CVR Energy (CVI) 8-K Regulation FD Disclosure

Exhibit 99.1

CVR ENERGY, INC. NYSE: CVI and UAN

The following information contains forward-looking statements based on management’s current expectations and beliefs, as well as a number of assumptions concerning future events. These statements are subject to risks, uncertainties, assumptions and other important factors. You are cautioned not to put undue reliance on such forward-looking statements (including forecasts and projections regarding our future performance) because actual results may vary materially from those expressed or implied as a result of various factors, including, but not limited to (i) those set forth under “Risk Factors” in CVR Energy, Inc.’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and any other filings CVR Energy, Inc. makes with the Securities and Exchange Commission, and (ii) those set forth under “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” in the CVR Partners, LP Prospectus and any other filings CVR Partners, LP makes with the Securities and Exchange Commission. CVR Energy, Inc. assumes no obligation to, and expressly disclaims any obligation to, update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Diversified in mid-continent — 115k bpd high complexity refinery NYSE — CVI NYSE — UAN — A Nitrogen fertilizer plant using Market Cap(1) — $2.1 billion Market Cap(1) — $1.6 billion pet coke gasification, rated CVI owns ~ 70% capacity of 1,225 tpd ammonia; 2,025 tpd UAN Nitrogen in PADD IV 4 PADD 2 Operate higher margin markets PADD II PADD V 5 Logistic assets supporting both business Financial flexibility PADD III Petroleum Segment Fertilizer Segment 1) As of October 10, 2011 22222

Refining & Fertilizer Utilization1 Capital Expenditures 100% 554 $M 600 95% 90% $M 400 86 144 85% $M 200 49 32 80% 75% $M 0 Prior to 2008 2009 2010 2011E 70% 2008 Petroleum Nitrogen Other 2008 2009 2010 2011FH Gasifier Ammonia UAN Refinery Utilization Market Cap / Operating cash flow NYMEX 211 & Brent-WTI Differential 150 $M 3 $Bn 45 40 35 2 $Bn 100 $M 30 24.12 Cap 25 20 OCF 50 $M 1 $Bn 15 Mkt /Barrel 10 $5 0 $M — $Bn 0 -5 -50 $M -10 -100 $M 1/1/2009 3/1/2009 5/1/2009 7/1/2009 9/1/2009 11/1/2009 1/1/2010 3/1/2010 5/1/2010 7/1/2010 9/1/2010 11/1/2010 1/1/2011 3/1/2011 5/1/2011 7/1/2011 9/1/2011 Mar Jun Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec Mar Jun NYMEX 211 Brent-WTI Differential (EB-CL) 2008 2009 2010 2011 Free cash flow Market Capitalization 1)Adjusted for major scheduled turnaround, third-party outage on air Source: CapitalIQ separation unit and UAN vessel rupture.

Cushing In-Flows vs. Outflows Pipelines In-bound Pipelines Out-bound Canada (In Thousands) Capacity (In Thousands) Capacity Keystone ~ 590 Clearbrook Outbound ~ 600 North Dakota Spearhead ~ 200 Minnesota Total Current ~ 600 BP/Basin ~ 450 Keystone XL: Wisconsin ~ 700 South Dakota (Proposed) Seaway ~ 300 Sioux Falls Wrangler: ~ 800 Iowa White Cliff ~ 60 (Proposed) Nebraska Flanagan Des ~ 2,100 Moines Rail (Hawthorn) ~ 40 TOTAL Omaha bpd Illinois Kansas (Various) ~ 60 Plainville Kansas Topeka Kansas City Valley Center Plains Wichita Pipeline Columbia Missouri Total Current ~ 1,700 Coffeyville Keystone XL: (Proposed) ~ 110 Cushing Tulsa Oklahoma City Oklahoma Parnon (Proposed) ~ 35 Arkansas Wichita Falls Pony Express (Proposed) ~ 210 Corsicana Louisiana ~2,055 Midland TOTAL bpd Texas Nederland Houma Houston Sugar Land Freeport

100.0 95.0 88.7 86.1 84.7 81.7 90.0 82.1 85.0 Utilization 80.0 75.0 Percent 70.0 65.0 60.0 2007 2008 2009 2010 2011 1H PADD 1 PADD II PADD III PADD IV PADD V Average Source: EIA Magellan Pipeline Inventories Magellan Pipeline Inventories Gasoline Prior 4 Year Average ULS Diesel Prior 4 Year Average 10 8 8 5 Barrels 5 Barrels 3 Million 3 Million 0 0 Jan Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2011 2011

CVR Barrels Sold 127,142 110,860 140,000 104,476 120,000 100,000 bpd 80,000 60,000 40,000 20,000 — 2006 2010 2011 YTD PADD II — Group 3 Basis CVR Market Terminals $12 Total 10 Year Average = $1.57 / bbl Year $10 Added Terminals $8 5 Year Average = $1.95 / bbl Pre-2006 $6 2 $4 2006 8 2007 17 /Barrel $2 2008 23 $ $0 ($2) 2009 30 2010 42 ($4) Magellan Pipeline 2Q’06 3Q’06 4Q’06 1Q’07 2Q’07 3Q’07 4Q’07 1Q’08 2Q’08 3Q’08 4Q’08 1Q’09 2Q’09 3Q’09 4Q’09 1Q’10 2Q’10 3Q’10 4Q’10 1Q’11 2Q’11 NuStar Pipeline Enterprise Pipeline Explorer Pipeline Corporate Headquarters

Canada Bakken Montana Clearbrook Big Timber North Dakota Minnesota Jackson Wisconsin Wyoming South Dakota Sioux Falls Sioux City Iowa Nebraska Flanagan Des Salt Lake City Moines Omaha Utah DJ Illinois Colorado Phillipsburg Denver Basin Plainville Kansas Topeka Kansas City Valley Center Humboldt Wichita Columbia Plains Missouri Winfield Pipeline Broome Coffeyville Legend Shidler Bartlesville Cushing Coffeyville Resources Tulsa Refining & Marketing and Nitrogen Oklahoma City New Mexico Oklahoma Fertilizer Arkansas Coffeyville Resources Refined Fuel Wichita Falls Products / Asphalt Terminal Coffeyville Resources Crude Transportation Corsicana Louisiana Offshore Deepwater Crude Midland Texas Foreign Crude Nederland Coffeyville Resources Crude Oil Houma Houston Pipeline Third-Party Crude Oil Pipeline Sugar Land Freeport Total 4.9 mm bbls * Under construction CVR Energy Headquarters

North Dakota South Dakota Nebraska Total Consumed Crude Discount to WTI $3 Colorado 3 year average is 3.44 Kansas Missouri $2 $1 $0 ($1) /bbl Oklahoma ($2) $ ($3) ($4) ($5) ($6) Texas ($7) Corporate Refining Operations Headquarters Barrels Gathered Per Day — LTM Q2 2011 15,000+ Up to 10,000 Up to 1,000 Growth Prospects 88888

NITROGEN FERTILIZER MLP

Strategically Located Assets & Logistics WA MT ND MN OR WI ID SD WY IA NE NV CA IL UT CO KS MO NM AR AZ OK TX LA Additional Shipments East of the Mississippi Corporate (1) As of August 4, 2011 Rail Distribution Fertilizer Plant Headquarters LTM Q2 2011 Tons Sold by State 100,000+ 10,000 to 100,000 Up to 10,000 LTM Q2 2011 Total Tons Sold ~ 738,000 1010101010

Stable & Economic Feedstock Abundant Supply of Third-Party Pet Coke in the Region U.S. Pet Coke Exports and Consumption 38% 44% 43% 41% 42% 38% 39% 41% 43% 47% 54% Source: Oil & Gas Journal 57% 69% 62% 62% 60% 56% 59% 57% 57% 53% 46% Texas Gulf Coast Coke Production = 40,000 tons/day Consumption Net Exports Source: EIA. Corporate Rail Distribution Fertilizer Plant Headquarters

Market Fundamentals — Key Growth Factors Declining Farmland Per Capita World Population: 1950-2050 (Hectares per Person) 10 3,500 9 3,000 8 7 2,500 6 2,000 5 Billions 1,500 4 3 1,000 2 500 1 0 0 Australia Canada USA Brazil India 1950 1970 1990 2010 2030 2050% Change: (31%) (26%) (33%) (14%) (42%) 1980 1990 2000 2008 Per Capita Consumption of Meat (lbs per year) U.S. corn use for wet-mill products 250 1,800 1,600 200 1,400 150 Bushels1,200 of1,000 100 800 1965 600 50 1998 Millions 400 2030 0 200 0 Traditional consumption Ethanol production Source: USDA, Census Bureau, World Bank, http://data.worldbank.org/indicator/AG.LND.ARBL.HA.PC 1212121212

• Corn consumes the largest amount of nitrogen fertilizer• At current & projected corn prices, farmers expected to generate significant income• Nitrogen fertilizer represents small percent of farmer’s input costs Corn Spot Prices Breakdown of U.S. Farmer Total Input Costs Input Costs and Prices per Bushel ($) 7 Corn Futures Prices: 9 Current 30 Day: $6.00 8 $6.07 6 12 Month: $5.93 7 5 6 5-Yr Avg. 4 3.68 $4.28 3.10 3.51 bu 5 Avg. % Total of Cost: 2.97 5-Yr Prior Avg. Fertilizers 22% per 3 2.60 4 $2.12 $ Other Variable Costs 13% 3 2 Seed and Chemicals 17% 2 1 Fixed Costs 48% 1 0 0 2005 2006 2007 2008 2009 Source: CIQ Source: CIQ Note: Fixed Costs include labor, machinery, land, taxes, insurance, and other. 1313131313

Market Fundamentals Global Shift in Cost of Production Natural Gas Prices — United States vs. Western Europe Natural Gas Price ($/MMBtu) $14 NBP, Britain $12 $10.33 Spot $10 $8 $6 $4 $2 Henry Hub, Louisiana $3.49 spot $- Sep’07 Feb’08 Jul’08 Dec’08 May’09 Oct’09 Mar’10 Aug’10 Jan’11 Jun’11 Nov’11 Apr’12 Sep’12 Source: European prices converted from GBP/Therm to $/MMBtu, based on daily exchange rate Historical Sources: Capital IQ NBP Monthly Spot Rate, Henry Hub Monthly Spot Rate Forecast Sources: Capital IQ NBP Forward Rate 10/07/11, Henry Hub Futures Nymex Exchange 10/07/11 Spot price as of 10/07/11 1414141414

MLP Forecasted Available Cash Illustrative EBITDA Sensitivity to UAN and Ammonia Prices(1) EBITDA(1) ($MM) Forecasted NTM 5 Year Avg. Spot Prices(2) 3/31/2012 $147 UAN Ammonia 400300 450 500 550 547 600650350 700 Price per Ton ($) Net Sales 171 221 246 271 296 297321196 346 371 Available 13 63 88 113 138 14016338 188 213 Cash 1) Based on projected next twelve months 3/31/12 cost structure as provided in the MLP’s prospectus dated April 7, 2011. 2) Based on 5 year average Ammonia and UAN spot prices of $467/ton and $292/ton respectively and forecasted next twelve months cost structure. 1515151515

FINANCIAL HIGHLIGHTS

YTD Q2 2011 Operating Cash Flow Per Barrel of Crude Throughput Adjusted EBITDA / Interest Coverage Ratio (1) $12.0 10.00x $8.0 8.00x $11.9 $8.6 6.00x $4.0 $6.3 8.54x $0.9 4.00x $0.0 $(2.1) 2.00x 2.19x -$4.0 0.00x HFC CVI WNR TSO ALJ LTM Q2 2010 LTM Q2 2011 Net Debt / (Net Cash) $1.1 billion of Liquidity as of August 4, 2011 $600 $42 $400 $243 Cash $487 $454 $200 Millions $277 In Working Capital $-$(156) Facilities $(200) Excess inventory 2008 2009 2010 YTD Q2 $810 2011 Source: Capital IQ, Company Filings (1) See Appendix for EBITDA reconciliation 1717171717

Q2 2011 LTM CVI Operating Expense(a) per Barrel of Crude Operating Expense(a) per Barrel of Crude $6.90 $4.00 $7.00 $3.80 $6.10 $6.00 $5.41 $5.47 $3.60 $4.81 $3.40 $5.00 $3.20 $3.91 $3.00 $4.00 $2.80 $3.00 $2.60 $2.00 $2.40 $1.00 $2.20 $2.00 $0.00 2008 2009 2010 LTM Q2 CVI FTO (b) HOC DK WNR TSO 2011 (a) Excludes Turnaround (b) Frontier is Q1 2011 LTM 1818181818

Adjusted Operating Cash to Cash Waterfall EBITDA(1) Cash Flow $1,000 $ in TTM TTM TTM TTM Thousands 6/30/10 6/30/11 6/30/10 6/30/11 $900 $55 $72 $800 $54 $64 Petroleum 61,777 402,523 (31,488) 298,340 $700 Fertilizer 43,056 94,318 64,977 96,523 $600 $419 $500 Total Consolidated $400 D&A 96,995 469,665 $748 Adjusted $300 $88 EBITDA(1) N.I. $200 $205 $100 39,469 342,399 $- $63 384% change 768% change (1) See Appendix for reconciliation 1919191919

Refinery turnaround year(1) Capital Summary Prior to ($ in millions) 2007 2007 2008 2009 2010 2011E(2) Non-discretionary Petroleum $193.8 $137.3 $50.1 $30.6 $18.2 $62.5 Nitrogen 7.5 4.4 6.5 2.6 8.9 9.0 Total non-discretionary $201.3 $141.7 $56.6 $33.2 $27.1 $71.5 Discretionary Petroleum $73.0 $124.3 $10.3 $3.4 $1.6 $31.5 [$23m Cushing Project] Nitrogen 6.5 2.1 17.6 10.8 1.2 39.0 [$38m UAN Expansion] Other 4.6 0.5 2.0 1.4 2.5 2.0 Total discretionary $84.1 $126.9 $29.9 $15.6 $5.3 $72.5 Total spending $285.4 $268.6 $86.5 $48.8 $32.4 $144.0 (1) Company expenses its turnaround and will expense an estimated $54 million in 2011. (2) Includes $38mm of the UAN expansion project and $23mm for Cushing tank farm project 2020202020

as of June 30, 2011 Date Closed Balance 1st Call Date Maturity Date 1st Lien 4/ 2010 $247.1 April 6, 2012 (106.75) April 6, 2015 2nd Lien 4/ 2010 $222.8 April 6, 2013 (108.15) April 6, 2017 Asset Based Loan 2/ 2011 $31.6* August 22, 2015 MLP Term Loan 4/ 2011 $125.0 April 13, 2016 MLP Revolver 4/ 2011 $ — April 13, 2016 300 250 1st Lien 200 ABL 2nd Lien Millions 150 n MLP Term I 100 $ Loan 50 Availability under 0 credit facilities 2011 2012 2013 2014 2015 2016 2017 Total Liquidity** at 8/04/11 is $1.1 B *Letters of credit outstanding ** Liquidity includes cash, excess inventory & working capital facility 2121212121

Q & A

APPENDIX

To supplement the actual results in accordance with U.S. generally accepted accounting principles (GAAP), for the applicable periods, the Company also uses certain non-GAAP financial measures as discussed below, which are adjusted for GAAP-based results. The use of non-GAAP adjustments are not in accordance with or an alternative for GAAP. The adjustments are provided to enhance the overall understanding of the Company’s financial performance for the applicable periods and are also indicators that management utilizes for planning and forecasting future periods. The non-GAAP measures utilized by the Company are not necessarily comparable to similarly titled measures of other companies. The Company believes that the presentation of non-GAAP financial measures provides useful information to investors regarding the Company’s financial condition and results of operations because these measures, when used in conjunction with related GAAP financial measures (i) together provide a more comprehensive view of the Company’s core operations and ability to generate cash flow, (ii) provide investors with the financial analytical framework upon which management bases financial and operational planning decisions, and (iii) presents measurements that investors and rating agencies have indicated to management are useful to them in assessing the Company and its results of operations. 2424242424

EBITDA: EBITDA represents net income before the effect of interest expense, interest income, income tax expense (benefit) and depreciation and amortization. EBITDA is not a calculation based upon GAAP; however, the amounts included in EBITDA are derived from amounts included in the consolidated statement of operations of the Company. Adjusted EBITDA by operating segment results from operating income by segment adjusted for items that the company believes are needed in order to evaluate results in a more comparative analysis from period to period. Additional adjustments to EBITDA include major scheduled turnaround expense, the impact of the Company’s use of accounting for its inventory under first-in, first-out (FIFO), net realized gains/losses on derivative activities, share-based compensation expense, loss on extinguishment of debt, and other income (expense). Adjusted EBITDA is not a recognized term under GAAP and should not be substituted for operating income or net income as a measure of performance but should be utilized as a supplemental measure of financial performance in evaluating our business. First-in, first-out (FIFO): The Company’s basis for determining inventory value on a GAAP basis. Changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in favorable FIFO impacts when crude oil prices increase and unfavorable FIFO impacts when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. 2525252525

Below is a reconciliation of Operating Income to Adjusted EBITDA, by segment (in thousands) TTM 6/30/10 TTM 6/30/11 Petroleum Operating income 6,844 396,241 Depreciation and amortization 65,137 67,720 Realized gain (loss) on derivatives, net 11,213 (24,600) Other income (expense) 714 325 FIFO impact (favorable), unfavorable (20,960) (61,394) Share-based compensation (2,656) 17,468 Loss on disposal of fixed assets 1,292 1,455 Major scheduled turnaround expense 193 5,308 Adjusted EBITDA 61,777 402,523 Fertilizer Operating income 22,524 56,998 Depreciation and amortization 18,685 18,412 Other income (expense) (74) 74 Share-based compensation 1,916 13,915 Loss on disposal of fixed assets — 1,369 Major scheduled turnaround expense 5 3,550 Adjusted EBITDA 43,056 94,318 2626262626

TTM 6/30/10 TTM 6/30/11 (In Thousands) Consolidated Net Income attributable to CVR Energy (15,187) 196,155 Interest expense, net of interest income 42,156 53,337 Depreciation and amortization 85,671 88,002 Income tax expense (16,403) 125,770 EBITDA adjustments included in NCI - (1,589) FIFO impact (favorable), unfavorable (20,958) (61,393) Share-based compensation 3,751 54,029 Loss on disposal of fixed asset 1,292 2,823 Loss on extinguishment of debt 16,475 3,673 Major scheduled turnaround expense 198 8,858 Adjusted EBITDA 96,995 469,665 2727272727