UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549
Form 10-Q
| (Mark One) | |||
ý | QUARTERLY REPORT PURSUANT TOSECTION 13 OR 15(d)OF THE SECURITIES EXCHANGE ACT OF 1934 | ||
| For the quarterly period ended | |||
| ¨ | TRANSITION REPORT PURSUANT TOSECTION 13 OR 15(d)OF THE SECURITIES EXCHANGE ACT OF 1934 | ||
For the transition period fromto . | |||
2014 heavy crude oil—A relatively inexpensive crude oil characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel fuel. turnaround—A periodically required standard procedure to inspect, refurbish, repair and maintain the refinery or nitrogen fertilizer plant assets. This process involves the shutdown and inspection of major processing units and occurs every four to five years for the refineries and every two to three years for the nitrogen fertilizer plant. ASSETS Current assets: Cash and cash equivalents Accounts receivable, net of allowance for doubtful accounts of $2.7 and $2.0, respectively Inventories Prepaid expenses and other current assets Insurance receivable Income tax receivable Deferred income taxes Due from parent Total current assets Property, plant, and equipment, net of accumulated depreciation Intangible assets, net Goodwill Deferred financing costs, net Insurance receivable Other long-term assets Total assets LIABILITIES AND EQUITY Current liabilities: Note payable and capital lease obligations Accounts payable Personnel accruals Accrued taxes other than income taxes Income taxes payable Due to parent Deferred revenue Other current liabilities Total current liabilities Long-term liabilities: Long-term debt and capital lease obligations, net of current portion Accrued environmental liabilities, net of current portion Deferred income taxes Other long-term liabilities Total long-term liabilities Commitments and contingencies Equity: CVR stockholders' equity: Common stock $0.01 par value per share, 350,000,000 shares authorized, 86,929,660 issued as of June 30, 2013 and December 31, 2012 Additional paid-in-capital Retained earnings Treasury stock, 98,610 as of June 30, 2013 and December 31, 2012, at cost Accumulated other comprehensive income (loss), net of tax Total CVR stockholders' equity Noncontrolling interest Total equity Total liabilities and equityDelaware 61-1512186 (I.R.S. EmployerIdentification No.)
2277 Plaza Drive, Suite 500
77479Registrant'sRegistrant’s telephone number, including area code)ýþ No oýþ No o"large“large accelerated filer," "accelerated filer"” “accelerated filer” and "smaller“smaller reporting company"company” in Rule 12b-2 of the Exchange Act.oþ ýo Smaller reporting companyoýþregistrant'sregistrant’s common stock outstanding at JulyApril 30, 2013.Page No. Page No.
Item 1.Legal Proceedings93
Item 1A.Risk Factors93
Item 6.Exhibits94
Signatures
June 30, 2013March 31, 2014 (this "Report"“Report”).—A geographic subset of the PADD II region comprising refineries in Oklahoma, Kansas, Missouri, Nebraska and Iowa. Current Group 3 refineries include the Refining Partnership'sPartnership’s Coffeyville and Wynnewood refineries; the Valero Ardmore refinery in Ardmore, OK; HollyFrontier'sHollyFrontier’s Tulsa refinery in Tulsa, OK and El Dorado refinery in El Dorado, KS; Phillips 66's66’s Ponca City refinery in Ponca City, OK; and NCRA'sNCRA’s refinery in McPherson, KS.Table of Contents"Nitrogen“Nitrogen Fertilizer Partnership"Partnership”), which closed on April 13, 2011."Refining Partnership"“Refining Partnership”), which closed on January 23, 2013 (which includes the underwriters'underwriters’ subsequently-exercised option to purchase additional common units).underwriters'underwriters’ subsequently-exercised option to purchase additional common units). WEC4Gary-Williams Energy Corporation, subsequently converted to Gary-Williams Energy Company, LLC and now known as Wynnewood Energy Company, LLC. WRC—Wynnewood Refining Company, LLC, the owner of the 70,000 bpd Wynnewood, Oklahoma refinery and related assets. WTI—West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an API gravity between 39 and 41 degrees and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils. June 30,
2013 December 31,
2012 March 31, 2014 December 31, 2013 (unaudited) (unaudited) (in millions, except
share data) (in millions, except share data) ASSETS $ 1,134.5 $ 896.0 $ 962.1 $ 842.1 277.0 210.6 Accounts receivable, net of allowance for doubtful accounts of $0.7 and $0.9, respectively 258.6 241.9 588.8 528.1 543.1 526.6 132.3 54.4 135.2 82.5 — 1.3 — 4.1 2.8 10.8 13.6 57.4 13.9 27.8 — 9.2 2,146.2 1,761.1 1,915.7 1,731.7 1,809.9 1,782.9 1,884.0 1,864.4 0.3 0.3 0.3 0.3 41.0 41.0 41.0 41.0 12.6 16.6 10.5 11.2 4.0 4.0 9.4 5.0 18.4 17.2 $ 4,023.4 $ 3,610.9 $ 3,869.9 $ 3,665.8 LIABILITIES AND EQUITY $ 1.2 $ 1.1 $ 1.3 $ 1.3 380.2 440.1 402.8 377.9 46.2 51.2 35.0 45.8 29.4 36.7 34.3 31.5 9.7 — 118.9 — 82.7 0.1 1.5 1.0 10.0 0.7 97.3 95.6 63.3 44.2 684.4 625.7 629.4 501.5 675.6 897.1 674.6 674.9 1.4 1.6 1.1 1.2 585.2 386.9 572.2 601.7 44.4 39.5 42.4 51.1 1,306.6 1,325.1 1,290.3 1,328.9 0.9 0.9 CVR stockholders’ equity: Common stock $0.01 par value per share, 350,000,000 shares authorized, 86,929,660 issued 0.9 0.9 1,114.8 582.3 1,114.4 1,114.4 185.3 945.4 137.6 76.2 (2.3 ) (2.3 ) 0.3 (1.2 ) 1,299.0 1,525.1 Treasury stock, 98,610 at cost (2.3 ) (2.3 ) Accumulated other comprehensive loss, net of tax (0.5 ) (0.6 ) Total CVR stockholders’ equity 1,250.1 1,188.6 733.4 135.0 700.1 646.8 2,032.4 1,660.1 1,950.2 1,835.4 $ 4,023.4 $ 3,610.9 $ 3,869.9 $ 3,665.8
Net sales Operating costs and expenses: Cost of product sold (exclusive of depreciation and amortization) Direct operating expenses (exclusive of depreciation and amortization) Selling, general and administrative expenses (exclusive of depreciation and amortization) Depreciation and amortization Total operating costs and expenses Operating income Other income (expense): Interest expense and other financing costs (Note 13) Interest income Gain (loss) on derivatives, net Loss on extinguishment of debt Other income, net Total other income (expense) Income before income taxes Income tax expense Net income Less: Net income attributable to noncontrolling interest Net income attributable to CVR Energy stockholders Basic earnings per share Diluted earnings per share Weighted-average common shares outstanding: Basic DilutedThree Months Ended
March 31, Three Months Ended
June 30, Six Months Ended
June 30, 2014 2013 2013 2012 2013 2012 (unaudited) (unaudited)
(in millions, except per share data) (in millions, except per share data) $ 2,220.3 $ 2,308.3 $ 4,572.7 $ 4,276.9 $ 2,447.4 $ 2,352.4 1,785.4 1,874.2 3,599.0 3,509.4 2,076.9 1,813.6 108.3 94.1 216.8 209.6 123.4 108.5 28.9 72.0 57.4 117.3 26.3 28.4 35.0 32.2 69.2 64.3 37.3 34.2 1,957.6 2,072.5 3,942.4 3,900.6 2,263.9 1,984.7 262.7 235.8 630.3 376.3 183.5 367.7 (12.5 ) (19.0 ) (27.9 ) (38.2 ) Interest expense and other financing costs (10.1 ) (15.4 ) 0.3 0.2 0.6 0.2 0.2 0.3 120.5 38.8 100.5 (108.5 ) 109.4 (20.0 ) — — (26.1 ) — — (26.1 ) 0.2 0.6 0.3 0.9 0.1 — 108.5 20.6 47.4 (145.6 ) 99.6 (61.2 ) 371.2 256.4 677.7 230.7 283.1 306.5 99.5 91.1 193.3 81.4 69.4 93.8 271.7 165.3 484.4 149.3 213.7 212.7 88.3 10.6 136.0 19.8 87.0 47.7 $ 183.4 $ 154.7 $ 348.4 $ 129.5 $ 126.7 $ 165.0 $ 2.11 $ 1.78 $ 4.01 $ 1.49 $ 1.46 $ 1.90 $ 2.11 $ 1.75 $ 4.01 $ 1.46 $ 1.46 $ 1.90 Dividends declared per share $ 0.75 $ 5.50 86.8 86.8 86.8 86.8 86.8 86.8 86.8 88.4 86.8 88.5 86.8 86.8
Net income Other comprehensive income (loss): Unrealized gain on available-for-sale securities, net of tax of $0.9, $0, $0.9 and $0 Change in fair value of interest rate swap, net of tax of $0.1, $(0.2), $0.1 and $(0.3) Net loss reclassified into income on settlement of interest rate swap, net of tax of $0.1, $0.1, $0.2 and $0.1 (Note 13) Total other comprehensive income (loss) Comprehensive income Less: Comprehensive income attributable to noncontrolling interest Comprehensive income attributable to CVR Energy stockholders (LOSS) Three Months Ended
June 30, Six Months Ended
June 30, 2013 2012 2013 2012 (unaudited)
(in millions) $ 271.7 $ 165.3 $ 484.4 $ 149.3 1.4 — 1.4 — 0.1 (0.5 ) 0.1 (0.7 ) 0.2 0.2 0.3 0.3 1.7 (0.3 ) 1.8 (0.4 ) 273.4 165.0 486.2 148.9 88.5 10.5 136.3 19.6 $ 184.9 $ 154.5 $ 349.9 $ 129.3 Three Months Ended
March 31, 2014 2013 (unaudited) (in millions) Net income $ 213.7 $ 212.7 Other comprehensive income: Net loss reclassified into income on settlement of interest rate swap, net of tax of $0.1 and $0.1 (Note 12) 0.2 0.2 Total other comprehensive income 0.2 0.2 Comprehensive income 213.9 212.9 Less: Comprehensive income attributable to noncontrolling interest 87.1 47.8 Comprehensive income attributable to CVR Energy stockholders $ 126.8 $ 165.1
Balance at December 31, 2012 January issuance of CVR Refining's common units to the public May issuance of CVR Refining's common units to the public Sale of CVR Refining's common units to AEPC Secondary offering of CVR Partners' common units to the public Dividends paid to CVR Energy stockholders Distributions from CVR Partners to public unitholders Distributions from CVR Refining to public unitholders Share-based compensation Redemption of common units Net income Net unrealized gain on available-for-sale securities, net of tax Net gain on interest rate swaps, net of tax Balance at June 30, 2013 Common Stockholders Shares
Issued $0.01 Par
Value
Common
Stock Additional
Paid-In
Capital Retained
Earnings Treasury
Stock Accumulated
Other
Comprehensive
Income (Loss) Total CVR
Stockholders'
Equity Noncontrolling
Interest Total
Equity (unaudited)
(in millions, except share data) 86,929,660 $ 0.9 $ 582.3 $ 945.4 $ (2.3 ) $ (1.2 ) $ 1,525.1 $ 135.0 $ 1,660.1 — — 229.3 — — — 229.3 276.4 505.7 — — 148.9 — — — 148.9 148.7 297.6 — — 23.6 — — — 23.6 22.7 46.3 — — 130.1 — — — 130.1 74.1 204.2 — — — (1,107.1 ) — — (1,107.1 ) — (1,107.1 ) — — — — — — — (17.8 ) (17.8 ) — — — — — — — (43.6 ) (43.6 ) — — 0.7 (1.4 ) — — (0.7 ) 1.7 1.0 — — (0.1 ) — — — (0.1 ) (0.1 ) (0.2 ) — — — 348.4 — — 348.4 136.0 484.4 — — — — — 1.4 1.4 — 1.4 — — — — — 0.1 0.1 0.3 0.4 86,929,660 $ 0.9 $ 1,114.8 $ 185.3 $ (2.3 ) $ 0.3 $ 1,299.0 $ 733.4 $ 2,032.4 Common Stockholders (unaudited) (in millions, except share data) Balance at December 31, 2013 86,929,660 $ 0.9 $ 1,114.4 $ 76.2 $ (2.3 ) $ (0.6 ) $ 1,188.6 $ 646.8 $ 1,835.4 Dividends paid to CVR Energy stockholders — — — (65.1 ) — — (65.1 ) — (65.1 ) Distributions from CVR Partners to public unitholders — — — — — — — (14.7 ) (14.7 ) Distributions from CVR Refining to public unitholders — — — — — — — (19.3 ) (19.3 ) Share-based compensation — — — (0.2 ) — — (0.2 ) 0.2 — Net income — — — 126.7 — — 126.7 87.0 213.7 Net gain on interest rate swaps, net of tax — — — — — 0.1 0.1 0.1 0.2 Balance at March 31, 2014 86,929,660 $ 0.9 $ 1,114.4 $ 137.6 $ (2.3 ) $ (0.5 ) $ 1,250.1 $ 700.1 $ 1,950.2
Cash flows from operating activities: Net income Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization Allowance for doubtful accounts Amortization of deferred financing costs Amortization of original issue discount Amortization of original issue premium Deferred income taxes Loss on disposition of assets Loss on extinguishment of debt Share-based compensation Unrealized (gain) loss on derivatives, net Changes in assets and liabilities: Accounts receivable Inventories Prepaid expenses and other current assets Insurance receivable Other long-term assets Accounts payable Due to parent Accrued income tax Deferred revenue Other current liabilities Accrued environmental liabilities Net cash provided by operating activities Cash flows from investing activities: Capital expenditures Proceeds from sale of assets Net cash used in investing activities Cash flows from financing activities: Payment of capital lease obligations Payments on senior secured notes Payment of financing costs Proceeds from CVR Refining's initial public offering in January, net of offering costs Proceeds from CVR Refining's offering in May, net of offering costs Proceeds from the sale of CVR Refining's common units to AEPC Proceeds from CVR Partners' secondary offering, net of offering costs Exercise of stock options Redemption of common units Dividends to CVR Energy's stockholders Distributions to CVR Refining's noncontrolling interest holders Distributions to CVR Partners' noncontrolling interest holders Net cash used in financing activities Net increase in cash and cash equivalents Cash and cash equivalents, beginning of period Cash and cash equivalents, end of period Supplemental disclosures: Cash paid for income taxes, net of refunds Cash paid for interest net of capitalized interest of $1.2 and $4.3 in 2013 and 2012, respectively Non-cash investing and financing activities: Accrual of construction in progress additions market. On May 28, 2013, Coffeyville Resources, LLC Partnership’s general partner, CVR GP, LLC, which only holds a non-economic general partner interest. The noncontrolling interest reflected on the Condensed Consolidated Balance Sheets of CVR is impacted by the net income of, and distributions from, the Nitrogen Fertilizer Partnership. represented an “Transactions.” February 26, 2014 (the "2013 Form 10-K"). the sole member of the general partner and not by the board of directors of the general partner. The officers of the general partner manage the day-to-day affairs of the business. The majority of the officers of both general partners are also officers of CVR. Based upon the general Results of operations and cash flows for the interim periods presented are not necessarily indicative of the results that will be realized for the year ending Stock Units Non-vested at January 1, 2013 Granted Vested Forfeited Non-vested at June 30, 2013 The In December 2012 and one unit of the Nitrogen Fertilizer Partnership's common units Non-vested at January 1, 2013 Granted Vested Forfeited Non-vested at June 30, 2013 Finished goods Raw materials and precious metals In-process inventories Parts and supplies Land and improvements Buildings Machinery and equipment Automotive equipment Furniture and fixtures Leasehold improvements Railcars Construction in progress Accumulated depreciation Total net, property, plant and equipment at both months are included in other long-term liabilities in the Condensed Consolidated Balance Sheets; unrecognized tax benefits that are expected to be settled within the next twelve months are included in income taxes payable. The Company has accrued interest of 2013. 10.875% Senior Secured Notes, due 2017, net of unamortized discount of $1.8 million as of December 31, 2012 6.5% Senior Notes, due 2022 CRNF credit facility Capital lease obligations Long-term debt Senior December 20, 2017. As of March 31, 2014. On January Dividend type Amount paid IEP Amounts paid to public stockholders Total amount paid Per common share Shares outstanding Net income attributable to CVR Energy stockholders Weighted-average number of shares of common stock outstanding Effect of dilutive securities: Non-vested common stock Stock options Weighted-average number of shares of common stock outstanding assuming dilution Basic earnings per share Diluted earnings per share Six months ending December 31, 2013 Year Ending December 31, 2014 2015 2016 2017 Thereafter For the The Vitol Agreement has an initial term commencing on August 31, 2012 and extending through December 31, 2014 (the "Initial Term"). Following the Initial Term, the Vitol Agreement will automatically renew for successive these locations. Under the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), the Resource Conservation and Recovery Act ("RCRA"), and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons can include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, and under certain circumstances, joint and several, so that any responsible party may be held liable for the entire cost of investigating and remediating the release of hazardous substances. Similarly, the Six months ending December 31, 2013 Year Ending December 31, 2014 2015 2016 2017 Thereafter Undiscounted total Less amounts representing interest at 2.24% Accrued environmental liabilities at June 30, 2013 the storage, handling, use and transportation of petroleum and nitrogen products, and the characteristics and composition of gasoline and diesel fuels. The ultimate impact of complying with evolving laws and regulations is not always clearly known or determinable due in part to the fact that our operations may change over time and certain implementing regulations for laws, such as the federal Clean Air Act, have not yet been finalized, are under governmental or judicial review or are being revised. These laws and regulations could result in increased capital, operating and compliance costs. Form 10-K. CRRM, CRNF, CRCT, WRC and CRT each believe it is in substantial compliance with existing EHS rules and regulations. There can be no assurance that the EHS matters described Company's experience related to Clean Water Act enforcement, it does not anticipate that the costs of any civil penalties, required additional controls or operational changes would be material. Location and Description Cash equivalents Other current assets (marketable securities) Other current assets (other derivative agreements) Other long-term assets (other derivative agreements) Total Assets Other current liabilities (other derivative agreements) Other current liabilities (interest rate swap) Other current liabilities (biofuel blending obligation) Other long-term liabilities (other derivative agreements) Other long-term liabilities (interest rate swap) Total Liabilities Location and Description Cash equivalents Other current assets (other derivative agreements) Other long-term assets (other derivative agreements) Total Assets Other current liabilities (other derivative agreements) Other current liabilities (interest rate swap) Other current liabilities (biofuel blending obligation) Other long-term liabilities (other derivative agreements) Other long-term liabilities (interest rate swap) Total Liabilities Realized gain (loss) on settlement of derivative agreements, net Change in unrealized gain (loss) on derivative agreements, net Total gain (loss) on derivatives, net There are no premiums paid or received at inception of the derivative contracts and upon settlement, there is no cost recovery associated with these contracts. Swaps settled with cash. The contract fair value of the commodity other long-term assets, respectively, in the Condensed Consolidated Balance Sheets as follows: Commodity Swaps Total Commodity Swaps Total Other Derivative Activity Total Commodity Swaps Total Commodity Swaps Total Enterprises its common shares. Principal products of the Net sales Petroleum Nitrogen Fertilizer Intersegment elimination Total Cost of product sold (exclusive of depreciation and amortization) Petroleum Nitrogen Fertilizer Intersegment elimination Total Direct operating expenses (exclusive of depreciation and amortization) Petroleum Nitrogen Fertilizer Other Total Depreciation and amortization Petroleum Nitrogen Fertilizer Other Total Operating income Petroleum Nitrogen Fertilizer Other Total Capital expenditures Petroleum Nitrogen fertilizer Other Total Total assets Petroleum Nitrogen Fertilizer Other Total Goodwill Petroleum Nitrogen Fertilizer Other Total On form of As of Nitrogen fertilizer business.The nitrogen fertilizer business consists of our interest in the Nitrogen Fertilizer Partnership. At 91,025 tons of ammonia. For the three months ended March 31, 2014, approximately 92% of the produced and purchased ammonia tons were upgraded into UAN. unit in connection with the exercise of the “CVRR.” “Transactions.” The direct operating expense structure is also important to the petroleum $2.8 million. Going forward, as a result of the UAN expansion process completion, the nitrogen fertilizer business expects to upgrade substantially all of its ammonia production into UAN for as long as it makes economic sense to do so. The value of nitrogen fertilizer products is also an important consideration in understanding results. opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process that takes into account margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The nitrogen fertilizer plant generally undergoes a facility turnaround every two to three years. The turnaround typically lasts 13-15 days each turnaround year and costs approximately additional ammonia fertilizer annually. Amount paid CRLLC Amounts paid to public unitholders Total amount paid Per common unit Common units outstanding Dividend type Amount paid IEP Amounts paid to public stockholders Total amount paid Per common share Shares outstanding Consolidated Statement of Operations Data: Net sales Cost of product sold(1) Direct operating expenses(1) Selling, general and administrative expenses(1) Depreciation and amortization(1) Operating income Interest expense and other financing costs Gain on derivatives, net Other income, net Income before income tax expense Income tax expense Net income Less: Net income attributable to noncontrolling interest Net income attributable to CVR Energy stockholders Basic earnings per share Diluted earnings per share Weighted-average common shares outstanding: Basic Diluted Consolidated Statement of Operations Data: Net sales Cost of product sold(1) Direct operating expenses(1) Selling, general and administrative expenses(1) Depreciation and amortization(1) Operating income Interest expense and other financing costs Gain (loss) on derivatives, net Loss on extinguishment of debt Other income, net Income before income tax expense Income tax expense Net income(2) Less: Net income attributable to noncontrolling interest Net income attributable to CVR Energy stockholders Basic earnings per share Diluted earnings per share Weighted-average common shares outstanding: Basic Diluted Balance Sheet Data Cash and cash equivalents Working capital Total assets Total debt, including current portion Total CVR Energy stockholders' equity Cash Flow Data Net cash flow provided by (used in): Operating activities Investing activities Financing activities Net cash flow Other Financial Data Capital expenditures for property, plant and equipment Depreciation and amortization is comprised of the following components as excluded from cost of product sold, direct operating expenses and selling, general and administrative expenses: Depreciation and amortization excluded from cost of product sold Depreciation and amortization excluded from direct operating expenses Depreciation and amortization excluded from selling, general and administrative expenses Total depreciation and amortization Loss on extinguishment of debt(a) Letter of credit expense included in selling, general and administrative expenses(b) Major scheduled turnaround expenses(c) Share-based compensation expense(d) Acquisition and integration expenses—Gary-Williams(e) (Consolidated) Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were relevant market indicators and its key operating statistics for the three Consolidated Petroleum Segment Summary Financial Results Net sales Cost of product sold(1) Direct operating expenses(1) Major scheduled turnaround expenses Depreciation and amortization Gross profit(3) Plus: Direct operating expenses and major scheduled turnaround expenses(1) Depreciation and amortization Refining margin(4) Operating income (loss) Adjusted Petroleum EBITDA(5) Key Operating Statistics Per crude oil throughput barrel: Refining margin(4) Gross profit(3) Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)(1)(2) Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold(1)(6) Barrels sold (barrels per day)(6) Refining Throughput and Production Data (barrels per day) Throughput: Sweet Medium Heavy sour Total crude oil throughput All other feedstocks and blendstocks Total throughput Production: Gasoline Distillate Other (excluding internally produced fuel) Total refining production (excluding internally produced fuel) Product price (dollars per gallon): Gasoline Distillate Market Indicators (dollars per barrel) West Texas Intermediate (WTI) NYMEX Crude Oil Differentials: WTI less WTS (light/medium sour) WTI less WCS (heavy sour) NYMEX Crack Spreads: Gasoline Heating Oil NYMEX 2-1-1 Crack Spread PADD II Group 3 Basis: Gasoline Ultra Low Sulfur Diesel PADD II Group 3 Product Crack: Gasoline Ultra Low Sulfur Diesel PADD II Group 3 2-1-1 Petroleum Consolidated: Petroleum operating income FIFO impacts (favorable), unfavorable(a) Share-based compensation, non-cash Major scheduled turnaround expenses(b) Current period settlements on derivative contracts Depreciation and amortization Other income (expense) Adjusted Petroleum EBITDA Coffeyville Refinery Financial Results Net sales Cost of product sold (exclusive of depreciation and amortization) Direct operating expenses (exclusive of depreciation and amortization) Major scheduled turnaround expenses Depreciation and amortization Gross profit Plus: Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) Depreciation and amortization Refining margin Coffeyville Refinery Key Operating Statistics Per crude oil throughput barrel: Refining margin Gross profit Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold Barrels sold (barrels per day) Coffeyville Refinery Throughput and Production Data (bpd) Throughput: Sweet Medium Heavy sour Total crude oil throughput All other feedstocks and blendstocks Total throughput Production: Gasoline Distillate Other (excluding internally produced fuel) Total refining production (excluding internally produced fuel) Wynnewood Refinery Financial Results Net sales Cost of product sold (exclusive of depreciation and amortization) Direct operating expenses (exclusive of depreciation and amortization) Major scheduled turnaround expenses Depreciation and amortization Gross profit Plus: Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) Depreciation and amortization Refining margin Wynnewood Refinery Key Operating Statistics Per crude oil throughput barrel: Refining margin Gross profit Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold Barrels sold (barrels per day) Wynnewood Refinery Throughput and Production Data (bpd) Throughput: Sweet Medium Heavy sour Total crude oil throughput All other feedstocks and blendstocks Total throughput Production: Gasoline Distillate Other (excluding internally produced fuel) Total refining production (excluding internally produced fuel) 5.7% as compared to the three months ended March 31, 2013, and the average sales price per gallon for distillates of $3.00 for the three months ended Gasoline Distillate our per barrel cost of consumed crude oil. Consumed crude oil costs increased due to a 4.5% increase in WTI for the three months ended Operating Income.Petroleum operating income was Gasoline Distillate Nitrogen Fertilizer Business Financial Results Net sales Cost of product sold(1) Direct operating expenses(1) Selling, general and administrative(1) Depreciation and amortization Operating income Adjusted Nitrogen Fertilizer EBITDA(2) Key Operating Statistics Production (thousand tons): Ammonia (gross produced)(3) Ammonia (net available for sale)(3)(4) UAN Pet coke consumed (thousand tons) Pet coke (cost per ton) Sales (thousand tons)(5): Ammonia UAN Product pricing (plant gate) (dollars per ton)(5): Ammonia UAN On-stream factor(6): Gasification Ammonia UAN Reconciliation of net sales (dollars in millions): Sales net plant gate Freight in revenue Hydrogen revenue Total net sales Market Indicators Natural gas NYMEX (dollars per MMBtu) Ammonia—Southern Plains (dollars per ton) UAN—Mid Cornbelt (dollars per ton) Nitrogen Fertilizer: Nitrogen fertilizer operating income Share-based compensation, non-cash Depreciation and amortization Other income (expense) Adjusted Nitrogen Fertilizer EBITDA Three Months Ended Ammonia UAN Hydrogen full first quarter of 2014. Direct Operating Expenses (Exclusive of Depreciation and Amortization).Direct operating expenses (exclusive of depreciation and amortization) for the nitrogen fertilizer operations include costs associated with the actual operations of the nitrogen fertilizer plant, such as repairs and maintenance, energy and utility costs, property taxes, catalyst and chemical costs, outside services, labor and environmental compliance costs. Nitrogen fertilizer direct operating expenses (exclusive of depreciation and amortization) for the three months ended Ammonia UAN Hydrogen $500.0 million. accrued and unpaid interest. Prior to November 1, 2017, some or all of the 2022 Notes may be redeemed at a price equal to clause (iii) will not apply, and (iii) the fixed charge coverage ratio for the immediately preceding twelve-month period shall be equal to or greater than 1.10 to . Borrowings under the Nitrogen Fertilizer Partnership credit facility bear interest based on a pricing grid determined by the trailing four quarter leverage ratio. The initial pricing for Eurodollar rate loans under the Nitrogen Fertilizer Partnership credit facility is currently based on the Eurodollar rate plus a margin of 3.50%, or for base rate loans, Swaps income, was not material. The following table summarizes our total actual capital expenditures for the Petroleum Business (the Refining Partnership): Coffeyville refinery: Maintenance Growth Coffeyville refinery total capital Wynnewood refinery: Maintenance Growth Wynnewood refinery total capital Other Petroleum: Maintenance Growth Other petroleum total capital Petroleum business total capital Nitrogen Fertilizer Business (the Nitrogen Fertilizer Partnership): Maintenance Growth Nitrogen fertilizer business total capital Corporate Total capital spending Net cash provided by (used in): Operating activities Investing activities Financing activities Net increase in cash and cash equivalents Contractual Obligations Long-term debt(1) Operating leases(2) Capital lease obligations(3) Unconditional purchase obligations(4) Environmental liabilities(5) Interest payments(6) Total Other Commercial Commitments Standby letters of credit(7) In addition, CVR Energy, the Refining Partnership and/or the Nitrogen Fertilizer Partnership may from time to time seek to issue debt or equity securities in the public or private capital markets, but there can be no assurance they will be able to do so at prices they deem reasonable or at all. PLEASE NOTE: Pursuant to the rules and regulations of the Three Months Ended
March 31, Six Months Ended
June 30, 2014 2013 2013 2012 (unaudited) (unaudited)
(in millions) (in millions) $ 484.4 $ 149.3 $ 213.7 $ 212.7 69.2 64.3 37.3 34.2 0.6 0.1 (0.2 ) 0.3 1.5 3.9 0.7 0.8 — 0.3 — (1.7 ) (101.2 ) (12.5 ) (22.2 ) 21.4 — 0.9 0.1 0.1 26.1 — — 26.1 10.3 21.9 4.1 6.0 (138.3 ) 81.3 (Gain) loss on derivatives, net (109.4 ) 20.0 Current period settlements on derivative contracts 21.1 (52.5 ) (67.1 ) (31.2 ) (16.5 ) (72.9 ) (60.7 ) 121.9 (16.6 ) 3.0 (11.7 ) (9.5 ) 21.6 (3.2 ) 1.3 — — 1.3 (0.2 ) (1.6 ) (0.4 ) (0.1 ) (41.9 ) (27.6 ) 26.2 (32.1 ) 128.1 28.3 82.6 66.4 13.8 58.6 8.0 (0.2 ) 0.5 (4.6 ) 9.3 27.6 47.9 (6.1 ) 22.1 19.5 (0.2 ) (0.1 ) (0.1 ) (0.1 ) Other long-term liabilities (0.1 ) — 362.4 435.9 281.3 278.3 (114.6 ) (105.2 ) (61.9 ) (63.7 ) 0.1 0.4 (114.5 ) (104.8 ) (61.9 ) (63.7 ) (0.6 ) (0.5 ) (0.3 ) (0.3 ) (243.4 ) — — (243.4 ) (0.2 ) (2.0 ) 655.7 — 393.7 — 61.5 — 292.6 — — 0.4 (0.2 ) (0.1 ) (1,107.1 ) — (43.6 ) — (17.8 ) (24.6 ) Proceeds from CVR Refining’s initial public offering, net of offering costs — 655.7 Dividends to CVR Energy’s stockholders (65.1 ) (477.6 ) Distributions to CVR Refining’s noncontrolling interest holders (19.3 ) — Distributions to CVR Partners’ noncontrolling interest holders (14.7 ) (4.2 ) (9.4 ) (26.8 ) (99.4 ) (69.8 ) 238.5 304.3 120.0 144.8 896.0 388.3 842.1 896.0 $ 1,134.5 $ 692.6 $ 962.1 $ 1,040.8 $ 152.6 $ 6.9 $ 0.9 $ 6.2 $ 33.2 $ 36.0 Cash paid for interest net of capitalized interest of $2.3 and $0.8 in 2014 and 2013, respectively $ 1.2 $ 12.8 $ (18.1 ) $ (12.2 ) Construction in process additions included in accounts payable $ 27.2 $ 26.8 Change in accounts payable related to construction in process additions $ (5.6 ) $ (29.4 ) Investment in available-for-sale securities included in accounts payable $ 4.3 $ — June 30, 2013"Company"“Company,” “CVR Energy” or "CVR"“CVR” are used in this report to refer to CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries.("(“CVR Refining"Refining” or the "Refining Partnership"“Refining Partnership”) and CVR Partners, LP ("(“CVR Partners"Partners” or the "Nitrogen“Nitrogen Fertilizer Partnership"Partnership”). The Refining Partnership is an independent petroleum refiner and marketer of high value transportation fuels. The Nitrogen Fertilizer Partnership produces nitrogen fertilizers in the form of ammoniaUAN and UAN.ammonia. The Company reports in two business segments: the petroleum segment (the operations of CVR Refining) and the nitrogen fertilizer segment (the operations of CVR Partners). CVR's"CVI."“CVI.” On May 7, 2012, IEP Energy LLC and certain of its affiliates (collectively, "IEP") announced that they had acquired control of CVR pursuant to a tender offer for all of the Company's common stock (the "IEP Acquisition"“IEP Acquisition”). As of June 30, 2013,March 31, 2014, IEP owned approximately 82% of all of the outstanding shares of CVR. Prior to the IEP Acquisition, the Company was owned 100% by the public. Pursuant to the Transaction Agreement (the "Transaction Agreement") as a result of the IEP Acquisition, the settlement terms of all employee restricted share awards were modified. See further discussion in Note 3 ("Share-Based Compensation").of 22,080,000 common units (the "Nitrogen Fertilizer Partnership IPO") priced at $16.00 per unit.. The common units, which are listed on the NYSE, began trading on April 8, 2011 under the symbol "UAN".“UAN.” In connection with the Nitrogen Fertilizer Partnership IPO and through May 27, 2013, the Company recorded a30% noncontrolling interest for the common units sold into the public market which represented an approximately 30% interest in the Nitrogen Fertilizer Partnership at the time of the Nitrogen Fertilizer Partnership IPO and through May 27, 2013.("CRLLC"(“CRLLC”), a wholly-owned subsidiary of the Company, completed a registered public offering (the "Secondary Offering"“Secondary Offering”) whereby it sold $25.15$25.15 per unit. Additionally, the underwriters were granted an option to purchase 1,800,000 common units at the public offering price, which expired unexercised at the end of the option period. The net proceeds to CRLLC from the Secondary Offering were approximately $292.6 million, after deducting approximately $9.2 million in underwriting discounts and commissions. The Nitrogen Fertilizer Partnership did not receive any of the proceeds from the sale of common units by CRLLC. In connection with the Secondary Offering, the Nitrogen Fertilizer Partnership incurred approximately $0.5 million in offering costs.June 30, 2013,March 31, 2014, public security holders held approximately 47% of the total outstanding Nitrogen Fertilizer Partnership had 73,074,945 common units, outstanding, consisting of 34,154,945 common units owned by the public, representingand CRLLC held approximately 47%53% of the total Nitrogen Fertilizer Partnership units, and 38,920,000 common units owned by CRLLC, representing approximately 53% of the total Nitrogen Fertilizer Partnership units. In addition, CRLLC owns 100% of the Nitrogen Fertilizer Partnership'sCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(1) Organization and History of the Company and Basis of Presentation (Continued)Partnership'sPartnership’s general partner following the end of such quarter. The partnership agreement does not require that the Nitrogen Fertilizer Partnership make cash distributions on a quarterly basis or at all, and the board of directors of the general partner of the Nitrogen Fertilizer Partnership can change the Nitrogen Fertilizer Partnership's distribution policy at any time.CVR'sCVR’s senior management (together with other officers of the general partner) pursuant to a services agreement among CVR, the general partner and the Nitrogen Fertilizer Partnership. The Nitrogen Fertilizer Partnership'sPartnership’s general partner CVR GP, LLC, manages the operations and activities of the Nitrogen Fertilizer Partnership, subject to the terms and conditions specified in the partnership agreement. The operations of the general partner in its capacity as general partner are managed by its board of directors. Actions by the general partner that are made in its individual capacity are made by CRLLC as the sole member of the general partner and not by the board of directors of the general partner. The members of the board of directors of the general partner are not elected by the common unitholders and are not subject to re-election on a regular basis. The officers of the general partner manage the day-to-day affairs of the business of the Nitrogen Fertilizer Partnership. CVR, the Nitrogen Fertilizer Partnership, their respective subsidiaries and the general partner are parties to a number of agreements to regulate certain business relations between them. Certain of these agreements were amended in connection with the Nitrogen Fertilizer Partnership IPO. In contemplation of an initial public offering, in September 2012, CRLLC formed CVR Refining Holdings, LLC ("CVR Refining Holdings"), which in turn formed CVR Refining GP, LLC. CVR Refining Holdings and CVR Refining GP, LLC formed the Refining Partnership, which issued them a 100% limited partnership interest and a non-economic general partner interest, respectively. CVR Refining Holdings formed CVR Refining, LLC ("Refining LLC") and CRLLC contributed its petroleum and logistics subsidiaries, as well as its equity interests in Coffeyville Finance Inc. ("Coffeyville Finance") to Refining LLC in October 2012. CVR Refining Holdings contributed Refining LLC to the Refining Partnership in December 2012.theits initial public offering of its common units representing limited partner interests (the "Refining“Refining Partnership IPO"IPO”). The Refining Partnership sold 24,000,000 common units to the public at a price of $25.00$25.00 per unit. Additionally, on January 30, 2013, the Refining Partnership sold an additional 3,600,000 common units to the public at a price of $25.00$25.00 per common unit in connection with the underwriters'underwriters’ exercise of their option to purchase additional common units. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR."“CVRR.” In connection with the Refining Partnership IPO, the Company recorded a noncontrolling interest for the common units sold into the public market whichCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(1) Organization and History of the Company and Basis of Presentation (Continued)approximate approximately "Underwritten Offering"“Underwritten Offering”) by selling 12,000,000 common units to the public at a price of $30.75$30.75 per unit. American Entertainment Properties Corporation ("AEPC"(“AEPC”), an affiliate of Icahn Enterprises LP,IEP, also purchased an additional 2,000,000 common units at the public offering price in a privately negotiated transaction with a subsidiary of CVR Energy, which was completed on May 29, 2013. In connection with the Underwritten Offering, on June 10, 2013, the Refining Partnership sold an additional 1,209,236 common units to the public at a price of $30.75$30.75 per unit in connection with a partial exercise by the underwriters of their option to purchase additional common units. The transactions described in this paragraph are collectively referred to as the "Transactions." In connection with the Transactions, the Refining Partnership paid approximately $12.2 million in underwriting fees and approximately $0.4 million in offering costs. The Refining Partnership utilized proceeds of approximately $394.0 million from the Underwritten Offering (including the underwriters' option) to redeem 13,209,236 common units from CVR Refining Holdings, an indirect wholly-owned subsidiary of CVR Energy. The net proceeds to a subsidiary of CVR Energy from the sale of 2,000,000 common units to AEPC were approximately $61.5 million. The Refining Partnership did not receive any of the proceeds from the sale of common units by CVR Energy to AEPC.June 30, 2013, the Refining Partnership had 147,600,000 common units outstanding, consisting of 42,809,236 common units owned by theMarch 31, 2014, public representingsecurity holders held approximately 29% of the total Refining Partnership common units (including 6,000,000 units owned by affiliates of Icahn EnterprisesIEP representing 4% of the total Refining Partnership units) and 104,790,764 common units owned byunits), and CVR Refining Holdings, representingLLC ("CVR Refining Holdings"), a wholly-owned subsidiary of the Company, held approximately 71% of the total Refining Partnership common units. In addition, CVR Refining Holdings an indirect wholly-owned subsidiary of CVR Energy, owns 100% of the Refining Partnership'sPartnership’s general partner, CVR Refining GP, LLC, which holds a non-economic general partner interest. The noncontrolling interest reflected on the Condensed Consolidated Balance Sheets of CVR is impacted by the net income of, and distributions from, the Refining Partnership.Partnership'sPartnership’s general partner CVR Refining GP, LLC, manages the Refining Partnership'sPartnership’s activities subject to the terms and conditions specified in the Refining Partnership'sPartnership’s partnership agreement. The Refining Partnership'sPartnership’s general partner is owned by CVR Refining Holdings. The operations of its general partner, in its capacity as general partner, are managed by its board of directors. Actions by its general partner that are made in its individual capacity are made by CVR Refining Holdings as the sole member of the Refining Partnership'sPartnership’s general partner and not by the board of directors of its general partner. The members of the board of directors of the Refining Partnership'sPartnership’s general partner are not elected by the Refining Partnership'sPartnership’s unitholders and are not subject to re-election on a regular basis. The officers of the general partner manage the day-to-day affairs of the business of the Refining Partnership.CVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(1) Organization and History of the Company and Basis of Presentation (Continued)Partnership'sPartnership’s general partner following the end of such quarter. The partnership agreement does not require that the Refining Partnership make cash distributions on a quarterly basis or at all, and the board of directors of the general partner of the Refining Partnership can change the distribution policy at any time.Partnership'sPartnership’s outstanding units.("GAAP"(“GAAP”) and in accordance with the rules and regulations of the Securities and Exchange Commission (the "SEC"“SEC”). The condensed consolidated financial statements include the accounts of CVR and its majority-owned direct and indirect subsidiaries including the Nitrogen Fertilizer Partnership, the Refining Partnership and their respective subsidiaries. The ownership interests of noncontrolling investors in CVR'sCVR’s subsidiaries are recorded as a noncontrolling interest included as a separate component of equity for all periods presented. All intercompany account balances and transactions have been eliminated in consolidation. Certain information and footnotes required for complete financial statements under GAAP have been condensed or omitted pursuant to SEC rules and regulations. These condensed consolidated financial statements should be read in conjunction with the December 31, 20122013 audited consolidated financial statements and notes thereto included in CVR'sCVR’s Annual Report on Form 10-K for the year ended December 31, 2012,2013, which was filed with the SEC on March 14, 2013.partner'spartner’s directors on an annual or other continuing basis. Each general partner can only be removed by a vote of the holders of at least 662/3% 2/3% of the outstanding common units, including any common units owned by the general partner and its affiliates (including CVR) voting together as a single class. Actions by the general partner that are made in its individual capacity are made by the CVR subsidiary that serves asCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(1) Organization and History of the Company and Basis of Presentation (Continued)partner'spartner’s role and rights as afforded by the partnership agreements and the limited rights afforded to the limited partners, the condensed consolidated financial statements of CVR will include the assets, liabilities, cash flows, revenues and expenses of the Nitrogen Fertilizer Partnership and the Refining Partnership.Company'sCompany’s management, the accompanying condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments) that are necessary to fairly present the financial position of the Company as of June 30, 2013March 31, 2014 and December 31, 2012,2013, the results of operations and comprehensive income for the three and six month periods ended June 30, 2013March 31, 2014 and 2012,2013, changes in equity for the sixthree month period ended June 30, 2013March 31, 2014 and cash flows of the Company for the sixthree month periods ended June 30, 2013March 31, 2014 and 2012. Results of operations and cash flows for the interim periods presented are not necessarily indicativeresults that will be realized for the year ending December 31, 2013 or any other interim period. The preparation ofcondensed consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates.December 2011, the FASB issued ASU No. 2011-11,"Disclosures about Offsetting Assets and Liabilities" ("ASU 2011-11"). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under GAAP with those prepared under IFRS. On January 31,July 2013, the FASB issued ASU No. 2013-01, "2013-11, Clarifying the Scope“Presentation of Disclosures about Offsetting Assets and Liabilities"an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists” ("(“ASU 2013-01"2013-11”). ASU 2013-01 limits2013-11 requires the scopenetting of unrecognized tax benefits against a deferred tax asset for a loss or other carryforward that would apply in settlement of the new balance sheet offsetting disclosures to derivatives, repurchase agreements and securities lending transactions. Both standards are effective for interim and annual periods beginning January 1, 2013 and are to be applied retrospectively. The Company adopted these standards as of January 1, 2013. The adoption of these standards expanded the Company's condensed consolidated financial statement footnote disclosures. In February 2013, the FASB issued ASU No. 2013-02,"Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income" ("ASU 2013-02"). ASU 2013-02 requires the Company to present information about reclassification adjustments from accumulated other comprehensive income in the financial statements in a single footnote or parenthetically on the face of the financial statements based on the source and the income statement line items affected by the reclassification.uncertain tax positions. The standard is effective for interim and annual periods beginning January 1,after December 15, 2013 and is to be applied prospectively.prospectively with optional retrospective adoption permitted. The Company adopted this standard prospectively as of January 1, 2013.2014. The adoption of this standard did not materially expandresulted in a reclassification on the Company's condensed consolidated financial statement footnote disclosures.Condensed Consolidated Balance Sheets. See Note 7 ("Income Taxes") for further discussion.June 30, 2013Share-BasedShare‑Based CompensationPlan—Plan – CVR Energy("LTIP"(“LTIP”), which permits the grant of options, stock appreciation rights, restricted stock,shares, restricted stock units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance-based restricted stock). As of June 30, 2013,March 31, 2014, only grants of restricted stock units and performance units under the LTIP remain outstanding. Individuals who are eligible to receive awards and grants under the LTIP include the Company'sCompany’s employees, officers, consultants, advisors and directors. The LTIP authorizesauthorized a share pool of 7,500,000 shares of the Company'sCompany’s common stock, 1,000,000 of which may be issued in respect of incentive stock options. A summary of the principal features of the LTIP is provided below.Sharessixthree months ended June 30, 2013March 31, 2014 is presented below: Shares Weighted-Average
Grant-Date
Fair Value 1,145,611 $ 23.24 Shares Non-vested at January 1, 2014 359,552 $ 28.09 2,600 54.75 — — (3,198 ) 27.51 (3,197 ) 27.51 (15,089 ) 22.76 (1,132 ) 31.93 1,129,924 $ 23.31 Non-vested at March 31, 2014 355,223 $ 28.09 Prior to the change of control as discussed in Note 1, the restricted shares, when granted, were valued at the closing market price of CVR's common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. These shares generally vest over a three-year period.change of controlIEP Acquisition and related Transaction Agreement in Maydated April 18, 2012 between CVR and IEP ("Transaction Agreement") triggered a modification to outstanding awards under the LTIP. Pursuant to the Transaction Agreement, all restricted shares scheduled to vest in 2012 were converted to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one non-transferable contingent cash payment ("CCP") upon vesting. Restricted shares scheduled to vest in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards will be settled in cash upon vesting in an amount equal to the lesser of the offer price of AsThe awards, which generally vest over a result of the modification, additional share-based compensation of approximately $12.4 million was incurred to revalue the unvested shares to the fair value upon the date of modification for the three and six months ended June 30, 2012. For awards vesting subsequent to 2012, the awardsthree-year period, will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards, the classification changed from equity-classified awards to liability-classified awards.Table of ContentsCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(3) Share-Based Compensation (Continued)subsequent periods,during 2013, restricted stock units and dividend equivalent rights were granted to certain employees of CVR. The non-vested restricted stock unitsawards are scheduledexpected to vest over three years, with one-third of the award vesting each year on the anniversary of the grant date, with the exception of awards granted to certain executive officers thatscheduled to vest over one year. Awards granted in December 2012 to Mr. Lipinski, the Company's Chief Executive Officer and President, were canceled in connection with the issuance of certain performance unit awards as discussed further below. Each restricted stock unit and dividend equivalent right represents the right to receive, upon vesting, a cash payment equal to (a) the fair market value of one share of the Company'sCompany’s common stock, plus (b) the cash value of all dividends declared and paid by the Company per share of the Company'sCompany’s common stock from the grant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest. Additionally, the Company approved a discretionary award of up to 62,920 restricted stock units to Mr. Lipinski, Chief Executive Officer and President of the Company, on or before December 31, 2013. This discretionary award remains subject to the review and recommendation of the Compensation Committee and approval of the board of directors of the Company, and is conditioned on Mr. Lipinski continuing to be employed by the Company through December 31, 2013. As such, no expense related to this discretionary award was recorded during the three and six months ended June 30, 2013. To the extent awarded, the discretionary award will vest immediately, and include dividend equivalent rights for the time period commencing on December 28, 2012 through the date of the award.June 30, 2013,March 31, 2014, there was approximately $13.4$3.7 million of total unrecognized compensation cost related to non-vested restricted stock units and associated dividendsdividend equivalent rights to be recognized over a weighted-average period of approximately 0.5 years.1.0 year. Total compensation expense for the three months ended June 30, 2013March 31, 2014 and 20122013 was approximately $3.7$0.5 million and $17.3$5.4 million, respectively, related to the LTIP. Total compensation expense for the six months ended June 30, 2013 and 2012 was approximately $9.1 million and $20.8 million, respectively, related to the LTIP. awardsJune 30, 2013March 31, 2014 and December 31, 2012,2013, the Company hashad a liability of $28.6$9.4 million and $19.5$8.9 million, respectively, for unvestednon-vested restricted stock unit awards and associated dividends,dividend equivalent rights, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.Plan—Plan – CVR PartnersCVR Partners'the Nitrogen Fertilizer Partnership's general partner adopted the CVR Partners, LP Long-Term Incentive Plan ("(“CVR Partners LTIP"LTIP”). Individuals who are eligible to receive awards under the CVR Partners LTIP include (1) employees of the Nitrogen Fertilizer Partnership and its subsidiaries, (2) employees of its general partner, and (3) members of the board of directors of its general partner.partner and (4) employees, consultants and directors of CVR Energy. The CVR Partners LTIP provides for the grant of options, unit appreciation rights, distribution equivalent rights, restricted units, phantom units and other unit-based awards, each in respect of common units. The maximum number of common units issuable under the CVR Partners LTIP is 5,000,000.5,000,000.2012, the board2013, awards of directors of the general partner of the Nitrogen Fertilizer Partnership approved an amendmentphantom units and distribution equivalent rights were granted to modify the terms of certain phantom unit awards previously granted to employees of the Nitrogen Fertilizer Partnership and its subsidiaries. Priorsubsidiaries and its general partner. The awards are expected to the amendment, the phantom units, when granted, were valued at the closing market pricevest over three years with one-third of the NitrogenCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(3) Share-Based Compensation (Continued)onfor the datefirst ten trading days in the month of issuancevesting, plus (b) the per unit cash value of all distributions declared and amortized to compensation expense on a straight-line basis over the vesting period of the units. These units generally vest over a three-year period. The amendment triggered a modification to the awardspaid by providing that the phantom units would be settled in cash rather than common units of the Nitrogen Fertilizer Partnership. ForPartnership from the grant date to and including the vesting date. The awards, vesting subsequent to the amendment, the awardswhich are liability-classified, will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards to employees of the Nitrogen Fertilizer Partnership, the classification changed from an equity-classified award to a liability-classified award."units"“units”) activity and changes under the CVR Partners LTIP during the sixthree months ended June 30, 2013March 31, 2014 is presented below: Units Weighted-Average
Grant-Date
Fair Value 201,812 $ 23.70 Units Non-vested at January 1, 2014 171,119 $ 21.34 — — — — (16,886 ) 19.74 — — — — (64,629 ) 23.36 184,926 $ 24.06 Non-vested at March 31, 2014 106,490 $ 20.12 June 30, 2013,March 31, 2014, there was approximately $2.1$1.4 million of total unrecognized compensation cost related to the awards under the CVR Partners LTIP to be recognized over a weighted-average period of 1.2 years. Compensation1.4 years. Total compensation expense recorded for the three months ended June 30, 2013March 31, 2014 and 20122013 related to the awards under the CVR Partners LTIP was approximately $0.6$0.3 million and $0.5$0.6 million, respectively. Compensation expense recorded for the six months ended June 30, 2013 and 2012 related to the awards under the Partners LTIP was approximately $1.2 million and $1.1 million, respectively. ENERGY, INC. AND SUBSIDIARIESJune 30, 2013March 31, 2014 and December 31, 2012,2013, the Company hasNitrogen Fertilizer Partnership had a liability of $0.4$0.4 million and $0.2$0.2 million, respectively, for unvestedcash settled non-vested phantom unit awards and associated distribution equivalent rights, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.Plan—Plan – CVR Refiningofficers,of the Refining Partnership and its subsidiaries, (2) employees of the general partner, (3) members of the board of directors of the general partner and (4) certain employees, consultants and directors of CRLLC and CVR Energy who perform services solely for the benefit of the Refining and its general partner and their respective subsidiaries and parents.Partnership. The CVR Refining LTIP provides for the grant of options, unit appreciation rights, restricted units, phantom units, unit awards, substitute awards, other-unit based awards, cash awards, performance awards, and distribution equivalent rights, each in respect of common units. The maximum number of common units issuable under the CVR Refining LTIP is 11,070,000. 11,070,000. Units Non-vested at January 1, 2014 187,177 $ 21.55 Granted — — Vested — — Forfeited (1,905 ) 21.55 Non-vested at March 31, 2014 185,272 $ 21.55 June 30, 2013, noMarch 31, 2014, there was approximately $3.7 million of total unrecognized compensation cost related to the awards have been granted under the plan.CVR Refining LTIP to be recognized over a weighted-average period of 1.7 years. Total compensation expense recorded for the three months ended March 31, 2014 related to the awards under the CVR Refining LTIP was approximately $0.7 million. Incentive Units Non-vested at January 1, 2014 251,431 $ 22.62 Granted — — Vested — — Forfeited — — Non-vested at March 31, 2014 251,431 $ 22.62 June 30, 2013March 31, 2014(unaudited), the Company had a liability of $0.8 million for non-vested incentive units and associated distribution equivalent rights, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.InventoriesFor all periods presented, inventories are valued at the lower of the first-in, first-out ("FIFO"(“FIFO”) cost or market for fertilizer products, refined fuels and by-products for all periods presented.by-products. Refinery unfinished and finished products inventory values were determined using the ability-to-bear process, whereby raw materials and production costs are allocated to work-in-process and finished products based on their relative fair values. Other inventories, including other raw materials, spare parts, and supplies, are valued at the lower of moving-average cost, which approximates FIFO, or market. The cost of inventories includes inbound freight costs. June 30,
2013 December 31,
2012 March 31, 2014 December 31, 2013 (in millions) (in millions) $ 317.4 $ 275.2 $ 268.0 $ 268.2 170.3 164.3 179.5 177.0 56.8 42.8 51.9 36.9 44.3 45.8 43.7 44.5 $ 543.1 $ 526.6 $ 588.8 $ 528.1 June 30,
2013 December 31,
2012 March 31, 2014 December 31, 2013 (in millions) (in millions) $ 33.3 $ 31.0 $ 36.5 $ 36.1 41.3 40.6 44.4 42.6 2,261.0 2,089.5 2,318.6 2,312.5 16.4 15.0 19.5 19.2 14.0 13.7 19.0 18.3 2.5 2.5 2.5 2.5 Aircraft 2.3 2.3 8.0 2.5 7.9 7.9 103.3 189.2 208.3 164.9 2,659.0 2,606.3 2,479.8 2,384.0 669.9 601.1 775.0 741.9 $ 1,809.9 $ 1,782.9 Total property, plant and equipment, net $ 1,884.0 $ 1,864.4 June 30, 2013March 31, 2014 and 20122013 totaled approximately $0.4$2.3 million and $2.3$0.8 million respectively. Capitalized interest recognized as a reduction in interest expense for the six months ended June 30, 2013 and 2012 totaled approximately $1.2 million and $4.3 million,, respectively. Land, buildings and equipment that are under a capital lease obligation had an original carrying value of approximately $25.1$24.8 million as ofTable of ContentsMarch 31, 2014CVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(5) Property, Plant, and Equipment (Continued)June 30, 2013 and December 31, 2012.2013. Amortization of assets held under capital leases is included in depreciation expense.("RINs"(“RINs”) expense and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of approximately $1.3$1.4 million and $0.9$1.2 million for the three months ended June 30, 2013March 31, 2014 and 2012,2013, respectively. For the six months ended June 30, 2013 and 2012, cost of product sold excludes depreciation and amortization of approximately $2.4 million and $1.6 million, respectively.$33.2$34.5 million and $30.7$32.5 million for the three months ended June 30, 2013March 31, 2014 and 2012,2013, respectively. For the six months ended June 30, 2013 and 2012, direct operating expenses exclude depreciation and amortization of approximately $65.7 million and $61.5 million, respectively.$0.5$1.4 million and $0.6$0.5 million for the three months ended June 30, 2013March 31, 2014 and 2012,2013, respectively. For the six months ended June 30, 2013 and 2012, selling, general and administrative expenses exclude depreciation and amortization of approximately $1.1 million and $1.2 million, respectively.Icahn Enterprises,IEP, and subsequently entered into a tax allocation agreement with AEPC (the "Tax“Tax Allocation Agreement"Agreement”). The Tax Allocation Agreement provides that AEPC will pay all consolidated federal income taxes on behalf of the consolidated tax group. CVR is required to make payments to AEPC in an amount equal to the tax liability, if any, that it would have paid if it were to file as a consolidated group separate and apart from AEPC. As of June 30, 2013,March 31, 2014, the Company has recorded a liability of $118.9$82.7 million for federal income taxes due to AEPC under the Tax Allocation Agreement. During the three months ended June 30,March 31, 2014 and 2013, the Company paid $54.0 million and $85.0 million for the first and second quarter estimated federal income taxno payments respectively, duewere made to AEPC under the Tax Allocation Agreement.June 30, 2013,March 31, 2014, the Company had unrecognized tax benefits of approximately $42.0$50.2 million, of which $17.0$22.0 million, if recognized, would impact the Company'sCompany’s effective tax rate. UnrecognizedUpon adoption of ASU 2013-11, approximately $12.6 million of unrecognized tax benefits associated with state tax credits were netted with deferred tax asset carryforwards resulting in a reclassification on the Condensed Consolidated Balance Sheets. The remaining unrecognized tax benefits that are not expected to be settled within the next twelveCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(7) Income Taxes (Continued)$1.1$3.6 million related to uncertain tax positions. The Company'sCompany’s accounting policy with respect to interest and penalties related to tax uncertainties is to classify these amounts as income taxes.June 30, 2013,March 31, 2014, the Company'sCompany’s tax filings are generally open to examination in the United States for the tax years ended December 31, 20092010 through December 31, 20122013 and in various individual states for the tax years ended December 31, 20082009 through December 31, 2012.Company'sCompany’s effective tax rate for the three and six months ended June 30, 2013March 31, 2014 was 26.8% and 28.5%, respectively,24.5% as compared to the Company'sCompany’s combined federal and state expected statutory tax rate of 39.2%39.6%. The Company'sCompany’s effective tax rate for the three and six months ended June 30,March 31, 2014 is lower than the statutory rate primarily due to the reduction of income subject to tax associated with the noncontrolling ownership interests of CVR Refining’s and CVR Partners’ earnings, as well as benefits for domestic production activities and state income tax credits. The Company’s effective tax rate for the three months ended March 31, 2013 is was 30.6% as compared to the Company’s combined federal and state expected statutory tax rate of 39.2%. The Company’s effective tax rate for the three months ended March 31, 2013 was lower than the statutory rate primarily due to the reduction of income subject to tax associated with the noncontrolling ownership interests of CVR Refining's and CVR Partners'Partners’ earnings, as well as benefits for domestic production activities and state income tax credits. The Company's effective tax rate for the three and six months ended June 30, 2012 was 35.5% and 35.3%, respectively, as compared to the Company's combined federal and state expected statutory tax rate of 39.4%. The Company's effective tax rate for the three and six months ended June 30, 2012 was lower than the statutory rate primarily due to the reduction of income subject to tax associated with the noncontrolling ownership interest of CVR Partners' earnings, as well as benefits for domestic production activities. Prior to the Refining Partnership IPO, CVR's deferred taxes were recorded based upon each separate component of the book versus tax basis difference of CVR's assets and liabilities, including CVR Refining's assets and liabilities. Subsequent to the Refining Partnership IPO, deferred taxes related to the net book versus tax basis difference associated with the investment in CVR Refining are recorded as a noncurrent deferred tax liability. June 30,
2013 December 31,
2012 (in millions) March 31, 2014 December 31, 2013 $ — $ 220.9 500.0 500.0 (in millions) 6.5% Senior Notes due 2022 $ 500.0 $ 500.0 125.0 125.0 125.0 125.0 50.6 51.2 49.6 49.9 $ 675.6 $ 897.1 $ 674.6 $ 674.9 On April 6, 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance (together the "Issuers") completed a private offering of $275.0$500.0 million aggregate principal amount of 9.0% First LienCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(8) Long-Term Debt (Continued) Secured Notes due 2015 (the "2010 First Lien Notes") and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the "Second Lien Notes," and together with the First Lien Notes, the "Old Notes"). The 2010 First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. On December 15, 2011, the Issuers sold an additional $200.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 ("Additional First Lien Notes" and together with the 2010 First Lien Notes, the "First Lien Notes"). The Additional First Lien Notes were sold at an issue price of 105.0%, plus accrued interest from October 1, 2011 of $3.7 million. The associated original issue premium of $10.0 million for the Additional First Lien Notes was amortized to interest expense and other financing costs over the term of the Additional First Lien Notes. The First Lien Notes were scheduled to mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. See further discussion below related to the tender for and subsequent redemption of all the outstanding First Lien Notes in the fourth quarter of 2012. The Second Lien Notes were scheduled to mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. On January 23, 2013, $253.0 million of the proceeds from the Refining Partnership's IPO were utilized to satisfy and discharge the indenture governing the Second Lien Notes. The amounts were used to (i) repay the face amount of all $222.8 million aggregate principal amount of Second Lien Notes then outstanding, (ii) pay the redemption premium of approximately $20.6 million and (iii) settle accrued interest with respect thereto in an amount of approximately $9.5 million. The repurchase of the Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million for the six months ended June 30, 2013, which includes the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.2022 Senior Secured Notes On October 23, 2012, Refining LLC and Coffeyville Finance completed a private offering of $500.0 million aggregate principal amount of 6.5% Second Lien Senior Secured Notes due 2022 (the "2022 Notes"). outstanding, which were issued by CVR Refining, LLC ("Refining LLC") and Coffeyville Finance Inc. ("Coffeyville Finance") on October 23, 2012. The 2022 Notes were issued at par. Refining LLC received approximately $492.5 million of cash proceeds, net of the underwriting fees, but before deducting other third-party feespar and expenses associated with the offering. The 2022 Notes were secured by substantially the same assets that secured the then outstanding Second Lien Notes, subject to exceptions, until such time that the outstanding Second Lien Notes were satisfied and discharged in full, which occurred on January 23, 2013. The 2022 Notes are fully and unconditionally guaranteed by CVR Refining and each of Refining LLC's existing domestic subsidiaries on a joint and several basis. CVR Refining has no independent assets or operations and Refining LLC is a 100% owned finance subsidiary of CVR Refining. Prior to the satisfaction and discharge of the Second Lien Notes, which occurred on January 23, 2013, the 2022 Notes were also guaranteed by CRLLC. CVR Energy, the Nitrogen Fertilizer Partnership and Coffeyville Resources Nitrogen Fertilizers, LLC ("CRNF"), a wholly owned subsidiary of the Nitrogen Fertilizer Partnership, are not guarantors. A portion of the net proceeds from the offering of the 2022 Notes approximating $348.1 million were used to purchase approximately $323.0 million of the First Lien Notes pursuant to a tender offer and to settle accrued interest of approximately $1.8 million through October 23, 2012 and to payCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(8) Long-Term Debt (Continued)related fees and expenses. Tendered notes were purchased at a premium of approximately $23.2 million in aggregate amount. CRLLC used the remaining proceeds from the offering to redeem the remaining $124.1 million of outstanding First Lien Notes and to settle accrued interest of approximately $1.6 million through November 23, 2012. Redeemed notes were purchased at a premium of approximately $8.4 million in aggregate amount. Previously deferred financing charges and unamortized original issuance premium related to the First Lien Notes totaled approximately $8.1 million and $6.3 million, respectively. As a result of the repayment of the First Lien Notes, a loss on extinguishment of debt of $33.4 million was recorded in the fourth quarter of 2012, which included the total premiums paid of $31.6 million and write-off of previously deferred financing charges of $8.1 million, partially offset by the write-off of the unamortized original issuance premium of $6.3 million. The debt issuance costs of the 2022 Notes totaled approximately $8.7 million and are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. On May 29, 2013, Refining LLC filed a registration statement on Form S-4 to satisfy its obligations contained in the registration right agreement entered into in connection with the issuance of the 2022 Notes. The Refining Partnership has incurred approximately $0.3 million of debt registration costs related to this registration, which are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. �� The 2022 Notes mature on November 1, 2022, unless earlier redeemed or repurchased by the issuers. Interest is payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013.June 30, 2013,March 31, 2014, the Refining Partnership was in compliance with the covenants contained in the 2022 Notes.June 30, 2013,March 31, 2014, the estimated fair value of the 2022 Notes was approximately $490.0 million. These estimates$526.3 million. This estimate of fair value areis Level 2 as they wereit was determined by quotations obtained from a broker-dealer who makes a market in these and similar securities. On December 20, 2012, CRLLC, theRefining LLC and each of the operating subsidiaries of Refining LLC (collectively, the "Credit Parties") entered into an amended and restated ABLhas a senior secured asset based revolving credit agreementfacility (the "Amended and Restated ABL Credit Facility") with a group of lenders and Wells Fargo Bank, National Association ("(“Wells Fargo"Fargo”), as administrative agent and collateral agent. The Amended and Restated ABL Credit Facility which replaced the prior ABL credit facility, is scheduled to mature on December 20, 2017. Under the amended and restated facility, theCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(8) Long-Term Debt (Continued)Refining Partnership assumed the Company's position as borrower and the Company's obligations under the facility upon the closing of the Refining Partnership's IPO on January 23, 2013. The Amended and Restated ABL Credit Facility is a senior secured asset based revolving credit facility inhas an aggregate principal amount of up to $400.0$200.0$200.0 million subject to receipt of additional lender commitments and certain other conditions. The proceeds of the loans may be used for capital expenditures and working capital and general corporate purposes of the Credit PartiesRefining Partnership and theirits subsidiaries. The Amended and Restated ABL Credit Facility provides for loans and letters of credit in an amount up to the aggregate availability under the facility, subject to meeting certain borrowing base conditions, with sub-limits of 10% of the total facility commitment for swingline loans and 90% of the total facility commitment for letters of credit. Borrowings under the Amended and Restated ABL Credit Facility bear interest at either a base rate or LIBOR plus an applicable margin. The applicable margin is (i) (a) 1.75% for LIBOR borrowings and (b) 0.75% for prime rate borrowings, in each case if quarterly average excess availability exceeds 50% of the lesser of the borrowing base and the total commitments and (ii) (a) 2.00% for LIBOR borrowings and (b) 1.00% for prime rate borrowings, in each case if quarterly average excess availability is less than or equal to 50% of the lesser of the borrowing base and the total commitments. The Amended and Restated ABL Credit Facility also requires the payment of customary fees, including an unused line fee of (i) 0.40% if the daily average amount of loans and letters of credit outstanding is less than 50% of the lesser of the borrowing base and the total commitments and (ii) 0.30% if the daily average amount of loans and letters of credit outstanding is equalscheduled to or greater than 50% of the lesser of the borrowing base and the total commitments. The Refining Partnership will also be required to pay customary letter of credit fees equal to, for standby letters of credit, the applicable marginmature on LIBOR loans on the maximum amount available to be drawn under and, for commercial letters of credit, the applicable margin on LIBOR loans less 0.50% on the maximum amount available to be drawn under, and customary facing fees equal to 0.125% of the face amount of, each letter of credit.Credit PartiesRefining Partnership and theirits respective subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investmentinvestments and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries. The amended and restated facility also contains a fixed charge coverage ratio financial covenant, as defined therein. The Credit Parties wereRefining Partnership was in compliance with the covenants of the Amended and Restated ABL Credit Facility as of June 30, 2013. Lender and other third-party costs associated with the Amended and Restated ABL Credit Facility of $2.1 million were deferred and are being amortized to interest expense and other financing costs using a straight-line method over the term of the amended facility. In accordance with guidance provided by the FASB regarding the modification of revolving debt arrangements, a portion of the unamortized deferred financing costs associated with the prior ABL credit facility of approximately $2.8 million will continue to be amortized over the term of the Amended and Restated ABL Credit Facility.Table of ContentsCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(8) Long-Term Debt (Continued)June 30, 2013,March 31, 2014, the Refining Partnership and its subsidiaries had availability under the Amended and Restated ABL Credit Facility of $372.9$372.9 million and had letters of credit outstanding of approximately $27.1 million.$27.1 million. There were no borrowings outstanding under the Amended and Restated ABL Credit Facility as of June 30, 2013. On April 13, 2011, CRNF,entered intohave a credit facility with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent. The credit facility includes a term loan facility of $125.0$125.0 million and a revolving credit facility of $25.0$25.0 million with an uncommitted incremental facility of up to $50.0 million. $50.0 million. No amounts were outstanding under the revolving credit facility at June 30, 2013.March 31, 2014. There is no scheduled amortization of the credit facility, which matures in April 2016. The carrying value of the Nitrogen Fertilizer Partnership'sPartnership’s debt approximates fair value. Borrowings under the credit facility bear interest based on a pricing grid determined by the trailing four quarter leverage ratio. The initial pricing for Eurodollar rate loans under the credit facility is the Eurodollar rate plus a margin of 3.50% or, for base rate loans, the prime rate plus 2.50%. Under its terms, the lenders under the credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in substantially all of the assets of CRNF and the Nitrogen Fertilizer Partnership.orand the ability to enter into sale-leaseback transactions andor affiliate transactions. The credit facility provides that the Nitrogen Fertilizer Partnership can make distributions to holders of its common units provided, among other things, it is in compliance with the leverage ratio and interest coverage ratio on a pro forma basis after giving effect to any distribution and there is no default or event of default under the credit facility. As of June 30, 2013,March 31, 2014, CRNF was in compliance with the covenants contained in the credit facility and there were no borrowings outstanding under the credit facility.wereare included in property, plant and equipment. The capital lease relates to a sales-lease back agreement with Sunoco Pipeline, L.P. for its membership interest in the Excel Pipeline. The lease has 196187 months remaining through September 2029. The financing agreement relates to the Magellan Pipeline terminals, bulk terminal and loading facility. The lease has 195186 months remaining and will expire in September 2029.June 30, 2013(unaudited)(9) Dividends24,23, 2013, the board of directors$253.0 million of the Company adoptedproceeds from the Refining Partnership’s IPO were utilized to satisfy and discharge the indenture governing the previously outstanding Second Lien Senior Secured Notes due 2017 (the "Second Lien Notes"). The amounts were used to (i) repay the face amount of all $222.8 million aggregate principal amount of Second Lien Notes then outstanding, (ii) pay the redemption premium of approximately $20.6 million and (iii) settle accrued interest with respect thereto in an amount of approximately $9.5 million. The repurchase of the Second Lien Notes resulted in a quarterly cash dividend policy. Subject to declaration by its boardloss on extinguishment of directors, CVR Energy's initial quarterly dividend is expected to be $0.75 per share, or $3.00 per share on an annualized basis, whichdebt of approximately $26.1 million for the Company began paying in the second quarter of 2013. Additionally, the Company declared and paid two special cash dividends during the sixthree months ended June 30, 2013. The following is a summaryMarch 31, 2013, which includes the write-off of the quarterlypreviously deferred financing fees of $3.7 million and special dividends paid to stockholders during the six months ended June 30, 2013: February 19,
2013 May 17,
2013 June 10,
2013 Total Dividends
Paid in 2013 ($ in millions, expect per share amounts) Special Quarterly Special $ 391.6 $ 53.4 $ 462.8 $ 907.8 86.0 11.7 101.6 199.3 $ 477.6 $ 65.1 $ 564.4 $ 1,107.1 $ 5.50 $ 0.75 $ 6.50 $ 12.75 86.8 86.8 86.8 (10)(9) Earnings Per Share For the Three Months
Ended June 30, For the Six Months
Ended June 30, 2013 2012 2013 2012 (in millions, except per share data) $ 183.4 $ 154.7 $ 348.4 $ 129.5 86.8 86.8 86.8 86.8 — 1.6 — 1.7 — — — — 86.8 88.4 86.8 88.5 $ 2.11 $ 1.78 $ 4.01 $ 1.49 $ 2.11 $ 1.75 $ 4.01 $ 1.46 Three Months Ended
March 31, 2014 2013 (in millions, except per share data) Net income attributable to CVR Energy stockholders $ 126.7 $ 165.0 Weighted-average shares of common stock outstanding - Basic 86.8 86.8 Weighted-average shares of common stock outstanding - Diluted 86.8 86.8 Basic earnings per share $ 1.46 $ 1.90 Diluted earnings per share $ 1.46 $ 1.90 All outstanding stock options totaling 22,900 were exercised in May 2012. and six months ended June 30, March 31, 2014 and 2013, as all unvested awards under the LTIP were liability-classified awards. See Note 3 ("Share-BasedShare‑Based Compensation").Table of ContentsCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(11)(10) Commitments and ContingenciesCVR'sCVR’s lease agreements and unconditional purchase obligations are as follows: Operating
Leases Unconditional
Purchase
Obligations(1) (in millions) $ 4.8 $ 99.2 9.1 112.9 7.7 101.2 6.7 94.0 4.0 92.8 8.0 951.4 $ 40.3 $ 1,451.5 (in millions) Nine Months Ending December 31, 2014 $ 7.1 $ 104.2 Year Ending December 31, 2015 7.9 110.4 2016 6.6 102.6 2017 4.3 101.4 2018 3.0 101.4 Thereafter 5.3 884.5 $ 34.2 $ 1,404.5
CVR ENERGY, INC. AND SUBSIDIARIES(1)This amount includes approximately $979.8 million payable ratably over eighteen years pursuant to petroleum transportation service agreements between CRRM and TransCanada Keystone Pipeline, LP ("TransCanada"). Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of twenty years on TransCanada's Keystone pipeline system. CRRM began receiving crude oil under the agreements in the first quarter of 2011.(1) rail cars,railcars and real properties, under long-term operating leases which expire at various dates. For the three months ended June 30, 2013March 31, 2014 and 2012,2013, lease expense totaled approximately $2.2$2.2 million and $1.4$2.3 million respectively. For the six months ended June 30, 2013 and 2012, lease expense totaled approximately $4.5 million and $2.7 million,, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at CVR'sCVR’s option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire.
three months ended March 31, 2014 and 2013, total expense of $35.8 million and $35.0 million, respectively, was incurred related to long-term commitments., entered into an Amended and Restated Crude Oil Supply Agreement (the "Vitol Agreement"). The Vitol Agreement amends and restates the Crude Oil Supply Agreement between CRRM and Vitol dated March 30, 2011, as amended. Under the Vitol Agreement, Vitol supplies the petroleum business with crude oil and intermediation logistics, which helps to reduce the Refining Partnership's inventory position and mitigate crude oil pricing risk.one-yearCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(11) Commitments and Contingencies (Continued)Litigation"Environmental,“Environmental, Health, and Safety ("EHS"(“EHS”) Matters."” Liabilities related to such litigation are recognized when the related costs are probable and can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. It is possible that management'smanagement’s estimates of the outcomes will change due to uncertainties inherent in litigation and settlement negotiations. Except as described below, there were no new proceedings or material developments in proceedings that CVR previously reported in its 2013 Form 10-K. In the opinion of management, the ultimate resolution of any other litigation matters is not expected to have a material adverse effect on the accompanying condensed consolidated financial statements. There can be no assurance that management'smanagement’s beliefs or opinions with respect to liability for potential litigation matters are accurate. In May 2010, separate groups of plaintiffs (the "Anstine and Arrow cases") filed two lawsuits against CRRM and other defendants in state court in Oklahoma and Kansas. Both lawsuits were removed to federal court and were then transferred to the Bankruptcy Court for the United States District Court for the District of Delaware. The Anstine and Arrow cases alleged the respective plaintiffs sold crude oil to a group of companies, which generally are known as SemCrude or SemGroup (collectively, "Sem"), which later declared bankruptcy and that Sem did not pay such plaintiffs for all of the crude oil purchased by Sem. Both lawsuits sought the same remedy, the imposition of a trust, an accounting and the return of crude oil or the proceeds therefrom. In February 2013, CRRM agreed to a settlement in the Anstine and Arrow cases, which was finalized with the plaintiffs in June 2013, and CRRM has been dismissed with prejudice. The settlement did not have a material adverse effect on the condensed consolidated financial statements. On June 21, 2012, Goldman, Sachs & Co. ("GS") filed suit against CVR in state court in New York, alleging that CVR failed to pay GS approximately $18.5 million in fees allegedly due to GS by CVR pursuant to an engagement letter dated March 21, 2012, which according to the allegations set forth in the complaint, provided that GS was engaged by CVR to assist CVR and the CVR board of directors in connection with a tender offer for CVR's stock, made by IEP and certain of its affiliates. CVR believes it has meritorious defenses and intends to vigorously defend against the suit. This amount has been fully accrued as of June 30, 2013. On August 10, 2012, Deutsche Bank ("DB") filed suit against CVR in state court in New York, alleging that CVR failed to pay DB approximately $18.5 million in fees allegedly due to DB by CVR pursuant to an engagement letter dated March 23, 2012, which according to the allegations set forth in the complaint, provided that DB was engaged by CVR to assist CVR and the CVR board of directors in connection with a tender offer for CVR's stock made by IEP and certain of its affiliates. CVR believes it has meritorious defenses and intends to vigorously defend against the suit. This amount has been fully accrued as of June 30, 2013. On December 17, 2012, Gary Community Investment Company, F/K/A The Gary-Williams Company and GWEC Holding Company, Inc. (referred to herein collectively as "Gary-Williams") filed a lawsuit in the Supreme Court of New York, New York County (Gary Community Investment Co. v. CVR Energy, Inc., No. 654401/12) against CVR and CRLLC (referred to collectively for purposes of this paragraph as "CVR"). The action arises out of claims relating to CVR's purchase of theCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(11) Commitments Contingencies (Continued)Wynnewood, Oklahoma refinery pursuant to the Purchase and Sale Agreement entered into by the parties on November 2, 2011 (the "Purchase Agreement"). Specifically, CVR provided notice to Gary-Williams that it sought indemnification for various breaches of the Purchase Agreement and subsequently made a claim notice for payment of the entire escrow property pursuant to the Escrow Agreement by and among Gary-Williams, CRLLC, and the escrow agent, dated as of December 15, 2011. Gary-Williams, in its lawsuit, alleges that CVR breached the Purchase Agreement and the Escrow Agreement, and is seeking a declaratory judgment that CVR's claims are without any legal basis, damages in an unspecified amount, and release of the full amount of the escrow property to Gary-Williams. CRNF received a ten year property tax abatement from Montgomery County, Kansas in connection with the construction of the nitrogen fertilizer plant that expired on December 31, 2007. In connection with the expiration of the abatement, the county reclassified and reassessed CRNF's nitrogen fertilizer plant for property tax purposes. The reclassification and reassessment resulted in an increase in CRNF's annual property tax expense by an average of approximately $10.7 million per year for the years ended December 31, 2008 and 2009, $11.7 million for the year ended December 31, 2010, $11.4 million for the year ended December 31, 2011, and $11.3 million for the year ended December 31, 2012. CRNF protested the classification and resulting valuation for each of those years to the Kansas Court of Tax Appeals ("COTA"), followed by an appeal to the Kansas Court of Appeals. However, CRNF fully accrued and paid the property taxes the county claimed were owed for the years ended December 31, 2008 through 2012. On February 25, 2013, Montgomery County and CRNF agreed to a settlement for tax years 2009 through 2012, which will lower CRNF's property taxes by about $10.5 million per year for tax years 2013 through 2016 based on current mill levy rates. In addition, the settlement provides that Montgomery County will support CRNF's application before COTA for a ten year tax exemption for the UAN expansion. Finally, the settlement provides that CRNF will continue its appeal of the 2008 reclassification and reassessment.Flood, Crude Oil Discharge and InsuranceCompany'sCompany’s Coffeyville refinery on July 1, 2007, due to the short amount of time available to shut down and secure the refinery in preparation for the flood that occurred on June 30, 2007. In May 2008, in connection with the discharge, the Company received notices of claims from sixteen private claimants under the Oil Pollution Act ("OPA") in an aggregate amount of approximately $4.4 million (plus punitive damages). In August 2008, those claimants filed suitThe last remaining claim against the Company inrelated to this matter was settled during the United States District Court for the District of Kansas in Wichita (the "Angleton Case"). In October 2009 and June 2010, companion cases to the Angleton Case were filed in the United States District Court for the District of Kansas in Wichita, seeking a total of approximately $3.2 million (plus punitive damages) for three additional plaintiffs as a result of the July 1, 2007 crude oil discharge.months ended March 31, 2014. The Company has settled all of the claims with the plaintiffs from the Angleton Case and has settled all of the claims except for one of the plaintiffs from the companion cases. The settlementssettlement did not have a material adverse effect on the condensed consolidated financial statements. The Company believes that the resolution of the remaining claim will not have a material adverse effect on the condensed consolidated financial statements.CVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(11) Commitments and Contingencies (Continued) On October 25, 2010, the Company received a letter from the United States Coast Guard on behalf of the U.S. Environmental Protection Agency (the "EPA") seeking approximately $1.8 million in oversight cost reimbursement. The Company responded by asserting defenses to the Coast Guard's claim for oversight costs. On September 23, 2011, the United States Department of Justice ("DOJ"), acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas seeking recovery from CRRM related to alleged non-compliance with the Clean Air Act's Risk Management Program ("RMP"), the Clean Water Act ("CWA") and the OPA. CRRM has reached an agreement with the DOJ resolving its claims under the CWA and the OPA. The agreement is memorialized in a Consent Decree that was filed with and approved by the Court on February 12, 2013 and March 25, 2013, respectively (the "2013 Consent Decree"). On April 19, 2013, CRRM paid a civil penalty plus accrued interest in the amount of $0.6 million for the CWA violations and reimbursed the Coast Guard for oversight costs under OPA in the amount of $1.7 million. The 2013 Consent Decree also requires CRRM to make small capital upgrades to the Coffeyville refinery crude oil tank farm, develop flood procedures and provide employee training. The parties also reached an agreement to settle DOJ's RMP claims. The agreement was filed with and approved by the Court on May 21, 2013 and July 2, 2013, respectively, and provided for a civil penalty of $0.3 million. On July 29, 2013, CRRM paid the civil penalty related to the RMP settlement agreement. The Company is seeking insurance coverage for this release and for the ultimate costs for remediation and third-party property damage claims. On July 10, 2008, the Company filed a lawsuit in the United States District Court for the District of Kansas against certain of the Company's environmental insurance carriers requesting insurance coverage indemnification for the June/July 2007 flood and crude oil discharge losses. Each insurer reserved its rights under various policy exclusions and limitations and cited potential coverage defenses. Although the Court has now issued summary judgment opinions that eliminate the majority of the insurance defendants' reservations and defenses, the Company cannot be certain of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the Company's claims. The Company has received $25.0 million of insurance proceeds under its primary environmental liability insurance policy which constitutes full payment to the Company of the primary pollution liability policy limit. The lawsuit with the insurance carriers under the environmental policies remains the only unsettled lawsuit with the insurance carriers related to these events.("EHS"(“EHS”) Matters("CRCT"(“CRCT”), Wynnewood Refining Company, LLC ("WRC"(“WRC”) and Coffeyville Resources Terminal, LLC ("CRT"(“CRT”) own and/or operate manufacturing and ancillary operations atCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(11) Commitments and Contingencies (Continued)OPAOil Pollution Act generally subjects owners and operators of facilities to strict, joint and several liability for all containment and clean-up costs, natural resource damages, and potential governmental oversight costs arising from oil spills into the waters of the United States. CRRM and CRT have agreedStates, which has been broadly interpreted to perform corrective actions at the Coffeyville, Kansas refinery and the now-closed Phillipsburg, Kansas terminal facility, pursuant to Administrative Orders on Consent issued under RCRA to address historical contamination by the prior owners (RCRA Docket No. VII-94-H-0020 and Docket No. VII-95-H-011, respectively). As of June 30, 2013 and December 31, 2012, environmental accruals of approximately $1.9 million and $2.3 million, respectively, were reflected in the Condensed Consolidated Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders, for which approximately $0.5 million and $0.7 million, respectively, are included in other current liabilities. The Company's accruals were determined based on an estimate of payment costs through 2031, for which the scope of remediation was arranged with the EPA, and were discounted at the appropriate risk free rates at June 30, 2013 and December 31, 2012, respectively. The accruals include estimated closure and post-closure costs of approximately $0.8 million for two landfills at both June 30, 2013 and December 31, 2012. The estimated future payments for these required obligations are as follows: Amount (in millions) $ 0.4 0.3 0.2 0.1 0.1 1.1 2.2 0.3 $ 1.9 Management periodically reviews and, as appropriate, revises its environmental accruals. Based on current information and regulatory requirements, management believes that the accruals established for environmental expenditures are adequate.theCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(11) Commitments and Contingencies (Continued) In 2007,EPA promulgatedpetroleum and nitrogen fertilizer businesses are party to, or otherwise subject to: (i) administrative orders and consent decrees with federal, state and local environmental authorities, as applicable, addressing corrective actions under RCRA, the Clean Air Act and the Clean Water Act; (ii) the Mobile Source Air Toxic II ("(“MSAT II"II”) rule thatwhich requires the reductionreductions of benzene in gasoline by 2011. CRRM and WRC are considered to be small refiners under the MSAT II rule and compliance with the rule is extended until 2015 for small refiners. However, the change in control resulting from the IEP Acquisition in 2012 triggered the loss of small refiner status. Accordingly, the MSAT II projects have been accelerated by three months. Capital expenditures to comply with the rule are expected to be approximately $59.0 million for CRRM and $98.0 million for WRC. The petroleum business is subject togasoline; (iii) the Renewable Fuel Standard ("RFS"(“RFS”), which requires refiners to blend "renewable fuels"“renewable fuels” in with their transportation fuels or purchase renewable energyfuel credits, known as RINs in lieu of blending. The EPA is required to determineblending; and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 for the forthcoming year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. The EPA has not yet finalized the 2013 renewable fuel percentage standard, but has proposed to raise it to 9.6%. Beginning in 2011, the Coffeyville refinery was required to blend renewable fuels into its gasoline and diesel fuel or purchase RINs in lieu of blending, and in 2013, the Wynnewood refinery was required to comply. From time to time, the petroleum business may purchase RINs on the open market or waiver credits for cellulosic biofuels from the EPA in order to comply with RFS. While the petroleum business cannot predict the future prices of RINs or waiver credits, the cost of purchasing RINs has been extremely volatile and has significantly increased over the last year. The cost of RINs for the three and six month periods ended June 30, 2012 was approximately $6.0 million and $9.3 million, respectively, and the cost of RINs for the three and six month periods ended June 30, 2013 was approximately $65.5 million and $97.6 million, respectively. As of June 30, 2013 and December 31, 2012, the petroleum business' biofuel blending obligation was approximately $82.6 million and $1.1 million, respectively, which was recorded in other current liabilities on the Condensed Consolidated Balance Sheets. The petroleum business expects that the cost of RINs will continue to be substantially higher in 2013 as compared to 2012. The ultimate cost of RINs for the petroleum business in 2013 is difficult to estimate. In particular, the cost of RINs is dependent upon a variety of factors, which include the price at which RINs can be purchased, transportation fuel production levels, the mix of the petroleum business' petroleum products, as well as the fuel blending performed at the its refineries, all of which can vary significantly from quarter to quarter. In 2013, the EPA proposed "Tier 3"(iv) “Tier 3” gasoline sulfur standards. Based onExcept as otherwise described below, there have been no new developments or material changes to the proposed standards, CRRM anticipates it will incur less than $20.0 million ofenvironmental accruals or expected capital expenditures to install controls in order to meet the anticipated new standards. The project is expected to be completed during the Coffeyville refinery's next scheduled turnaround in 2016. It is not anticipated that the Wynnewood refinery will require additional controls or capital expenditures to meet the anticipated new standard. In March 2004, CRRM and CRT entered into a Consent Decree (the "2004 Consent Decree") with the EPA and the Kansas Department of Health and Environment (the "KDHE") to resolve airCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(11) Commitments and Contingencies (Continued)compliance concerns raised by the EPA and KDHE related to Farmland Industries Inc.'s prior ownership and operation of the Coffeyville crude oil refinery and the now-closed Phillipsburg terminal facilities. Under the 2004 Consent Decree, CRRM agreed to install controls to reduce emissions of sulfur dioxide, nitrogen oxides and particulate matter from its FCCU by January 1, 2011. In addition, pursuant to the 2004 Consent Decree, CRRM and CRT assumed clean-up obligations at the Coffeyville refinery and the now-closed Phillipsburg terminal facilities. In March 2012, CRRM entered into a "Second Consent Decree" with the EPA, which replaces the 2004 Consent Decree, as amended (other than certain financial assurance provisions associated with corrective action at the refinery and terminal under RCRA). The Second Consent Decree gives CRRM more time to install the FCCU controls from the 2004 Consent Decree and expands the scope of the settlement so that it is now considered a "global settlement" under the EPA's "National Petroleum Refining Initiative." Under the National Petroleum Refining Initiative, the EPA identified industry-wide non-compliance with four "marquee" issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The National Petroleum Refining Initiative has resulted in most U.S. refineries (representing more than 90% of the US refining capacity) entering into consent decrees imposing civil penalties and requiring the installation of pollution control equipment and enhanced operating procedures. Under the Second Consent Decree, the Company was required to pay a civil penalty of approximately $0.7 million and complete the installation of FCCU controls required under the 2004 Consent Decree, add controls to certain heaters and boilers and enhance certain work practices relating to wastewater and fugitive emissions. The remaining costs of complying with the Second Consent Decree are expected to be approximately $40.0 million. CRRM also agreed to complete a voluntary environmental project that will reduce air emissions and conserve water at an estimated cost of approximately $1.2 million. Additional incremental capital expenditures associated with the Second Consent Decree will not be material and will be limited primarily to the retrofit and replacement of heaters and boilers over a five to seven year timeframe. The Second Consent Decree was entered by the U.S. District Court for the District of Kansas on April 19, 2012. WRC's refinery has not entered into a global settlement with the EPA and the Oklahoma Department of Environmental Quality (the "ODEQ") under the National Petroleum Refining Initiative, although it had discussions with the EPA and the ODEQ about doing so. Instead, WRC entered into a Consent Order with the ODEQ in August 2011 (the "Wynnewood Consent Order"). The Wynnewood Consent Order addresses some, but not all, of the traditional marquee issues under the National Petroleum Refining Initiative and addresses certain historic Clean Air Act compliance issues that are generally beyond the scope of a traditional global settlement. Under the Wynnewood Consent Order, WRC paid a civil penalty of $950,000, and agreed to install certain controls, enhance certain compliance programs, and undertake additional testing and auditing. A substantial portion of the costs of complying with the Wynnewood Consent Order were expended during the last turnaround. The remaining costs are expected to be approximately $3.0 million. In consideration for entering into the Wynnewood Consent Order, WRC received a release from liability from ODEQ for matters described in the ODEQ order.CVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(11) Commitments and Contingencies (Continued) From time to time, the EPA has conducted inspections and issued information requests to CRNF with respect to the Company's compliance with the RMP and the release reporting requirements under CERCLA and the EPCRA. These previous investigations have resultedforegoing environmental matters from those provided in the issuance of preliminary findings regarding CRNF's compliance status. In the fourth quarter of 2010, following CRNF's reported release of ammonia from its cooling water system and the rupture of its UAN vessel (which released ammonia and other regulated substances), the EPA conducted its most recent inspection and issued an additional request for information to CRNF. The EPA has not made any formal claims against the Company and the Company has not accrued for any liability associated with the investigations or releases. WRC has entered into a series of Clean Water Act consent orders with ODEQ. The latest Consent Order (the "CWA Consent Order"), which supersedes other consent orders, became effective in September 2011. The CWA Consent Order addresses alleged noncompliance by WRC with its Oklahoma Pollutant Discharge Elimination System permit limits. The CWA Consent Order requires WRC to take corrective action steps, including undertaking studies to determine whether the Wynnewood refinery's wastewater treatment plant capacity is sufficient. The Wynnewood refinery may need to install additional controls or make operational changes to satisfy the requirements of the CWA Consent Order. The cost of additional controls, if any, cannot be predicted at this time. However, based on our experience with wastewater treatment and controls, the Company does not anticipate that the costs of any required additional controls or operational changes would be material. Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended June 30,CVR's 2013 and 2012, capital expenditures were approximately $15.8 million and $8.1 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations. For the six months ended June 30, 2013 and 2012, capital expenditures were approximately $38.0 million and $11.0 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.aboveor referenced herein or other EHS matters which may develop in the future will not have a material adverse effect on the Company's business, financial condition, or results of operations.Wynnewood Refinery IncidentAt On September 28, 2012,March 31, 2014, the Company’s Condensed Consolidated Balance Sheet included total environmental accruals of $1.4 million, compared with $1.5 million at December 31, 2013. Management periodically reviews and, as appropriate, revises its environmental accruals. Based on current information and regulatory requirements, management believes that the accruals established for environmental expenditures are adequate.experienced an explosion inand pursues enforcement related to any alleged non-compliance with the Clean Air Act seeking civil penalties and injunctive relief, which may necessitate the installation of controls. In January 2014, ODEQ issued a boiler unit during startup after a short outage as partfull compliance evaluation ("FCE") report covering the period from December 2010 through June 2013, which covered periods of the turnaround process. Two employees were fatally injured. Damage atprevious owner's ownership and operation and, in some cases, continued into CVR Refining's ownership of the refinery was limitedWynnewood refinery. In addition, on April 11, 2014, WRC received a partial compliance evaluation ("PCE") report from ODEQ alleging additional violations of the Clean Air Act. ODEQ has indicated that it will pursue enforcement related to the boiler. Additionally, there was no environmental impact. The refinery was inalleged non-compliance and that it expects to enter into a consent order with WRC to resolve its claims, which would necessitate the final stagespayment of shutdown for turnaround maintenance ata civil penalty and the time of the incident. The petroleum business completed an internal investigation of the incident and continues to cooperate with OSHA and Oklahoma Department of Labor investigations. OSHA also conducted a general inspection of the facility during the boiler incident investigation. In March 2013, OSHA completed its investigation and communicated its citations to WRC. OSHA also placed WRC in its Severe Violators Enforcement Program ("SVEP"). WRC has filed its notice of contest against the citations, and willJune 30, 2013(11) CommitmentsContingencies (Continued)vigorously defend againstcontrol requirements, the citations and OSHA's placementCompany does not anticipate that the costs of WRC inany civil penalties, required additional controls or operational changes would be material.SVEP. WRC is in the processWynnewood refinery related to alleged violations of reviewing the citations and no settlement has been reached. Any penalties associated with OSHA's citations are not expectedits Clean Water Act permit. The costs of any enforcement related to have a material adverse effectthese issues cannot be predicted at this time. However, based on the condensed consolidated financial statements.Company'sCompany’s capital stock. Applicable pension and tax laws make each member of a "controlled group"“controlled group” of entities, generally defined as entities in which there is at least an 80% common ownership interest, jointly and severally liable for certain pension plan obligations of any member of the controlled group. These pension obligations include ongoing contributions to fund the plan, as well as liability for any unfunded liabilities that may exist at the time the plan is terminated. In addition, the failure to pay these pension obligations when due may result in the creation of liens in favor of the pension plan or the Pension Benefit Guaranty Corporation ("PBGC") against the assets of each member of the controlled group.OneTwo such entity,entities, ACF Industries LLC is(“ACF”) and Federal-Mogul, are the sponsorsponsors of several pension plans. All the minimum funding requirements of the Code and the Employee Retirement Income Security Act of 1974, as amended by the Pension Protection Act of 2006, for these plans have been met as of June 30,March 31, 2014 and December 31, 2013. If the ACF and Federal-Mogul plans were voluntarily terminated, they would be underfunded by approximately $125.4$483.1 million and $591.8 million as of June 30, 2013. Subsequent to June 30,March 31, 2014 and December 31, 2013, as a result of Mr. Icahn's affiliates obtaining approximately 80.7% of the outstanding common stock of Federal-Mogul Corporation, ("Federal-Mogul") the Company is also subject to the pension liabilities of Federal-Mogul. If the plans of Federal-Mogul and ACF were voluntarily terminated, as of June 30, 2013, they would collectively be underfunded by approximately $764.4 million.respectively. These results are based on the most recent information provided by Mr. Icahn's affiliates based on information from the plans' actuaries. These liabilities could increase or decrease, depending on a number of factors, including future changes in benefits, investment returns, and the assumptions used to calculate the liability. As members of the controlled group, CVR Energy would be liable for any failure of ACF and subsequent to June 30, 2013, Federal-Mogul to make ongoing pension contributions or to pay the unfunded liabilities upon a termination of their respective pension plans. In addition, other entities now or in the future within the controlled group that includes CVR Energy may have pension plan obligations that are, or may become, underfunded, and the Company would be liable for any failure of such entities to make ongoing pension contributions or to pay the unfunded liabilities upon a termination of such plans. The current underfunded status of the ACF and Federal-Mogul pension plans requires such entities to notify the PBGC of certain "reportable“reportable events,"” such as if CVR Energy were to cease to be a member of the controlled group, or if CVR Energy makes certain extraordinary dividends or stock redemptions. The obligation to report could cause the Company to seek to delay or reconsider the occurrence of such reportable events. Based on the contingent nature of potential exposure related to these affiliate pension obligations, no liability has been recorded in the condensed consolidated financial statements.June 30, 2013 Commitments and Contingencies (Continued) Starfire Holding Corporation ("Starfire") which is 99.4% owned by Mr. Icahn, has undertaken to indemnify CVR Energy from losses resulting from any imposition of certain pension funding or termination liabilities that may be imposed the Company or its assets as a result of being a member of the Icahn controlled group. However, Starfire is not required to maintain a net worth equal to the amounts by which ACF and Federal-Mogul are underfunded, and there can be no guarantee Starfire will be able to fund its indemnification obligations to the Company.(12) Fair Value Measurements820—820 — Fair Value Measurements and Disclosures ("(“ASC 820"820”), the Company utilizes the market approach to measure fair value for its financial assets and liabilities. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities or a group of assets or liabilities, such as a business.•1—1 — Quoted prices in active markets for identical assets and liabilities•2—2 — Other significant observable inputs (including quoted prices in active markets for similar assets or liabilities)•3—3 — Significant unobservable inputs (including the Company'sCompany’s own assumptions in determining the fair value)June 30, 2013March 31, 2014 and December 31, 2012:2013: June 30, 2013 March 31, 2014 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (in millions) (in millions) $ 124.0 $ — $ — $ 124.0 $ 81.0 $ — $ — $ 81.0 20.9 — — 20.9 4.3 — — 4.3 — 66.6 — 66.6 — 70.7 — 70.7 — 5.0 — 5.0 — 1.5 — 1.5 $ 144.9 $ 71.6 $ — $ 216.5 $ 85.3 $ 72.2 $ — $ 157.5 — (0.1 ) — (0.1 ) — (0.9 ) — (0.9 ) — (0.9 ) — (0.9 ) — (43.1 ) — (43.1 ) — — — — Other current liabilities (biofuel blending obligations) — (28.6 ) — (28.6 ) — (1.2 ) — (1.2 ) — (0.8 ) — (0.8 ) $ — $ (45.3 ) $ — $ (45.3 ) $ — $ (30.3 ) $ — $ (30.3 ) December 31, 2013 Level 1 Level 2 Level 3 Total (in millions) Location and Description Cash equivalents $ 81.0 $ — $ — $ 81.0 Other current assets (other derivative agreements) — 0.9 — 0.9 Other long-term assets (other derivative agreements) — 0.1 — 0.1 Total Assets $ 81.0 $ 1.0 $ — $ 82.0 Other current liabilities (other derivative agreements) — (15.3 ) — (15.3 ) Other current liabilities (interest rate swap) — (0.9 ) — (0.9 ) Other current liabilities (biofuel blending obligation) — (16.2 ) — (16.2 ) Other long-term liabilities (other derivative agreements) — (1.8 ) — (1.8 ) Other long-term liabilities (interest rate swap) — (1.0 ) — (1.0 ) Total Liabilities $ — $ (35.2 ) $ — $ (35.2 ) June 30, 2013(12) Fair Value Measurements (Continued) December 31, 2012 Level 1 Level 2 Level 3 Total (in millions) $ 134.0 $ — $ — $ 134.0 — — — — — 0.9 — 0.9 $ 134.0 $ 0.9 $ — $ 134.9 — (67.7 ) — (67.7 ) — (0.9 ) — (0.9 ) — (1.1 ) — (1.1 ) — — — — — (1.9 ) — (1.9 ) $ — $ (71.6 ) $ — $ (71.6 ) June 30, 2013March 31, 2014 and December 31, 2012,2013, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Company'sCompany’s cash equivalents, available-for-sale marketable securities, derivative instruments and the uncommitted biofuel blending obligation. Additionally, the fair value of the Company'sCompany’s debt issuances is disclosed in Note 8 ("Long-Term Debt"). The Refining Partnership'sPartnership’s commodity derivative contracts and the uncommitted biofuel blending obligation, which use fair value measurements and are valued using broker quoted market prices of similar instruments, which are considered Level 2 inputs. The Nitrogen Fertilizer Partnership has an interest rate swap that is measured at fair value on a recurring basis using Level 2 inputs. The fair value of these interest rate swap instruments are based on discounted cash flow models that incorporate the cash flows of the derivatives, as well as the current LIBOR rate and a forward LIBOR curve, along with other observable market inputs. The Company's investments in marketable securities are classified as available-for-sale, and as a result, are reported at fair market value using quoted market prices. As of June 30, 2013,March 31, 2014, the aggregate cost basis for the Company's available-for-sale securities is approximately $18.6 million.$4.3 million. The Company had no transfers of assets or liabilities between any of the above levels during the sixthree months ended June 30, 2013.March 31, 2014.Table of ContentsCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(13)(12) Derivative Financial Instrumentsconsisted of the following:and current period settlements on derivative contracts were as follows: Three Months Ended
June 30, Six Months Ended
June 30, 2013 2012 2013 2012 (in millions) $ 14.7 $ (8.1 ) $ (37.8 ) $ (27.2 ) 105.8 46.9 138.3 (81.3 ) $ 120.5 $ 38.8 $ 100.5 $ (108.5 ) Three Months Ended
March 31, 2014 2013 (in millions) Current period settlements on derivative contracts $ 21.1 $ (52.5 ) Gain (loss) on derivatives, net 109.4 (20.0 ) (gain) lossgain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.an other current assetassets or an other current liabilityliabilities within the Condensed Consolidated Balance Sheets. From time to time, the Refining Partnership may be required to deposit additional funds into this margin account. The fair value of theThere were no open commodity positions as of June 30, 2013 was a net loss of $0.1 million included in other current liabilities.March 31, 2014. For the three months ended June 30, 2013March 31, 2014 and 2012,2013, the Refining Partnership recognized a net losslosses of $0.2$0.1 million and a net gain of $4.1$2.2 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. For the six months ended June 30, 2013 and 2012, the Refining Partnership recognized net losses of $2.4 million and $3.9 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.SwapCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(13) Derivative Financial Instruments (Continued)June 30, 2013March 31, 2014 and December 31, 2012,2013, the Refining Partnership had open commodity hedging instruments consisting of 20.018.1 million barrels and 23.3 million barrels of crack spreads, respectively, primarily to fix the margin on a portion of its future gasoline and distillate production. The fair value of the outstanding contracts at June 30, 2013March 31, 2014 was a net unrealized gain of $71.6$72.2 million, of which $66.6$70.7 million is included in current assets and $5.0$1.5 million is included in non-current assets. For the three months ended June 30, 2013March 31, 2014 and 2012,2013, the Refining Partnership recognized a net gainsgain of $120.7$109.5 million and $34.7a net loss of $17.8 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. For the six months ended June 30, 2013 and 2012, the Refining Partnership recognized a net gain of $102.9 million and a net loss of $104.6 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.Swap On June 30 and July 1, 2011, Swapsentered into is subject to two floating-to-fixed interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of the nitrogen fertilizer business' $125.0business’ $125.0 million floating rate term debt which matures in April 2016. See Note 8 ("Long-Term Debt"). The aggregate notional amount covered under these agreements, which commenced on August 12, 2011 and expires on February 12, 2016, totals $62.5$62.5 million (split evenly between the two agreement dates). Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.975%. Both swap agreements are settled every 90 days.days. The effect of these swap agreements is to lock in a fixed rate of interest of approximately 1.96% plus the applicable margin paid to lenders over three month LIBOR as calculated under the CRNF credit agreement.facility. At June 30, 2013,March 31, 2014, the effective rate was approximately 4.58%4.56%. The agreements were designated as cash flow hedges at inception and accordingly, the effective portion of the gain or loss on the swap is reported as a component of accumulated other comprehensive income (loss) ("AOCI"(“AOCI”), and will be reclassified into interest expense when the interest rate swap transaction affects earnings. The ineffective portion of the gain or loss will be recognized immediately in current interest expense on the Condensed Consolidated Statements of Operations.swapswaps re-classed from AOCI into interest expense and other financing costs on the Condensed Consolidated Statements of Operations was $0.3$0.3 million and $0.2 million for each of the three months ended June 30, 2013March 31, 2014 and 2012, respectively.2013. For each of the three months ended June 30, 2013March 31, 2014 and 2012,2013, the Nitrogen Fertilizer Partnership recognized an increase in the fair value of the interest rate swap agreements of $0.2 million and a decrease in the fair value of the interest rate swap agreements of $0.7 million, respectively,swaps, which was unrealized in accumulated other comprehensive income. The realized loss on the interest rate swap re-classed from AOCI, into interestwas not material.CVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(13) Derivative Financial Instruments (Continued)expense and other financing costs on the Condensed Consolidated Statements of Operations was $0.5 million for each of the six months ended June 30, 2013 and 2012. For the six months ended June 30, 2013 and 2012, the Nitrogen Fertilizer Partnership recognized an increase in fair value of the interest rate swap agreements of $0.2 million and a decrease in fair value of the interest rate swap agreements of $1.0 million, respectively, which was unrealized in accumulated other comprehensive income.Partnership'sPartnership’s exchange-traded crude oil futures and certain over-the-counter forward swap agreements are potentially exposed to concentrations of credit risk as a result of economic conditions and periods of uncertainty and illiquidity in the credit and capital markets. The Refining Partnership manages credit risk on its exchange-traded crude oil futures by completing trades with an exchange clearinghouse, which subjects the trades to mandatory margin requirements until the contract settles. The Refining Partnership also monitors the creditworthiness of its commodity swap counterparties and assesses the risk of nonperformance on a quarterly basis. Counterparty credit risk identified as a result of this assessment is recognized as a valuation adjustment to the fair value of the commodity swaps recorded in the Condensed Consolidated Balance Sheets. As of June 30, 2013,March 31, 2014, the counterparty credit risk adjustment was not material to the condensed consolidated financial statements. Additionally, the Refining Partnership does not require any collateral to support commodity swaps into which it enters; however, it does have master netting arrangements that allow for the setoff of amounts receivable from and payable to the same party, which mitigates the risk associated with nonperformance.Partnership'sPartnership’s recognized assets and liabilities associated with the outstanding derivative positions have beenJune 30, 2013March 31, 2014 and December 31, 2012.2013. In accordance with guidance issued by the FASB related to "“Disclosures about Offsetting Assets and Liabilities,"” the tables below outline the gross amounts of the recognized assets and liabilities and the gross amounts offset in the Condensed Consolidated Balance Sheets for the various types of open derivative positions at the Refining Partnership.Partnership'sPartnership’s derivatives as of June 30, 2013March 31, 2014 are recorded as current assets and non-current assets in prepaid expenses and other current assets andCVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(13) Derivative Financial Instruments (Continued) As of March 31, 2014 Description (in millions) Commodity Swaps $ 75.8 $ (5.1 ) $ 70.7 $ — $ 70.7 Total $ 75.8 $ (5.1 ) $ 70.7 $ — $ 70.7 As of March 31, 2014 Description (in millions) Commodity Swaps $ 1.7 $ (0.2 ) $ 1.5 $ — $ 1.5 Total $ 1.7 $ (0.2 ) $ 1.5 $ — $ 1.5 As of June 30, 2013 As of December 31, 2013 Gross
Current
Assets Gross
Amounts
Offset Net
Current
Assets
Presented Cash
Collateral
Not Offset Net
Amount (in millions) (in millions) $ 68.3 $ (1.7 ) $ 66.6 $ — $ 66.6 $ 4.3 $ (3.4 ) $ 0.9 $ — $ 0.9 $ 68.3 $ (1.7 ) $ 66.6 $ — $ 66.6 $ 4.3 $ (3.4 ) $ 0.9 $ — $ 0.9 As of June 30, 2013 Gross
Non-
Current
Assets Gross
Amounts
Offset Net
Non-
Current
Assets
Presented Cash
Collateral
Not Offset Net
Amount (in millions) $ 5.0 $ — $ 5.0 $ — $ 5.0 $ 5.0 $ — $ 5.0 $ — $ 5.0 As of June 30, 2013 Gross
Current
Liabilities Gross
Amounts
Offset Net
Current
Liabilities
Presented Cash
Collateral
Not Offset Net
Amount (in millions) $ 0.1 $ — $ 0.1 $ (0.1 ) $ — $ 0.1 $ — $ 0.1 $ (0.1 ) $ — The offsetting assets and liabilities for the Refining Partnership's derivatives as of December 31, 2012 are recorded as non-current assets in other long-term assets in the Condensed Consolidated Balance Sheets and as current liabilities in other current liabilities in the Condensed Consolidated Balance Sheets as follows: As of December 31, 2012 As of December 31, 2013 Gross
Non-
Current
Assets Gross
Amounts
Offset Net
Non-
Current
Assets
Presented Cash
Collateral
Not Offset Net
Amount (in millions) (in millions) $ 0.9 $ — $ 0.9 $ — $ 0.9 $ 0.1 $ — $ 0.1 $ — $ 0.1 $ 0.9 $ — $ 0.9 $ — $ 0.9 $ 0.1 $ — $ 0.1 $ — $ 0.1 June 30, 2013(13) Derivative Financial Instruments (Continued) As of December 31, 2012 As of December 31, 2013 Gross
Current
Liabilities Gross
Amounts
Offset Net
Current
Liabilities
Presented Cash
Collateral
Not Offset Net
Amount (in millions) (in millions) $ 74.2 $ (6.5 ) $ 67.7 $ — $ 67.7 $ 31.4 $ (16.1 ) $ 15.3 $ — $ 15.3 $ 74.2 $ (6.5 ) $ 67.7 $ — $ 67.7 $ 31.4 $ (16.1 ) $ 15.3 $ — $ 15.3 As of December 31, 2013 Description (in millions) Commodity Swaps $ 1.9 $ (0.1 ) $ 1.8 $ — $ 1.8 Total $ 1.9 $ (0.1 ) $ 1.8 $ — $ 1.8 (14)(13) Related Party TransactionsAcquisitionJune 30, 2013,March 31, 2014, IEP owned approximately 82% of all common shares outstanding.Lease Since2009, the Company, through the Nitrogen Fertilizer Partnership, has leased 199 railcars from American Railcar Leasing LLC ("ARL"),10, 2014, we paid a company controlled by Mr. Carl Icahn,cash dividend to the Company's majority stockholder. The agreement was scheduled to expirestockholders of record at the close of business on March 31, 2014. For3, 2014 for the three months ended June 30,fourth quarter of 2013 and 2012, $0.1 million and $0.3 million, respectively, of rent expense was recorded related to this agreement and is included in cost of product sold (exclusive of depreciation and amortization) in the Condensed Consolidated Statementsamount of Operations. For the six months ended June 30, 2013 and 2012, rent expense$0.75 per share, or $65.1 million in aggregate. IEP received $53.4 million in respect of $0.4 million and $0.5 million, respectively, was recorded related to this agreement. The Nitrogen Fertilizer Partnership negotiated an agreement with ARL to purchase the railcars under the lease for approximately $5.0 million. On June 13, 2013, the Nitrogen Fertilizer Partnership completed the purchase of the railcars.Icahn Enterprises,IEP, and subsequently entered into a tax allocation agreement with AEPC (the "Tax“Tax Allocation Agreement"Agreement”). The Tax Allocation Agreement provides that AEPC will pay all consolidated federal income taxes on behalf of the consolidated tax group. CVR is required to make payments to AEPC in an amount equal to the tax liability, if any, that it would have paid if it were to file as a consolidated group separate and apart from AEPC.June 30, 2013,March 31, 2014, the Company has recorded approximately $118.9$82.7 million for federal income taxes due to AEPC under the Tax Allocation Agreement. During the three months ended June 30,March 31, 2014 and 2013, the Company paid $54.0 million and $85.0 million for the first and second quarter estimated federal income taxno payments respectively, duewere made to AEPC under the Tax Allocation Agreement. In April 2014, the Company paid $49.0 million for the first quarter estimated federal income tax payment due to AEPC.CVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(14) Related Party Transactions (Continued)("(“Insight Portfolio Group"Group”) is an entity formed by Mr. Icahn in order to maximize the potential buying power of a group of entities with which Mr. Icahn has a relationship in negotiating with a wide range of suppliers of goods, services and tangible and intangible property at negotiated rates. In January 2013, CVR Energy acquired a minority equity interest in Insight Portfolio Group and agreed to pay a portion of Insight Portfolio Group'sGroup’s operating expenses in 2013.2013 and subsequent periods. The Company paid Insight Portfolio Group approximately $0.1 million during each of the three and six months ended June 30, 2013, respectively.March 31, 2014 and 2013. The Company may purchase a variety of goods and services as membersa member of the buying group at prices and terms that management believes would be more favorable than those which would be achieved on a stand-alone basis.(15)29Petroleumpetroleum and Nitrogen Fertilizer, CVR's nitrogen fertilizer, CVR’s two reporting segments, based on the definitions provided in ASC Topic 280—280 – Segment Reporting. All operations of the segments are located within the United States.PetroleumPetroleum Segmentpetroleum segment are refined fuels, propane, and petroleum refining by-products, including pet coke. The Petroleum Segment'spetroleum segment’s Coffeyville refinery sells pet coke to the Nitrogen Fertilizer Partnership for use in the manufacture of nitrogen fertilizer at the adjacent nitrogen fertilizer plant. For the Petroleum Segment,petroleum segment, a per-ton transfer price is used to record intercompany sales on the part of the Petroleum Segmentpetroleum segment and corresponding intercompany cost of product sold (exclusive of depreciation and amortization) for the Nitrogen Fertilizer Segment.nitrogen fertilizer segment. The per ton transfer price paid, pursuant to the pet coke supply agreement that became effective October 24, 2007, is based on the lesser of a pet coke price derived from the price received by the Nitrogen Fertilizer Segmentnitrogen fertilizer segment for UAN (subject to a UAN based price ceiling and floor) and a pet coke price index for pet coke. The intercompany transactions are eliminated in the Other Segment.other segment. Intercompany sales included in petroleum net sales were approximately $2.6$2.3 million and $2.4$2.7 million for the three months ended June 30, 2013March 31, 2014 and 2012,2013, respectively. Intercompany sales included innet sales were approximately $5.3 million and $4.8 million for the six months ended June 30, 2013 and 2012, respectively. The Petroleum Segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the net hydrogen purchases (sales) described below under "Nitrogen Fertilizer" of approximately and $4.0 million and $(0.1) million for the three months ended June 30, 2013 and 2012, respectively. For the six months ended June 30, 2013 and 2012, the Petroleum Segmentsegment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen purchases (sales)described below under “Nitrogen Fertilizer” of approximately $4.0$5.6 million,$29,000 for the three months ended March 31, 2014 and 2013, respectively. The Petroleum Segmentpetroleum segment recorded intercompany revenue for hydrogen sales of approximately $0.1$0 and $0.2 million and $0 for the three months ended June 30, 2013March 31, 2014 and 2012,2013, respectively. For the six months ended June 30, 2013 and 2012,CVR ENERGY, INC. AND SUBSIDIARIESNOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)June 30, 2013(unaudited)(15) Business Segments (Continued)the Petroleum Segment recorded intercompany revenue of approximately $0.3 million and $0, respectively.Nitrogen Fertilizer Segmentnitrogen fertilizer segment is nitrogen fertilizer. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was approximately $2.5$2.2 million and $2.3$2.6 million for the three months ended June 30, 2013March 31, 2014 and 20122013 respectively. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was approximately $5.1 million and $5.2 million for the six months ended June 30, 2013 and 2012, respectively.Company'sCompany’s segments have the right to transfer excess hydrogen between the Coffeyville refinery and nitrogen fertilizer plant. Sales of hydrogen to the Petroleum Segmentpetroleum segment have been reflected as net sales for the Nitrogen Fertilizer Segment.nitrogen fertilizer segment. Receipts of hydrogen from the Petroleum Segmentpetroleum segment have been reflected in cost of product sold (exclusive of depreciation and amortization) for the Nitrogen Fertilizer Segment.nitrogen fertilizer segment. For the three months ended June 30, 2013March 31, 2014 and 2012,2013, the net sales generated from intercompany hydrogen sales were $4.0$5.9 million and $0,$29,000, respectively. For the six months ended June 30, 2013 and 2012, the net sales generated from intercompany hydrogen sales were $4.0 million and $5.7 million, respectively. For each of the three months ended June 30, 2013March 31, 2014 and 2012,2013, the nitrogen fertilizer segment also recognized approximately $0.1$0 and $0.2 million of cost of product sold related to the transfer of excess hydrogen. For the six months ended June 30, 2013 and 2012, the Nitrogen Fertilizer Segment also recognized approximately $0.3 million and $0.1 million,, respectively, of cost of product sold related to the transfer of excess hydrogen. As these intercompany sales and cost of product sold are eliminated, there is no financial statement impact on the condensed consolidated financial statements.Other Segmentother segment reflects intercompany eliminations, corporate cash and cash equivalents, income tax activities and other corporate activities that are not allocated to the operating segments.June 30, 2013(15) Business Segments (Continued) Three Months Ended
June 30, Six Months Ended
June 30, Three Months Ended
March 31, 2013 2012 2013 2012 2014 2013 (in millions) (in millions) $ 2,138.1 $ 2,229.5 $ 4,412.1 $ 4,128.0 $ 2,375.3 $ 2,274.0 88.8 81.4 170.2 159.7 80.3 81.4 (6.6 ) (2.6 ) (9.6 ) (10.8 ) (8.2 ) (3.0 ) $ 2,220.3 $ 2,308.3 $ 4,572.7 $ 4,276.9 $ 2,447.4 $ 2,352.4 $ 1,776.6 $ 1,866.1 $ 3,582.3 $ 3,496.8 $ 2,063.3 $ 1,805.8 15.6 10.7 26.2 23.3 21.7 10.6 (6.8 ) (2.6 ) (9.5 ) (10.7 ) (8.1 ) (2.8 ) $ 1,785.4 $ 1,874.2 $ 3,599.0 $ 3,509.4 $ 2,076.9 $ 1,813.6 $ 83.8 $ 71.6 $ 169.9 $ 164.3 $ 99.2 $ 86.0 24.4 22.4 47.0 45.3 24.2 22.6 0.1 0.1 (0.1 ) — — (0.1 ) $ 108.3 $ 94.1 $ 216.8 $ 209.6 $ 123.4 $ 108.5 $ 28.4 $ 26.6 $ 56.4 $ 52.9 $ 29.5 $ 28.0 6.2 5.2 12.0 10.6 6.7 5.8 0.4 0.4 0.8 0.8 1.1 0.4 $ 35.0 $ 32.2 $ 69.2 $ 64.3 $ 37.3 $ 34.2 $ 229.1 $ 248.9 $ 564.7 $ 383.8 $ 164.6 $ 335.6 37.1 36.1 73.9 67.5 23.1 36.8 (3.5 ) (49.2 ) (8.3 ) (75.0 ) (4.2 ) (4.7 ) $ 262.7 $ 235.8 $ 630.3 $ 376.3 $ 183.5 $ 367.7 $ 35.5 $ 27.0 $ 80.1 $ 62.4 $ 57.9 $ 44.6 13.8 16.9 31.9 39.2 3.4 18.1 1.6 1.7 2.6 3.6 0.6 1.0 $ 50.9 $ 45.6 $ 114.6 $ 105.2 $ 61.9 $ 63.7 June 30, 2013(15) Business Segments (Continued) As of June 30,
2013 As of December 31,
2012 As of March 31, 2014 As of December 31, 2013 (in millions) (in millions) $ 2,800.2 $ 2,258.5 $ 2,769.4 $ 2,533.3 619.2 623.0 592.6 593.5 604.0 729.4 507.9 539.0 $ 4,023.4 $ 3,610.9 $ 3,869.9 $ 3,665.8 $ — $ — $ — $ — 41.0 41.0 41.0 41.0 — — — — $ 41.0 $ 41.0 $ 41.0 $ 41.0 (16)(15) Subsequent EventsDividendJuly 31, 2013,April 30, 2014, the board of directors of the Company declared a cash dividend for the secondfirst quarter of 20132014 to the Company'sCompany’s stockholders of $0.75$0.75 per share, or $65.1$65.1 million in aggregate. The dividend will be paid on AugustMay 19, 20132014 to stockholders of record at the close of business on AugustMay 12, 2013.2014. IEP will receive $53.4$53.4 million in respect of its 82% ownership interest in the Company'sCompany’s shares.July 26, 2013,April 30, 2014, the board of directors of the Nitrogen Fertilizer Partnership'sPartnership’s general partner declared a cash distribution for the secondfirst quarter of 20132014 to the Nitrogen Fertilizer Partnership'sPartnership’s unitholders of $0.583$0.38 per common unit, or $42.6$27.8 million in aggregate. The cash distribution will be paid on August 14, 2013May 19, 2014 to unitholders of record at the close of business on August 7, 2013.May 12, 2014. The Company will receive $22.7$14.8 million in respect of its Nitrogen Fertilizer Partnership common units.July 26, 2013,April 30, 2014, the board of directors of the Refining Partnership'sPartnership’s general partner declared a cash distribution for the secondfirst quarter of 20132014 to the Refining Partnership'sPartnership’s unitholders of $1.35$0.98 per common unit, or $199.3$144.6 million in aggregate. The cash distribution will be paid on August 14, 2013May 19, 2014 to unitholders of record at the close of business on August 7, 2013.May 12, 2014. The Company will receive $141.5$102.7 million in respect of its Refining Partnership common units.Item 2. Management'sManagement’s Discussion and Analysis of Financial Condition andResults of Operations20122013 filed with the Securities and Exchange Commission ("SEC"(“SEC”) on March 14, 2013.February 26, 2014 (the "2013 Form 10-K"). Results of operations for the three and six months ended June 30, 2013March 31, 2014 are not necessarily indicative of results to be attained for any other period.Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations, contains "forward-looking statements"“forward-looking statements” as defined by the SEC. SuchSEC, including statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. TheseForward-looking statements include, without limitation:•••"anticipates," "believes," "expects," "plans," "intends," "estimates," "projects," "could," "should," "may,"“anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “projects,” “could,” “should,” “may,” or similar expressions.Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations, are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements as a result of various factors, including but not limited to those set forth in the summary risks noted below:•change in control;••••••••••••••••••••business'business’ transportation cost advantage over its competitors;•••business'business’ ability to purchase gasoline and diesel RINs on a timely and cost effective basis;•business'business’ continued ability to secure environmental and other governmental permits necessary for the operation of our business;••••ammoniaUAN and UAN.ammonia. We own the general partner and a majority of the common units representing limited partner interests in each of the Refining Partnership and the Nitrogen Fertilizer Partnership.fertilizer. Throughout the remainder of the document, our business segmentsfertilizer, which are referred to in this document as our "petroleum business"“petroleum business” and our "nitrogen“nitrogen fertilizer business,"” respectively.June 30, 2013,March 31, 2014, we owned the general partner and approximately 71% of the common units of the Refining Partnership. The petroleum business consists of a 115,000 bpd bpcd rated capacity complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and a 70,000 bpd bpcd rated capacity medium complexity crude oil unit refinery in Wynnewood, Oklahoma capable of processing 20,000 bpd bpcd of light sour crude oil (within its rated capacity of 70,000 bpd capacity) bpcd). In addition, its supporting businesses include (1) a crude oil50,00055,000 bpd serving Kansas, Nebraska, Oklahoma, Missouri and Texas, (2) a rack marketing business supplying refined petroleum product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and Wynnewood, Oklahoma and at throughput terminals on Magellan and NuStar'sNuStar’s refined petroleum products distribution systems, (3) a 145,000 bpd pipeline system (supported by approximately 350 miles of Company owned and leased pipeline) that transports crude oil to the Coffeyville refinery and associated crude oil storage tanks with a capacity of 1.2 million barrels, (4) crude oil storage tanks with a capacity of 0.5 million barrels in Wynnewood, Oklahoma, (5) 1.0 million barrels of company owned crude oil storage capacity in Cushing, Oklahoma, (6) an additional 3.3 million barrels of leased crude oil storage capacity located in Cushing and (7) approximately 4.5 million barrels of combined refinery related storage capacity.$60.0$60.0 million on a hydrocracker project that will increase the conversion capability and the ULSD yield of the Wynnewood refinery. As of March 31, 2014, approximately $33.3 million has been spent on the Wynnewood hydrocracker project. The access to a variety of crude oils coupled with the complexity of the refineries allows the petroleum business to purchase crude oil at a discount to WTI. The consumed crude oil cost discount to WTI for the secondfirst quarter of 20132014 was $(2.90)$2.68 per barrel compared to $(2.06)$4.98 per barrel in the secondfirst quarter of 2012.2013.Table of ContentsJune 30, 2013,March 31, 2014, we owned the general partner and approximately 53% of the common units of the Nitrogen Fertilizer Partnership. The nitrogen fertilizer business consists of a nitrogen fertilizer manufacturing facility that is the only operation in North America that utilizes a petroleum coke, or pet coke, gasification process to produce nitrogen fertilizer. The facility includes a 1,225 ton-per-day ammonia unit, a 3,000 ton-per-day UAN unit and a gasifier complex having a capacity of 84 million standard cubic feet per day of hydrogen. The gasifier is a dual-train facility, with each gasifier able to function independently of the other, thereby providing redundancy and improving reliability. For the three and six months ended June 30, 2013,March 31, 2014, the nitrogen fertilizer business produced 91,318 and 202,670 tons of ammonia, respectively, of which approximately 100% and 86% was upgraded into 225,166 and 421,323257,232 tons of UAN respectively.and business'business’ existing asset base to execute its growth strategy. The Nitrogen Fertilizer Partnership'sPartnership’s growth strategy includes expanding production of UAN and acquiring additional infrastructure and production assets. The Nitrogen Fertilizer Partnership recently completed a significant two-year plant expansion designed to increasein February 2013, which increased its UAN production capacity by 400,000 tons, or approximately 50%, per year. The UAN expansion was completed in February 2013 and was at full rates prior to the end of the first quarter. The Nitrogen Fertilizer Partnership now upgradesexpects to upgrade substantially all of the ammonia it produces into higher margin UAN fertilizer.substantially all of the nitrogen fertilizer businesses'businesses’ competitors use natural gas as their primary raw material feedstock. Historically, pet coke has been less expensive than natural gas on a per ton of fertilizer produced basis and pet coke prices have been more stable when compared to natural gas prices. We believe the nitrogen fertilizer business has historically been one of the lowest cost producers and marketers of UAN and ammonia fertilizers in North America. The nitrogen fertilizer business currently purchases most of its pet coke from the Refining Partnership pursuant to a long-term agreement having an initial term that ends in 2027, subject to renewal. During 2012, the Nitrogen Fertilizer Partnership entered into a pet coke supply agreement with HollyFrontier Corporation. The initial term ends in December 2013 and is subject to renewal. On average, during the past five years, over 70% of the pet coke utilized by the nitrogen fertilizer plant was produced and supplied by the Refining Partnership'sPartnership’s crude oil refinery in Coffeyville.Transaction Agreement On April 18, 2012, CVR Energy entered into a Transaction Agreement (the "Transaction Agreement") with IEP Energy LLC and certainTable of its affiliates (collectively "IEP"). Pursuant to the Transaction Agreement, IEP offered (the "Offer") to purchase all of the issued and outstanding shares of CVR Energy's common stock for a price of $30.00 per share in cash, without interest, less any applicable withholding taxes, plus one non-transferable contingent cash payment ("CCP") right for each share, which represents the contractual right to receive an additional cash payment per share if a definitive agreement for the sale of CVR Energy is executed on or before August 18, 2013 and such transaction closes. In May 2012, IEP acquired a majority of the common stock of CVR Energy through the Offer. As of June 30, 2013, IEP owned approximately 82% of CVR Energy's outstanding common stock.$25.00$25.00 per common unit, resulting in gross proceeds of $600.0 million.$600.0 million. Of the common units issued, 4,000,000 units were purchased by IEP. Additionally, on January 30, 2013, the Refining Partnership sold an additional 3,600,000 common units to the public at a price of $25.00$25.00 per commonunderwriters'underwriters’ option to purchase additional common units, resulting in gross proceeds of $90.0 million."CVRR."Partnership'sPartnership’s outstanding common units and 100% of the Refining Partnership'sPartnership’s general partner, which holds a non-economic general partner interest.$30.75$30.75 per unit. American Entertainment Properties Corporation ("AEPC"(“AEPC”), an affiliate of Icahn Enterprises LP,IEP, also purchased an additional 2,000,000 common units at the public offering price in a privately negotiated transaction with a subsidiary of CVR Energy, which was completed on May 29, 2013. In connection with the Underwritten Offering, on June 10, 2013, the Refining Partnership sold an additional 1,209,236 common units to the public at a price of $30.75$30.75 per unit in connection with the exercise by the underwriters of their option to purchase additional common units. The transactions described in this paragraph are collectively referred to as the "Transactions."June 30, 2013,March 31, 2014, public security holders held 42,809,236 units representing approximately 29% of all outstanding Refining Partnership common units (including 6,000,000 units held by affiliates of Icahn Enterprises,IEP, representing approximately 4% of all outstanding Refining Partnership common units), and CVR Refining Holdings held 104,790,764 units representing approximately 71% of all outstanding Refining Partnership common units in addition to owning 100% of CVR Refining GP, LLC, the general partner.$394.0$394.0 million from the Underwritten Offering (including proceeds from the underwriters'exercise of the underwriters’ option) to redeem 13,209,236 common units from CVR Refining Holdings. The net proceeds to a subsidiary of CVR Energy from the sale of 2,000,000 common units to AEPC were approximately $61.5 million.$61.5 million. The Refining Partnership did not receive any of the proceeds from the sale of common units by CVR Energy to AEPC. In connection with the Underwritten Offering, the Refining Partnership incurred approximately $0.4 million of offering expenses.("CRLLC"(“CRLLC”), a wholly-owned subsidiary of CVR Energy, completed the Secondary Offering in which it sold 12,000,000 Nitrogen Fertilizer Partnership common units to the public at a price of $25.15$25.15 per unit. Additionally, the underwriters were granted an option to purchase 1,800,000 common units at the public offering price, which expired unexercised at the end of the option period. The net proceeds to CRLLC from the Secondary Offering were approximately $292.6$292.6 million, after deducting approximately $9.2$9.2 million in underwriting discounts and commissions. The Nitrogen Fertilizer Partnership did not receive any of the proceeds from the sale of common units by CRLLC. In connection with the Secondary Offering, the Nitrogen Fertilizer Partnership incurred approximately $0.5 million of offering expenses.June 30, 2013,March 31, 2014, public security holders held 34,154,945 units representing approximately 47% of all outstanding Nitrogen Fertilizer Partnership common units, and CRLLC held 38,920,000 units representing approximately 53% of all outstanding Nitrogen Fertilizer Partnership common units in addition to owning 100% of CVR GP, LLC, the general partner.("FIFO"(“FIFO”) accounting to value its inventory, crude oil price movements may impact net income in the short term because of changes in the value of its unhedged on-hand inventory. The effect of changes in crude oil prices on our results of operations is influenced by the rate at which the prices of refined products adjust to reflect these changes.competitors'competitors’ facilities, price volatility, international political and economic developments and other factors are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for home heating oil during the winter, primarily in the Northeast. In addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations, and increased mileage standards for vehicles. The petroleum business is also subject to the EPA'sEPA’s Renewable Fuel Standard ("RFS"(“RFS”), which requires it to blend "renewable fuels"“renewable fuels” in with its transportation fuels or purchase renewable energyfuel credits, known as renewable identification numbers ("RINs"(“RINs”), in lieu of blending.The EPA has not yet finalized the 2013 renewable fuel percentage standard, but has proposed to raise it to approximately 9.6%. In 2013, the Wynnewood refinery becamewas subject to the RFS for the first time,time. However, because the cost of purchasing RINs has been extremely volatile and has significantly increased over the last year, the Wynnewood refinery has petitioned the EPA as a “small refinery” for hardship relief from the RFS requirements in 2013 and 2014 based on the “disproportionate economic impact” on the Wynnewood refinery. During 2013, the cost of RINs became extremely volatile as the EPA's proposed renewable fuel volume mandates approached the "blend wall." The blend wall refers to the point at which refiners are required to blend more ethanol into the transportation fuel supply than can be supported by the demand for E10 gasoline (gasoline containing 10 percent ethanol by volume). The EPA has published the proposed volume mandates for 2014, which acknowledge the blend wall and significantly higherare generally lower than the cost during the comparable 2012 period.volumes for 2013 and lower than statutory mandates. The costprice of RINs fordecreased significantly after the year ended December 31, 20122014 proposed mandate was approximately $21.0 million.published; however, RIN prices have remained volatile and have increased in 2014. The cost of RINs for the three and six months ended June 30, 2012 was approximately $6.0 millionMarch 31, 2014 and $9.3 million, respectively, and the cost of RINs for the three and six months ended June 30, 2013 was approximately $65.5$34.7 million and $97.6$32.1 million, respectively. The petroleum business expects that the cost of RINs will continue to be substantially higher in 2013 as compared to 2012. The ultimatefuture cost of RINs for the petroleum business in 2013 is difficult to estimate. In particular, the cost of RINs is dependent upon a variety of factors, which include the price at which RINs can be purchased, transportation fuel production levels, the mix of the petroleum business'business’ petroleum products, as well as the fuel blending performed at its refineries, all of which can vary significantly from quarter to quarter. Based upon recent market prices of RINs and current estimates related to the other variable factors, the petroleum business estimates that the total cost of RINs will be approximately $200.0$75.0 million to $240.0$150.0 million for the year ending December 31, 2013.2014. When the 2013 volume mandate is finalized by the EPA, if Because the cost of purchasing RINs has been extremely volatile and has significantly increased over the last year, the Wynnewood refinery will be petitioning the EPA as a "small refinery" for hardship relief from the RFS2 requirements in 2013 and 2014.ourits total crude oil volume and will correlate more closely with such published differentials the heavier and more sour the crude oil slate.Table of Contentsbusiness'business’ profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor and environmental compliance. The predominant variable cost is energy, which is comprised primarily of electrical cost and natural gas. The petroleum business is therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption of natural gas for the sixthree months ended June 30, 2013,March 31, 2014, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $4.4 million.ourits target level of titled inventory have a major effect on its financial results.business'business’ financial performance and results of operations. Unplanned downtime at the refineries may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The petroleum business seeks to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The refineries generally require a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. The Coffeyville refinery completed the first phase of a two phase turnaround during the fourth quarter of 2011. The second phase was completed during the first quarter of 2012 and the first phase of its next turnaround is scheduled to begin in late 2015, with the second phase scheduled to begin in early 2016. The Wynnewood Refinery completed a turnaround in December 2012. Its next turnaround is scheduled to begin in late 2016.long-term20 year pet coke supply agreement entered into in October 2007. The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the global supply and demand for nitrogen fertilizer products which, in turn, depends on, among other factors, world grain demand and production levels, changes in world population, the cost and availability of fertilizer transportation infrastructure, weather conditions, the availability of imports, and the extent of government intervention in agriculture markets.competitors'competitors’ facilities, international political and economic developments and other factors are likely to continue to play an important role in nitrogen fertilizer industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products.competitors'competitors’ production of nitrogen fertilizers. Over the last tenpast several years, natural gas prices have significantly decreased.experienced high levels of price volatility. However, calendar years 2012 and 2013 were two of the lowest priced years for natural gas prices as compared to the last 10 years. This decreasepricing and volatility has significantly lowered oura direct impact on the nitrogen fertilizer business' competitors' cost of producing nitrogen fertilizer.we calculatethe nitrogen fertilizer business calculates plant gate price to determine ourits operating margin. Plant gate price refers to the unit price of nitrogen fertilizer, in dollars per ton, offered on a delivered basis, excluding final shipment costs. Weour out-of-region competitors in serving the U.S. farm belt agricultural market. In 2012,2013, approximately 54%53% of the corn planted in the United States was grown within a $45$45 per UAN ton freight train rate of the nitrogen fertilizer plant. We areThe nitrogen fertilizer business is therefore able to cost-effectively sell substantially all of ourits products in the higher margin agricultural market, whereas a significant portion of our competitors'its competitors’ revenues are derived from the lower margin industrial market. OurThe nitrogen fertilizer business' products leave the plant either in trucks for direct shipment to customers or in railcars for destinations located principally on the Union Pacific Railroad, and we doit does not currently incur significant intermediate transfer, storage, barge freight or pipeline freight charges. We estimateThe nitrogen fertilizer business estimates that ourits plant enjoys a transportation cost advantage of approximately $15$15 per UAN ton for transportation of UAN over competitors located in the U.S. Gulf Coast. Selling products to customers within economic rail transportation limits of the nitrogen fertilizer plant and keeping transportation costs low are keys to maintaining profitability.our results. For the three and six months ended June 30, 2013, the nitrogen fertilizer business upgraded approximately 100% and 86%, respectively, of its ammonia production into UAN, a product that presently generates a greater value than ammonia. As a result of the completion of the UAN expansion project, the nitrogen fertilizer business now upgrades substantially all of its ammonia into UAN. UAN production is a major contributor to the nitrogen fertilizer business' profitability.business'business’ largest raw material expense is pet coke, which it purchases from the petroleum business and third parties. InFor the three and six months ended June 30,March 31, 2014 and 2013, the nitrogen fertilizer business spent approximately $3.4$3.6 million and $7.4$4.0 million, respectively for pet coke, which equaled an average cost per ton of $29$29 and $30,$31, respectively. In the three and six months ended June 30, 2012, the nitrogen fertilizer business spent approximately $4.1 million and $9.1 million, respectively, for pet coke, which equaled an average cost per ton of $31 and $36, respectively. The nitrogen fertilizer business obtains most (over 70% on average during the last five years) of the pet coke it needs from the adjacent Coffeyville crude oil refinery pursuant to the pet coke supply agreement, and procures the remainder through a third-party contact with HollyFrontier Corporation. The price the nitrogen fertilizer business pays pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received for UAN, or the UAN-based price, and a pet coke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN (exclusive of transportation cost), or netback price, of $205 per ton, and adjusts up or down $0.50 per ton for every $1.00 change in the netback price. The UAN-based price has a ceiling of $40 per ton and a floor of $5 per ton.$3.0$5.0$5.0 million per turnaround. The Nitrogen Fertilizer Partnership is planning to defer the next full facility turnaround to 2015. It is anticipated that a less involved facility shutdown will be performed during the second quarter of 2014 to both install a waste heat boiler and upgrade the pressure swing absorption unit, which is projected to increase hydrogen recovery enough to allow the nitrogen fertilizer plant underwent a turnaround in the fourth quarterbusiness to produce approximately 7,000 to 9,000 tons of 2012, at a cost of approximately $4.8 million. The next turnaround is currently scheduled for the fourth quarter of 2014.arm's-lengtharm’s-length negotiations and the terms of these agreements are not$150.0$150.0 million intercompany credit facility between CRLLC and the Refining Partnership and (ii) a services agreement, pursuant to which our management operates the petroleum business.the Vitol Agreement. The Vitol Agreement amendsan Amended and restates theRestated Crude Oil Supply Agreement between CRRM and Vitol dated March 30, 2011, as amended.(the "Vitol Agreement"). Under the agreement, Vitol supplies usthe petroleum business with crude oil and intermediation logistics, which helps usthe petroleum business to reduce ourits inventory position and mitigate crude oil pricing risk. The Vitol Agreement has an initial term commencing on August 31, 2012 and extending through December 31, 2014 (the "Initial Term"). Following the Initial Term, the Vitol Agreement will automatically renew for successive one-yearone-year terms (each such term, a "Renewal Term") unless either party provides the other with notice of nonrenewal at least 180 days prior to the expiration of the Initial Term or any Renewal Term. Three Months Ended
March 31, 2014 2013 (in millions) Loss on extinguishment of debt (a) $ — $ 26.1 Share-based compensation (b) 4.1 6.0 (Gain) loss on derivatives, net (109.4 ) 20.0 Transaction Expenses In February 2012, IEP commenced a tender offeracquire allthe extinguishment of the outstanding shares of common stock of our Company. On April 18, 2012, we entered into a transaction agreement and on May 7, 2012, IEP announced that control of the Company had been acquired. CVR incurred related costs of approximately $29.4 million and $44.2 million for the three and six months ended June 30, 2012 that did not occur in 2013. We are currently challenging a majority of the expenses charged and, if we are successful, such expenses would be reversed and have a favorable impact to our results of operations.New and Refinanced Indebtedness Notes. In April 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance, Inc. ("Coffeyville Finance"), issued $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the "First Lien Notes") and $225.0 million aggregate principal amount of 10.875%CRLLC's Second Lien Senior Secured Notes due 2017 (the "Second Lien Notes" and together with the First Lien Notes, the "Old Notes"). In December 2010, CRLLC voluntarily redeemed $27.5 million the First Lien Notes. On December 15, 2011, CRLLC and Coffeyville Finance issued an additional $200.0 million of the First Lien Notes to partially fund the acquisition of the Wynnewood refinery. In connection with the acquisition of the Wynnewood refinery, in November 2011, we received a commitment for a one year bridge loan, which remained undrawn and was terminated as a result of the issuance of the $200.0 million of First Lien Notes. On October 23, 2012, Refining LLC and Coffeyville Finance completed a private offering of $500.0 million aggregate principal amount of 6.5% Second Lien Senior Secured Notes due 2022 (the "2022 Notes"). The 2022 Notes were issued at par. A portion of the net proceeds from the offering approximating $348.1 million were used to purchase approximately $323.0 million of the First Lien Notes pursuant to a tender offer and to settle accrued interest of approximately $1.8 million through October 23, 2012. Tendered notes were purchased at a premium of approximately $23.2 million in aggregate amount. A portion of the remaining net proceeds from the 2022 Notes offering were used to fund the redemption of the remaining $124.1 million of outstanding First Lien Notes and to settle accrued interest of approximately $1.6 million through November 23, 2012. Redeemed notes were purchased at a premium of approximately $8.4 million in aggregate amount. On January 23, 2013, $253.0 million of the proceeds from the Refining Partnership's IPO were utilized to satisfy and discharge the indenture governing the Second Lien Notes. The amounts were used to (i) repay the face amount of all $222.8 million aggregate principal amount of Second Lien Notes then outstanding, (ii) pay the redemption premium of approximately $20.6 million and (iii) settle accrued interest with respect thereto in an amount of approximately $9.5 million. The repurchase of the Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million for the six months ended June 30, 2013, which includes the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.Share-Based Compensation Through the Company's Long-Term Incentive Plan ("LTIP"), equity compensation awards may be awarded to the Company's employees, officers, consultants, advisors and directors including, but not limited to, shares of non-vested common stock. Prior to the acquisition by IEP Energy LLC and therelated change of control, restricted shares, when granted, were valued at the closing market price of CVR Energy's common stock at the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. The change of control and related Transaction Agreement in May 2012 triggered a modification to outstanding awards under the LTIP. Pursuant to the Transaction Agreement, all restricted shares scheduled to vest in 2012 were converted to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one CCP upon vesting. Restricted shares scheduled to vest in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards will be settled in cash upon vesting in an amount equal to the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. As a result of the modification, additional share-based compensation of $12.4 million was incurred to revalue the unvested shares to the fair value upon the date of modification for the three and six months ended June 30, 2012. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest. In addition, the classification changed from an equity-classified award to a liability-classified award due to the cash settlement of the awards. For the three months ended June 30, 2013 and 2012, we incurred compensation expense of $3.7 million and $17.3 million, respectively, related to non-vested share-based compensation awards related to the LTIP. For the six months ended June 30, 2013 and 2012, we incurred compensation expense of $9.1 million and $20.8 million, respectively, related to non-vested share-based compensation awards related to the LTIP. Through the CVR Partners, LP Long-Term Incentive Plan ("CVR Partners LTIP"), shares of non-vested common units and phantom units may be awarded to (1) employees of the Nitrogen Fertilizer Partnership, (2) employees of the general partner and (3) members of the board of directors of the general partner. In December 2012, the board of directors of the general partner of the Nitrogen Fertilizer Partnership approved an amendment to modify the terms of certain phantom unit awards previously granted to employees of the Nitrogen Fertilizer Partnership and its subsidiaries. The amendment triggered a modification to the awards by providing that the phantom units would be settled in cash rather than common units of the Nitrogen Fertilizer Partnership. For awards vesting subsequent to amendment, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards to employees of the Nitrogen Fertilizer Partnership, the classification changed from an equity-classified award to a liability-classified award. For the three months ended June 30, 2013 and 2012, we incurred compensation expense of $0.6 million and $0.5 million, respectively, related to non-vested share-based compensation awards related to the CVR Partners LTIP. For the six months ended June 30, 2013 and 2012, we incurred compensation expense of $1.2 million and $1.1 million, respectively, related to non-vested share-based compensation awards related to the CVR Partners LTIP.Partnership'sPartnership’s net income and related distributions. As a result of the Refining Partnership IPO, CVR Energy recorded an additional noncontrolling interest for the Refining Partnership common units sold into the public market, which represented an approximately 19% interest of the Refining Partnership. Effective with the Refining Partnership'sPartnership’s IPO, the noncontrolling interest reflected on the Condensed Consolidated Balance Sheets was impacted additionally by the noncontrolling ownership percentage of the net income of the Refining Partnership and related distributions for each future reporting period. As a result of the Refining Partnership'sPartnership’s closing of the Underwritten Offering, to sell an additional 13,209,326 common units to the public (including 1,209,236 units purchased through the underwriters' option) and the sale of 2,000,000 common units to AEPC, the noncontrolling interest reflected in our condensedconsolidated financial statements subsequent to the completion of the Transactions and as of June 30, 2013 is approximately 29%. Additionally, as a result of the Secondary Offering to sell 12,000,000 Nitrogen Fertilizer Partnership common units, the noncontrolling interest reflected in our condensed consolidated financial statements subsequent to the completion of the Secondary Offering on May 28,offering in the second quarter of 2013 and as of June 30, 2013Publicly Traded Partnership Expenses We expect our general and administrative expenses will increase in 2013 in part due to the costs of the Refining Partnership operating as a publicly traded company, including costs associated with SEC reporting requirements (including annual and quarterly reports to unitholders), tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities and registrar and transfer agent fees. We estimate that these incremental general and administrative expenses, which also include increased personnel costs, will approximate $5.0 million per year, excluding the costs associated with the initial implementation of the Refining Partnership's Sarbanes-Oxley Section 404 internal controls review and testing. These increased costs will be paid by the Refining Partnership. Our historical condensed consolidated financial statements for periods ended prior to January 23, 2013 do not reflect the impact of these expenses, which affects the comparability of the post-Refining Partnership IPO results with our financial statements from periods prior to the completion of the Refining Partnership IPO.Turnaround Projects The Coffeyville refinery completed the second phase of a two-phase turnaround project during the first quarter of 2012. The first phase was completed during the fourth quarter of 2011. The Coffeyville refinery incurred costs of approximately $21.0 million for the six months ended June 30, 2012 associated with the 2011/2012 turnaround.Wynnewood Transaction Fees and Integration Expenses As a result of the acquisition of the Wynnewood refinery in December 2011, we incurred transaction fees and integration expenses for the three and six months ended June 30, 2012 of $4.6 million and $8.3 million, respectively. We did not incur such expenses for the three and six months ended June 30, 2013 as the Wynnewood refinery's operations were fully integrated.Fertilizer Plant Property Taxes CRNF received a ten year property tax abatement from Montgomery County, Kansas in connection with the construction of the nitrogen fertilizer plant that expired on December 31, 2007. In connection with the expiration of the abatement, the county reclassified and reassessed CRNF's nitrogen fertilizer plant for property tax purposes. The reclassification and reassessment resulted in an increase in CRNF's annual property tax expense by an average of approximately $10.7 million per year for the years ended December 31, 2008 and 2009, $11.7 million for the year ended December 31, 2010, $11.4 million for the year ended December 31, 2011, and $11.3 million for the year endedDecember 31, 2012. CRNF protested the classification and resulting valuation for each of those years to the Kansas Court of Tax Appeals ("COTA"), followed by an appeal to the Kansas Court of Appeals. However, CRNF fully accrued and paid the property taxes the county claimed were owed for the years ended December 31, 2008 through 2012. On February 25, 2013, Montgomery County and CRNF agreed to a settlement for tax years 2009 through 2012, which will lower CRNF's property taxes by about $10.5 million per year for tax years 2013 through 2016 based on current mill levy rates. In addition, the settlement provides that Montgomery County will support CRNF's application before COTA for a ten year tax exemption for the UAN expansion. Finally, the settlement provides that CRNF will continue its appeal of the 2008 reclassification and reassessment.Partnership'sPartnership’s general partner is to distribute all of the available cash the Nitrogen Fertilizer Partnership generates each quarter. Available cash for distribution for each quarter will be determined by the board of directors of the Nitrogen Fertilizer Partnership'sPartnership’s general partner following the end of such quarter. Beginning with the first quarter of 2013, theThe board of directors of the Nitrogen Fertilizer Partnership'sPartnership’s general partner has adopted an amended policy to calculatecalculates available cash for distribution starting with Adjusted Nitrogen Fertilizer EBITDA reduced for cash needed for net interest expense (excluding capitalized interest) and debt service and other contractual obligations, maintenance capital expenditures and, to the extent applicable, major scheduled turnaround expense incurred and reserves for future operating or capital needs that the board of directors of the Nitrogen Fertilizer Partnership'sPartnership’s general partner deems necessary or appropriate, if any. Available cash for distributions may be increased by previously established cash reserves, if any, at the discretion of the board of directors of the Nitrogen Fertilizer Partnership'sPartnership’s general partner. Actual distributions are set by the board of directors of the Nitrogen Fertilizer Partnership'sPartnership’s general partner. The board of directors of the Nitrogen Fertilizer PartnershipPartnership's general partner may modify the cash distribution policy at any time, and the partnership agreement does not require the Nitrogen Fertilizer Partnership to make distributions at all. The following issummary of cash distributions paiddistribution to the Nitrogen Fertilizer PartnershipPartnership's unitholders during 2013of record at the close of business on March 3, 2014 for the respective quarters to whichfourth quarter of 2013 in the distributions relate: December 31,
2012 March 31,
2013 Total Cash
Distributions
Paid in 2013 ($ in millions, expect per common
unit amounts) $ 9.8 $ 31.1 $ 40.8 4.2 13.5 17.8 $ 14.0 $ 44.6 $ 58.6 $ 0.192 $ 0.610 $ 0.802 73.1 73.1 July 26, 2013,April 30, 2014, the board of directors of the Nitrogen Fertilizer Partnership'sPartnership’s general partner declared a cash distribution for the secondfirst quarter of 20132014 to the Nitrogen Fertilizer Partnership'sPartnership’s unitholders of $0.583$0.38 per common unit or $42.6$27.8 million in aggregate. The cash distribution will be paid on August 14, 2013May 19, 2014 to unitholders of record at the close of business on August 7, 2013.May 12, 2014. We will receive $22.7$14.8 million in respect of our common units.Partnership'sPartnership’s general partner is to distribute all of the available cash the Refining Partnership generates each quarter. Available cash for distribution for each quarter will be determined by the board of directors of the Refining Partnership'sPartnership’s general partner following the end of such quarter and will generally equal Adjusted Petroleum EBITDA reduced for cash needed for debt service, reserves for environmental and maintenance capital expenditures, reserves for future major scheduled turnaround expenses and, to the extent applicable, reserves for future operating or capital needs that the board of directors of the Refining Partnership'sPartnership’s general partner deems necessary or appropriate, if any. Available cash for distributions may be increased by previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of the Refining Partnership'sPartnership’s general partner. Actual distributions are set by the board of directors of the Refining Partnership'sPartnership’s general partner. The board of directors of the Refining PartnershipPartnership's general partner may modify the cash distribution policy at any time, and the partnership agreement does not require the Refining Partnership to make distributions at all.May 17, 2013,March 10, 2014, the Refining Partnership paid out a cash distribution to the Refining Partnership's unitholders of record at the close of business on May 10, 2013March 3, 2014 for the firstfourth quarter of 2013 in the amount of $1.58$0.45 per common unit, or $233.2$66.4 million in aggregate. We received $189.6$47.1 million in respect of our common units. This distribution was adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Refining Partnership IPO).July 26, 2013,April 30, 2014, the board of directors of the Refining Partnership'sPartnership’s general partner declared a cash distribution for the secondfirst quarter of 20132014 to the Refining Partnership'sPartnership’s unitholders of $1.35$0.98 per common unit or $199.3$144.6 million in aggregate. The cash distribution will be paid on August 14, 2013May 19, 2014 to unitholders of record at the close of business on August 7, 2013.May 12, 2014. We will receive $141.5$102.7 million in respect of our common units.initial quarterly dividend is expected to be $0.75$0.75 per share, or $3.00$3.00 per share on an annualized basis, which we began paying in the second quarter of 2013. Additionally,declared and paid two speciala cash dividends duringdividend to the six months ended JuneCompany's stockholders of record at the close of business on March 3, 2014 for the fourth quarter of 2013 in the amount of $0.75 per share, or $65.1 million in aggregate.2013. The following is a summary of the quarterly and special dividends paid to stockholders during the six months ended June 30, 2013: February 19,
2013 May 17,
2013 June 10,
2013 Total Dividends
Paid in 2013 ($ in millions, expect per share amounts) Special Quarterly Special $ 391.6 $ 53.4 $ 462.8 $ 907.8 86.0 11.7 101.6 199.3 $ 477.6 $ 65.1 $ 564.4 $ 1,107.1 $ 5.50 $ 0.75 $ 6.50 $ 12.75 86.8 86.8 86.8 On July 31, 2013,2014secondfirst quarter of 20132014 of $0.75$0.75 per share, or $65.1$65.1 million in aggregate. The dividend will be paid on AugustMay 19, 20132014 to stockholders of record at the close of business on AugustMay 12, 2013.2014.Commodity Swaps—Petroleum Segment The Refining Partnership enters into commodity swap contracts in order to fix the margin on a portion of future production. The physical volumes are not exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the Condensed Consolidated Balance Sheets with changes in fair value currently recognized in the Condensed Consolidated Statements of Operations. At June 30, 2013 and December 31, 2012, the Refining Partnership had open commodity hedging instruments consisting of 20.0 million barrels and 23.3 million barrels of crack spreads, respectively, primarily to fix the margin on a portion of future gasoline and distillate production. None of these swap contracts were designated as cash flow hedges, and all changes in fair market value will be reported in earnings in the period in which the value change occurs. For the three months ended June 30, 2013 and 2012, the Refining Partnership recognized net gains of $120.7 million and $34.7 million, respectively. For the six months ended June 30, 2013 and 2012, the Refining Partnership recognized a net gain of $102.9 million and a net loss of $104.6 million, respectively.and six months ended June 30, 2013March 31, 2014 and 2012.2013. The following data should be read in conjunction with our condensed consolidated financial statements and the notes thereto included elsewhere in this Report. All information in "Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations,"” except for the balance sheet data as of December 31, 2012,2013, is unaudited. Three Months Ended
June 30, Change from 2012 2013 2012 Change Percent Three Months Ended
March 31, (in millions, except per share amount) 2014 2013 (in millions, except per share amount) Consolidated Statement of Operations Data $ 2,220.3 $ 2,308.3 $ (88.0 ) (3.8 )% $ 2,447.4 $ 2,352.4 1,785.4 1,874.2 (88.8 ) (4.7 ) 2,076.9 1,813.6 108.3 94.1 14.2 15.1 123.4 108.5 28.9 72.0 (43.1 ) (59.9 ) 26.3 28.4 35.0 32.2 2.8 8.7 37.3 34.2 262.7 235.8 26.9 11.4 183.5 367.7 (12.5 ) (19.0 ) 6.5 (34.2 ) (10.1 ) (15.4 ) 120.5 38.8 81.7 210.6 Interest income 0.2 0.3 Gain (loss) on derivatives, net 109.4 (20.0 ) Loss on extinguishment of debt — (26.1 ) 0.5 0.8 (0.3 ) (37.5 ) 0.1 — 371.2 256.4 114.8 44.8 283.1 306.5 99.5 91.1 8.4 9.2 69.4 93.8 (2) 271.7 165.3 106.4 64.4 213.7 212.7 88.3 10.6 77.7 733.0 87.0 47.7 $ 183.4 $ 154.7 $ 28.7 18.6 % $ 126.7 $ 165.0 $ 2.11 $ 1.78 $ 0.33 18.5 % $ 1.46 $ 1.90 $ 2.11 $ 1.75 $ 0.36 20.6 % $ 1.46 $ 1.90 Dividends declared per share $ 0.75 $ 5.50 Adjusted EBITDA(2) $ 154.1 $ 286.6 86.8 86.8 — — % 86.8 86.8 86.8 88.4 (1.6 ) (1.8 )% 86.8 86.8 Six Months Ended
June 30, Change from 2012 2013 2012 Change Percent (in millions, except per share amount) $ 4,572.7 $ 4,276.9 $ 295.8 6.9 % 3,599.0 3,509.4 89.6 2.6 216.8 209.6 7.2 3.4 57.4 117.3 (59.9 ) (51.1 ) 69.2 64.3 4.9 7.6 630.3 376.3 254.0 67.5 (27.9 ) (38.2 ) 10.3 (27.0 ) 100.5 (108.5 ) 209.0 (192.6 ) (26.1 ) — (26.1 ) — 0.9 1.1 (0.2 ) (18.2 ) 677.7 230.7 447.0 193.8 193.3 81.4 111.9 137.5 484.4 149.3 335.1 224.4 136.0 19.8 116.2 586.9 $ 348.4 $ 129.5 $ 218.9 169.0 % $ 4.01 $ 1.49 $ 2.52 169.1 % $ 4.01 $ 1.46 $ 2.55 174.7 % 86.8 86.8 — — % 86.8 88.5 (1.7 ) (1.9 )% As of March 31, 2014 As of December 31, 2013 (audited) (in millions) Balance Sheet Data Cash and cash equivalents $ 962.1 $ 842.1 Working capital 1,286.3 1,230.2 Total assets 3,869.9 3,665.8 Total debt, including current portion 675.9 676.2 Total CVR Energy stockholders’ equity 1,250.1 1,188.6 As of June 30,
2013 As of December 31,
2012 (audited) (in millions) $ 1,134.5 $ 896.0 1,461.8 1,135.4 4,023.4 3,610.9 676.8 898.2 1,299.0 1,525.1 Three Months Ended
June 30, Six Months Ended
June 30, 2013 2012 2013 2012 (in millions) $ 84.1 $ 249.6 $ 362.4 $ 435.9 (50.8 ) (45.4 ) (114.5 ) (104.8 ) 60.4 (12.4 ) (9.4 ) (26.8 ) $ 93.7 $ 191.8 $ 238.5 $ 304.3 $ 50.9 $ 45.6 $ 114.6 $ 105.2 Three Months Ended
March 31, 2014 2013 (in millions) Cash Flow Data Net cash flow provided by (used in): Operating activities $ 281.3 $ 278.3 Investing activities (61.9 ) (63.7 ) Financing activities (99.4 ) (69.8 ) Net cash flow $ 120.0 $ 144.8 Other Financial Data Capital expenditures for property, plant and equipment $ 61.9 $ 63.7 (1)Amounts are shown exclusive of depreciation and amortization.(1) Amounts are shown exclusive of depreciation and amortization. Three Months Ended
June 30, Six Months Ended
June 30, 2013 2012 2013 2012 (in millions) $ 1.3 $ 0.9 $ 2.4 $ 1.6 33.2 30.7 65.7 61.5 0.5 0.6 1.1 1.2 $ 35.0 $ 32.2 $ 69.2 $ 64.3 (2)The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance due to their unusual or infrequent nature. Positive amounts represent expenses which should be added to reported operating income for comparability, while negative amounts should be subtracted for comparability: Three Months Ended
June 30, Six Months Ended
June 30, 2013 2012 2013 2012 (in millions) $ — $ — $ 26.1 $ — 0.1 0.4 0.2 0.7 — 2.5 — 23.5 4.3 17.8 10.3 21.9 — 4.6 — 8.3 (a)On January 23, 2013, $253.0 million of the proceeds from the Refining Partnership's IPO were utilized to satisfy and discharge the indenture governing the Second Lien Notes. The repurchase of the Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million for the six months ended June 30, 2013, which includes the premium paid of $20.6 million, the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.(b)Consists of fees which are expensed to selling, general and administrative expenses in connection with letters of credit outstanding.(c)Represents expenses associated with major scheduled turnarounds in the petroleum segment.(d)Represents the impact of share-based compensation awards.(e)On December 15, 2011, CRLLC acquired the stock of WEC (formerly known as Gary-Williams Energy Corporation) and its wholly-owned subsidiaries which owned a 70,000 barrel per day refinery in Wynnewood, Oklahoma. Included in "Acquisition and integration expenses—Gary-Williams" are legal and other professional fees associated with the acquisition and certain costs incurred in 2012 associated with the preliminary integration of the acquired business. Three Months Ended
March 31, 2014 2013 (in millions) Depreciation and amortization excluded from cost of product sold $ 1.4 $ 1.2 Depreciation and amortization excluded from direct operating expenses 34.5 32.5 Depreciation and amortization excluded from selling, general and administrative expenses 1.4 0.5 Total depreciation and amortization $ 37.3 $ 34.2 (2) Three Months Ended
March 31, 2014 2013 (in millions) Net income attributable to CVR Energy stockholders $ 126.7 $ 165.0 Add: Interest expense and other financing costs, net of interest income 9.9 15.1 Income tax expense 69.4 93.8 Depreciation and amortization 37.3 34.2 EBITDA adjustments included in noncontrolling interest (15.0 ) (8.0 ) EBITDA 228.3 300.1 Add: FIFO impacts, (favorable) unfavorable (21.6 ) (4.7 ) Share-based compensation 4.1 6.0 (Gain) loss on derivatives, net (109.4 ) 20.0 Current period settlement on derivative contracts(a) 21.1 (52.5 ) Loss on extinguishment of debt — 26.1 Adjustments included in noncontrolling interest 31.6 (8.4 ) Adjusted EBITDA $ 154.1 $ 286.6 June 30, 2013March 31, 2014 Compared to the Three Months Ended June 30, 2012Consolidated Results of OperationsMarch 31, 2013$2,220.3$2,447.4 million for the three months ended June 30, 2013March 31, 2014 compared to $2,308.3$2,352.4 million for the three months ended June 30, 2012.March 31, 2013. The decreaseincrease of $88.0$95.0 million was primarily due to loweran increase in petroleum net sales of $101.3 million due to higher overall sales volume, andpartially offset by lower product prices in the petroleum segment.prices. The higher sales volume is due to increased production of transportation fuels. The petroleum segment'ssegment’s average sales price per gallon for the three months ended June 30, 2013March 31, 2014 of $2.88$2.66 for gasoline and $3.00 for distillate decreased by 0.6% while the average sales price for distillates of $2.95 remained unchanged,5.7% and 3.5%, respectively, as compared to the three months ended June 30, 2012.March 31, 2013. The nitrogen fertilizer segment net sales increaseddecreased $1.1 million primarily due to higher UANlower ammonia sales volumes and higher ammonialower UAN sales prices, partially offset by lower ammoniahigher UAN and hydrogen sales volumes. The higher UAN sales volumes were primarily attributable to the UAN expansion being fully operational during the quarter.$1,785.4$2,076.9 million for the three months ended June 30, 2013,March 31, 2014, as compared to $1,874.2$1,813.6 million for the three months ended June 30, 2012.March 31, 2013. The decreaseincrease of $88.8$263.3 million primarily resulted from a decrease in refined fuel sales volume, partially offset by an increase in the cost of RINsconsumed crude oil due to increases in consumed crude oil volume and crude oil prices at the petroleum segment. The decrease in the petroleumnitrogen fertilizer segment was partially offset by higher cost of productproducts sold (exclusive of depreciation and amortization) in the nitrogen fertilizer segment, which wasincreased primarily driven bydue to higher costs from ammonia purchases, railcar repairs and increased freight costs and increased ammonia purchases.costs.$108.3$123.4 million for the three months ended June 30, 2013,March 31, 2014, as compared to $94.1$108.5 million for the three months ended June 30, 2012.March 31, 2013. The increase of $14.2$14.9 million was due primarily to increasesan increase in repairs and maintenance costs, labor andthe petroleum segment for expenses related to energy and utility costs in the petroleum segment, partially offset by decreased expenses for the major scheduled turnaround performed in the prior year. The nitrogen fertilizer segment also had an increase in direct operating expenses (exclusive of depreciation and amortization), which was primarily the result of higher costs for repairs and maintenance and utilities, partially offset by lower property taxes. Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $28.9 million for the three months ended June 30, 2013, as compared to $72.0 million for the three months ended June 30, 2012. The $43.1 million decrease was primarily the result of a decrease of $29.4 million related to costs incurred in the prior year period associated with the tender offer by certain entities affiliated with IEP and a decrease in share-based compensation of approximately $13.0 million primarily related to the modification of restricted shares to liability-classified restricted stock unit awards in the prior year. Operating Income. Consolidated operating income was $262.7 million for the three months ended June 30, 2013, as compared to operating income of $235.8 million for the three months ended June 30, 2012, an increase of $26.9 million. The increase in operating income was primarily the result of a decrease in the corporate selling, general, and administrative expenses discussed above, partially offset by a decrease in the Petroleum segment operating income of $19.8 million as a result of higher direct operating expenses and higher selling, general and administrative expenses. Nitrogen fertilizer segment operating income increased $1.0 million primarily as a result of higher net sales and lower selling, general and administrative expenses. Interest Expense. Consolidated interest expense for the three months ended June 30, 2013 was $12.5 million as compared to $19.0 million for the three months ended June 30, 2012. This $6.5 million decrease resulted primarily from lower interest expense on the outstanding 2022 Notes for the threemonths ended June 30, 2013 as compared to the outstanding First and Second Lien Senior Secured Notes for the three months ended June 30, 2012. Gain on Derivatives, net. For the three months ended June 30, 2013, we recorded a $120.5 million net gain on derivatives. This compares to a $38.8 million net gain on derivatives for the three months ended June 30, 2012. The change in the net gain on derivatives was primarily due to changes in crack spreads and an increase in the number of positions closing during the quarter to 7.7 million barrels from 5.3 million barrels in the prior year period. The petroleum segment entered into several over-the-counter commodity swaps to fix the margin on a portion of its future gasoline and distillate production beginning in the fourth quarter of 2011 and continuing throughout 2014. Income Tax Expense. Income tax expense for the three months ended June 30, 2013 was $99.5 million or 26.8% of income before income taxes, as compared to an income tax expense for the three months ended June 30, 2012 of $91.1 million or 35.5% of income before income taxes. Our 2013 effective tax rate is lower than the expected statutory rate primarily due to the reduction of income subject to tax associated with our noncontrolling ownership interests in CVR Refining's and CVR Partners' earnings and the benefits related to the domestic production activities deduction.Six Months Ended June 30, 2013 Compared to the Six Months Ended June 30, 2012Consolidated Results of Operations Net Sales. Consolidated net sales were $4,572.7 million for the six months ended June 30, 2013 compared to $4,276.9 million for the six months ended June 30, 2012. The increase of $295.8 million was primarily due to higher overall sales volume at the petroleum segment, which was partially offset by lower product prices. The increase in overall sales volume was largely a result of increased production due to the downtime associated with the completion of the second phase of the Coffeyville refinery's turnaround during the first quarter of 2012. The petroleum segment's average sales price per gallon for the six months ended June 30, 2013 of $2.85 for gasoline decreased by 1.2% while the average sales price for distillates of $3.03 remained unchanged, as compared to the six months ended June 30, 2012. The nitrogen fertilizer segment net sales increased by $10.5 million primarily due to higher UAN sales volumes as a result of the completion of the UAN expansion and higher ammonia sales prices, partially offset by lower UAN sales prices and lower ammonia sales volumes. Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was $3,599.0 million for the six months ended June 30, 2013, as compared to $3,509.4 million for the six months ended June 30, 2012. The increase of $89.6 million primarily resulted from an increase in crude oil throughputs and an increase in the cost of RINs in the petroleum segment, which was partially offset by a decrease in crude oil prices. The nitrogen fertilizer segment cost of product sold (exclusive of depreciation and amortization) also increased primarily due to higher freight costs due to increased UAN sales volumes and increased ammonia purchases. Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $216.8 million for the six months ended June 30, 2013, as compared to $209.6 million for the six months ended June 30, 2012. The increase of $7.2 million was due primarily to increases in repairs and maintenance costs, energy and utility costs, labor and outside services in the petroleum segment, partially offset by decreases in major scheduled turnaround expenses performed in the prior year.labor. The nitrogen fertilizer segment also had an increase in direct operating expenses (exclusive of depreciation and amortization), which was primarily the result of increases in utilities, repairsenergy and maintenanceutility costs, and labor, partially offset by lower property taxes.decreases in labor and insurance costs.Table of Contents$57.4$26.3 million for the sixthree months ended June 30, 2013,March 31, 2014, as compared to $117.3$28.4 million for the sixthree months ended June 30, 2012.March 31, 2013. The decrease of $59.9$2.1 million was primarily the result of lower share-based compensation costs.of $44.2 million related to costs incurred in the prior year associated with the tender offer by certain entities affiliated with IEP and a decrease in share-based compensation of approximately $11.4 million primarily related to the modification of restricted shares to liability-classified restricted stock unit awards during the three months ended June 30, 2012. Operating Income. Consolidated operating income was $630.3 million for the six months ended June 30, 2013, as compared topetroleum segment operating income of $376.3$171.0 million for the six months ended June 30, 2012, an increase as a result of $254.0 million. Petroleumlower refining margins and higher direct operating expenses. Nitrogen fertilizer segment operating income increased $180.9decreased $13.7 million primarily as a result of higher refining margins. Nitrogen fertilizer segment operating income increased $6.4 million primarily as a resultcost of higher net sales. Decreased corporate selling, general and administrative expenses discussed above also had a favorable impact on operating income for the period.product sold.sixthree months ended June 30, 2013March 31, 2014 was $27.9$10.1 million as compared to $38.2$15.4 million for the sixthree months ended June 30, 2012.March 31, 2013. The decrease of $10.3$5.3 million resulted primarily from lower interest expense on the outstanding 2022 Notes (as defined below) for the sixthree months ended June 30, 2013March 31, 2014 as compared to interest expense incurred during the outstanding First andthree months ended March 31, 2013 related to both the Second Lien Senior Secured Notes for(prior to their extinguishment in the six months ended June 30, 2012.first quarter of 2013) and the 2022 Notes.sixthree months ended June 30, 2013, weMarch 31, 2014, the petroleum segment recorded a $100.5$109.4 million net gain on derivatives. This compares to a $108.5$20.0 million net loss on derivatives for the sixthree months ended June 30, 2012.March 31, 2013. The change in the gain (loss) on derivatives was primarily due to changes in crack spreads and an increase in the number of positions closing during the six month period to 14.3 million barrels from 8.2 million barrels in the prior year period.periods. The petroleum segment enteredenters into several over-the-counter commodity swaps to fix the margin on a portion of its future gasoline and distillate production beginning in the fourth quarter of 2011 and continuing throughout 2014.production.sixthree months ended June 30,March 31, 2013, we incurred a $26.1 million loss on extinguishment of debt. The loss on extinguishment of debt was the result of the extinguishment of the Second Lien Notes and included amounts related to the premium paid, the write-off of previously deferred financing costs and the write-off of the unamortized original issuance discount.sixthree months ended June 30, 2013March 31, 2014 was $193.3$69.4 million or 28.5%24.5% of income before income taxes, as compared to an income tax expense for the sixthree months ended June 30, 2012March 31, 2013 of $81.4$93.8 million or 35.3%30.6% of income before income taxes. Our 20132014 effective tax rate is lower than the expected statutory rate primarily due to the reduction of income subject to tax associated with ourthe noncontrolling ownership interests in CVR Refining'sRefining’s and CVR Partners'Partners’ earnings and the benefits related to the domestic production activities deduction.deduction and state income tax credits.and six months ended June 30, 20132012:2013: Three Months Ended
June 30, Six Months Ended
June 30, Three Months Ended
March 31, 2013 2012 2013 2012 2014 2013 (in millions, except as otherwise indicated) (in millions) $ 2,138.1 $ 2,229.5 $ 4,412.1 $ 4,128.0 $ 2,375.3 $ 2,274.0 1,776.6 1,866.1 3,582.3 3,496.8 2,063.3 1,805.8 83.8 69.1 169.9 140.8 — 2.5 — 23.5 Direct operating expenses(1)(2) 99.2 86.0 28.4 26.6 56.4 52.9 29.5 28.0 249.3 265.2 603.5 414.0 $ 183.3 $ 354.2 83.8 71.6 169.9 164.3 Direct operating expenses(1) 99.2 86.0 28.4 26.6 56.4 52.9 29.5 28.0 361.5 363.4 829.8 631.2 $ 312.0 $ 468.2 $ 229.1 $ 248.9 $ 564.7 $ 383.8 Operating income $ 164.6 $ 335.6 $ 250.6 $ 381.4 $ 560.5 $ 535.2 $ 194.1 $ 309.9 Three Months Ended
June 30, Six Months Ended
June 30, Three Months Ended
March 31, 2013 2012 2013 2012 2014 2013 (dollars per barrel) (dollars per barrel) $ 20.56 $ 20.98 $ 23.63 $ 20.58 $ 17.17 $ 26.71 $ 14.18 $ 15.31 $ 17.19 $ 13.50 $ 10.09 $ 20.20 $ 4.77 $ 4.13 $ 4.84 $ 5.36 $ 4.60 $ 3.81 $ 4.62 $ 4.75 Direct operating expenses (exclusive of depreciation and amortization)(1)(2) $ 5.46 $ 4.91 Direct operating expenses (exclusive of depreciation and amortization) per barrel sold(1)(6) $ 5.08 $ 4.64 200,314 206,606 203,079 181,589 217,186 205,875 Three Months Ended June 30, Six Months Ended June 30, 2013 2012 2013 2012 % % % % 153,944 76.2 148,912 74.6 155,304 76.4 129,781 73.1 18,089 9.0 20,488 10.3 16,455 8.1 22,728 12.8 21,168 10.5 20,972 10.5 22,244 10.9 16,006 9.0 193,201 95.7 190,372 95.4 194,003 95.4 168,515 94.9 8,724 4.3 9,129 4.6 9,248 4.6 8,929 5.1 201,925 100.0 199,501 100.0 203,251 100.0 177,444 100.0 95,253 47.1 96,972 48.7 96,710 47.4 89,131 50.4 84,617 41.8 82,075 41.3 84,232 41.3 72,202 40.9 22,546 11.1 19,910 10.0 23,043 11.3 15,396 8.7 202,416 100.0 198,957 100.0 203,985 100.0 176,729 100.0 $ 2.88 $ 2.89 $ 2.85 $ 2.88 $ 2.95 $ 2.95 $ 3.03 $ 3.03 Three Months Ended
June 30, Six Months Ended
June 30, 2013 2012 2013 2012 $ 94.17 $ 93.35 $ 94.26 $ 98.15 0.06 5.28 3.09 4.48 16.79 20.45 21.94 23.79 24.72 30.42 27.87 27.95 27.19 28.13 30.21 28.87 25.95 29.27 29.04 28.41 1.52 (3.24 ) (2.88 ) (5.00 ) 2.13 2.16 2.11 0.28 26.23 27.18 24.99 22.95 29.33 30.29 32.32 29.14 27.78 28.74 28.66 26.05 (1)Amounts are shown exclusive of depreciation and amortization.(2)Direct operating expense is presented on a per crude oil throughput barrel basis. In order to derive the direct operating expenses per crude oil throughput barrel, we utilize total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period.(3)Gross profit is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization), direct operating expenses (exclusive of Three Months Ended March 31, 2014 2013 % % Refining Throughput and Production Data (bpd) Throughput: Sweet 178,253 83.3 156,725 76.6 Medium 3,047 1.4 14,757 7.2 Heavy sour 20,602 9.6 23,334 11.4 Total crude oil throughput 201,902 94.3 194,816 95.2 All other feedstocks and blendstocks 12,154 5.7 9,774 4.8 Total throughput 214,056 100.0 204,590 100.0 Production: Gasoline 104,452 48.5 98,184 47.8 Distillate 88,901 41.2 83,841 40.8 Other (excluding internally produced fuel) 22,093 10.3 23,543 11.4 Total refining production (excluding internally produced fuel) 215,446 100.0 205,568 100.0 Product price (dollars per gallon): Gasoline $ 2.66 $ 2.82 Distillate $ 3.00 $ 3.11 Three Months Ended
March 31, 2014 2013 Market Indicators (dollars per barrel) West Texas Intermediate (WTI) NYMEX $ 98.61 $ 94.36 Crude Oil Differentials: WTI less WTS (light/medium sour) 5.58 6.33 WTI less WCS (heavy sour) 20.87 27.26 NYMEX Crack Spreads: Gasoline 18.12 31.24 Heating Oil 27.95 33.43 NYMEX 2-1-1 Crack Spread 23.04 32.33 PADD II Group 3 Basis: Gasoline (4.87 ) (7.57 ) Ultra Low Sulfur Diesel (1.94 ) 2.09 PADD II Group 3 Product Crack: Gasoline 13.25 23.66 Ultra Low Sulfur Diesel 26.01 35.52 PADD II Group 3 2-1-1 19.63 29.59 (1) Amounts are shown exclusive of depreciation and amortization. (2) Direct operating expense is presented on a per crude oil throughput barrel basis. In order to derive the direct operating expenses per crude oil throughput barrel, we utilize total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period. (3) Gross profit is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization), direct operating expenses (exclusive of depreciation and amortization), major scheduled turnaround expenses and depreciation and amortization. Each of the components used in this calculation are taken directly from the petroleum business' financial results. In order to derive the gross profit per crude oil throughput barrel, we utilize the depreciation and amortization), major scheduled turnaround expenses and depreciation and amortization. Each of the components used in this calculation are taken directly from our Condensed Consolidated Statements of Operations. In order to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by the applicable number of crude oil throughput barrels for the period.(4)Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that we believe is important to investors in evaluating the refineries' performance as a general indication of the amount above the cost of product sold that it is able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold (exclusive of depreciation and amortization)) are taken directly from the petroleum business' Statements of Operations. The petroleum business' calculation of refining margin may differ from similar calculations of other companies in its industry, thereby limiting its usefulness as a comparative measure. In order to derive the refining margin per crude oil throughput barrel, we utilize the total dollar figures for refining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining margin and refining margin per crude oil throughput barrel is important to enable investors to better understand and evaluate our ongoing operating results and for greater transparency in the review of our overall business, financial, operational and economic financial performance.(5)Adjusted Petroleum EBITDA represents operating income for the petroleum segment adjusted for (i) FIFO impacts (favorable) unfavorable, (ii) share-based compensation, non-cash, (iii) major scheduled turnaround expenses, (iv) current period settlements on derivative contracts, (v) depreciation and amortization and (vi) other income (expense). We present Adjusted Petroleum EBITDA because it is the starting point for the Refining Partnership's available cash for distribution. Adjusted Petroleum EBITDA is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance. Management believes that Adjusted Petroleum EBITDA enables investors to better understand the Refining Partnership's ability to make distributions to its common unitholders, evaluate the petroleum segment's ongoing operating results and allows for greater transparency in reviewing the petroleum segment's overall financial, operational and economic performance. Adjusted Petroleum EBITDA presented by other companies may not be comparable to our presentation, since each company may define these terms differently. Below is a reconciliation of operating income for the petroleum segment to Adjusted Petroleum EBITDA for the three and six months ended June 30, 2013 and 2012: Three Months Ended
June 30, Six Months Ended
June 30, 2013 2012 2013 2012 (in millions) $ 229.1 $ 248.9 $ 564.7 $ 383.8 (24.2 ) 105.4 (29.0 ) 95.0 2.5 5.4 6.1 6.4 — 2.5 — 23.5 14.7 (8.1 ) (37.8 ) (27.2 ) 28.4 26.6 56.4 52.9 0.1 0.7 0.1 0.8 $ 250.6 $ 381.4 $ 560.5 $ 535.2 (a)FIFO is the petroleum business' 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,(4) Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that we believe is important to investors in evaluating the refineries’ performance as a general indication of the amount above the cost of product sold at which it is able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold (exclusive of depreciation and amortization)) are taken directly from the petroleum business’ financial results. Our calculation of refining margin may differ from similar calculations of other companies in the industry, thereby limiting its usefulness as a comparative measure. In order to derive the refining margin per crude oil throughput barrel, we utilize the total dollar figures for refining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining margin and refining margin per crude oil throughput barrel is important to enable investors to better understand and evaluate the petroleum business' ongoing operating results and for greater transparency in the review of our overall business, financial, operational and economic financial performance. (5) Three Months Ended
March 31, 2014 2013 (in millions) Petroleum: Petroleum operating income $ 164.6 $ 335.6 FIFO impacts (favorable), unfavorable(a) (21.6 ) (4.7 ) Share-based compensation, non-cash 0.5 3.5 Current period settlements on derivative contracts(b) 21.1 (52.5 ) Depreciation and amortization 29.5 28.0 Adjusted Petroleum EBITDA $ 194.1 $ 309.9 (a) FIFO is the petroleum business’ basis for determining inventory value on a GAAP basis. Changes in crude oil prices can cause fluctuations in the inventory valuation of 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. In order to derive the FIFO impact per crude oil throughput barrel, we utilize the total dollar figures for the FIFO impact and divide by the number of crude oil throughput barrels for the period. (b) Represents the portion of gain (loss) on derivatives, net related to contracts that matured during the respective periods and settled with counterparties. There are no premiums paid or received at inception of the derivative contracts and upon settlement, there is no cost recovery associated with these contracts. (6) Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refineries. We utilize direct operating expenses, which does not include depreciation or amortization expense, and divide the applicable number of barrels sold for the period to derive the metric. 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. In order to derive the FIFO impact per crude oil throughput barrel, we utilize the total dollar figures for the FIFO impact and divide by the number of crude oil throughput barrels for the period.(b)Represents expense associated with a major scheduled turnaround at the petroleum segment.(6)Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refineries. We utilize direct operating expenses, which does not include depreciation or amortization expense, and divide the applicable number of barrels sold for the period to derive the metric. Three Months Ended
June 30, Six Months Ended
June 30, Three Months Ended
March 31, 2013 2012 2013 2012 2014 2013 (in millions) (in millions) $ 1,349.2 $ 1,447.0 $ 2,841.7 $ 2,579.5 $ 1,572.3 $ 1,492.6 1,117.6 1,219.4 2,312.6 2,192.5 1,358.8 1,195.1 50.1 43.6 102.3 87.4 53.3 52.2 — 0.9 — 21.0 17.7 17.4 35.2 34.7 18.0 17.5 163.8 165.7 391.6 243.9 $ 142.2 $ 227.8 50.1 44.5 102.3 108.4 Direct operating expenses (exclusive of depreciation and amortization) 53.3 52.2 17.7 17.4 35.2 34.7 18.0 17.5 $ 231.6 $ 227.6 $ 529.1 $ 387.0 $ 213.5 $ 297.5 Three Months Ended
June 30, Six Months Ended
June 30, Three Months Ended
March 31, 2013 2012 2013 2012 2014 2013 (dollars per barrel) (dollars per barrel) $ 21.71 $ 20.61 $ 24.27 $ 20.27 $ 19.14 $ 26.73 $ 15.35 $ 15.00 $ 17.97 $ 12.78 $ 12.75 $ 20.47 $ 4.69 $ 4.03 $ 4.69 $ 5.68 $ 4.37 $ 3.69 $ 4.35 $ 5.41 Direct operating expenses (exclusive of depreciation and amortization) $ 4.78 $ 4.69 Direct operating expenses (exclusive of depreciation and amortization) per barrel sold $ 4.26 $ 4.33 125,851 132,534 129,777 110,034 139,016 133,746 Three Months Ended March 31, 2014 2013 % % Coffeyville Refinery Throughput and Production Data (bpd) Throughput: Sweet 101,856 76.3 99,793 76.0 Medium 1,495 1.1 512 0.4 Heavy sour 20,602 15.4 23,334 17.8 Total crude oil throughput 123,953 92.8 123,639 94.2 All other feedstocks and blendstocks 9,670 7.2 7,570 5.8 Total throughput 133,623 100.0 131,209 100.0 Production: Gasoline 66,316 48.4 62,414 46.7 Distillate 57,825 42.2 55,602 41.6 Other (excluding internally produced fuel) 12,776 9.4 15,717 11.7 Total refining production (excluding internally produced fuel) 136,917 100.0 133,733 100.0 Three Months Ended June 30, Six Months Ended June 30, 2013 2012 2013 2012 % % % % 95,763 77.1 100,166 78.4 97,767 76.6 86,041 77.7 334 0.3 187 0.1 423 0.3 2,817 2.5 21,168 17.0 20,972 16.4 22,244 17.4 16,006 14.4 117,265 94.4 121,325 94.9 120,434 94.3 104,864 94.6 6,962 5.6 6,500 5.1 7,265 5.7 5,934 5.4 124,227 100.0 127,825 100.0 127,699 100.0 110,798 100.0 59,908 47.3 62,351 47.9 61,154 47.0 56,310 50.1 53,471 42.2 54,933 42.3 54,531 41.9 48,004 42.7 13,272 10.5 12,753 9.8 14,488 11.1 8,123 7.2 126,651 100.0 130,037 100.0 130,173 100.0 112,437 100.0 Three Months Ended
March 31, 2014 2013 (in millions) Wynnewood Refinery Financial Results Net sales $ 802.0 $ 780.4 Cost of product sold (exclusive of depreciation and amortization) 704.5 610.4 Direct operating expenses (exclusive of depreciation and amortization) 45.6 33.8 Depreciation and amortization 10.0 9.3 Gross Profit $ 41.9 $ 126.9 Plus: Direct operating expenses (exclusive of depreciation and amortization) 45.6 33.8 Depreciation and amortization 10.0 9.3 Refining margin $ 97.5 $ 170.0 Three Months
Ended
June 30, Six Months
Ended
June 30, 2013 2012 2013 2012 (in millions) $ 787.8 $ 782.3 $ 1,568.2 $ 1,548.2 658.8 647.5 1,269.2 1,305.4 33.7 25.5 67.6 53.4 — 1.6 — 2.5 9.5 8.4 18.8 16.7 85.8 99.3 212.6 170.2 33.7 27.1 67.6 55.9 9.5 8.4 18.8 16.7 $ 129.0 $ 134.8 $ 299.0 $ 242.8 Three Months Ended
March 31, 2014 2013 (dollars per barrel) Wynnewood Refinery Key Operating Statistics Per crude oil throughput barrel: Refining margin $ 13.89 $ 26.55 Gross profit $ 5.97 $ 19.80 Direct operating expenses (exclusive of depreciation and amortization) $ 6.49 $ 5.29 Direct operating expenses (exclusive of depreciation and amortization) per barrel sold $ 6.48 $ 5.22 Barrels sold (barrels per day) 78,170 72,129 Three Months Ended
June 30, Six Months Ended
June 30, 2013 2012 2013 2012 (dollars per barrel) $ 18.67 $ 21.47 $ 22.46 $ 20.97 $ 12.41 $ 15.82 $ 15.97 $ 14.70 $ 4.88 $ 4.30 $ 5.08 $ 4.83 $ 4.97 $ 4.02 $ 5.09 $ 4.29 74,463 74,072 73,302 71,556 Three Months Ended March 31, 2014 2013 % % Wynnewood Refinery Throughput and Production Data (bpd) Throughput: Sweet 76,397 95.0 56,932 77.6 Medium 1,552 1.9 14,245 19.4 Heavy sour — — — — Total crude oil throughput 77,949 96.9 71,177 97.0 All other feedstocks and blendstocks 2,484 3.1 2,204 3.0 Total throughput 80,433 100.0 73,381 100.0 Production: Gasoline 38,136 48.6 35,770 49.8 Distillate 31,076 39.6 28,239 39.3 Other (excluding internally produced fuel) 9,317 11.8 7,826 10.9 Total refining production (excluding internally produced fuel) 78,529 100.0 71,835 100.0 Three Months Ended June 30, Six Months Ended June 30, 2013 2012 2013 2012 % % % % 58,181 74.8 48,745 68.0 57,537 76.2 43,740 65.6 17,755 22.9 20,301 28.3 16,032 21.2 19,911 29.9 — — — — — — — — 75,936 97.7 69,046 96.3 73,569 97.4 63,651 95.5 1,762 2.3 2,629 3.7 1,983 2.6 2,995 4.5 77,698 100.0 71,675 100.0 75,552 100.0 66,646 100.0 35,345 46.7 34,621 50.2 35,556 48.2 32,821 51.0 31,146 41.1 27,142 39.4 29,701 40.2 24,198 37.6 9,274 12.2 7,157 10.4 8,555 11.6 7,273 11.4 75,765 100.0 68,920 100.0 73,812 100.0 64,292 100.0 June 30, 2013March 31, 2014 Compared to the Three Months Ended June 30, 2012March 31, 2013 (Petroleum Business)$2,138.1$2,375.3 million for the three months ended June 30, 2013March 31, 2014 compared to $2,229.5$2,274.0 million for the three months ended June 30, 2012.March 31, 2013. The decreaseincrease of $91.4$101.3 million was the result of lowerhigher overall sales volume, andwhich was partially offset by lower product prices for gasoline. Our averageprices. The higher sales price per gallon forvolume is due to increased production of transportation fuels. Overall sales volumes increased 8.4% in the three months ended June 30, 2013 for gasoline of $2.88 decreased by approximately 0.6%March 31, 2014 as compared to the three months ended June 30, 2012. OurMarch 31, 2013. For the three months ended March 31, 2014, the average sales price per gallon for gasoline of $2.66decreased byJune 30,March 31, 2014 decreased by approximately 3.5% as compared to the three months ended March 31, 2013 for distillates of $2.95 was unchanged from the same period in 2012. Three Months Ended
June 30, 2013 Three Months Ended
June 30, 2012 Total Variance Price
Variance Volume
Variance Volume(1) $ per barrel Sales $(2) Volume(1) $ per barrel Sales $(2) Volume(1) Sales $(2) (in millions) 9.2 $ 120.80 $ 1,110.7 9.7 $ 121.49 $ 1,178.3 (0.5 ) $ (67.6 ) $ (6.4 ) $ (61.2 ) 7.4 $ 124.07 $ 926.5 7.6 $ 124.00 $ 946.9 (0.2 ) $ (20.4 ) $ 0.5 $ (20.9 )
.(1)Barrels in millions Three Months Ended
March 31, 2014 Three Months Ended
March 31, 2013 Total Variance Price
Variance Volume
Variance Volume(1) $ per barrel Sales $(2) Volume(1) $ per barrel Sales $(2) Volume(1) Sales $(2) (in millions) Gasoline 9.9 $ 111.58 $ 1,100.5 9.6 $ 118.30 $ 1,136.8 0.3 $ (36.3 ) $ (66.2 ) $ 29.9 Distillate 9.1 $ 125.86 $ 1,151.5 7.8 $ 130.44 $ 1,023.4 1.3 $ 128.1 $ (41.9 ) $ 170.0 (1) Barrels in millions (2)Sales dollars in millions(2) Sales dollars in millions $1,776.6$2,063.3 million for the three months ended June 30, 2013March 31, 2014 compared to $1,866.1$1,805.8 million for the three months ended June 30, 2012.March 31, 2013. The decreaseincrease of $89.5$257.5 million was primarily the result of a decrease of approximately 3.3% in sales volume of refined fuel, which was partially offset by an increase in the cost of RINs andconsumed crude oil. The increase in consumption costsconsumed crude oil cost was due to increasedan increase in consumed volumes and crude throughputs.oil prices. The average cost per barrel of crude oil consumed for the three months ended March 31, 2014 was $95.91 compared to $89.34 for the comparable period of 2013, an increase of approximately 7.4%. The impact of FIFO accounting also impacted cost of product sold during the comparable periods. Under ourthe FIFO accounting method, 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 a favorable FIFO inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the three months ended June 30, 2013, weMarch 31, 2014, the petroleum business had a favorable FIFO inventory impact of $24.2$21.6 million compared to an unfavorablea favorable FIFO inventory impact of $105.4$4.7 million for the comparable period of 2012.2013.$20.98$26.71 for the three months ended June 30, 2012March 31, 2013 to $20.56$17.17 for the three months ended June 30, 2013.March 31, 2014. Refining margin adjusted for FIFO impact was $19.18$15.98 per crude oil throughput barrel for the three months ended June 30, 2013,March 31, 2014, as compared to $27.07$26.44 per crude oil throughput barrel for the three months ended June 30, 2012.March 31, 2013. Gross profit per barrel decreased to $14.18$10.09 for the three months ended June 30, 2013March 31, 2014 as compared to gross profit per barrel of $15.31$20.20 in the equivalent period in 2012.2013. The decrease of thein refining margin and gross profit per barrel was due to thea decrease in sales coupled with higher consumption costs associated with the increase in throughput ratesprices of gasoline and distillates and an increase in RINs costs.ourthe petroleum operationsbusiness include costs associated with the actual operations of ourthe refineries, such as energy and utility costs, property taxes, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. Petroleum direct operating expenses (exclusive of depreciation and amortization) were $83.8$99.2 million for the three months ended June 30, 2013March 31, 2014 compared to direct operating expenses and major scheduled turnaround expenses of $71.6$86.0 million for the three months ended June 30, 2012.March 31, 2013. The increase of $12.2$13.2 million was primarily the result of the increase in expenses associated with repairs and maintenance costs ($5.2 million), labor ($4.7 million), energy and utility costs ($3.78.1 million) and production chemicals and catalyst costslabor ($0.7 million). These increases were partially offset by a decrease in expenses associated with a major scheduled turnaround performed in the prior year ($2.54.0 million). Direct operating expenses per barrel of crude oil throughput for the three months ended June 30, 2013March 31, 2014 increased to $4.77$5.46 per barrel as compared to $4.13$4.91 per barrel for the three months ended June 30, 2012.March 31, 2013. The increase in the direct operating expenses per barrel of crude oil throughput is a function of the higher overall expenses.Table of Contents$229.1$164.6 million for the three months ended June 30, 2013March 31, 2014 as compared to operating income of $248.9$335.6 million for the three months ended June 30, 2012. This March 31, 2013. The decrease of $19.8$171.0 million was primarily the result of a decrease in the refining margin ($1.9 million), an increase($156.2 million) and increases in direct operating expenses ($12.2 million), selling, general and administrative expenses ($3.9 million)($13.2 million) and depreciation and amortization ($1.8 million)($1.5 million).Six Months Ended June 30, 2013 Compared to the Six Months Ended June 30, 2012 (Petroleum Business) Net Sales. Petroleum net sales were $4,412.1 million for the six months ended June 30, 2013 compared to $4,128.0 million for the six months ended June 30, 2012. The increase of $284.1 million was the result of higher overall sales volume, which was partially offset by lower product prices. The higher sales volume is due to the downtime associated with completion of the second phase of the Coffeyville refinery's turnaround in the first quarter of 2012, which decreased products available for sale. Our average sales price per gallon for the six months ended June 30, 2013 for gasoline of $2.85 decreased by approximately 1.2% as compared to the six months ended June 30, 2012. Our average sales price per gallon for the six months ended June 30, 2013 for distillates of $3.03 was unchanged from the same period in 2012. Six Months Ended
June 30, 2013 Six Months Ended
June 30, 2012 Total Variance Price
Variance Volume
Variance Volume(1) $ per barrel Sales $(2) Volume(1) $ per barrel Sales $(2) Volume(1) Sales $(2) (in millions) 18.8 $ 119.52 $ 2,247.5 17.9 $ 120.98 $ 2,159.8 0.9 $ 87.7 $ (27.4 ) $ 115.1 15.3 $ 127.34 $ 1,949.9 13.8 $ 127.23 $ 1,758.5 1.5 $ 191.4 $ 1.7 $ 189.7 (1)Barrels in millions(2)Sales dollars in millions Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, RINs, transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciation and amortization) was $3,582.3 million for the six months ended June 30, 2013 compared to $3,496.8 million for the six months ended June 30, 2012. The increase of $85.5 million was primarily the result of an increase in crude oil throughputs and an increase in the cost of RINs, which was partially offset by a decrease in crude oil prices. The increase in crude oil throughputs is due to the downtime associated with completion of the second phase of the Coffeyville refinery's turnaround in the first quarter of 2012. Our average cost per barrel of crude oil consumed for the six months ended June 30, 2013 was $90.33 compared to $95.62 for the comparable period of 2012, a decrease of approximately 5.5%. Sales volume of refined fuels increased by approximately 7.7%. The impact of FIFO accounting also impacted cost of product sold during the comparable periods. Under our FIFO accounting method, 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 a favorable FIFO inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the six months ended June 30, 2013, we had a favorable FIFO inventory impact of $29.0 million compared to an unfavorable FIFO inventory impact of $95.0 million for the comparable period of 2012. Refining margin per barrel of crude oil throughput increased from $20.58 for the six months ended June 30, 2012 to $23.63 for the six months ended June 30, 2013. Refining margin adjusted for FIFO impact was $22.80 per crude oil throughput barrel for the six months ended June 30, 2013, as compared to $23.68 per crude oil throughput barrel for the six months ended June 30, 2012. Gross profit per barrel increased to $17.19 for the six months ended June 30, 2013 as compared to gross profit per barrel of $13.50 in the equivalent period in 2012. The increase of our refining margin perbarrel is due to a decrease in our per barrel cost of consumed crude oil which was partially offset by a decrease in the average sales prices of our produced gasoline and increased cost of RINs. Consumed crude oil costs decreased due to a 4.0% decrease in WTI for the six months ended June 30, 2013 over the six months ended June 30, 2012. Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for our petroleum operations include costs associated with the actual operations of our refineries, such as energy and utility costs, property taxes, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. Petroleum direct operating expenses (exclusive of depreciation and amortization) were $169.9 million for the six months ended June 30, 2013 compared to direct operating expenses and major scheduled turnaround expenses of $164.3 million for the six months ended June 30, 2012. The increase of $5.6 million was primarily the result of the increase in expenses associated with general repairs and maintenance costs ($13.1 million), energy and utility costs ($7.6 million), labor ($4.6 million) and outside services ($3.2 million). These increases were partially offset by a decrease in major scheduled turnaround performed in the prior year ($23.5 million). Our Coffeyville refinery completed the second phase of its planned turnaround in March 2012. Direct operating expenses per barrel of crude oil throughput for the six months ended June 30, 2013 decreased to $4.84 per barrel as compared to $5.36 per barrel for the six months ended June 30, 2012. The decrease in the direct operating expenses per barrel of crude oil throughput is a function of the higher volume of throughput, partially offset by the increase in expenses. Operating Income. Petroleum operating income was $564.7 million for the six months ended June 30, 2013 as compared to operating income of $383.8 million for the six months ended June 30, 2012. This increase of $180.9 million was the result of an increase in the refining margin ($198.6 million). The increase in refining margin was partially offset by an increase in direct operating expense ($5.6 million), selling, general and administrative expense ($8.6 million) and depreciation and amortization ($3.5 million).business'business’ results of operations, relevant market indicators and key operating statistics for the three and six months ended June 30, 2013March 31, 2014 and 2012:2013: Three Months
Ended
June 30, Six Months
Ended
June 30, Three Months Ended
March 31, 2013 2012 2013 2012 2014 2013 (in millions) (in millions) $ 88.8 $ 81.4 $ 170.2 $ 159.7 $ 80.3 $ 81.4 15.6 10.7 26.2 23.3 21.7 10.6 24.4 22.4 47.0 45.3 24.2 22.6 5.5 7.0 11.1 13.0 4.6 5.6 6.2 5.2 12.0 10.6 6.7 5.8 $ 37.1 $ 36.1 $ 73.9 $ 67.5 $ 23.1 $ 36.8 $ 44.1 $ 44.1 $ 87.9 $ 82.1 $ 29.9 $ 43.8 Three Months Ended
March 31, 2014 2013 Key Operating Statistics Production (thousand tons): Ammonia (gross produced)(3) 91.0 111.4 Ammonia (net available for sale)(3)(4) 8.9 30.7 UAN 257.2 196.2 Pet coke consumed (thousand tons) 124.8 129.8 Pet coke (cost per ton) $ 29 $ 31 Sales (thousand tons)(5): Ammonia 5.4 27.6 UAN 254.7 194.1 Product pricing (plant gate) (dollars per ton)(5): Ammonia $ 479 $ 663 UAN $ 253 $ 295 On-stream factor(6): Gasification 98.8 % 99.5 % Ammonia 92.1 % 98.8 % UAN 97.0 % 92.8 % Reconciliation of net sales (dollars in millions): Sales net plant gate $ 67.0 $ 75.6 Freight in revenue 6.9 5.7 Hydrogen revenue 5.9 0.1 Other revenue 0.5 — Total net sales $ 80.3 $ 81.4 Three Months Ended
June 30, Six Months Ended
June 30, 2013 2012 2013 2012 91.3 108.9 202.7 198.2 2.2 34.9 32.9 59.9 225.2 180.0 421.3 334.6 114.4 130.2 244.2 250.7 $ 29 $ 31 $ 30 $ 36 7.1 29.4 34.6 59.3 217.3 177.2 411.4 335.5 $ 688 $ 568 $ 668 $ 591 $ 331 $ 329 $ 314 $ 322 91.6 % 99.2 % 95.5 % 96.2 % 89.1 % 98.0 % 93.9 % 94.7 % 86.5 % 96.7 % 89.7 % 90.1 % $ 76.8 $ 75.1 $ 152.5 $ 142.9 8.0 6.3 13.7 11.1 4.0 — 4.0 5.7 $ 88.8 $ 81.4 $ 170.2 $ 159.7 Three Months
Ended
June 30, Six Months
Ended
June 30, 2013 2012 2013 2012 $ 4.02 $ 2.35 $ 3.76 $ 2.43 653 585 674 585 381 417 380 380 (1)Amounts are shown exclusive of depreciation and amortization.(2)Adjusted Nitrogen Fertilizer EBITDA represents operating income adjusted for (i) share-based compensation, non-cash, (ii) major scheduled turnaround expenses, (iii) depreciation and amortization and (iv) other income (expense). We present Adjusted Nitrogen Fertilizer EBITDA because it is a key measure used in material covenants in the Nitrogen Fertilizer Partnership's credit facility and because it is the starting point for the Nitrogen Fertilizer Partnership's available cash for distribution. Adjusted Nitrogen Fertilizer EBITDA is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance. Management believes that Adjusted EBITDA enables investors to better understand and evaluate the Nitrogen Fertilizer Partnership's ability to make distributions to the its common unitholders and its compliance with the covenants contained in the Nitrogen Fertilizer Partnership's credit facility. Adjusted Nitrogen Fertilizer EBITDA presented by other companies may not be comparable to our presentation, since each company may define those terms differently. Below is a reconciliation of operating income to Three Months Ended
March 31, 2014 2013 Market Indicators Natural gas NYMEX (dollars per MMBtu) $ 4.72 $ 3.48 Ammonia — Southern Plains (dollars per ton) 441 696 UAN — Corn belt (dollars per ton) 332 378 (1) Amounts are shown exclusive of depreciation and amortization. (2) Three Months Ended
March 31, 2014 2013 (in millions) Nitrogen Fertilizer: Nitrogen fertilizer operating income $ 23.1 $ 36.8 Share-based compensation, non-cash 0.1 1.2 Depreciation and amortization 6.7 5.8 Adjusted Nitrogen Fertilizer EBITDA $ 29.9 $ 43.8 (3) Gross tons produced for ammonia represent total ammonia produced, including ammonia produced that was upgraded into UAN. As a result of the completion of the UAN expansion project in February 2013, the Nitrogen Fertilizer Partnership now expects to upgrade substantially all of the ammonia it produces into UAN. Net tons available for sale represent ammonia available for sale that was not upgraded into UAN. (4) (5) Plant gate sales per ton represent net sales less freight revenue divided by product sales volume in tons and is shown in order to provide a pricing measure that is comparable across the fertilizer industry. (6) Adjusted EBITDA for the nitrogen fertilizer segment for the three and six months ended June 30, 2013 and 2012: Three Months
Ended
June 30, Six Months
Ended
June 30, 2013 2012 2013 2012 (in millions) $ 37.1 $ 36.1 $ 73.9 $ 67.5 0.8 2.8 2.0 4.0 6.2 5.2 12.0 10.6 — — — — $ 44.1 $ 44.1 $ 87.9 $ 82.1 (3)Gross tons produced for ammonia represent total ammonia, including ammonia produced that was upgraded into UAN. As a result of the recently completed UAN expansion project, we expect to upgrade substantially all of the ammonia we produce into UAN. The net tons available for sale represent ammonia available for sale that was not upgraded into UAN.(4)In addition to produced ammonia, the Nitrogen Fertilizer Partnership acquired approximately 4,000 tons of ammonia, which was upgraded to UAN during the three and six months ended June 30, 2013.(5)Plant gate sales per ton represent net sales less freight costs and hydrogen revenue divided by product sales volume in tons in the reporting period. Plant gate pricing per ton is shown in order to provide a pricing measure that is comparable across the fertilizer industry.(6)On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period and is a measure of operating efficiency. Excluding the impact of the unplanned Linde air separation unit outages and the unplanned downtime associated with weather issues, the on-stream factors for the three months ended June 30, 2013 would have been 99.6% for gasifier, 99.1% for ammonia and 97.1% for UAN.Excluding the impact of the UAN expansion coming online, the unplanned Linde air separation unit outages and the unplanned downtime associated with weather issues, the on-stream factors for the six months ended June 30, 2013 would have been 99.6% for gasifier, 98.9% for ammonia and 97.7% for UAN.June 30, 2013March 31, 2014 compared to the Three Months Ended June 30, 2012March 31, 2013 (Nitrogen Fertilizer Business)$88.8$80.3 million for the three months ended June 30, 2013 March 31, 2014compared to $81.4$81.4 million for the three months ended June 30, 2012.March 31, 2013. The increasedecrease of $7.4$1.1 million was primarily the result of higherlower ammonia sales volumes ($15.0 million), lower UAN sales volumesprices ($14.711.0 million) and hydrogen sales volumes ($4.0 million) combined with higherlower ammonia sales prices ($3.6 million) and higher UAN sales prices ($1.0 million), partially offset by lower ammoniahigher UAN sales volumes ($15.919.5 million) combined with higher hydrogen sales volumes ($6.2 million). For the three months ended June 30, 2013,March 31, 2014, UAN and ammonia and UAN made up $5.0$71.2 million and $79.8$2.7 million of nitrogen fertilizer net sales, respectively. This compared to ammoniaUAN and UANammonia net sales of $17.3$62.7 million and $64.1$18.7 million, respectively, for the three months ended June 30, 2012.March 31, 2013. The following table demonstrates the impact of sales volumes and pricing for UAN, ammonia UAN and hydrogen for the three months ended June 30,March 31, 2014 and March 31, 2013: Three Months Ended
March 31, 2014 Three Months Ended
March 31, 2013Total Variance Volume(1) $ per ton(2) Sales $(3) Volume(1) $ per ton(2) Sales $(3) Volume(1) Sales $(3) (in millions) UAN 254,671 $ 280 $ 71.2 194,141 $ 323 $ 62.7 60,530 $ 8.5 $ (11.0 ) $ 19.5 Ammonia 5,446 $ 495 $ 2.7 27,572 $ 679 $ 18.7 (22,126 ) $ (16.0 ) $ (1.0 ) $ (15.0 ) Hydrogen 578,464 $ 10 $ 5.9 2,713 $ 11 $ — 575,751 $ 5.9 $ (0.3 ) $ 6.2 June 30, 2012: Three Months Ended
June 30, 2013 Three Months Ended
June 30, 2012 Total Variance Volume(1) $ per ton(2) Sales $(3) Volume(1) $ per ton(2) Sales $(3) Volume(1) Sales $(3) Price
Variance Volume
Variance (in millions) 7,068 $ 710 $ 5.0 29,414 $ 568 $ 17.3 (22,346 ) $ (12.3 ) $ 3.6 $ (15.9 ) 217,287 $ 367 $ 79.8 177,169 $ 362 $ 64.1 40,118 $ 15.7 $ 1.0 $ 14.7 375,102 $ 11 $ 4.0 — $ — $ — 375,102 $ 4.0 $ — $ 4.0 (1)Ammonia and UANammonia sales volumes are in tons. Hydrogen sales volumes are in MSCF.June 30, 2013 March 31, 2014compared to the three months ended June 30, 2012 March 31, 2013was primarily attributable to the UAN expansion being fully operational during the quarter. On-stream factors (total number of hours operated divided by total hours in the reporting period)operation for the gasification, ammonia and UAN units were 91.6%, 89.1% and 86.5%, respectively, for the three months ended June 30, 2013. On-stream factors during the period were adversely affected by unscheduled downtime, which was largely due to the Linde air separation unit outages and power outages resulting from severe weather. On-stream rates for the three months ended June 30, 2012 were 99.2%, 98.0% and 96.7%, for the gasification, ammonia and UAN units, respectively.we absorbthe nitrogen fertilizer business absorbs to deliver the product. We believeThe nitrogen fertilizer business believes plant gate price is meaningful because we sellit sells products both at ourits plant gate (sold plant) and delivered to the customer'scustomer’s designated delivery site (sold delivered) and the percentage of sold plant versus sold delivered can change month-to-month or quarter-to-quarter. The plant gate price provides a measure that is consistently comparable period to period. Average plant gate prices for the three months ended June 30,March 31, 2014 compared to the three months ended March 31, 2013 were higher decreased 14.2% for bothUAN and 27.8% for ammonia, and UAN over the comparable period of 2012, increasing 21.0% and 0.6% respectively.June 30, 2013March 31, 2014 was $15.6$21.7 million compared to $10.7$10.6 million for the three months ended June 30, 2012.March 31, 2013. The $4.9$11.1 millionincrease resulted from $4.6$12.0 million in higher costs from transactions with third parties, combined with higherpartially offset by lower costs from transactions with affiliates of $0.3$0.9 million. The higher third-party costs incurred during the three months ended June 30, 2013March 31, 2014 were primarily the result of ammonia purchases (approximately 22,900 tons for the three months ended March 31, 2014 and none in the three months ended March 31, 2013), increased railcar repairs and inspections and increased freight costs.Table of ContentsJune 30, 2013 March 31, 2014were $24.4$24.2 million as compared to $22.4$22.6 million for the three months ended June 30, 2012.March 31, 2013. The $2.0$1.6 millionincrease resulted primarily from higher repairs and maintenance costsutilities ($1.71.6 million), utilities ($1.3 million), catalystrefractory brick amortization ($0.5 million) and insurancecatalyst amortization ($0.4 million), partially offset by lower property taxespersonnel costs ($2.70.5 million) and insurance ($0.4 million). The increased utility costs were largely due to the UAN expansion, which came on-line in February 2013. The lower labor costs are the result of the higher labor incurred during the UAN expansion project.$37.1$23.1 million for the three months ended June 30, 2013,March 31, 2014, as compared to operating income of $36.1$36.8 million for the three months ended June 30, 2012.March 31, 2013. The increasedecrease of $1.0$13.7 million for the three months ended June 30, 2013March 31, 2014 as compared to the three months ended June 30, 2012March 31, 2013 was the result of the increaseincreases in netcost of($7.4 million) and lower($1.1 million), partially offset by a decrease in selling, general and administrative expenses ($1.5 million), partially offset by increased cost of product sold ($4.9 million), direct operating costs ($2.0 million) and depreciation and amortization ($($1.0 million)million).Six Months Ended June 30, 2013 compared to the Six Months Ended June 30, 2012 (Nitrogen Fertilizer Business) Net Sales. Nitrogen fertilizer net sales were $170.2 million for the six months ended June 30, 2013 compared to $159.7 million for the six months ended June 30, 2012. The increase of $10.5 million was the result of both higher average plant gate prices for ammonia and higher sales volumes for UAN, offset by lower sales volumes for ammonia, lower average plant gate prices for UAN and reduced hydrogen sales to the Refining Partnership's refinery. For the six months ended June 30, 2013, ammonia and UAN made up $23.7 million and $142.4 million of our net sales, respectively. This compared to ammonia and UAN net sales of $36.1 million and $117.9 million, respectively, for the six months ended June 30, 2012. The following table demonstrates the impact of sales volumes and pricing for ammonia, UAN and hydrogen for the six months ended June 30, 2013 and June 30, 2012: Six Months Ended
June 30, 2013 Six Months Ended
June 30, 2012 Total Variance Volume(1) $ per ton(2) Sales $(3) Volume(1) $ per ton(2) Sales $(3) Volume(1) Sales $(3) Price
Variance Volume
Variance (in millions) 34,640 $ 685 $ 23.7 59,280 $ 608 $ 36.0 (24,640 ) $ (12.3 ) $ 4.6 $ (16.9 ) 411,428 $ 346 $ 142.4 335,462 $ 352 $ 117.9 75,966 $ 24.5 $ (1.8 ) $ 26.3 377,815 $ 11 $ 4.0 562,657 $ 10 $ 5.7 (184,842 ) $ (1.7 ) $ 0.2 $ (1.9 ) (1)Ammonia and UAN sales volumes are in tons. Hydrogen sales volumes are in MSCF.(2)Includes freight charges(3)Sales dollars in millions The increase in UAN sales volume for the six months ended June 30, 2013 compared to the six months ended June 30, 2012 was primarily attributable to the UAN expansion being fully operational during the quarter. On-stream factors (total number of hours operated divided by total hours in the reporting period) for the gasification, ammonia and UAN units were 95.5%, 93.9% and 89.7%, respectively, for the six months ended June 30, 2013. On-stream factors during the period were adversely affected by the downtime associated with the UAN expansion and unscheduled downtime, which was largely due to the Linde air separation unit outages and power outages resulting from severeweather. On-stream rates for the six months ended June 30, 2012 were 96.2%, 94.7% and 90.1%, for the gasification, ammonia and UAN units, respectively. Plant gate prices are prices at the designated delivery point less any freight cost we absorb to deliver the product. We believe plant gate price is meaningful because we sell products both at our plant gate (sold plant) and delivered to the customer's designated delivery site (sold delivered) and the percentage of sold plant versus sold delivered can change month to month or quarter-to-quarter. The plant gate price provides a measure that is consistently comparable period to period. Average plant gate prices for the six months ended June 30, 2013 compared to the six months ended June 30, 2012 increased 13.1% for ammonia and decreased 2.3% for UAN. Cost of Product Sold (Exclusive of Depreciation and Amortization). Nitrogen fertilizer cost of product sold is primarily comprised of pet coke expense, freight expense and distribution expense. Cost of product sold for the six months ended June 30, 2013 was $26.2 million compared to $23.3 million for the six months ended June 30, 2012. The increase of $2.9 million is primarily the result of higher third-party costs of $2.5 million associated with higher freight costs due to the increased UAN sales volumes and purchased ammonia. Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses for the nitrogen fertilizer operations include costs associated with the actual operations of the nitrogen fertilizer plant, such as repairs and maintenance, energy and utility costs, catalyst and chemical costs, outside services, labor and environmental compliance costs. Direct operating expenses (exclusive of depreciation and amortization) for the six months ended June 30, 2013 were $47.0 million as compared to $45.3 million for the six months ended June 30, 2012. The $1.7 million increase was largely the result of increased utilities ($2.0 million), repairs and maintenance costs ($1.2 million), labor ($1.0 million), insurance ($0.9 million), catalyst amortization ($0.7 million) and chemicals ($0.5 million), partially offset by lower property taxes ($5.4 million). The increased utility costs were largely due to the UAN expansion, which came on-line in February 2013. Operating Income. Nitrogen fertilizer operating income was $73.9 million for the six months ended June 30, 2013 as compared to operating income of $67.5 million for the six months ended June 30, 2012. This increase of $6.4 million was due to an increase in net sales ($10.5 million) and lower selling, general and administrative expenses ($1.9 million), partially offset by increased cost of product sold ($2.9 million), direct operating costs ($1.7 million) and depreciation and amortization ($1.4 million).Since the Nitrogen Fertilizer Partnership's IPO in April 2011, withWith the exception of cash distributions paid to us by the Refining Partnership and Nitrogen Fertilizer Partnership, the cash needs of both the Refining Partnership and the Nitrogen Fertilizer Partnership have been met independently from the cash needs of CVR Energy and the refining businesseach other with a combination of existing cash and cash equivalent balances, cash generated from operating activities and credit facility borrowings. Prior to December 31, 2012, CVR Energy provided cash as needed to support the Refining Partnership's operations. Beginning January 1, 2013, CVR Energy and the Refining Partnership also operate with independent capital structures. The Refining Partnership'sPartnership’s and the Nitrogen Fertilizer Partnerships'Partnership's ability to generate sufficient cash flows from their respective operating activities and to then make distributions on their common units, including to us (which we will need to pay salaries, reporting expenses and other expenses as well as dividends on our common stock) will continue to be primarily dependent on producing or purchasing, and selling, sufficient quantities of refined and nitrogen fertilizer products at margins sufficient to cover fixed and variable expenses.business'business’ cash flows from operations and existing cash and cash equivalents, along with borrowings under their respective existing credit facilities, as necessary, will be sufficient to satisfy the anticipated cash requirements associated with their existing operations for at least the next twelve months, and that we have sufficient cash resources to fund our operations for at least the next twelve months. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, the ability to generate sufficient cash from operating activities depends on future performance, which is subject to general economic, political, financial, competitive, and other factors.June 30, 2013,March 31, 2014, we had consolidated cash and cash equivalents of $1,134.5 million.$962.1 million. Of that amount, $539.3$462.8 million was cash and cash equivalents of CVR Energy, $483.3$413.4 million was cash and cash equivalents of the Refining Partnership and $111.9$85.9 million was cash and cash equivalents of the Nitrogen Fertilizer Partnership. During the six months ended June 30, 2013, our consolidated cash position increased approximately $238.5 million primarily as a result of cash flows from operations and financing activities, which were partially offset by our dividend payments and distributions paid by the petroleum and nitrogen fertilizer businesses. As of JulyApril 30, 2013,2014, we had consolidated cash and cash equivalents of approximately $1,230.8 million.$893.2 million.$400.0$400.0 million with an incremental facility, subject to compliance with a borrowing base. The Amended and Restated ABL Credit Facility is scheduled to mature on December 20, 2017. The proceeds of the loans may be used for capital expenditures and working capital and general corporate purposes of the Refining Partnership and the credit facility provides for loans and letters of credit in an amount up to the aggregate availability under the facility, subject to meeting certain borrowing base conditions, with sub-limits of 10% of the total facility commitment for swingline loans and 90% of the total facility commitment for letters of credit. As of June 30, 2013,March 31, 2014, the Refining Partnership had $372.9$372.9 million available under the Amended and Restated ABL Credit Facility.$125.0$125.0 million and a revolving credit facility of $25.0$25.0 million with an uncommitted incremental facility of up to $50.0 million.$50.0 million. The Nitrogen Fertilizer Partnership credit facility matures in April 2016. The Nitrogen Fertilizer Partnership credit facility is used to finance on-going working capital, capital expenditures, letter of credit issuances and general needs of CRNF. As of June 30, 2013,March 31, 2014, the Nitrogen Fertilizer Partnership had $25.0$25.0 million available under the credit facility.a distribution policy inpolicies pursuant to which they will generally distribute all of their available cash each quarter, within 60 days after the end of each quarter. The Refining Partnership'sPartnership’s distributions began with the quarter ending March 31, 2013 and were adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Refining Partnership IPO). The distributions will be made to all common unitholders. At June 30, 2013,March 31, 2014, we currently hold approximately 71% and 53% of the Refining Partnership'sPartnership’s and the Nitrogen Fertilizer Partnership'sPartnership’s common units outstanding, respectively. The amount of each distribution will be determined pursuant to each general partner's calculation of available cash for the applicable quarter. The general partner of each partnership, as a non-economic interest holder, is not entitled to receive cash distributions. As a result of each general partner's distribution policy, funds held by the Refining Partnership and the Nitrogen Fertilizer Partnership will not be available for our use, and we as a unitholder expect to receive our applicable percentage of the distribution of funds within 60 days following each quarter. The Refining Partnership and the Nitrogen Fertilizer Partnership do not have a legal obligation to pay distributions and there is no guarantee that they will pay any distributions on the units in any quarter.$500.0$500.0 million aggregate principal amount of the6.5% Senior Notes due 2022 Notes. A portion of the net proceeds from the offering approximating $348.1 million were used to purchase approximately $323.0 million of the First Lien Notes pursuant to a tender offer and to settle accrued interest of approximately $1.8 million through October 23, 2012 and to pay related fees and expenses. Tendered notes were purchased at a premium of approximately $23.2 million in aggregate amount. The remaining proceeds from the offering were used to redeem the remaining $124.1 million of outstanding First Lien Notes and to settle accrued interest of approximately $1.6 million through November 23, 2012. Redeemed notes were purchased at a premium of approximately $8.4 million in aggregate amount. Previously deferred financing charges and unamortized original issuance premium related to the First Lien Notes totaled approximately $8.1 million and $6.3 million, respectively.(the "2022 Notes"). As a result of the repaymentissuance, approximately $8.7 million of the First Lien Notes, a loss on extinguishment of debt of $33.4 million was recorded in the fourth quarter of 2012, which included the total premiums paid of $31.6 million and write-off of previously deferred financing charges of $8.1 million, partially offset by the write-off of the unamortized original issuance premium of $6.3 million. The debt issuance costs of the 2022 Notes totaled approximately $8.7 million andwere incurred, which are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. As of June 30, 2013,March 31, 2014, the 2022 Notes had an aggregate principal balance and a net carrying value of $500.0 million.May 29,September 17, 2013, Refining LLC filedand Coffeyville Finance consummated a registration statement on Form S-4 to satisfy itsregistered exchange offer, whereby all $500.0 million of the outstanding 2022 Notes were exchanged for an equal principal amount of notes with identical terms that were registered under the Securities Act of 1933. The exchange offer fulfilled the Refining Partnership's obligations contained in the registration rights agreement entered into in connection with the issuance of the 2022 Notes. The Refining Partnership has incurred approximately $0.3 million of debt registration costs related to this registration, which are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method."change“change of control,"” the issuers are required to offer to buy back all of the 2022 Notes at 101% of their principal amount. A change of control is generally defined as (1) the direct or indirect sale or transfer (other than by a merger) of all or substantially all of the assets of Refining LLC to any person other than qualifying owners (as defined in the indenture), (2) liquidation or dissolution of Refining LLC, or (3) any person, other than a qualifying owner, directly or indirectly acquiring 50% of the voting stock of Refining LLC.Poor'sPoor’s Rating Services and Moody'sMoody’s Investors Services, Inc. However, such covenants would be reinstituted if the 2022 Notes subsequently lost their investment grade rating. In addition, the indenture contains customary events of default, the occurrence of which would result in, or permit the trustee or the holders of at least 25% of the 2022 Notes to cause, the acceleration of the 2022 Notes, in addition to the pursuit of other available remedies.Partnership'sPartnership’s ability to pay distributions to unitholders. The covenants will apply differently depending on the Refining Partnership'sPartnership’s fixed charge coverage ratio (as defined in the indenture). If the fixed charge coverage ratio is not less than 2.5 to 1.0, the Refining Partnership$100.0$100.0 million basket plus certain other amounts referred to as "incremental funds"“incremental funds” under the indenture. The Refining Partnership was in compliance with the covenants as of June 30, 2013.March 31, 2014."Credit Parties"“Credit Parties”) entered into the Amended and Restated ABL Credit Facility with Wells Fargo Bank, National Association, as administrative agent and collateral agent for a syndicate of lenders. The Amended and Restated ABL Credit Facility replaced our ABL credit facility. Under the Amended and Restated ABL Credit Facility, the Refining Partnership assumed our position as borrower and our obligations under the Amended and Restated ABL Credit Facility upon the closing of the Refining Partnership IPO on January 23, 2013. The Amended and Restated ABL Credit Facility is a $400.0$400.0 million asset-based revolving credit facility, with sub-limits for letters of credit and swingline loans of $360.0$360.0 million and $40.0$40.0 million, respectively. The Amended and Restated ABL Credit Facility also includes a $200.0$200.0 million uncommitted incremental facility. The borrowing-base components, advance rates, prepayment provisions, collateral provisions, affirmative covenants and negative covenants in the Amended and Restated ABL Credit Facility are substantially similar to the corresponding provisions in the ABL credit facility. The Amended and Restated ABL Credit Facility permits the payment of distributions, subject to the following conditions: (i) no default or event of default exists, (ii) excess availability and projected excess availability at all times during the 3-month period following the distribution exceeds 20% of the lesser of the borrowing base and the total commitments; provided, that, if excess availability and projected excess availability for the 6-month period following the distribution is greater than 25% at all times, then the following condition in1.00.1.00. The Amended and Restated ABL Credit Facility has a five-year maturity and will be used for working capital and other general corporate purposes (including permitted acquisitions).investmentinvestments and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries. The Amended and Restated ABL Credit Facility also contains a fixed charge coverage ratio financial covenant, as defined therein. The Refining Partnership was in compliance with the covenants of the Amended and Restated ABL Credit Facility as of June 30, 2013. Old Notes. On April 6, 2010, CRLLC and its wholly-owned subsidiary, Coffeyville Finance completed the private offering of $275.0 million aggregate principal amount of First Lien Notes and $225.0 million aggregate principal amount of Second Lien Notes. The 2010 First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. On December 15, 2011, we issued an additional $200.0 million aggregate principal amount of First Lien Notes to partially fund the acquisition of the Wynnewood refinery. The additional First Lien Notes were issued at 105% of their principal amount. On October 23, 2012, we repurchased approximately $323.0 million of our First Lien Notes pursuant to a tender offer and redeemed the remaining $124.1 million of outstanding First Lien Notes not tendered, on November 23, 2012, as discussed above. We redeemed all outstanding Second Lien Notes on January 23, 2013, following the closing of the Refining Partnership IPO, with a combination of proceeds from the Refining Partnership IPO and cash on hand.March 31, 2014Facility.Facility. On April 13, 2011, CRNF, as borrower, and the Nitrogen Fertilizer Partnership, as guarantor, entered into a credit facility (the "Nitrogen“Nitrogen Fertilizer Partnership credit facility"facility”) with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent. The Nitrogen Fertilizer Partnership credit facility includes a term loan facility of $125.0$125.0 million and a revolving credit facility of $25.0$25.0 million with an uncommitted incremental facility of up to $50.0 million.$50.0 million. There is no scheduled amortization and the Nitrogen Fertilizer Partnership credit facility matures in April 2016.or the prime rate plus 2.50%. Under its terms, the lenders under the Nitrogen Fertilizer Partnership credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in substantially all of the assets of CRNF and the Nitrogen Fertilizer Partnership and all of the capital stock of CRNF and each domestic subsidiary owned by the Nitrogen Fertilizer Partnership or CRNF. CRNF is the borrower under the Nitrogen Fertilizer Partnership credit facility. All obligations under the Nitrogen Fertilizer Partnership credit facility are unconditionally guaranteed by the Nitrogen Fertilizer Partnership and substantially all of its future, direct and indirect, domestic subsidiaries. Borrowings under the credit facility are non-recourse to the Company and its direct subsidiaries.June 30, 2013,March 31, 2014, no amounts were drawn under the Nitrogen Fertilizer Partnership's $25.0Partnership’s $25.0 million revolving credit facility.SwapPartnership'sPartnership’s CRNF subsidiary entered into two Interest Rate Swap agreements with J. Aron & Company. These Interest Rate Swap agreements commenced on August 12, 2011. We have determined that the Interest Rate Swaps qualify for hedge accounting treatment. The impact recorded for each of the three months ended June 30,March 31, 2014 and 2013 and 2012 is $0.2$0.3 million in interest expense. The impact recorded for each of the six months ended June 30, 2013 and 2012 is $0.5 million in interest expense. For each of the three months ended June 30,March 31, 2014 and 2013, and 2012, the Nitrogen Fertilizer Partnership recognized an increase in fair value on the Interest Rate Swap agreements of $0.2 million and a decrease in fair value on the Interest Rate Swap agreements, of $0.7 million, respectively, which is unrealized in accumulated other comprehensive income. For the six months ended June 30, 2013 and 2012, the Nitrogen Fertilizer Partnership recognized an increase in fair value on the Interest Rate Swap agreements of $0.2 million and a decrease in fair value on the Interest Rate Swap agreements of $1.0 million, respectively, which is unrealized in accumulated other comprehensive income.business'business’ capital spending needs into two categories: maintenance and growth. Maintenance capital spending includes only non-discretionary maintenance projects and projects required to comply with environmental, health and safety regulations. We undertake discretionary capital spending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields, and/or a reduction in direct operating expenses. Major scheduled turnaround expenses are expensed when incurred.Table of Contentssixthree months ended June 30, 2013March 31, 2014 by operating segment and major category: Six Months Ended
June 30, 2013 Three Months Ended
March 31, 2014 (in millions) (in millions) $ 18.8 $ 20.8 0.5 0.6 19.3 21.4 47.0 19.7 8.0 11.7 55.0 31.4 5.4 1.7 0.4 3.4 5.8 5.1 80.1 57.9 1.2 1.0 30.7 2.4 31.9 3.4 2.6 0.6 $ 114.6 $ 61.9 sixthree months ended June 30, 2013,March 31, 2014, the petroleum business expects to spend, in total, approximately $275.0$340.0 million to $295.0$350.0 million (excluding capitalized interest) on capital expenditures for the year ending December 31, 2013.2014. Of this amount, $95.0$145.0 million to $105.0$150.0 million is expected to be spent for the Coffeyville refinery, which includes approximately $85.0$115.0 million to $90.0$120.0 million of maintenance capital. Approximately $140.0$170.0 million to $150.0$175.0 million is expected to be spent on capital expenditures for the Wynnewood refinery, which includes approximately $95.0$95.0 million to $105.0$100.0 million of maintenance capital. We also expect to spend $35.0$25.0 million on other petroleum capital projects and approximately $5.0$7.0 million to $8.0 million associated with corporate related projects.sixthree months ended June 30, 2013,March 31, 2014, the nitrogen fertilizer business expects to spend in total, $40.0$9.0 million to $50.0$11.0 million on maintenance capital expenditures for the year ending December 31, 2013 (excluding capitalized interest). Of this amount, $6.0 million2014. A less involved facility shutdown is expected to $8.0 million will be spent on maintenance projectsperformed during the second quarter of 2014 to both install a waste heat boiler and $34.0 millionupgrade the pressure swing adsorption ("PSA") unit. The upgraded PSA unit is projected to $42.0 million will be spent on growth projects including approximately $25.0 million spent relatedincrease hydrogen recovery enough to the UAN expansion project. In February 2013,allow the nitrogen fertilizer business completed a significant two-year plant expansion designed to increase its UAN production capacity by 400,000produce approximately 7,000 to 9,000 tons or approximately 50% per year. The expanded facility was running at full operating rates prior to the end of the first quarter. The UAN expansion providesadditional ammonia fertilizer annually, for which the nitrogen fertilizer business withexpects the abilitytotal cost to upgrade substantially all of its ammonia productionbe approximately $5.0 million to UAN. Total capital expenditures associated with the UAN expansion were approximately $130.0 million, excluding capitalized interest.following table sets forth our cash flows for the periods indicated below: Six Months Ended
June 30, 2013 2012 (unaudited) (in millions) $ 362.4 $ 435.9 (114.5 ) (104.8 ) (9.4 ) (26.8 ) $ 238.5 $ 304.3 Cash Flows Provided by Operating Activities For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital. Net cash flows provided by operating activities for the six months ended June 30, 2013 were $362.4 million. The positive cash flow from operating activities generated over this period was primarily driven by $484.4 million of net income and $179.9 million of favorable other working capital, partially offset by unfavorable impacts to trade working capital of $169.7 million. Net income was primarily driven by increased throughput rates and refining margins in the petroleum business and favorable pricing in the nitrogen fertilizer business resulting in higher profit margins. Trade working capital for the six months ended June 30, 2013 resulted in a cash outflow of $169.7 million, which was attributable to increases in accounts receivable ($67.1 million) and inventory ($60.7 million) and a decrease in accounts payable ($41.9 million). Other working capital activities resulted in net cash inflow of $179.9 million and were primarily related to increases in due to parent ($128.1 million) and other current liabilities ($47.9 million). Net cash flows provided by operating activities for the six months ended June 30, 2012 were $435.9 million. The positive net cash flow used for operating activities was primarily driven by operating income of $376.3 million which was the result of higher operating margins. This positive operating income was coupled with a favorable change in trade working capital and other working capital. Trade working capital for the six months ended June 30, 2012 resulted in a cash inflow of $63.1 million, primarily as a result of a decrease in inventory of $121.9 million, partially offset by a decrease in accounts payable of $27.6 million and an increase in accounts receivable of $31.2 million. Other working capital activities of $66.7 million was primarily driven by an increase in current liabilities of $76.2 million partially offset by a decrease in prepaid expenses and other current assets of $9.5 million.Cash Flows Used in Investing Activities Net cash used in investing activities for the six months ended June 30, 2013 was $114.5 million compared to $104.8 million for the six months ended June 30, 2012. The increase in cash used in investing activities was primarily the result of an increase in capital expenditures of $9.4 million. The petroleum business' capital expenditures increased $17.5 million for the six months ended June 30, 2013 compared to the same period in 2012 due to projects at the Wynnewood refinery. This increase was offset by a decrease in nitrogen fertilizer capital expenditures of $7.4 million primarily related to decreased capital expenditures for the UAN expansion, which was completed in February 2013.Cash Flows Used In Financing Activities Net cash used in financing activities for the six months ended June 30, 2013 was approximately $9.4 million as compared to $26.8 million for six months ended June 30, 2012. The net cash used in financing activities for the six months ended June 30, 2013 was primarily attributable to dividend payments to common stockholders of $1,107.1 million, distributions to the Refining Partnership and Nitrogen Fertilizer Partnership common unitholders of $61.4 million and payments to extinguish the Second Lien Notes of $243.4 million, largely offset by proceeds from CVR Refining's initial public offering of $655.7 million, proceeds from CVR Refining's Underwritten Offering of $393.7 million, proceeds from CVR Energy's sale of CVR Refining's units to AEPC of $61.5 million and proceeds from the Secondary Offering of CVR Partner's common units of $292.6 million. Net cash used in financing activities for the six months ended June 30, 2012 was $26.8 million. During the six months ended June 30, 2012, we paid a cash distribution to noncontrolling interest holders of the Nitrogen Fertilizer Partnership totaling $24.6 million. Additionally, financing costs of approximately $2.0 million were paid during the period associated with increasing the borrowing capacity of the ABL credit facility and the issuance of additional notes in December 2011. For the three and six months ended June 30, 2013, there were no borrowings or repayments under the Amended and Restated ABL credit facility or the Nitrogen Fertilizer Partnership credit facility. As of June 30, 2013, there were no short-term borrowings outstanding under the Amended and Restated ABL credit facility.Capital and Commercial Commitments In addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of June 30, 2013 relating to long-term debt outstanding on that date, operating leases, capital lease obligations, unconditional purchase obligations and other specified capital and commercial commitments for the period following June 30, 2013 and thereafter. As of June 30, 2013, there were no amounts outstanding under the Amended and Restated ABL Credit Facility or the revolving facility under the Nitrogen Fertilizer Partnership's credit facility. Payments Due by Period Total 2013 2014 2015 2016 2017 Thereafter (in millions) $ 625.0 $ — $ — $ — $ 125.0 $ — $ 500.0 40.3 4.8 9.1 7.7 6.7 4.0 8.0 51.7 0.6 1.3 1.4 1.6 1.8 45.0 1,451.5 99.2 112.9 101.2 94.0 92.8 951.4 2.2 0.4 0.3 0.2 0.1 0.1 1.1 376.8 22.4 42.3 42.1 38.6 37.1 194.3 $ 2,547.5 $ 127.4 $ 165.9 $ 152.6 $ 266.0 $ 135.8 $ 1,699.8 $ 27.1 $ — $ — $ — $ — $ — $ — (1)Consists of the 2022 NotesPartnership’s and the Nitrogen Fertilizer Partnership's term loan facility outstanding on June 30, 2013.(2)The Refining Partnership and the Nitrogen Fertilizer Partnership lease various facilities and equipment, including railcars and real property, under operating leases for various periods.(3)The amount includes commitments under capital lease arrangements for equipment and for two leases associated with pipelines and storage and terminal equipment associated with the acquisition of the Wynnewood refinery.(4)The amount includes (a) commitments under several agreements for the petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation, (b) commitments under an electric supply agreement with the city of Coffeyville, (c) a product supply agreement with Linde and (d) a pet coke supply agreement with HollyFrontier Corporation having an initial term that ends in December 2013, subject to renewal, (e) commitments related to our biofuels blending obligation and (f) approximately $979.8 million payable ratably over eighteen years pursuant to petroleum transportation service agreements between CRRM and TransCanada Keystone Pipeline, LP ("TransCanada"). Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of twenty years on TransCanada's Keystone pipeline system. The Refining Partnership began receiving crude oil under the agreements in the first quarter of 2011.(5)Environmental liabilities represents our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas. We also have other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. See "Commitments and Contingencies—Environmental, Health & Safety Matters."(6)Interest payments are based on stated interest rates for our long-term debt outstanding on June 30, 2013 and interest payments for the capital lease obligations.(7)Standby letters of credit issued against our Amended and Restated ABL Credit Facility include $0.2 million of letters of credit issued in connection with environmental liabilities, $26.3 million in letters of credit to secure transportation services for crude oil, a $0.5 million letter of credit issued to guarantee a portion of our insurance policy and $0.1 million issued for the purpose of providing support during the transition of letters of credit assumed during the acquisition of the Wynnewood refinery. The Refining Partnership's and the Nitrogen Fertilizer Partnership'sPartnership’s ability to make payments on and to refinance their indebtedness, to fund budgeted capital expenditures and to satisfy their other capital and commercial commitments will depend on their respective independent abilities to generate cash flow in the future. Their ability to refinance their respective indebtedness is also subject to the availability of the credit markets. This, to a certain extent, is subject to refining spreads (for the Refining Partnership), fertilizer margins (for the Nitrogen Fertilizer Partnership) and general economic, financial, competitive, legislative, regulatory and other factors they are unable to control. Our businesses may not generate sufficient cash flow from operations, and future borrowings may not be available to the Nitrogen Fertilizer Partnership under its revolving credit facility, or the Refining Partnership under the Amended and Restated ABL Credit Facility (or other credit facilities our businesses may enter into in the future) in an amount sufficient to enable them to pay indebtedness or to fund other liquidity needs. They may seek to sell assets to fund liquidity needs but may not be able to do so. They may also need or seek to refinance all or a portion of their indebtedness on or before maturity, and may not be able to refinance such indebtedness on commercially reasonable terms or at all. Three Months Ended
March 31, 2014 2013 (unaudited) (in millions) Net cash provided by (used in): Operating activities $ 281.3 $ 278.3 Investing activities (61.9 ) (63.7 ) Financing activities (99.4 ) (69.8 ) Net increase in cash and cash equivalents $ 120.0 $ 144.8 June 30, 2013,March 31, 2014, as defined within the rules and regulations of the SEC. In December 2011, the FASB issued ASU No. 2011-11,"Disclosures about Offsetting Assets and Liabilities" ("ASU 2011-11"). ASU 2011-11 retains the existing offsetting requirements and enhancesTable of Contentsthe disclosure requirements to allow investors to better compare financial statements prepared under GAAP with those prepared under IFRS. On January 31,In July 2013, the FASB issued ASU No. 2013-01, "2013-11, Clarifying the Scope“Presentation of Disclosures about Offsetting Assets and Liabilities"an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists” ("(“ASU 2013-01"2013-11”). ASU 2013-01 limits2013-11 requires the scopenetting of unrecognized tax benefits against a deferred tax asset for a loss or other carryforward that would apply in settlement of the new balance sheet offsetting disclosures to derivatives, repurchase agreements and securities lending transactions. Both standards are effective for interim and annual periods beginning January 1, 2013 and are to be applied retrospectively. We adopted these standards as of January 1, 2013. The adoption of these standards expanded our condensed consolidated financial statement footnote disclosures. In February 2013, the FASB issued ASU No. 2013-02,"Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income" ("ASU 2013-02"). ASU 2013-02 requires us to present information about reclassification adjustments from accumulated other comprehensive income in our financial statements in a single footnote or parenthetically on the face of the financial statements based on the source and the income statement line items affected by the reclassification.uncertain tax positions. The standard is effective for interim and annual periods beginning January 1,after December 15, 2013 and is to be applied prospectively.prospectively with optional retrospective adoption permitted. We adopted this standard prospectively as of January 1, 2013.2014. The adoption of this standard did not materially expand our condensed consolidated financial statement footnote disclosures.resulted in a reclassification on the Condensed Consolidated Balance Sheets. See Note 7 ("Income Taxes") in Part I, Item I for further discussion."Critical“Critical Accounting Policies"Policies” section of our Annual Report on2013 Form 10-K for the year ended December 31, 2012.10-K. No modifications have been made to our critical accounting policies.Item 3. Quantitative and Qualitative Disclosures About Market Risksixthree months ended June 30, 2013March 31, 2014 does not differ materially from that discussed under Part II—Item 7A of our Annual Report on2013 Form 10-K for the year ended December 31, 2012.10-K. We are exposed to market pricing for all of the products sold in the future both at our petroleum business and the nitrogen fertilizer business, as all of the products manufactured in both businesses are commodities.June 30, 2013,March 31, 2014, the Refining Partnership had open commodity hedging instruments consisting of 20.018.1 million barrels of crack spreads primarily to fix the margin on a portion of our future gasoline and distillate production. The fair value of the outstanding contracts at June 30, 2013March 31, 2014 was a net unrealized gain of $71.6$72.2 million, comprised of both short-term and long-term unrealized gains and losses. A change of $1.00 per barrel in the fair value of the crack spread swaps would result in an increase or decrease in the related fair values of commodity hedging instruments of $20.0 million.$18.1 million. On June 30 and July 1, 2011, CRNF entered into two floating-to-fixed interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of the nitrogen fertilizer business' $125.0 million floating rate term debt which matures in April 2016. The aggregate notional amount covered under these agreements, which commenced on August 12, 2011 and expires on February 12, 2016, totals $62.5 million (split evenly between the two agreement dates). Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.975%. Both swap agreements will be settled every 90 days. The effect of these swap agreements is to lock in a fixed rate of interest of approximately 1.96% plus the applicable margin paid to lenders over three month LIBOR as governed by the CRNF credit agreement. At June 30, 2013, the effective rate was approximately 4.58%. The agreements were designated as cash flow hedges at inception and accordingly, the effective portion of the gain or loss on the swap is reported as a component of accumulated other comprehensive income (loss) ("AOCI"), and will be reclassified into interest expense when the interest rate swap transaction affects earnings. The ineffective portion of the gain or loss will be recognized immediately in current interest expense. still has exposure to interest rate risk on 50% of its $125.0$125.0 million floating rate term debt. A 1.0% increase over the Eurodollar floor spread of 3.5%3.50%, as specified in the credit agreement,facility, would increase interest cost to the Nitrogen Fertilizer Partnership by approximately $625,000$625,000 on an annualized basis, thus decreasing the Refining Partnership'sNitrogen Fertilizer Partnership’s net income by the same amount.Item 4. Controls and ProceduresJune 30, 2013,March 31, 2014, we have evaluated, under the direction of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC'sSEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. It should be noted that any system of disclosure controls and procedures, however well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the system are met. In addition, the design of any system of disclosure controls and procedures is based in part upon assumptions about the likelihood of future events. Due to these and other inherent limitations of any such system, there can be no assurance that any design will always succeed in achieving its stated goals under all potential future conditions.June 30, 2013March 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.Item 1. Legal Proceedings1110 ("Commitments and Contingencies") to Part I, Item I of this Report, which is incorporated by reference into this Part II, Item 1, for a description of thecertain litigation, legal and administrative proceedings and environmental matters. With the exception of the additional risk factor below, thereAnnual Report on2013 Form 10-K for the year ended December 31, 2012.We may be subject to the pension liabilities of our affiliates. Mr. Icahn, through certain affiliates, owns approximately 82% of the Company's capital stock. Applicable pension and tax laws make each member of a "controlled group" of entities, generally defined as entities in which there is at least an 80% common ownership interest, jointly and severally liable for certain pension plan obligations of any member of the controlled group. These pension obligations include ongoing contributions to fund the plan, as well as liability for any unfunded liabilities that may exist at the time the plan is terminated. In addition, the failure to pay these pension obligations when due may result in the creation of liens in favor of the pension plan or the Pension Benefit Guaranty Corporation ("PBGC") against the assets of each member of the controlled group. As a result of the more than 80% ownership interest in us by Mr. Icahn's affiliates, we are subject to the pension liabilities of all entities in which Mr. Icahn has a direct or indirect ownership interest of at least 80%. One such entity, ACF Industries LLC, is the sponsor of several pension plans. All the minimum funding requirements of the Code and the Employee Retirement Income Security Act of 1974, as amended by the Pension Protection Act of 2006, for these plans have been met as of June 30, 2013. If the ACF plans were voluntarily terminated, they would be underfunded by approximately $125.4 million as of June 30, 2013. Subsequent to June 30, 2013, as a result of Mr. Icahn's affiliates obtaining approximately 80.7% of the outstanding common stock of Federal-Mogul Corporation ("Federal-Mogul"), the Company is also subject to the pension liabilities of Federal-Mogul. If the plans of Federal-Mogul and ACF were voluntarily terminated, as of June 30, 2013, they would collectively be underfunded by approximately $764.4 million. These results are based on the most recent information provided to us by Mr. Icahn's affiliates based on information from the plans' actuaries. These liabilities could increase or decrease, depending on a number of factors, including future changes in benefits, investment returns, and the assumptions used to calculate the liability. As members of the controlled group, we would be liable for any failure of ACF, and subsequent to June 30, 2013, Federal-Mogul to make ongoing pension contributions or to pay the unfunded liabilities upon a termination of their respective pension plans. In addition, other entities now or in the future within the controlled group that includes us may have pension plan obligations that are, or may become, underfunded, and we would be liable for any failure of such entities to make ongoing pension contributions or to pay the unfunded liabilities upon a termination of such plans. The current underfunded status of the ACF and Federal-Mogul pension plans requires such entities to notify the PBGC of certain "reportable events," such as if we cease to be a member of the controlled group, or if we make certain extraordinary dividends or stock redemptions. The obligation to report could cause us to seek to delay or reconsider the occurrence of such reportable events. Starfire Holding Corporation ("Starfire") which is 99.4% owned by Mr. Icahn, has undertaken to indemnify us and our subsidiaries from losses resulting from any imposition of certain pension funding or termination liabilities that may be imposed on us and our subsidiaries or our assets as a result ofTable of Contentsbeing a member of the Icahn controlled group. However, Starfire is not required to maintain a net worth equal to the amounts by which ACF and Federal-Mogul are underfunded, and there can be no guarantee Starfire will be able to fund its indemnification obligations to us.Exhibit Title 31.110.1**Amendment to Second Amended and Restated Services Agreement, dated February 17, 2014, by and among CVR Partners, LP, CVR GP, LLC and CVR Energy, Inc.10.2* Amendment to Services Agreement, dated February 17, 2014, by and among CVR Refining, LP, CVR Refining GP, LLC and CVR Energy, Inc. 31.1* Company'sCompany’s Chief Executive Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act. 31.2* 31.2*Company'sCompany’s Chief Financial Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act. 32.1* 32.1*Company'sCompany’s Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2* 32.2*Company'sCompany’s Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 101* 101*'s’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013,March 31, 2014, filed with the SEC on AugustMay 2, 2013,2014, formatted in XBRL ("(“Extensible Business Reporting Language"Language”) includes: (1) Condensed Consolidated Balance Sheets (unaudited), (2) Condensed Consolidated Statements of Operations (unaudited), (3) Condensed Consolidated Statements of Comprehensive Income (Loss) (unaudited), (4) Condensed Consolidated Statement of Changes in Equity (unaudited), (5) Condensed Consolidated Statements of Cash Flows (unaudited) and (6) the Notes to Condensed Consolidated Financial Statements (unaudited), tagged in detail.* *Filed herewith. *Filed herewith.**Users of this data are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and is otherwise not subject to liability under these sections.Securities and Exchange Commission,SEC, we have filedmay file or incorporatedincorporate by reference the agreements referenced above as exhibits to this quarterly report on Form 10-Q.the reports that we file with or furnish to the SEC. The agreements have beenare filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about the Company or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in the Company'sCompany’s public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about the Company or its business or operations on the date hereof.May 2, 2014 CVR Energy, Inc.August 2, 2013By:By:
/s/ JOHN J. LIPINSKIChief Executive Officer (Principal Executive Officer) AugustMay 2, 20132014
By:
/s/ SUSAN M. BALLChief Financial Officer (Principal Financial and Accounting Officer)