EX-99.1 2 y92286exv99w1.htm EX-99.1
Exhibit 99.1

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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.

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Diversified in mid-continent

– 115k bpd high complexity refinery

NYSE – CVI NYSE – UAN

– Rated capacity of 1,225 tpd Market Cap(1) — $2.0 billion Market Cap(1) — $1.6 billion

ammonia; 2,025 tpd UAN CVI owns ~ 70% Nitrogen fertilizer using pet coke gasification Crude slate flexibility PADD IV 4 PADD 2

PADD II

Operate in higher margin PADD V 5 markets Unique refining logistic assets supporting the business PADD III Financial flexibility

Petroleum Segment Fertilizer Segment

1) As of August 5, 2011

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• Received first Canadian barrels on Keystone pipeline • Refinanced revolver in petroleum segment

• Completed IPO of fertilizer segment in a simplified MLP structure

• Completed $150mm credit facility to support MLP growth capital

• Private equity shareholder “overhang” removed • Added management to support MLP growth strategy • Carbon solution in fertilizer business

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Cushing In-Flows vs. Outflows

Canada

Pipelines In-bound Pipelines Out-bound (In Thousands) Capacity (In Thousands) Capacity

Keystone (Current) ~ 590 Outbound ~ 600 Clearbrook North Dakota

Keystone XL: (Proposed) ~ 110 Keystone XL:

~ 500 Minnesota

(Proposed) Spearhead ~ 200

Monarch Wisconsin

~ 350

BP/Basin ~ 450 (Proposed) South Dakota

Seaway ~ 300 Enterprise & Sioux Falls Energy Transfer ~ 400

Iowa

White Cliff ~ 60 (Proposed) Nebraska

Des Flanagan

Rail (Hawthorn) ~ 40 ~ 1,850 Moines TOTAL Omaha

Kansas (Various) ~ 60 bpd Illinois

~ 1,810 Plainville Kansas Topeka Kansas City TOTAL Valley Center Plains bpd Wichita Pipeline Columbia

Missouri

Coffeyville

NYMEX 2-1-1 & Brent-WTI Differential Cushing

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Tulsa Oklahoma

40 City Oklahoma

Arkansas

30 Wichita Falls

20.6 20 10

Corsicana Louisiana

/Barrel 0 Midland

Texas

$

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-10 Nederland Houma Houston Sugar Land

1/1/2010 2/1/2010 3/1/2010 4/1/2010 5/1/2010 6/1/2010 7/1/2010 8/1/2010 9/1/2010 10/1/2010 11/1/2010 12/1/2010 1/1/2011 2/1/2011 3/1/2011 4/1/2011 5/1/2011 6/1/2011 7/1/2011 8/1/2011 Freeport NYMEX 2-1-1 Brent-WTI Differential (EB-CL)

4 4444

Total Canadian oil production is expected to increase 68% by 2025 Production expectations continue to increase

Canadian Oil Sands & Conventional Production

Refining Utilization

100.0

95.0

88.7 86.1 84.7 90.0 82.1 85.0

80.0

75.0

70.0

2007 2008 2009 2010 Source: EIA PADD 1 PADD II PADD III

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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

Year Total

10 Year Average = $1.57 / bbl $10 Added Terminals

$8 5 Year Average = $1.95 / bbl $6 Pre-2006 2 $4 2006 8 2007 17 /Barrel $2 2008 23 $ $0 2009 30 ($2) 2010 42 ($4) Magellan Pipeline NuStar 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 Enterprise Pipeline Corporate Headquarters

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Canada

Bakken

Montana Clearbrook Big Timber

North Dakota

Minnesota

Jackson Wisconsin Wyoming South Dakota

Sioux Falls

Sioux City Iowa

Nebraska Flanagan

Salt Lake City Des 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

Oklahoma City

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Refining & Marketing and Nitrogen New Mexico Oklahoma

Arkansas

Fertilizer

Coffeyville Resources Refined Fuel Wichita Falls Products / Asphalt Terminal Coffeyville Resources Crude

Transportation Corsicana Louisiana Offshore Deepwater Crude Midland Foreign Crude Texas

Nederland Houma

Coffeyville Resources Crude Oil

Pipeline Houston

Sugar Land

Third-Party Crude Oil Pipeline Freeport

Total 4.9 mm bbls

CVR Energy Headquarters

* Under construction

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North Dakota

South Dakota

Nebraska

Total Consumed Crude Discount to WTI

$3 Colorado

Kansas $2 Missouri $1 $0 ($1)

/bbl Oklahoma

($2) $

($3) ($4) ($5) ($6)

Texas

($7)

Corporate Refining Operations Headquarters Barrels Gathered Per Day – LTM Q2 2011

• Twenty year off-take agreement for 850,000 annual CO2 tons

• Chaparral to construct CO2

Kansas

compression facility, install pipeline to the North Burbank field in OK

• CO2 enhanced oil recovery to increase current field production Oklahoma

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• Fertilizer consumption is driven by: Global Fertilizer Consumption Over Time

(Millions of Metric Tonnes) (Population in Millions)

• Population growth

200 8,000

• Decrease in farmland

• Income growth in emerging 7,000 markets, preference for proteins 150 6,000

• Ethanol production 5,000

• Nitrogen represents ~63% of 100 4,000 fertilizer consumption(1)

3,000

• Nitrogen has the most stable demand because it must be applied 50 2,000 annually

1,000

• Primary determinant of crop yield

0 0

• Current “UAN” fertilizer book of 1972 1977 1982 1987 1992 1997 2002 2007 2010 (2)

~300k tons at >$300/ ton net back Population

Nitrogen Phosphate Potash

(midyear)

Note: Nutrient Tonnes; Fertilizer Years.

(1) Based on International Fertilizer Industry Association Source: International Fertilizer Industry Association; U.S. Bureau of the Census, International Data (2) As of August 4, 2011 Base

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• World demand for grain has increased significantly, leading to increases in grain prices

– USDA projects 2011 U.S. grain stocks to be at 15-year lows

• Grain production is directly tied to nitrogen fertilizer applications

• Farmland per capita is declining

World Grain Production and Stock to Use Ratios Declining Farmland Per Capita

Grain Production (Millions of Tons) Stock to Use Ratio (%) (Hectares per Person) 2,000 40 3,500

3,000 1,800 35

2,500 1,600 30 2,000 1,400 25 1,500 1,200 20 1,000

1,000 15 500

800 10 0

1980 1985 1990 1995 2000 2005 2011 Australia Canada USA Brazil India

Note: Grains include barley, corn, oats, sorghum, and wheat. Stock to use ratio is ending stocks % Change: (30%) (22%) (25%) (25%) (50%) / consumption for that year. Years are fertilizer years ending on June 30. Data as of February 28, 2011. 1980 1990 2000 2007 Source:USDA

Source: World Bank, http://data.worldbank.org/indicator/AG.L ND.ARBL.HA.PC

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• 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 ($) 8 8 Corn Futures Prices: Current 12 Month: $7.22 7 7 $7.13 30 Day: $6.96 6 6 5 5 4 4 3.68 3.10 3.51 Avg. % Total of Cost: 5-Yr Prior Avg. 2.97 3 3 2.60 Fertilizers 22% $2.14 5-Yr Avg. Other Variable Costs 13% 2$ 4.20 2 Seed and Chemicals 17% 1 1 Fixed Costs 48% 0 0 2001 2002 2004 2006 2007 2009 2011 2005 2006 2007 2008 2009 Source: CIQ Source: CIQ Note: Fixed Costs include labor, machinery, land, taxes, insurance, and other.

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Financial Highlights

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

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Year—End Net Debt / Cash $ Millions 500 Net Cash 1$ 153 0

3 3 5 4 (500) Net (1,000) Debt (1,500) (2,000) 2007 2008 2009 2010 2011 Q2 1 CVI Ranking Relative to Peers Peer range*: ALJ, HFC, 1 being the highest net cash WNR, TSO, DK *Note: Holly & Frontier Historical Data as Reported (1) Proforma balance sheet from CVR 10-Q dated August 8, 2011

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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 Nitrogen 6.5 2.1 17.6 10.8 1.2 39.0 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 $54mm in 2011 (2) Includes $38mm of the UAN expansion project and $23mm for Cushing tank farm project

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Q2 2011 LTM CVI Operating Expense(a) per Barrel of Crude Operating Expense(a)

per Barrel of Crude $4.00 $6.90 $7.00 $3.80 $6.10 $3.60 $6.00 $5.41 $4.81 $3.40 $5.00 $4.01 $3.20 $3.91 $3.00 $4.00 $2.80 $3.00 $2.60 $2.00 $2.40 $2.20 $1.00 $2.00 $0.00 2008 2009 2010 LTM Q2 CVI ALJ FTO (b) HOC WNR TSO 2011

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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 credit facilities 0 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

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Q & A

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Appendix

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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.

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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.

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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

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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