CVI

The following discussion and analysis of our financial condition, results of operations, and cash flows should be read in conjunction with our unaudited condensed consolidated financial statements and related notes and with the statistical information and financial data included elsewhere in this Report, as well as our Annual Report on Form 10-K for the year ended December 31, 2025 filed with the U.S. Securities and Exchange Commission (the “SEC”) on February 18, 2026 (the “2025 Form 10-K”). Results of operations for the three and six months ended June 30, 2026 and cash flows for the six months ended June 30, 2026 are not necessarily indicative of results of operations and cash flows to be attained for any other period. See “Important Information Regarding Forward-Looking Statements.” References to “CVR Energy”, the “Company”, “we”, “us”, and “our”, may refer to consolidated subsidiaries of CVR Energy, including CVR Refining, LP or CVR Partners, LP, as the context may require. Reflected in this discussion and analysis is how management views the Company’s current financial condition and results of operations, along with key external variables and management’s actions that may impact the Company. This discussion may contain forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this Report. Company Overview CVR Energy is a diversified holding company primarily engaged in the petroleum refining and marketing industry (the “Petroleum Segment”) and the nitrogen fertilizer manufacturing industry through its interest in CVR Partners, LP, a publicly traded limited partnership (the “Nitrogen Fertilizer Segment” or “CVR Partners”). 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 operate under two reportable segments: petroleum and nitrogen fertilizer, which are referred to in this document as our “Petroleum Segment” and our “Nitrogen Fertilizer Segment”, respectively. Company Developments In December 2025, the Company reverted the renewable diesel unit (“RDU”) at the refinery located in Wynnewood, Oklahoma (the “Wynnewood Refinery”) back to hydrocarbon processing service, considering the unfavorable economics of the renewables business and to optimize feedstock and relieve certain logistical constraints within the refining business. While the Company maintains the option to switch back to renewable diesel service if incentivized to do so, it no longer refines renewable feedstocks, such as soybean oil, corn oil, and other similar feedstocks, into renewable diesel nor does it currently market renewable diesel. Based on the Company’s revised reporting assessment performed during the first quarter of 2026, the renewables business no longer met the quantitative or qualitative requirements under ASC 280, Segment Reporting, to be disclosed as a separate reportable segment. Effective beginning with the Form 10-Q for the quarter ended March 31, 2026, all prior period Renewables activity has been consolidated within “Other” and disclosures have been retrospectively adjusted to reflect the current segment presentation. Refer to Part I, Item 1, Note 13 (“Business Segments”) for segment disclosures. Strategy and Initiatives Potential Strategic Transactions As previously disclosed, Icahn Enterprises L.P. and its affiliates (“IEP”) and the Company are considering potential strategic transactions available to the Company and our subsidiaries and affiliates, which may include the acquisition of additional entities, assets or businesses, including the acquisition of material amounts of refining assets through negotiated mergers and/or stock or asset purchase agreements by the Company or our subsidiaries, and/or strategic options involving CVR Partners. There is no assurance that any of the aforementioned or previously disclosed or other transactions will develop or materialize, or if they do, as to their timing. As of June 30, 2026, IEP owns approximately 71% of the Company’s total outstanding common stock and approximately 3% of the total outstanding common units of CVR Partners. As of June 30, 2026, CVR Energy, through its subsidiaries, held approximately 37% of CVR Partners’ outstanding common units and 100% of CVR Partners’ general partner interests. June 30, 2026 | 25 Table of Contents Company Initiatives Petroleum Segment •The Company has undertaken a project to replace the hydrofluoric acid catalyst alkylation unit at the Wynnewood Refinery with a fixed bed catalyst system. If successfully completed, this project should expand the alkylation unit by up to 2,500 bpd resulting in increased production of premium gasoline, through utilization of propylene which is currently sold as a product, and eliminate hydrofluoric acid inventory. The capital investment is estimated at $136 million, and the unit is currently expected to become operational in late 2027; however, timing could be impacted by various factors including but not limited to logistics constraints. •In connection with our settlement with the Environmental Protection Agency (“EPA”) on certain environmental issues at the refinery in Coffeyville, Kansas (the “Coffeyville Refinery”) entered into in 2023 and by the court in January 2024, the Company is in the process of installing a flare gas recovery system along with other improvements at a cost of approximately $53 million, which is expected to be operational in late 2026. •The Company has been assessing opportunities to improve margin capture at both refineries through optimizing crude and feedstock slates and refined product marketing, and has begun repurposing and utilizing rail assets following the reversion of the RDU to provide additional feedstock security and product shipment optionality. Nitrogen Fertilizer Segment •In 2025 and into 2026, CVR Partners progressed several projects focused on improving water and electrical reliability, expanding diesel exhaust fluid production, and increasing loadout capabilities, among other initiatives, using funds previously reserved by the board of directors of CVR Partners’ general partner (the “UAN GP Board”). •During the planned turnaround at the fertilizer facility in East Dubuque, Illinois operated by CVR Partners’ wholly owned subsidiary, East Dubuque Nitrogen Fertilizers, LLC (“EDNF”) (the “East Dubuque Fertilizer Facility”), scheduled for August 2026, EDNF will continue to progress work on the upgrades to its water systems, in addition to completing the brownfield ammonia expansion that is expected to increase production capacity by approximately 5%. •Based on engineering studies completed in 2025, the fertilizer facility in Coffeyville, Kansas operated by CVR Partners’ wholly owned subsidiary, Coffeyville Resources Nitrogen Fertilizers, LLC (“CRNF”) (the “Coffeyville Fertilizer Facility” and together with the East Dubuque Fertilizer Facility, the “Facilities”) has the potential to utilize natural gas as an alternative feedstock in conjunction with pet coke in the production of nitrogen fertilizer. CVR Partners is in the final phases of completing detailed engineering and cost estimates, and following final approval by the UAN GP Board, expects to proceed with construction in 2026 and 2027. If completed, these initiatives would make the Coffeyville Fertilizer Facility the only nitrogen fertilizer facility in the United States with dual feedstock flexibility, providing management with the ability to choose the optimal mix of natural gas and third-party pet coke depending on prevailing prices. •In June 2026, the Coffeyville Fertilizer Facility received its Verified Ammonia Carbon Intensity certification from an independent third-party auditor under The Fertilizer Institute framework, which will enable the Coffeyville Fertilizer Facility to market ammonia it produces as “blue.” Industry Factors General Business Environment Geopolitical Matters •On February 28, 2026, a war began between the U.S., Israel and Iran (the “Iran War”), further increasing the conflicts and tensions in the Middle East, resulting in significant disruptions to oil, refined products, and fertilizer production facilities in the region, as well as to global energy and fertilizer supply chain production and availability. The Iran War has disrupted key trade routes, especially the Strait of Hormuz, tightened global supply of certain commodities, and increased energy costs, contributing to elevated and volatile crude oil, refined product, and fertilizer prices. Recent escalations in the Iran War have increased the uncertainty regarding the duration and severity of these disruptions and any further impacts on the global and energy markets. While certain global coordinated activities have been implemented with the intention to mitigate price volatility and provide near-term relief to market conditions, crude oil, refined product, and fertilizer prices remain elevated relative to prior periods. June 30, 2026 | 26 Table of Contents •In addition, the ongoing Russia-Ukraine war and related geopolitical developments have disrupted, and could further disrupt, the production and trade of petroleum products, fertilizer, grains, and other feedstocks through various means, such as trade restrictions, sanctions or transportation bottlenecks. •Changes, and proposed changes, to the U.S. global trade policy, together with related judicial, regulatory and administrative developments, as well as renewed trade tensions and related international retaliatory measures, have continued to influence global markets and impact short- and long-term economics in the U.S. and around the globe, including concerns over inflation, recession, and slowing growth. These factors, together with evolving diplomatic efforts and ongoing geopolitical developments in the affected regions, have contributed to, and may continue to contribute to, volatility in crude oil, refined product and fertilizer pricing and inventories, as well as disruptions in the production, transportation and trade of crude oil, refined products, fertilizer, grains, and feedstocks through various means, including trade restrictions and sanctions. The ultimate impacts of these geopolitical developments and economic policy changes, including any further escalation, de-escalation, or resolution thereof, and any associated market disruptions remain difficult to predict and may materially affect our business, operations, cash flows, and access to capital in unforeseen ways. Regulatory Environment Our businesses are subject to significant regulatory oversight and requirements and numerous rules, regulations, policies and legal proceedings relating to climate, energy and environmental matters enacted or introduced, as applicable, at federal, state, and international levels. These laws, rules, regulations and policies, and the implementation and enforcement thereof, are further subject to shifting priorities at the federal level, including various executive orders, regulatory guidance and new legislation, some of which have curtailed, delayed, modified or restructured certain climate-related regulatory initiatives advanced under the prior administration. Given these shifting priorities, we face an uncertain regulatory landscape at the federal, state, and international levels, such potential changes to reporting of greenhouse gas emissions and climate risk. Each of these factors further contributes to ongoing uncertainty in the regulatory environment in which we operate and may materially impact our businesses, operations, feedstock sourcing, operating and compliance costs, results of operations and overall market conditions. Petroleum Segment The earnings and cash flows of the Petroleum Segment are primarily affected by the relationship between refined product prices and the cost of crude oil and other feedstocks that are used in refining and blending, as well as refinery compliance costs, including costs associated with Renewable Fuel Standard (“RFS”) regulations. The effect of changes in crude oil prices on the Petroleum Segment’s results of operations is also influenced by the rate at which the refined products adjusts to reflect those changes. Crude oil costs and the prices of refined products have historically been subject to wide fluctuations, which can impact, among other things, the level of inventories in the market and a reduction in product margins. Widespread expansion or upgrades of third-party facilities, shutdowns or curtailments, price volatility, international political and economic developments, and other factors are likely to continue to play an important role in refining industry economics. Specific factors impacting the Petroleum Segment’s operations are outlined below. Current Market Outlook •Since February 28, 2026, the Iran War has been the primary driver of volatility in global energy and refined product markets. Disruptions to key trade routes, especially the Strait of Hormuz, and damage to refining and energy infrastructure in the Middle East have constrained global refined product supply and contributed to significant increases in prices, particularly for diesel. At its outset, the U.S. saw geographical market dislocations with waterborne regions elevating more rapidly than inland regions as international shortages took effect. This dislocation has moderated with some stabilization of trade flows and inventories but continues to be wider than historical averages. Pricing and inventories remain volatile and are expected to remain volatile in the future, influenced by developments in diplomatic relations, among other factors. •Group 3 2-1-1 crack spreads increased from below to above mid-cycle levels following the start of the Iran War. Diesel crack spreads remained elevated into 2026 and increased significantly with the war. We expect diesel crack spreads to remain elevated in 2026 until global supply chains normalize. Group 3 gasoline crack spreads were particularly challenged early in the year as refinery utilization was high going into the winter months, and June 30, 2026 | 27 Table of Contents subsequently, refiners have increased throughputs to capture incremental margin on distillate volumes. More recently, inventories have begun to draw and the gasoline crack spread has improved. •In addition to moving barrels out of the mid-continent region to balance supply and demand needs around the U.S. and globally, several projects have been announced to move products to western states in PADDs IV and V which should continue to help balance domestic trade flows and move excess barrels to regions where demand should outpace supply in the coming years. •Total operable refining capacity in the United States has declined on a net basis since 2020. In addition, recent damage to refineries in the Middle East and reduced refinery utilization in Russia, caused by drone strikes during the Russia-Ukraine war, have further tightened global refining capacity and supported global refined product crack spreads. •Over the next few years, the pace of global capacity growth is expected to slow with few new refineries scheduled to come online, which could lead to a tightening in global refined product supply and demand balances as global demand growth is expected to continue increasing. •Recent damage to liquid natural gas (“LNG”) production facilities and loss of LNG trade flows through the Middle East have contributed to higher natural gas prices in Europe, impacting competitiveness of European refineries. Meanwhile, the abundance of natural gas supply available in the U.S. continues to keep domestic prices subdued, providing a sustained cost advantage for U.S. refiners. Regulatory Environment •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 renewable fuel credits, known as renewable identification numbers (“RINs”), in lieu of blending, or otherwise face liability. Actions of the EPA under the RFS, the outcomes of various RFS-related legal challenges and various legislative efforts relating to the RFS and renewable fuels, have in the past and are expected to continue to materially impact our results. In addition, certain governmental regulations and incentives associated with the automobile transportation, agricultural, and renewables industries, including the ones related to corn-based ethanol and vegetable oil-based biodiesel, renewable diesel, and sustainable aviation fuel production or consumption, have impacted, and are expected to continue to impact, our business. For example: ◦On April 1, 2026, the EPA issued a final rule, effective on June 15, 2026, that (a) establishes applicable blending volumes and percentage standards under the RFS for 2026 and 2027 for cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel, reflecting the highest renewable fuel volume in the program’s history, including for biomass-based diesel and advanced biofuel; (b) partially waives the 2025 cellulosic biofuel volume requirement and revises the associated percentage standard due to a shortfall in cellulosic biofuel production; and (c) promulgates several regulatory changes to the RFS program, including the removal of renewable electricity as a qualifying renewable fuel under the RFS program and makes minor revisions to the biogas provisions of the RFS program (the “2026/2027 RFS Final Rule”). In the 2026/2027 RFS Final Rule, the EPA confirmed its intention to add to annual blending obligations volumes that account for 70% of volumes actually exempted by the EPA for 2023 and 2024 compliance years and those projected to be exempted by the EPA for the 2025 compliance year, estimated by the EPA to total 2.89 billion RINs. Numerous refiners, including Coffeyville Resources Refining & Marketing, LLC and Wynnewood Refining Company, LLC (“WRC”), biofuels groups and others filed petitions for review of the 2026/2027 RFS Final Rule in the D.C. Circuit, which petitions remain pending and in their early stages. ▪As of June 30, 2026, we have an estimated liability of $408 million for the Petroleum Segment’s obligated-party subsidiaries’ compliance with the RFS through June 30, 2026, which consists of approximately 169 million RINs, excluding open, fixed-price commitments to purchase a net 20 million RINs. The Company’s open RFS position is marked-to-market each period, and thus market volatility could significantly impact 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) and has the potential to remain significant through 2026 and beyond. ◦Over the past year, certain oil, biofuels and agriculture groups have pushed not only for Congressional approval of year-round E15 (gasoline blended with 15% ethanol) but also certain amendments to the RFS. In May 2026, the U.S. House of Representatives passed H.R. 1346, intended to permit year-round, nationwide E15 and ban certain small refiners, including WRC, from future eligibility for small refinery exemptions (“SREs”) under the RFS beginning in 2028, among other actions. H.R. 1346, along with related proposed bills seeking to amend portions of the RFS and related legislation, are being considered by the U.S. Senate, including S. 593, which seeks to June 30, 2026 | 28 Table of Contents authorize year-round, nationwide E15 but does not currently contain language changing the definition of “small refinery” under the RFS. ◦The EPA issued a nationwide emergency waiver of the Reid Vapor Pressure specifications during the summer of 2026 to increase the size of the gasoline pool for the summer driving season, as a result of the conflict with Iran, and issued a temporary emergency fuel waiver in March 2026 which became effective May 1, 2026, to allow nationwide sales of E15 and to remove all federal impediments to selling E10 (gasoline blended with 10 percent ethanol) across the country. ◦Provisions of the Section 45Z Clean Fuel Production Credit exclude imports of renewable fuels and imported feedstocks used to produce renewable fuels in the United States, which we expect to support demand for domestic corn and soybean oil feedstocks and will impact both our refining and fertilizer operations. 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 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. Current Market Outlook •The fertilizer industry continues to face additional scrutiny from legislators, regulators, agriculture groups and others following fertilizer and fertilizer input price increases related to the impacts of the Iran War, which only exacerbated price increases caused by the ongoing Russia-Ukraine war, continued conflicts and tensions in the Middle East, and related geopolitical developments. Such scrutiny has increased in 2026 and may result in additional government inquiries, investigations, legislative actions or regulatory initiatives affecting participants in the fertilizer industry. Regulatory Environment •Certain governmental regulations and incentives associated with the automobile transportation, agricultural and renewables industries, including the ones related to corn-based ethanol and vegetable oil-based biodiesel, renewable diesel, and sustainable aviation fuel production or consumption, have impacted, and is expected to continue to impact, our business. For example: ◦Ethanol is blended with gasoline to meet requirements under the RFS and for its octane value. Since 2020, corn used in ethanol production has historically consumed an average of approximately 36% of annual domestic corn production. Accordingly, corn and/or ethanol demand can be impacted by the actions of the EPA under the RFS, including its establishment of annual blending obligations and related actions. Even if the EPA decreases RFS blending obligations, we believe ethanol should continue to be blended into transportation fuel for its inherent octane value. Results of Operations Due to the reversion of the RDU at the Wynnewood Refinery back to hydrocarbon processing and based on the Company’s revised reporting assessment performed during the first quarter of 2026, the renewables business no longer met the quantitative or qualitative requirements under ASC 280, Segment Reporting, to be disclosed as a separate reportable segment. Effective beginning with the Form 10-Q for the quarter ended March 31, 2026, all prior period Renewables activity has been consolidated within “Other” and disclosures have been retrospectively adjusted to reflect the current segment presentation. June 30, 2026 | 29 Table of Contents Consolidated Our consolidated results of operations include certain unallocated corporate activities and the elimination of intercompany transactions and, therefore, do not equal the sum of the operating results of the Petroleum and Nitrogen Fertilizer Segments. Three Months Ended June 30, Six Months Ended June 30, (in millions, except per share data) 2026 2025 2026 2025 Operating income (loss) $ 78 $ (103) $ (67) $ (235) Interest expense, net (25) (30) (83) (55) Other income, net 3 1 17 4 Income tax (expense) benefit (10) 42 19 91 Net income (loss) 46 (90) (114) (195) Less: Net income attributable to noncontrolling interest (49) (24) (81) (42) Net loss attributable to CVR Energy stockholders $ (3) $ (114) $ (195) $ (237) Loss per share $ (0.03) $ (1.14) $ (1.94) $ (2.36) EBITDA (1) $ 161 $ (24) $ 109 $ (85) (1)See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown above. Overview - For the three months ended June 30, 2026, the Company’s net income increased $136 million compared to the three months ended June 30, 2025. For the six months ended June 30, 2026 the Company’s net loss decreased $81 million compared to the six months ended June 30, 2025. Refer to our discussion of each segment’s result of operations below for further information. Interest expense, net - The $5 million decrease for the three months ended June 30, 2026 compared to the three months ended June 30, 2025 was primarily driven by lower borrowing costs resulting from the Company’s debt refinancing activities completed in the first quarter of 2026. The $28 million increase for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 was primarily driven by losses on extinguishment of debt associated with the redemption of the 8.500% Senior Notes, due 2029 (the “2029 Notes”) and 5.750% Senior Notes, due 2028 (the “2028 Notes”), and the loss on the prepayment of the senior secured term loan facility (the “Term Loan”) during the first quarter of 2026. See Part I, Item 1, Note 6 (“Long-Term Debt and Finance Lease Obligations”) for further details. Other Income, Net - The $13 million increase for the six months ended June 30, 2026, compared to the six months ended June 30, 2025 was primarily driven by the recognition of the Production Tax Credit (the “PTC”) related to qualifying renewable fuel sales. The Company recognized the full 2025 tax credit benefit during the first quarter of 2026. Income Tax (Expense) Benefit - Income tax (expense) benefit for the three and six months ended June 30, 2026 was $(10) million and $19 million, or 17.8% and 14.1% of income (loss) before income tax, respectively, compared to income tax benefit for the three and six months ended June 30, 2025 of $42 million and $91 million, or 31.7% and 31.8% of loss before income tax, respectively. The changes in income tax benefit were primarily due to an increase in overall pretax earnings. The changes in effective tax rate from the three and six months ended June 30, 2025 to the three and six months ended June 30, 2026 were primarily caused by changes in pretax earnings attributable to noncontrolling interests and the impact of state tax credits relative to overall pretax earnings. Petroleum Segment The Petroleum Segment utilizes certain inputs within its refining operations. These inputs include crude oil, butanes, natural gasoline, ethanol, and biodiesel (these are also known as “throughputs”). June 30, 2026 | 30 Table of Contents Refining Throughput and Production Data Throughput Data Three Months Ended June 30, Six Months Ended June 30, (in bpd) 2026 2025 2026 2025 Gathered crude 113,627 125,940 112,149 110,705 Other domestic 70,165 32,313 70,989 22,671 Canadian 19,475 581 18,436 610 Other feedstocks and blendstocks 9,698 13,315 12,039 12,420 Total throughput 212,965 172,149 213,613 146,406 Production Data Three Months Ended June 30, Six Months Ended June 30, (in bpd) 2026 2025 2026 2025 Gasoline 103,194 86,980 107,318 72,908 Distillate 92,280 70,556 89,894 57,938 Other liquid products 9,337 7,839 8,101 9,601 Solids 6,711 3,723 6,353 2,534 Total production 211,522 169,098 211,666 142,981 Crude utilization (1) 98.4 % 76.9 % 97.6 % 64.9 % Distillate yield (as % of crude throughput) (2) 45.4 % 44.4 % 44.6 % 43.2 % Light product yield (as % of crude throughput) (3) 96.2 % 99.2 % 97.8 % 97.7 % Liquid volume yield (as % of total throughput) (4) 96.2 % 96.1 % 96.1 % 95.9 % (1)Total Gathered crude, Other domestic, and Canadian throughput (collectively, “Total Crude Throughput”) divided by consolidated crude oil throughput capacity of 206,500 bpd. (2)Total Distillate divided by Total Crude Throughput. (3)Total Gasoline and Distillate divided by Total Crude Throughput. (4)Total Gasoline, Distillate, and Other liquid products divided by total throughput. 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 crude oils and WTI, known as differentials, show how the market for other crude oils, such as WCS, Brent Crude (“Brent”), and Midland WTI (“Midland”) are trending. Due to geopolitical events, such as escalating military conflicts in the Middle East, the Strait of Hormuz closure, and the Russia-Ukraine war, 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 likely continue to be volatile. We utilize NYMEX and Group 3 crack spreads as a performance benchmark and a comparison with other industry participants. These crack spreads are a measure of the difference between market prices for crude oil and refined products and are a commonly used proxy within the industry to estimate or identify trends in refining margins. Crack spreads can fluctuate significantly over time as a result of market conditions and supply and demand balances. The NYMEX 2-1-1 crack spread is calculated using two barrels of WTI producing one barrel of NYMEX RBOB Gasoline (“RBOB”) and one barrel of NYMEX NY Harbor ULSD (“HO”). 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. NYMEX 2-1-1 crack spreads increased during the three and six months ended June 30, 2026 averaging $54.34 and $45.66 per barrel, respectively, compared to $25.87 and $24.29 per barrel during the three and six months ended June 30, 2025, respectively. Group 3 2-1-1 crack spreads also increased during the three and six months ended June 30, 2026 averaging $44.91 and $33.34 per barrel, respectively, compared to $24.02 and $20.89 per barrel during the three and six months ended June 30, 2025, respectively. June 30, 2026 | 31 Table of Contents Average monthly prices for RINs on a blended barrel basis (calculated using applicable renewable volume obligation (“RVO”) percentages) increased during the three and six months ended June 30, 2026 to $13.78 and $11.64 per barrel, respectively, compared to $6.08 and $5.39 per barrel during the three and six months ended June 30, 2025, respectively. The charts below are presented, on a per barrel basis, by month through June 30, 2026: Crude Oil Differentials against WTI (1)(2) NYMEX Crack Spreads (2) PADD II Group 3 Product Crack Spread and RIN Pricing (2)(3) ($/bbl) June 30, 2026 | 32 Table of Contents 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: (in $/bbl) Average 2024 Average December 2024 Average 2025 Average December 2025 Average 2026 Average June 2026 WTI $ 75.77 $ 69.70 $ 64.73 $ 57.87 $ 82.77 $ 81.79 (2)Information used within these charts was obtained from reputable market sources, including the New York Mercantile Exchange (“NYMEX”), Intercontinental Exchange, and Argus Media, among others. (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. Petroleum Segment Financial Highlights Three Months Ended June 30, Six Months Ended June 30, (in millions, except throughput data) 2026 2025 2026 2025 Net sales $ 2,540 $ 1,561 $ 4,344 $ 3,038 Operating income (loss) 5 (133) (188) (295) Net income (loss) 12 (137) (182) (297) EBITDA (1) 58 (84) (81) (202) Refining margin (1) $ 193 $ 35 $ 195 $ 30 Direct operating expenses 116 102 233 193 Depreciation and amortization 49 48 102 90 Selling, general, and administrative expenses 22 20 47 42 $ (per total throughput barrel) Refining margin per total throughput barrel (1) $ 9.94 $ 2.21 $ 5.04 $ 1.14 Direct operating expenses per total throughput barrel (1) 5.93 6.45 6.02 7.32 (1)See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown above. Overview - For the three months ended June 30, 2026, the Petroleum Segment’s operating income and net income increased $138 million and $149 million, respectively, compared to the three months ended June 30, 2025. For the six months ended June 30, 2026, the Petroleum Segment’s operating loss and net loss decreased $107 million and $115 million, respectively, compared to the six months ended June 30, 2025. These variances were primarily due to an increase in gasoline and distillate crack spreads and higher throughput volumes in the current period as a result of the Coffeyville Refinery’s major turnaround during the first quarter of 2025 (the “2025 Refinery Turnaround”), partially offset by increases in RINs prices and obligations, backwardation in NYMEX WTI, and unfavorable derivative impacts. June 30, 2026 | 33 Table of Contents Net Sales - The $979 million increase and $1.3 billion increase for the three and six months ended June 30, 2026, respectively, compared to the three and six months ended June 30, 2025 were primarily driven by higher throughput volumes in the current period as a result of the 2025 Refinery Turnaround, combined with higher gasoline and distillate prices, partially offset by lower revenue from sales of crude oil in 2026 due to selling crude to manage inventory during the 2025 Refinery Turnaround. Refining Margin - The $158 million increase for the three months ended June 30, 2026 compared to the three months ended June 30, 2025 was primarily due to the following factors: •An increase in the Group 3 2-1-1 crack spread of $20.89 per barrel, driven by an improvement in gasoline and distillate crack spreads primarily due to the Iran War in the current period; •Increased throughput volumes in the current period due to the 2025 Refinery Turnaround in the prior period; and •Favorable inventory valuation impacts of $19 million for the three months ended June 30, 2026 compared to unfavorable inventory valuation impacts of $31 million for the three months ended June 30, 2025, primarily due to an increase in feedstock prices in the current period compared to a decrease during the second quarter of 2025. Factors partially offsetting the increases in refining margin were: •An increase in the RVO weighted cost of RFS compliance of $7.70 per barrel primarily due to an increase in the price of Ethanol and Biodiesel RINs combined with an increase in the RVO requirement for 2026 compared to 2025; •Unfavorable backwardation in NYMEX WTI resulting in approximately $90 million impact to purchased crude oil differentials; and •Unfavorable derivatives impacts of $80 million, resulting primarily from losses on crack swap positions in the current period. The $165 million increase for the six months ended June 30, 2026, compared to the six months ended June 30, 2025 was primarily due to the following factors: •An increase in the Group 3 2-1-1 crack spread of $12.45 per barrel, driven by an improvement in distillate and gasoline crack spreads, primarily due to the Iran War in the current period; •Increased throughput volumes in the current period due to the 2025 Refinery Turnaround in the prior period; and •Favorable inventory valuation impacts of $138 million for the six months ended June 30, 2026 compared to unfavorable inventory valuation impacts of $10 million for the six months ended June 30, 2025, primarily due to an increase in crude oil prices in the current year as compared to a decrease in 2025, combined with larger increases in gasoline and distillate prices in the current year. Factors partially offsetting the increase in refining margin were: •Unfavorable derivatives impacts of $275 million in the 2026 period as compared to the 2025 period resulting primarily from losses on crack swap positions in the current year; •An increase in the RVO weighted cost of RFS compliance of $6.25 per barrel primarily due to an increase in the price of Ethanol and Biodiesel RINs combined with an increase in the RVO; •Unfavorable second quarter 2026 backwardation in NYMEX WTI resulting in approximately $90 million impact to purchased crude oil differentials. Direct Operating Expenses (Exclusive of Depreciation and Amortization) - The $14 million increase and $40 million increase for the three and six months ended June 30, 2026 compared to the three and six months ended June 30, 2025 was primarily due to higher personnel costs combined with increased natural gas and electricity utilities, production chemicals, and catalyst costs in the current period as a result of increased throughput volumes in 2026 due to the 2025 Refinery Turnaround in the prior period, partially offset by lower share-based compensation expenses as a result of a decrease in the market price of CVR Energy’s common shares in the current period compared to an increase in the prior period. On a total throughput barrel basis, direct operating expenses during the three and six months ended June 30, 2026 declined $0.52 and $1.30 per barrel, respectively, compared to the prior periods due to increased throughput volumes in the current period resulting from the 2025 Refinery Turnaround in the prior period, partially offset by the increased direct operating expenses discussed above in the current period. Depreciation and Amortization Expense - The $1 million increase and $12 million increase for the three and six months ended June 30, 2026, respectively, compared to the three and six months ended June 30, 2025 was primarily attributable to June 30, 2026 | 34 Table of Contents fixed asset additions during the 2025 Refinery Turnaround, partially offset by certain assets being retired or fully depreciated during 2026. Selling, General, and Administrative Expenses - The $2 million increase and $5 million increase for the three and six months ended June 30, 2026, respectively, compared to the three and six months ended June 30, 2025 was primarily due to higher personnel costs combined with increased consulting and software costs, partially offset by decreased share-based compensation expense as a result of a decrease in the market price of CVR Energy’s common shares in the current period compared to an increase in the prior period. Nitrogen Fertilizer Segment Utilization and Production Volumes - The following table summarizes the ammonia utilization rates on a consolidated basis and production volumes for the Nitrogen Fertilizer Segment’s two manufacturing Facilities. Utilization is an important measure used by management to assess operational output at each of the Facilities and is calculated as actual tons of ammonia produced divided by capacity. 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 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. These metrics are presented in the table below: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Ammonia utilization rate 99 % 91 % 101 % 96 % Production volumes (thousands of tons) Ammonia—gross produced 214 197 434 413 Ammonia—net available for sale 64 54 134 117 UAN 342 321 678 668 On a consolidated basis, for the three months ended June 30, 2026 as compared to June 30, 2025, the Nitrogen Fertilizer Segment’s utilization increased 8% primarily due to planned downtime associated with control systems upgrades at the East Dubuque Fertilizer Facility and other minor unplanned outages at the Facilities during the second quarter of 2025. For the six months ended June 30, 2026 as compared to June 30, 2025, utilization increased 5% primarily due to the aforementioned control systems upgrades at the East Dubuque Fertilizer Facility and other minor unplanned outages at the Facilities during 2025 (the “2025 Outages”). Sales Volume 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, which represents net sales less freight revenue divided by product sales volume in tons and is shown in order to provide a pricing measure comparable across the fertilizer industry. Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Consolidated sales volumes (thousands of tons) Ammonia 54 57 127 117 UAN 333 345 643 681 Consolidated product pricing at gate (dollars per ton) Ammonia $ 791 $ 593 $ 731 $ 573 UAN 392 317 368 287 June 30, 2026 | 35 Table of Contents For the three months ended June 30, 2026, ammonia sales volumes decreased by 6% due to an early start to spring ammonia application in 2026 shifting volume into the first quarter of 2026, while UAN sales volumes decreased by 3% due to lower consumer demand as a result of fewer corn acres planted and higher prices for UAN relative to other comparable fertilizer products during the end of the current period. For the six months ended June 30, 2026, ammonia sales volumes increased by 8% due to higher ammonia production in the current period as a result of the 2025 Outages in the prior period, while UAN sales volumes decreased by 6% due to the aforementioned decrease in corn acres planted and increase in UAN prices in the current period. For the three months ended June 30, 2026, ammonia and UAN sales prices increased by 33% and 24%, respectively. For the six months ended June 30, 2026, ammonia and UAN sales prices increased by 28% and 28%, respectively. These increases were primarily due to changes in market conditions, primarily driven by tight inventory levels as a result of the conflicts and tensions in the Middle East combined with domestic and international production outages, logistics constraints, and other impacts that reduced global supply 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. These feedstocks for the Facilities are presented in the table below: Three Months Ended June 30, Six Months Ended June 30, 2026 2025 2026 2025 Petroleum coke used in production (thousands of tons) 136 130 274 261 Petroleum coke used in production (dollars per ton) $ 44.94 $ 56.68 $ 39.39 $ 49.54 Natural gas used in production (thousands of MMBtus) (1) 2,014 1,897 4,129 4,057 Natural gas used in production (dollars per MMBtu) (1) $ 2.84 $ 3.29 $ 4.15 $ 4.00 (1)The feedstock natural gas shown above does not include natural gas used for fuel, which is included in Direct operating expenses (exclusive of depreciation and amortization). Market Indicators The Nitrogen Fertilizer Segment maintains that the anticipated combination of (i) increasing global population, (ii) decreasing arable land per capita, (iii) continued evolution to more protein-based diets in developing countries, (iv) sustained use of corn and soybeans as feedstock for the domestic production of ethanol and other renewable fuels, and (v) positioning at the lower end of the global cost curve should provide a solid foundation for nitrogen fertilizer producers in the United States over the longer term. Corn and soybeans are two major crops planted by farmers in North America. 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. 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 18 billion pounds of soybean oil is expected to be used in producing renewable fuels in marketing year 2026/2027. Weather continues to be a critical variable for crop production. Even with escalating prices for nitrogen fertilizer, demand was strong for the spring 2026 planting season, primarily due to elevated grain prices and favorable weather conditions for planting. With high planted acres and above trendline yields per acre for corn in the United States in 2025, global inventory levels for corn remain above historical 10-year averages, but prices have risen in 2026 on expectations of lower carryout inventory levels compared to 2025. While soybean production declined slightly due to fewer planted acres in 2025, yields were above historical levels, and pricing has increased in the United States due in part to increased biofuel blending obligations set by the EPA increasing demand for soybean oil used in the production of biodiesel and renewable diesel. June 30, 2026 | 36 Table of Contents The United States Department of Agriculture (“USDA”) estimates that in spring 2026 farmers planted 3.5% fewer corn acres and 5.1% more soybean acres compared to 2025. The combined estimated corn and soybean planted acres of 181 million in 2026 represents a slight increase compared to the acreage planted in 2025. Due to the relative grain prices of corn versus soybeans, economics slightly favor planting corn compared to soybeans in 2026. Inventory levels of corn and soybeans are expected to be higher in 2026 but supportive of grain prices through the fall 2026 harvest. The charts below show the corn-soybean rotational planting cycle and average fuel ethanol production volumes in the U.S.: Corn and Soybean Planted Acres (1) U.S. Plant Production of Fuel Ethanol (2) (1)Information used within this chart was obtained from the USDA, National Agricultural Statistics Services as of June 30, 2026. (2)Information used within this chart was obtained from the U.S. Energy Information Administration (“EIA”) through June 30, 2026. Given the current geopolitical events, we believe the structural shortage of natural gas in Europe will continue to be a source of volatility through at least 2027. Pet coke prices have risen slightly in 2026 and prices are largely contractually set for 2026. The charts below show relevant market indicators for the Nitrogen Fertilizer Segment by month through June 30, 2026: Ammonia and UAN 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, among others. June 30, 2026 | 37 Table of Contents 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, among others. Nitrogen Fertilizer Segment Financial Highlights Three Months Ended June 30, Six Months Ended June 30, (in millions) 2026 2025 2026 2025 Net sales $ 202 $ 169 $ 382 $ 311 Operating income 85 46 142 81 Net income 78 39 127 66 EBITDA (1) 107 67 185 120 Cost of materials and other $ 28 $ 33 $ 58 $ 60 Direct operating expenses 59 60 122 115 Depreciation and amortization 22 21 42 39 Selling, general, and administrative expenses 7 8 16 16 (1)See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown above. Overview - For the three months ended June 30, 2026, the Nitrogen Fertilizer Segment’s operating income and net income increased $39 million and $39 million, respectively, compared to the three months ended June 30, 2025. For the six months ended June 30, 2026, the Nitrogen Fertilizer Segment’s operating income and net income increased $61 million and $61 million, respectively, compared to the six months ended June 30, 2025. These increases resulted from higher revenues which were due primarily to the increases in UAN and ammonia sales prices described below. Net Sales - The $33 million increase for the three months ended June 30, 2026 compared to the three months ended June 30, 2025 was primarily due to favorable UAN and ammonia sales prices contributing $36 million in higher revenue, partially offset by decreased UAN and ammonia sales volumes reducing revenues by $6 million. June 30, 2026 | 38 Table of Contents 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 three months ended June 30, 2026 compared to the three months ended June 30, 2025: (in millions) Price Variance Volume Variance UAN $ 25 $ (4) Ammonia 11 (2) Ammonia and UAN sales price variances were favorable primarily due to the aforementioned improved pricing and inventory conditions discussed in “—Sales Volume and Pricing per Ton” above. The $71 million increase for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 was primarily due to favorable UAN and ammonia sales prices contributing $72 million in higher revenue, combined with favorable ammonia sales volumes contributing $6 million in higher revenue, partially offset by decreased UAN sales volumes reducing revenues by $11 million. 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 six months ended June 30, 2026 compared to the six months ended June 30, 2025: (in millions) Price Variance Volume Variance UAN $ 52 $ (11) Ammonia 20 6 Ammonia and UAN sales price variances were favorable primarily due to aforementioned improved pricing and inventory conditions discussed in “—Sales Volume and Pricing per Ton” above. Cost of Materials and Other - The $5 million decrease and $2 million decrease for the three and six months ended June 30, 2026 compared to the three and six months ended June 30, 2025 were driven primarily by decreased feedstock prices primarily related to petroleum coke, combined with favorable changes in inventory adjustments due to a build of inventory in the current periods compared to a draw of inventory in the prior periods and lower volumes of other purchased feedstocks. These decreases were partially offset by higher distribution costs for the three months ended June 30, 2026 and increased natural gas feedstock prices for the six months ended June 30, 2026 compared to the respective prior period. Non-GAAP Measures Our management uses certain non-GAAP measures, and reconciliations to those measures, to evaluate current and past performance and prospects for the future to supplement our financial information presented in accordance with accounting principles generally accepted in the United States (“GAAP”). These non-GAAP measures are important factors in assessing our operating results and profitability and include the measures defined below. The following are non-GAAP measures we present for the periods ended June 30, 2026 and 2025: EBITDA - Consolidated net income (loss) before (i) interest expense, net, (ii) income tax expense (benefit) and (iii) depreciation and amortization expense. Petroleum EBITDA and Nitrogen Fertilizer EBITDA - Segment net income (loss) before segment (i) interest expense, net, (ii) income tax expense (benefit), and (iii) depreciation and amortization. Refining Margin - The difference between our Petroleum Segment net sales and cost of materials and other. Refining Margin per Throughput Barrel - Refining Margin divided by the total throughput barrels during the period, which is calculated as total throughput barrels per day times the number of days in the period. Direct Operating Expenses per Throughput Barrel - Direct operating expenses for our Petroleum Segment divided by total throughput barrels for the period, which is calculated as total throughput barrels per day times the number of days in the period. June 30, 2026 | 39 Table of Contents 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 underlying operational results of the period or that may obscure results and trends we deem useful. 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 cost basis or financing methods and our ability to incur and service debt and fund capital and turnaround 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. These measures should not be considered substitutes for their most directly comparable GAAP financial measures. See “Non-GAAP Reconciliations” included herein for reconciliation of these amounts. Due to rounding, numbers presented within this section may not add or equal to numbers or totals presented elsewhere within this document. Factors Affecting Comparability of Our Financial Results Our 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 Major Scheduled Turnaround Activities - Total capitalized expenditures as part of planned turnarounds were $1 million and $24 million during the three months ended June 30, 2026 and 2025, respectively, and $1 million and $190 million during the six months ended June 30, 2026 and 2025, respectively. Non-GAAP Reconciliations Reconciliation of Net Income (Loss) to EBITDA and Adjusted EBITDA Three Months Ended June 30, Six Months Ended June 30, (in millions) 2026 2025 2026 2025 Net income (loss) $ 46 $ (90) $ (114) $ (195) Interest expense, net 25 30 83 55 Income tax expense (benefit) 10 (42) (19) (91) Depreciation and amortization 80 78 159 146 EBITDA 161 (24) 109 (85) Adjustments: Changes in RFS obligation, unfavorable 73 89 124 200 Unrealized (gain) loss on derivatives, net (6) 2 151 (1) Inventory valuation impacts, (favorable) unfavorable (19) 32 (138) 8 Adjusted EBITDA $ 209 $ 99 $ 246 $ 122 June 30, 2026 | 40 Table of Contents Reconciliation of Petroleum Segment Net Income (Loss) to EBITDA and Adjusted EBITDA Three Months Ended June 30, Six Months Ended June 30, (in millions) 2026 2025 2026 2025 Petroleum net income (loss) $ 12 $ (137) $ (182) $ (297) Interest expense (income), net (3) 5 (1) 5 Depreciation and amortization 49 48 102 90 Petroleum EBITDA 58 (84) (81) (202) Adjustments: Changes in RFS obligation, unfavorable 73 89 124 200 Unrealized (gain) loss on derivatives, net (6) 2 151 (1) Inventory valuation impacts, (favorable) unfavorable (1) (19) 31 (138) 10 Petroleum Adjusted EBITDA $ 106 $ 38 $ 56 $ 7 (1)The Petroleum Segment’s basis for determining inventory value under GAAP is First-In, First-Out (“FIFO”). Changes in crude oil prices can cause fluctuations in the inventory valuation of crude oil, work in process and finished goods, thereby resulting in a favorable inventory valuation impact when crude oil prices increase and an unfavorable inventory valuation impact when crude oil prices decrease. The inventory valuation impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. Reconciliation of Petroleum Segment Gross Profit (Loss) to Refining Margin Three Months Ended June 30, Six Months Ended June 30, (in millions, except throughput data) 2026 2025 2026 2025 Net sales $ 2,540 $ 1,561 $ 4,344 $ 3,038 Less: Cost of materials and other (2,347) (1,526) (4,149) (3,008) Direct operating expenses (exclusive of depreciation and amortization) (116) (102) (233) (193) Depreciation and amortization (49) (48) (102) (90) Gross profit (loss) 28 (115) (140) (253) Add: Direct operating expenses (exclusive of depreciation and amortization) 116 102 233 193 Depreciation and amortization 49 48 102 90 Refining margin $ 193 $ 35 $ 195 $ 30 Total throughput barrels per day 212,965 172,149 213,613 146,406 Days in the period 91 91 181 181 Total throughput barrels 19,379,847 15,665,597 38,663,976 26,499,565 Refining margin per total throughput barrel $ 9.94 $ 2.21 $ 5.04 $ 1.14 Direct operating expenses per total throughput barrel 5.93 6.45 6.02 7.32 June 30, 2026 | 41 Table of Contents Reconciliation of Nitrogen Fertilizer Segment Net Income to EBITDA and Adjusted EBITDA Three Months Ended June 30, Six Months Ended June 30, (in millions) 2026 2025 2026 2025 Nitrogen Fertilizer net income $ 78 $ 39 $ 127 $ 66 Interest expense, net 7 7 16 15 Depreciation and amortization 22 21 42 39 Nitrogen Fertilizer EBITDA and Adjusted EBITDA $ 107 $ 67 $ 185 $ 120 Liquidity and Capital Resources Our primary source of liquidity continues to be cash generated from operations and its primary uses are for working capital, capital and turnaround expenditures, servicing debt obligations, and paying dividends to our stockholders when approved by the Board of Directors, as discussed further below. Certain external factors, such as volatile commodity prices, industry utilization rates, and market inventory supply, have adversely impacted and are expected to continue to adversely impact our businesses, particularly within our Petroleum segment. On February 12, 2026, CVR Energy completed the issuance of $600 million in aggregate principal amount of 7.500% Senior Notes due 2031 (the “2031 Notes”) and $400 million in aggregate principal amount of 7.875% Senior Notes due 2034 (together with the 2031 Notes, the “Notes”). The net proceeds from the Notes were used to repay all of the aggregate principal balance under the Term Loan, redeem all of the outstanding 2029 Notes, and redeem $217 million aggregate principal amount of the outstanding 2028 Notes. Also, on February 12, 2026, certain subsidiaries of CVR Energy entered into Amendment No. 5 to the CVR Energy ABL (the “CVR Energy ABL Amendment”) with a group of lenders and Wells Fargo Bank, National Association, as administrative agent, and collateral agent. The CVR Energy ABL Amendment amended that certain Amended and Restated ABL Credit Agreement, dated December 20, 2012 (as amended, the “CVR Energy ABL”), to, among other things, (i) increase the aggregate principal amount available under the CVR Energy ABL by an additional $205 million, and (ii) extend the maturity date of the facility from June 2027 to February 2031. Refer to Part I, Item 1, Note 6 (“Long-Term Debt and Finance Lease Obligations”) of this Report and Part II, Item 8, Note 8 (“Long-Term Debt and Finance Lease Obligations”) of the 2025 Form 10-K for further discussion of the above mentioned items. Despite the favorable outcomes of previous SRE petitions, the Company continues to accrue WRC’s 2025 and 2026 RFS obligations at 100% of the required amounts as no waiver has been granted for the corresponding compliance years. WRC’s current 2025 obligation represents approximately 120 million RINs absent a waiver. No assurance can be given regarding the outcome or timing of the EPA’s decision. While we believe that cash generated from operations, combined with existing cash and cash equivalents and access to available lines of credit, will be sufficient to meet anticipated cash requirements for our existing operations for the next 12 months, future expenditure—including those related to turnaround, capital projects, RFS obligations and other operational needs—may exceed current expectations. Our ability to generate sufficient cash from operations, monetize non-core assets, access capital markets, or incur additional debt is subject to these risks and uncertainties, as well as those discussed elsewhere in this Report. Our future liquidity also depends on our operational performance, which is influenced by a range of factors—economic, political, financial, and competitive— many of which are beyond our control. Furthermore, shifts in demand and tightening credit market conditions could impact our financial stability. Subject to business needs, contractual limitations, and market conditions, we may pursue financing strategies such as issuing equity or debt securities, incurring additional borrowings, or refinancing existing debt, through various means, including open market repurchases, redemptions, exchanges, tender offers or privately negotiated transactions. There can be no assurance that we will be able to do any of the foregoing or that any of the foregoing will be undertaken or, if pursued, completed on favorable terms. We closely monitor the amounts and timing of our sources and uses of funds and the availability of borrowings, if any, under the CVR Energy ABL, as defined below. Our ability to incur additional indebtedness could be restricted by the terms of our existing Senior Notes, the CVR Energy ABL, or the Term Loan. The Board will continue to evaluate the economic environment, the Company’s liquidity needs, optimal uses of cash, payment of dividends (if any), and other relevant factors, and may elect to make additional changes to the Company’s capital allocation in future periods. June 30, 2026 | 42 Table of Contents The Company and its subsidiaries were in compliance with applicable financial covenants under their respective debt instruments as of June 30, 2026, and through the date of filing of this Report, as applicable. Cash Balances and Other Liquidity As of June 30, 2026, we had total liquidity of approximately $1.3 billion, which consists of $737 million of consolidated cash and cash equivalents, $540 million available under the CVR Energy ABL, and $50 million available under the CVR Partners’ Credit Agreement (“CVR Partners ABL”). As of December 31, 2025, we had total liquidity of approximately $807 million, which consisted of $511 million of consolidated cash and cash equivalents, $248 million available under the CVR Energy ABL, and $48 million available under the CVR Partners ABL. Long-term debt consisted of the following: (in millions) June 30, 2026 December 31, 2025 CVR Energy: 7.500% Senior Notes, due February 2031 $ 600 $ — 7.875% Senior Notes, due February 2034 400 — 8.500% Senior Notes, due January 2029 — 600 5.750% Senior Notes, due February 2028 183 400 Unamortized debt issuance costs (13) (3) Total CVR Energy debt 1,170 997 Petroleum Segment: Term Loan — 154 Unamortized debt discount and debt issuance costs — (3) Total Petroleum Segment debt — 151 Nitrogen Fertilizer Segment: 6.125% Senior Secured Notes, due June 2028 550 550 Unamortized debt issuance costs (1) (2) Total Nitrogen Fertilizer Segment debt 549 548 Total long-term debt 1,719 1,696 Current portion of long-term debt — 3 Total long-term debt, including current portion $ 1,719 $ 1,699 Refer to Part II, Item 8, Note 8 (“Long-Term Debt and Finance Lease Obligations”) of our 2025 Form 10-K for further discussion of these debt instruments. Capital Spending We divide capital spending needs into two categories: maintenance and growth. Maintenance capital spending includes non-discretionary maintenance projects and projects required to comply with environmental, health, and safety regulations. Growth capital projects generally involve an expansion of existing capacity, reliability improvements, and/or a reduction in direct operating expenses. We undertake growth capital spending based on the expected return on incremental capital employed, which is typically funded by reserves taken in prior years. June 30, 2026 | 43 Table of Contents Our total capital expenditures for the six months ended June 30, 2026, along with our estimated expenditures for 2026, by segment, are as follows: Six Months Ended June 30, 2026 Actual 2026 Estimate Maintenance Growth Total (in millions) Maintenance Growth Total Low High Low High Low High Petroleum $ 42 $ 16 $ 58 $ 79 $ 87 $ 40 $ 43 $ 119 $ 130 Nitrogen Fertilizer 20 11 31 49 57 36 38 85 95 Other 1 — 1 11 14 — 1 11 15 Total $ 63 $ 27 $ 90 $ 139 $ 158 $ 76 $ 82 $ 215 $ 240 Our estimated capital expenditures are subject to further change due to changes in capital projects’ cost, scope, and completion time. For example, we may experience labor or equipment cost changes necessary to comply with government regulations or to complete projects that sustain the operations of the refineries or facilities. The UAN GP Board determines CVR Partners’ capital spending. We will continue to monitor market conditions and make adjustments, if needed, to our current capital spending or turnaround plans. We may also accelerate or defer some capital expenditures from time to time. For example, as described further above, volatile commodity pricing and higher industry utilization and oversupply have had an unfavorable impact on our business and have negatively impacted our cash from operating activities and liquidity. As a result, in October 2024, the Board elected to suspend payment of the cash dividend, defer new growth capital spending, and reduce certain expected capital expenditures, as further discussed under “Liquidity and Capital Resources” above. The Petroleum Segment’s next planned turnaround is currently scheduled to take place during 2027 at the Wynnewood Refinery. There were $1 million and $24 million of capitalized turnaround expenditures during the three months ended June 30, 2026 and 2025, respectively, and $1 million and $190 million during the six months ended June 30, 2026 and 2025, respectively. The Nitrogen Fertilizer Segment’s next scheduled turnaround is currently expected to commence in August 2026 at the East Dubuque Fertilizer Facility at an estimated cost of $35 million to $40 million, and is expected to last approximately 40 days. Turnaround costs in the Nitrogen Fertilizer Segment are not capitalized, but instead are expensed as incurred within Direct operating expenses (exclusive of depreciation and amortization), and are expected to be funded through cash reserves taken preceding the turnaround. Cash Requirements Debt obligations - Except as outlined above and in Part I, Item 1, Note 6 (“Long-Term Debt and Finance Lease Obligations”) of this Report, there have been no material changes to the cash requirements disclosed in our Annual Report on Form 10-K for the year ended December 31, 2025, outside the ordinary course of business. Dividends to CVR Energy Stockholders Dividends, if any—including the amount and timing—are determined at the discretion of the board of directors of the Company (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 applicable record date. Three Months Ended June 30, Six Months Ended June 30, (in millions, except per share data) 2026 2025 2026 2025 Public stockholders $ 3 $ — $ 3 $ — IEP 7 — 7 — Total dividends paid $ 10 $ — $ 10 $ — Dividends per share $ 0.10 $ — $ 0.10 $ — June 30, 2026 | 44 Table of Contents For the second quarter of 2026, the Company, upon approval by the Board on July 29, 2026, declared a cash dividend of $0.10 per share, or $10 million, which is payable August 17, 2026 to shareholders of record as of August 10, 2026. Of this amount, IEP will receive $7 million due to its ownership interest in the Company’s shares. Distributions to CVR Partners’ Unitholders Distributions, if any—including the amount, timing, and the UAN GP Board’s distribution policy—are subject to change at the discretion of the UAN GP Board. This includes the definition of available cash and any related reserves, which may be adjusted based on the UAN GP Board’s judgment and prevailing business concerns. The following table presents quarterly distributions paid by CVR Partners to CVR Partners’ unitholders, including amounts received by the Company and IEP, during 2026 and 2025 (amounts presented in the table below may not add to totals presented due to rounding): Three Months Ended June 30, Six Months Ended June 30, (in millions, except per unit data) 2026 2025 2026 2025 Public unitholders $ 26 $ 14 $ 28 $ 26 IEP 1 1 1 1 CVR Energy 16 9 17 16 Total distributions paid $ 42 $ 24 $ 46 $ 42 Distributions per common unit (1) $ 4.00 $ 2.26 $ 4.37 $ 4.01 (1)Amount represents the cumulative distributions, calculated quarterly, paid in the respective period. For the second quarter of 2026, upon approval by the UAN GP Board on July 29, 2026, CVR Partners declared a distribution of $6.08 per common unit, or approximately $64 million, which is payable August 17, 2026 to unitholders of record as of August 10, 2026. Of this amount, CVR Energy and IEP will receive approximately $24 million and $2 million, respectively, with the remaining amount payable to public unitholders. Cash Flows The following table sets forth our consolidated cash flows for the periods indicated below: Six Months Ended June 30, (in millions) 2026 2025 Change Net cash provided by (used in): Operating activities $ 371 $ (19) $ 390 Investing activities (86) (267) 181 Financing activities (59) (105) 46 Net increase (decrease) in cash and cash equivalents $ 226 $ (391) $ 617 Operating Activities The change in operating cash flows for the six months ended June 30, 2026, compared to the six months ended June 30, 2025, was primarily driven by an $81 million reduction in net loss combined with $261 million of non-cash adjustments, primarily related to unrealized loss on derivatives resulting from losses on crack swap positions in the current period and deferred income taxes. In addition, working capital provided a favorable impact of approximately $48 million, primarily due to higher commodity prices affecting accounts receivable, accounts payable and inventory, as well as an increase in the RFS obligation resulting from higher RIN prices coupled with an increase in renewable volume requirements for the 2026 and 2027 compliance years in the current period. June 30, 2026 | 45 Table of Contents Investing Activities The change in net cash used in investing activities for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 was primarily due to a decrease in turnaround expenditures of $190 million due to the 2025 Refinery Turnaround. Financing Activities The change in net cash used for financing activities for the six months ended June 30, 2026 compared to the six months ended June 30, 2025 was primarily due to the cash inflow of $1.0 billion received from issuance of the Notes during 2026 being used to fund principal payments on the 2029 Notes and 2028 Notes of $817 million and the Term Loan of $157 million, as well as the $25 million call premium on the 2029 Notes, whereas in the prior period the $72 million of Term Loan principal payments was funded with cash on hand. The Company also paid deferred financing costs of $15 million related to the issuance of the Notes and an additional $13 million in dividends and distributions to CVR Energy stockholders and CVR Partners noncontrolling interest holders in 2026 compared to the prior year. Critical Accounting Estimates Our critical accounting estimates are disclosed in the “Critical Accounting Estimates” section of our 2025 Form 10-K. No modifications have been made during the three and six months ended June 30, 2026 to these estimates.