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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): August 8, 2011
CVR ENERGY, INC.
(Exact name of registrant as specified in its charter)
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Delaware
(State or other
jurisdiction of
incorporation)
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001-33492
(Commission File Number)
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61-1512186
(I.R.S. Employer
Identification Number) |
2277 Plaza Drive, Suite 500
Sugar Land, Texas 77479
(Address of principal executive offices,
including zip code)
Registrant’s telephone number, including area code: (281) 207-3200
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the
filing obligation of the registrant under any of the following provisions:
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Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
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Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
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Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
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Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
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| Item 7.01. |
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Regulation FD Disclosure. |
On August 8, 2011, CVR Energy, Inc., or the “Company,” posted an investor presentation to its
website at www.cvrenergy.com under the tab “Investor Relations”. The information included in the
presentation provides an overview of the Company’s strategy and performance and includes, among
other things, information concerning refining and fertilizer markets. The presentation is intended
to be made available to stockholders, analysts and investors, including investor groups
participating in forums such as sponsored investor conferences, during the third quarter of 2011.
The presentation is furnished as Exhibit 99.1 to this Current Report on Form 8-K.
In accordance with General Instruction B.2 of Form 8-K, the information in this
Current Report on Form 8-K and Exhibit 99.1 attached hereto are being furnished pursuant to Item
7.01 of Form 8-K and will not, except to the extent required by applicable law or regulation, be
deemed filed by the Company for purposes of Section 18 of the Securities Exchange Act of 1934, as
amended, or otherwise subject to the liabilities of that Section, nor will any of such information
or exhibits be deemed incorporated by reference into any filing under the Securities Act of 1933,
as amended, or the Securities Exchange Act of 1934, as amended, except as expressly set forth by
specific reference in such filing.
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| Item 9.01. |
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Financial Statements and Exhibits |
(d) Exhibits
The following exhibit is being “furnished” as part of this Current Report on Form 8-K:
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| 99.1
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Slides from management presentation. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant
has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
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Date: August 8, 2011
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CVR ENERGY, INC.
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By: |
/s/ Edward Morgan
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Edward Morgan |
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Chief Financial Officer and Treasurer |
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exv99w1
| 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 |
| – 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 |
| Operate in higher margin PADD V 5 markets Unique refining
logistic assets supporting the business PADD III Financial flexibility |
| Petroleum Segment Fertilizer
Segment |
| • 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 |
| Cushing In-Flows vs. Outflows |
| 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: |
| (Proposed)
Spearhead ~ 200 |
| BP/Basin ~ 450 (Proposed) South Dakota |
| Seaway ~ 300 Enterprise & Sioux Falls Energy Transfer ~ 400 |
| White Cliff ~ 60 (Proposed) Nebraska |
| 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 |
| NYMEX 2-1-1 & Brent-WTI Differential Cushing |
| -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) |
| Total Canadian oil production is expected to increase 68% by 2025
Production expectations continue to increase |
| Canadian Oil Sands & Conventional Production |
| 88.7 86.1 84.7 90.0 82.1 85.0 |
| 2007 2008 2009 2010 Source: EIA PADD 1
PADD II PADD III |
| 127,142 110,860 140,000 104,476 120,000 |
| 100,000 bpd 80,000 60,000 |
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| 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 |
| Montana Clearbrook Big
Timber |
| Jackson Wisconsin
Wyoming South Dakota |
| Salt Lake City Des Moines Omaha |
| Denver Basin
Plainville
Kansas
Topeka Kansas City
Valley Center Humboldt
Wichita Columbia |
| Winfield Pipeline Broome Coffeyville |
| Shidler Bartlesville Cushing |
| Coffeyville Resources Tulsa |
| Refining & Marketing and Nitrogen New Mexico
Oklahoma |
| Coffeyville Resources Refined Fuel Wichita
Falls Products / Asphalt Terminal Coffeyville
Resources Crude |
| Transportation Corsicana
Louisiana Offshore Deepwater Crude
Midland Foreign Crude Texas |
| Coffeyville Resources Crude Oil |
| Third-Party Crude Oil Pipeline Freeport |
| Total Consumed Crude Discount to WTI |
| Kansas $2 Missouri $1 $0 ($1) |
| 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 |
| compression facility, install pipeline to the
North Burbank field in OK |
| • CO2 enhanced oil recovery to increase current field production
Oklahoma |
| • Fertilizer consumption is driven by: Global Fertilizer Consumption Over Time |
| (Millions of Metric Tonnes)
(Population in Millions) |
| • 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) |
| • Nitrogen has the most stable demand because it must be applied 50 2,000
annually |
| • Primary determinant of crop yield |
| • Current “UAN” fertilizer book of 1972 1977 1982 1987 1992 1997 2002 2007 2010
(2) |
| ~300k tons at >$300/ ton net back Population |
| Nitrogen Phosphate Potash |
| Note: Nutrient Tonnes;
Fertilizer Years. |
| (1) Based on International Fertilizer Industry Association Source: International
Fertilizer Industry Association; U.S. Bureau of the Census, International Data (2) As of
August 4, 2011 Base |
| • World demand for grain has increased significantly, leading to increases in grain prices |
| – USDA projects 2011 U.S. grain stocks to be at 15-year lows |
| • Grain production is directly tied to nitrogen fertilizer applications |
| • Farmland per capita is declining |
| World Grain Production and Stock to Use Ratios Declining Farmland Per Capita |
| Grain Production (Millions of Tons) Stock to Use Ratio (%) (Hectares per Person)
2,000 40 3,500 |
| 2,500 1,600 30 2,000 1,400 25 1,500 1,200 20 1,000 |
| 1980 1985 1990 1995 2000 2005 2011 Australia Canada USA Brazil India |
| Note: Grains include barley, corn, oats, sorghum, and wheat. Stock to use ratio is ending
stocks % Change: (30%) (22%) (25%) (25%) (50%) / consumption for that year. Years are
fertilizer years ending on June 30. Data as of February 28, 2011. 1980 1990 2000 2007
Source:USDA |
| Source: World Bank,
http://data.worldbank.org/indicator/AG.L
ND.ARBL.HA.PC |
| • Corn consumes the largest amount of nitrogen fertilizer • At
current & projected corn prices, farmers expected to generate significant income •
Nitrogen fertilizer represents small percent of farmer’s input costs Corn Spot
Prices Breakdown of U.S. Farmer Total Input Costs Input Costs and Prices per Bushel ($) 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. |
| 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 $- |
| 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 |
| 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 |
| 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 |
| 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 |
| 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. |
| 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. |
| 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 |
| 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 |
