spending, with the exception of the RDU project and construction of the renewables feedstock pretreater project at the Wynnewood Refinery;

• 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 cost reductions;

• For the Petroleum Segment, deferred the turnaround at the refinery in Coffeyville, Kansas (the “Coffeyville Refinery”) from fall of 2021 to spring of 2023.

• 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 Renewable Fuel Standard’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, 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 February 22, 2022, CVR Partners redeemed the remaining $65 million in aggregate principal amount of its 2023 UAN Notes at par, plus accrued and unpaid interest.

This transaction represents a significant and favorable change in CVR Partners’ cash flow and liquidity position, with annual savings of approximately $6 million in future interest expense.

On June 30, 2022, CVR Refining and certain of its subsidiaries entered into Amendment No.

3 to the Amended and Restated ABL Credit

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Agreement (as amended, the “Petroleum ABL”).

The Petroleum ABL is a senior secured asset based revolving credit facility in an aggregate principal amount of up to $275 million and a maturity date of June 30, 2027.

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.

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, 2022, as applicable.

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.

Cash and Other Liquidity

As of December 31, 2022, we had total liquidity of approximately $797 million which consisted of consolidated cash and cash equivalents of $510 million, $252 million available under the Petroleum ABL, and $35 million available under the Asset Based Credit Agreement (“Nitrogen Fertilizer ABL”).

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.

Total liquidity consists of $581 million of consolidated cash and cash equivalents, $249 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.

Long-term debt consisted of the following:

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

CVR Partners:

9.25% Senior Secured Notes, due June 2023 (1)

6.125% Senior Notes, due June 2028

Unamortized discount and debt issuance costs (3) (4)

Total CVR Partners debt

5.25% Senior Notes, due February 2025

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

5.75% Senior Notes, due February 2028

8.50% Senior Notes, due January 2029

Unamortized debt issuance costs (5) (4)

Total CVR Energy debt 995 996

Nitrogen Fertilizer Segment:

6.125% Senior Secured Notes, due June 2028

Unamortized debt issuance costs (3) (3)

Total Nitrogen Fertilizer Segment debt

Total long-term debt 1,542 1,543

(1) The $65 million outstanding balance of the 2023 UAN Notes was paid in full on February 22, 2022 at par, plus accrued and unpaid interest.

As of December 31, 2022, the Nitrogen Fertilizer Segment has the 6.125% Senior Secured Notes, due June 2028 (the “2028 UAN Notes”) and the Nitrogen Fertilizer ABL, the proceeds of which may be used to fund working capital, capital expenditures, and for other general corporate purposes.

Refer to Part II, Item 8, Note 6 (“Long-Term Debt and Finance Lease Obligations”) of this Report for further discussion.

As of December 31, 2022, the Petroleum Segment has the Petroleum ABL, the proceeds of which may be used to fund working capital, capital expenditures, and for other general corporate purposes.

Current portion of long-term debt (1)

Total long-term debt, including current portion $ 2,141 $ 1,543

(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.

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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.

As of December 31, 2022, CVR Energy has the 5.25% Senior Notes, due 2025 (the “2025 Notes”) and the 5.75% Senior Notes, due 2028 (the “2028 Notes” and together with the 2025 Notes, the “Notes”), the net proceeds of which may be used for general corporate purposes, which may include funding acquisitions, capital projects, and/or share repurchases or other distributions to our stockholders.

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.

December 31, 2022 | 70

Capital Spending

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

In April 2022, we completed the renewable diesel project at our Wynnewood Refinery by converting the refinery’s hydrocracker to a RDU capable of producing approximately 100 million gallons of renewable diesel per year at a total cost of $179 million.

In November 2021, the Board approved the renewable feedstock pretreater project at the Wynnewood Refinery, which is expected to be completed in the third quarter of 2023 at an estimated cost of $95 million.

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.

Our total capital expenditures for the year ended December 31, 2023, along with our estimated expenditures for 2024, by segment, are as follows:

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Petroleum $ 94 $ 14 $ 108 $ 113 $ 123 $ 51 $ 55 $ 164 $ 178

Renewables (2)

2 67 69 — 1 39 47 39 48

Nitrogen Fertilizer 28 1 29 32 35 12 13 44 48

Other 7 — 7 7 8 — — 7 8

6 54 60 8 10 9 14 17 24

Total $ 128 $ 69 $ 197 $ 153 $ 168 $ 72 $ 82 $ 225 $ 250

(1) Total 2023 estimated capitalized costs include approximately $6 million of growth related projects that will require additional approvals before commencement.

(2) Renewables reflects spending on the Wynnewood Refinery’s RDU and renewable feedstock pretreater projects.

(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 unanticipated changes in the cost, scope, and completion time for capital projects.

For example, we may experience unexpected 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.

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 board of directors of its general partner (the “UAN GP Board”).

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

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

The Petroleum Segment began a major scheduled turnaround at the Wynnewood Refinery in late February 2022 that was completed in early April 2022.

We capitalized expenditures of $67 million and $7 million for the years ended December 31, 2022 and 2021, respectively.

The Petroleum Segment’s next planned turnaround at the Coffeyville Refinery is currently expected to start in the spring of 2023, with pre-planning expenditures of $14 million capitalized for the year ended December 31, 2022.

The Nitrogen Fertilizer Segment’s planned turnaround at the Coffeyville Fertilizer Facility commenced in July 2022 and was completed in mid-August 2022.

The planned turnaround at the East Dubuque Fertilizer Facility commenced in August 2022 and was completed in mid-September 2022.

For the years ended December 31, 2022 and 2021, we incurred turnaround expense of $12 million and less than $1 million, respectively, at the Coffeyville Fertilizer Facility and $21 million and $1 million, respectively, at the East Dubuque Fertilizer Facility.

Additionally, the Coffeyville Fertilizer Facility had planned downtime for certain maintenance activities during the fourth quarter of 2021 at a cost of $2 million.

The Petroleum Segment’s total capitalized expenditures were $60 million, $81 million, and $8 million during the years ended December 31, 2023, 2022, and 2021, 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

Cash Requirements

The following table summarizes our known contractual obligations and other commercial commitments as of December 31, 2023 that are expected to be paid within the next year and thereafter:

Payments Due by Period

(in millions) Short-Term Long-Term Total

Debt obligations (1)

$ 600 $ 1,550 $ 2,150

Interest payments related to debt obligations (2)

Operating lease liabilities (3)

Finance lease obligations (3)

Purchase commitments (4)

Transportation agreements (5)

Total cash requirements $ 875 $ 2,519 $ 3,394

(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.

(2) Interest payments related to debt obligations consist of interest payments for our long-term debt outstanding as of December 31, 2023 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.

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

Dividends to CVR Energy Stockholders

Dividends, if any, including the payment, amount and timing thereof, are determined at the discretion of our Board.

Dividends, if any, including the payment, amount and timing thereof, are determined at the discretion of the Board.

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

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):

Quarterly Dividends Paid ( in millions )

Related Period Date Paid Quarterly Dividends

Per Share Public Stockholders IEP Total

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

November 20, 2023 0.50 17 33 50

Total 2023 quarterly dividends

$ 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

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$ 1.20 $ 36 $ 85 $ 121

No quarterly dividends were 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.

During the year ended December 31, 2020, the Company paid quarterly dividends totaling $1.20 per common share, or $121 million.

Of these dividends, IEP received $85 million due to its ownership interest in the Company’s shares.

On August 1, 2022 and October 31, 2022, the Company also declared special dividends of $2.60 and $1.00 per share, or $261 million and $101 million, respectively, which were paid on August 22, 2022 and November 21, 2022, respectively.

Of these amounts, IEP received $185 million and $71 million, respectively, due to its ownership interest in the Company’s shares.

Special Dividends Paid ( in millions )

Related Period Date Paid Special Dividends

Per Share Public Stockholders IEP Total

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 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.

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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 2022, the Company, upon approval by the Company’s Board on February 21, 2023, declared a cash dividend of $0.50 per share, or $50 million, which is payable March 13, 2023 to shareholders of record as of March 6, 2023.

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.

Distributions to CVR Partners ’ Unitholders

Distributions, if any, including the payment, amount and timing thereof, are subject to change at the discretion of the UAN GP Board.

The following tables present distributions paid by CVR Partners to CVR Partners’ unitholders, including amounts received by the Company, as of December 31, 2022 and 2021 (amounts presented in tables below may not add to totals presented due to rounding):

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):

Quarterly Distributions Paid (in millions)

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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

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$ 19.32 $ 129 $ 75 $ 205

Quarterly Distributions Paid (in millions)

Related Period Date Paid Quarterly Distributions

Per Common Unit Public Unitholders CVR Energy Total

2021 - 2nd Quarter

August 23, 2021 $ 1.72 $ 12 $ 7 $ 18

2021 - 3rd Quarter

November 22, 2021 2.93 20 11 31

Total 2021 quarterly distributions

$ 4.65 $ 32 $ 18 $ 50

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

During the year ended December 31, 2020, there were no quarterly distributions declared or paid by CVR Partners.

For the fourth quarter of 2023, CVR Partners, upon approval by the UAN GP Board on February 20, 2024, declared a distribution of $1.68 per common unit, or $18 million, which is payable March 11, 2024 to unitholders of record as of March 4, 2024.

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Capital Structure

On October 23, 2019, the Board authorized a stock repurchase program (the “Stock Repurchase Program”).

The Stock Repurchase Program would enable the Company to repurchase up to $300 million of the Company’s common stock.

Repurchases under the Stock Repurchase Program may be 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) will be made at the discretion of management and are subject to market conditions as well as corporate, regulatory, debt maintenance and other considerations.

While the Stock Repurchase Program currently has a duration of four years, it does not obligate the Company to acquire any stock and may be terminated by the Board at any time.

As of December 31, 2022, the Company has not repurchased any of the Company’s common stock under the Stock Repurchase Program.

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, 2022, CVR Partners had a nominal authorized amount remaining under the Unit Repurchase Program.

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

December 31, 2023 | 71

The following table sets forth our consolidated cash flows for the periods indicated below:

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Financing activities (40) (696) (315)

Net increase (decrease) in cash, cash equivalents and restricted cash $ — $ (157) $ 22

December 31, 2022 | 73

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

Operating Activities

The change in net cash provided by operating activities for the year ended December 31, 2022 compared to the year ended December 31, 2021 was primarily due to a $712 million increase in EBITDA during 2022 as a result of stronger operations during 2022 compared to 2021.

This is partially offset by a decrease in working capital of $209 million primarily associated with lower liability variances in 2022 compared to 2021.

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.

Investing Activities

The change in net cash used in investing activities for the year ended December 31, 2022 compared to the year ended December 31, 2021 was primarily due to an increase in our turnaround expenditures of $78 million in 2022 compared to 2021 related to the planned turnaround at the Wynnewood Refinery completed in 2022 and a reduction in the proceeds from the sale of assets of $7 million.

These are partially offset by a reduction in capital expenditures of $33 million, as the Wynnewood Refinery’s RDU was completed in April 2022, and a $20 million acquisition of pipeline assets in 2021 with no corresponding asset purchases in 2022.

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.

Financing Activities

The change in net cash used in financing activities for the year ended December 31, 2022 compared to the year ended December 31, 2021 was primarily due to an increase in dividends paid to CVR Partners non-controlling interest holders and CVR Energy stockholders of $98 million and $242 million, respectively, during 2022 compared to 2021, a change of $33 million in the redemption of the remaining balance of the 2023 UAN Notes in 2022 compared to the partial redemption of the 2023 UAN Notes and the 6.5% UAN Notes due April 2021 during 2021, and an increase of $11 million in unit repurchases of CVR Partners’ common units in 2022 compared to 2021.

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.

Recent Accounting Pronouncements

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Actual results could differ from the estimates and assumptions used.

December 31, 2023 | 72

Inventory Valuation

The cost of our petroleum and nitrogen fertilizer product inventories is determined under the FIFO method.

Our FIFO inventories are carried at the lower of cost or net realizable value.

The cost of our products is determined under the FIFO method and our FIFO inventories are carried at the lower of cost or net realizable value.

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

In our Petroleum Segment, 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.

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.

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.

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

For 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.

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.

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

During the year ended December 31, 2020, we recognized

December 31, 2022 | 74

losses on inventory of $59 million to reflect net realizable value, primarily associated with our Petroleum Segment.

No amounts were recognized for the years ended December 31, 2022 and 2021.

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.

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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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