10-Q 1 cviq12016form10-q.htm 10-Q
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q

(Mark One)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2016
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to

Commission file number: 001-33492
CVR ENERGY, INC.
(Exact name of registrant as specified in its charter)

Delaware | 61-1512186
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.)
2277 Plaza Drive, Suite 500 |
Sugar Land, Texas (Address of principal executive offices) | 77479 (Zip Code)

(281) 207-3200
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ |  | Accelerated filer o |  | Non-accelerated filer o |  | Smaller reporting company o
|  |  |  | (Do not check if smaller reporting company.) |  |

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act). Yes o No þ
There were 86,831,050 shares of the registrant's common stock outstanding at April 26, 2016.

CVR ENERGY, INC. AND SUBSIDIARIES
INDEX TO QUARTERLY REPORT ON FORM 10-Q
For The Quarter Ended March 31, 2016

|  | Page No.
Part I. Financial Information |
Item 1. | Financial Statements | 6
| Condensed Consolidated Balance Sheets - March 31, 2016 (unaudited) and December 31, 2015 | 6
| Condensed Consolidated Statements of Operations - Three Months Ended March 31, 2016 and 2015 (unaudited) | 7
| Condensed Consolidated Statements of Comprehensive Income (Loss) - Three Months Ended March 31, 2016 and 2015 (unaudited) | 8
| Condensed Consolidated Statement of Changes in Equity - Three Months Ended March 31, 2016 (unaudited) | 9
| Condensed Consolidated Statements of Cash Flows - Three Months Ended March 31, 2016 and 2015 (unaudited) | 10
| Notes to the Condensed Consolidated Financial Statements - March 31, 2016 (unaudited) | 11
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 36
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 68
Item 4. | Controls and Procedures | 69
Part II. Other Information |
Item 1. | Legal Proceedings | 70
Item 1A. | Risk Factors | 70
Item 6. | Exhibits | 82
Signatures | 83

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GLOSSARY OF SELECTED TERMS
The following are definitions of certain terms used in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2016 (this "Report").
2-1-1 crack spread — The approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate. The 2-1-1 crack spread is expressed in dollars per barrel.
ammonia — Ammonia is a direct application fertilizer and is primarily used as a building block for other nitrogen products for industrial applications and finished fertilizer products.
barrel — Common unit of measure in the oil industry which equates to 42 gallons.
blendstocks — Various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel fuel; these may include natural gasoline, fluid catalytic cracking unit or FCCU gasoline, ethanol, reformate or butane, among others.
bpd — Abbreviation for barrels per day.
bpcd — Abbreviation for barrels per calendar day, which refers to the total number of barrels processed in a refinery within a year, divided by 365 days, thus reflecting all operational and logistical limitations.
bulk sales — Volume sales through third-party pipelines, in contrast to tanker truck quantity rack sales.
capacity — Capacity is defined as the throughput a process unit is capable of sustaining, either on a barrel per calendar or stream day basis. The throughput may be expressed in terms of maximum sustainable, nameplate or economic capacity. The maximum sustainable or nameplate capacities may not be the most economical. The economic capacity is the throughput that generally provides the greatest economic benefit based on considerations such as crude oil and other feedstock costs, product values and downstream unit constraints.
catalyst — A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process.
corn belt — The primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio and Wisconsin.
crack spread — A simplified calculation that measures the difference between the price for light products and crude oil. For example, the 2-1-1 crack spread is often referenced and represents the approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate.
distillates — Primarily diesel fuel, kerosene and jet fuel.
ethanol — A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate.
farm belt — Refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin.
feedstocks — Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products, such as gasoline, diesel fuel and jet fuel, during the refining process.
Group 3 — 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's Coffeyville and Wynnewood refineries; the Valero Ardmore refinery in Ardmore, OK; HollyFrontier's Tulsa refinery in Tulsa, OK and El Dorado refinery in El Dorado, KS; Phillips 66's Ponca City refinery in Ponca City, OK; and CHS Inc.'s refinery in McPherson, KS.
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.
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independent petroleum refiner — A refiner that does not have crude oil exploration or production operations. An independent refiner purchases the crude oil throughputs in its refinery operations from third parties.
light crude oil — A relatively expensive crude oil characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel fuel.
Magellan — Magellan Midstream Partners L.P., a publicly traded company, whose business is the transportation, storage and distribution of refined petroleum products.
MMBtu — One million British thermal units or Btu: a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree Fahrenheit.
MSCF — One thousand standard cubic feet, a customary gas measurement unit.
natural gas liquids — Natural gas liquids, often referred to as NGLs, are both feedstocks used in the manufacture of refined fuels, as well as products of the refining process. Common NGLs used include propane, isobutane, normal butane and natural gasoline.
PADD II — Midwest Petroleum Area for Defense District which includes Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee and Wisconsin.
petroleum coke (pet coke) — A coal-like substance that is produced during the refining process.
product pricing at gate — Product pricing at gate represents net sales less freight revenue divided by product sales volume in tons. Product pricing at gate is also referred to as netback.
rack sales — Sales which are made at terminals into third-party tanker trucks.
refined products — Petroleum products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery.
Refining Partnership IPO — The initial public offering of 27,600,000 common units representing limited partner interests of CVR Refining, LP (the "Refining Partnership"), which closed on January 23, 2013 (which includes the underwriters' subsequently exercised option to purchase additional common units).
Second Underwritten Offering — The second underwritten offering of 7,475,000 common units of the Refining Partnership, which closed on June 30, 2014 (which includes the underwriters' subsequently exercised option to purchase additional common units).
sour crude oil — A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.
spot market — A market in which commodities are bought and sold for cash and delivered immediately.
sweet crude oil — A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil.
throughput — The volume processed through a unit or a refinery or transported on a pipeline.
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.
UAN — An aqueous solution of urea and ammonium nitrate used as a fertilizer.
Underwritten Offering — The underwritten offering of 13,209,236 common units of the Refining Partnership, which closed on May 20, 2013 (which includes the underwriters' subsequently exercised option to purchase additional common units).
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WCS — Western Canadian Select crude oil, a medium to heavy, sour crude oil, characterized by an American Petroleum Institute gravity ("API gravity") of between 20 and 22 degrees and a sulfur content of approximately 3.3 weight percent.
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.
WTS — West Texas Sour crude oil, a relatively light, sour crude oil, characterized by an API gravity of between 30 and 32 degrees and a sulfur content of approximately 2.0 weight percent.
yield — The percentage of refined products that is produced from crude oil and other feedstocks.
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CVR ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS

| March 31, 2016 |  | December 31, 2015
| (unaudited) |  |
| (in millions, except share data)
ASSETS
Current assets: |  |  |
Cash and cash equivalents (including $197.9 and $237.3, respectively, of consolidated variable interest entities ("VIEs")) | $ | 681.8 |  |  | $ | 765.1 |
Accounts receivable of VIEs, net of allowance for doubtful accounts of $0.5 and $0.3, respectively | 109.7 |  |  | 95.8 |
Inventories of VIEs | 259.4 |  |  | 289.9 |
Prepaid expenses and other current assets (including $76.2 and $101.2, respectively, of VIEs) | 84.3 |  |  | 104.3 |
Income tax receivable | 6.9 |  |  | 6.9 |
Due from parent | 11.6 |  |  | 11.6 |
Total current assets | 1,153.7 |  |  | 1,273.6 |
Property, plant and equipment, net of accumulated depreciation (including $1,947.4 and $1,942.6, respectively, of VIEs) | 1,972.4 |  |  | 1,967.1 |
Intangible assets of VIEs, net | 0.2 |  |  | 0.2 |
Goodwill of VIEs | 41.0 |  |  | 41.0 |
Other long-term assets (including $12.4 and $13.0, respectively, of VIEs) | 16.2 |  |  | 17.5 |
Total assets | $ | 3,183.5 |  |  | $ | 3,299.4 |
LIABILITIES AND EQUITY
Current liabilities: |  |  |
Note payable and capital lease obligations of VIEs | $ | 1.7 |  |  | $ | 1.6 |
Current portion of long-term debt of VIEs | 125.0 |  |  | 124.8 |
Accounts payable (including $246.1 and $258.0, respectively, of VIEs) | 249.6 |  |  | 261.5 |
Personnel accruals (including $11.9 and $21.7, respectively, of VIEs) | 23.7 |  |  | 45.7 |
Accrued taxes other than income taxes of VIEs | 26.3 |  |  | 23.5 |
Deferred revenue of VIEs | 0.8 |  |  | 3.1 |
Other current liabilities (including $46.7 and $23.9, respectively, of VIEs) | 47.1 |  |  | 24.4 |
Total current liabilities | 474.2 |  |  | 484.6 |
Long-term liabilities: |  |  |
Long-term debt and capital lease obligations of VIEs, net of current portion | 540.4 |  |  | 540.7 |
Deferred income taxes (including $0.1 and $0.1, respectively, of VIEs) | 624.3 |  |  | 639.7 |
Other long-term liabilities (including $3.1 and $3.1, respectively, of VIEs) | 27.6 |  |  | 33.9 |
Total long-term liabilities | 1,192.3 |  |  | 1,214.3 |
Commitments and contingencies |  |  |
Equity: |  |  |
CVR stockholders' equity: |  |  |
Common stock $0.01 par value per share, 350,000,000 shares authorized, 86,929,660 shares issued | 0.9 |  |  | 0.9 |
Additional paid-in-capital | 1,174.7 |  |  | 1,174.7 |
Retained deficit | (248.8 | ) |  | (189.2 | )
Treasury stock, 98,610 shares at cost | (2.3 | ) |  | (2.3 | )
Total CVR stockholders' equity | 924.5 |  |  | 984.1 |
Noncontrolling interest | 592.5 |  |  | 616.4 |
Total equity | 1,517.0 |  |  | 1,600.5 |
Total liabilities and equity | $ | 3,183.5 |  |  | $ | 3,299.4 |

See accompanying notes to the condensed consolidated financial statements.
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CVR ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

| Three Months Ended March 31,
| 2016 |  | 2015
| (unaudited)
| (in millions, except per share data)
Net sales | $ | 905.5 |  |  | $ | 1,388.9 |
Operating costs and expenses: |  |  |
Cost of product sold (exclusive of depreciation and amortization) | 736.8 |  |  | 1,073.6 |
Direct operating expenses (exclusive of depreciation and amortization) | 141.4 |  |  | 111.4 |
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 27.2 |  |  | 25.3 |
Depreciation and amortization | 40.0 |  |  | 42.0 |
Total operating costs and expenses | 945.4 |  |  | 1,252.3 |
Operating income (loss) | (39.9 | ) |  | 136.6 |
Other income (expense): |  |  |
Interest expense and other financing costs | (12.1 | ) |  | (12.7 | )
Interest income | 0.2 |  |  | 0.2 |
Loss on derivatives, net | (1.2 | ) |  | (51.4 | )
Other income, net | 0.3 |  |  | 36.0 |
Total other expense | (12.8 | ) |  | (27.9 | )
Income (loss) before income taxes | (52.7 | ) |  | 108.7 |
Income tax expense (benefit) | (21.8 | ) |  | 24.0 |
Net income (loss) | (30.9 | ) |  | 84.7 |
Less: Net income (loss) attributable to noncontrolling interest | (14.7 | ) |  | 29.8 |
Net income (loss) attributable to CVR Energy stockholders | $ | (16.2 | ) |  | $ | 54.9 |
Basic earnings (loss) per share | $ | (0.19 | ) |  | $ | 0.63 |
Diluted earnings (loss) per share | $ | (0.19 | ) |  | $ | 0.63 |
Dividends declared per share | $ | 0.50 |  |  | $ | 0.50 |
Weighted-average common shares outstanding: |  |  |
Basic | 86.8 |  |  | 86.8 |
Diluted | 86.8 |  |  | 86.8 |

See accompanying notes to the condensed consolidated financial statements.
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CVR ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

| Three Months Ended March 31,
| 2016 |  | 2015
| (unaudited)
| (in millions)
Net income (loss) | $ | (30.9 | ) |  | $ | 84.7 |
Other comprehensive income (loss): |  |  |
Unrealized gain on available-for-sale securities, net of tax of $0 and $12.6, respectively | — |  |  | 19.2 |
Net gain reclassified into income on sale of available-for-sale securities, net of tax of $0 and ($8.0), respectively (Note 11) | — |  |  | (12.1 | )
Net gain reclassified into income on reclassification of available-for-sale securities to trading securities, net of tax of $0 and ($4.6), respectively (Note 11) | — |  |  | (7.1 | )
Change in fair value of interest rate swaps, net of tax of $0 and $0, respectively | — |  |  | (0.1 | )
Net loss reclassified into income on settlement of interest rate swaps, net of tax of $0 and $0.1, respectively (Note 12) | — |  |  | 0.2 |
Total other comprehensive income | — |  |  | 0.1 |
Comprehensive income (loss) | (30.9 | ) |  | 84.8 |
Less: Comprehensive income (loss) attributable to noncontrolling interest | (14.7 | ) |  | 29.9 |
Comprehensive income (loss) attributable to CVR Energy stockholders | $ | (16.2 | ) |  | $ | 54.9 |

See accompanying notes to the condensed consolidated financial statements.
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CVR ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

| Common Stockholders |  |  |  |
| Shares Issued |  | $0.01 Par Value Common Stock |  | Additional Paid-In Capital |  | Retained Deficit |  | Treasury Stock |  | Total CVR Stockholders' Equity |  | Noncontrolling Interest |  | Total Equity
| (unaudited)
| (in millions, except share data)
Balance at December 31, 2015 | 86,929,660 |  |  | $ | 0.9 |  |  | $ | 1,174.7 |  |  | $ | (189.2 | ) |  | $ | (2.3 | ) |  | $ | 984.1 |  |  | $ | 616.4 |  |  | $ | 1,600.5 |
Dividends paid to CVR Energy stockholders | — |  |  | — |  |  | — |  |  | (43.4 | ) |  | — |  |  | (43.4 | ) |  |  |  |  | (43.4 | )
Distributions from CVR Partners to public unitholders | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (9.2 | ) |  | (9.2 | )
Net loss | — |  |  | — |  |  | — |  |  | (16.2 | ) |  | — |  |  | (16.2 | ) |  | (14.7 | ) |  | (30.9 | )
Balance at March 31, 2016 | 86,929,660 |  |  | $ | 0.9 |  |  | $ | 1,174.7 |  |  | $ | (248.8 | ) |  | $ | (2.3 | ) |  | $ | 924.5 |  |  | $ | 592.5 |  |  | $ | 1,517.0 |

See accompanying notes to the condensed consolidated financial statements.
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CVR ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

| Three Months Ended March 31,
| 2016 |  | 2015
| (unaudited)
| (in millions)
Cash flows from operating activities: |  |  |
Net income (loss) | $ | (30.9 | ) |  | $ | 84.7 |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: |  |  |
Depreciation and amortization | 40.0 |  |  | 42.0 |
Allowance for doubtful accounts | 0.3 |  |  | — |
Amortization of deferred financing costs | 0.7 |  |  | 0.7 |
Deferred income taxes benefits | (21.8 | ) |  | (14.1 | )
Loss on disposition of assets | — |  |  | 0.8 |
Share-based compensation | 1.8 |  |  | 4.0 |
Gain on sale of available-for-sale securities | — |  |  | (20.1 | )
Unrealized gain on securities | (0.3 | ) |  | — |
Loss on derivatives, net | 1.2 |  |  | 51.4 |
Current period settlements on derivative contracts | 21.4 |  |  | (6.3 | )
Changes in assets and liabilities: |  |  |
Accounts receivable | (14.2 | ) |  | — |
Inventories | 30.5 |  |  | 18.2 |
Prepaid expenses and other current assets | 1.9 |  |  | (5.0 | )
Due from parent | — |  |  | 35.5 |
Accounts payable | (8.5 | ) |  | (3.8 | )
Accrued income taxes | — |  |  | 2.6 |
Deferred revenue | (2.3 | ) |  | (7.3 | )
Other current liabilities | 1.9 |  |  | (4.9 | )
Other long-term liabilities | (0.1 | ) |  | (0.2 | )
Net cash provided by operating activities | 21.6 |  |  | 178.2 |
Cash flows from investing activities: |  |  |
Capital expenditures | (47.5 | ) |  | (45.5 | )
Purchase of securities | (4.2 | ) |  | — |
Proceeds from sale of available-for-sale securities | — |  |  | 42.1 |
Net cash used in investing activities | (51.7 | ) |  | (3.4 | )
Cash flows from financing activities: |  |  |
Payment of capital lease obligations | (0.4 | ) |  | (0.3 | )
Payment of deferred financing costs | (0.2 | ) |  | — |
Dividends to CVR Energy's stockholders | (43.4 | ) |  | (43.4 | )
Distributions to CVR Refining's noncontrolling interest holders | — |  |  | (18.6 | )
Distributions to CVR Partners' noncontrolling interest holders | (9.2 | ) |  | (14.0 | )
Net cash used in financing activities | (53.2 | ) |  | (76.3 | )
Net increase (decrease) in cash and cash equivalents | (83.3 | ) |  | 98.5 |
Cash and cash equivalents, beginning of period | 765.1 |  |  | 753.7 |
Cash and cash equivalents, end of period | $ | 681.8 |  |  | $ | 852.2 |
Supplemental disclosures: |
Cash paid for interest net of capitalized interest of $1.5 and $0.4 in 2016 and 2015, respectively | $ | 3.4 |  |  | $ | 3.9 |
Non-cash investing and financing activities: |  |  |
Construction in process additions included in accounts payable | $ | 18.9 |  |  | $ | 15.0 |
Change in accounts payable related to construction in process additions | $ | (3.4 | ) |  | $ | (6.6 | )
Receivable for sale of available-for-sale securities included in prepaid expenses and other current assets | $ | — |  |  | $ | 25.9 |
Investment in available-for-sale securities reclassified to trading securities | $ | — |  |  | $ | 37.4 |

See accompanying notes to the condensed consolidated financial statements.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2016
(unaudited)
(1) Organization and History of the Company and Basis of Presentation
Organization
The "Company," "CVR Energy" or "CVR" are used in this Report to refer to CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries.
CVR is a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries through its holdings in CVR Refining, LP ("CVR Refining" or the "Refining Partnership") and CVR Partners, LP ("CVR Partners" or the "Nitrogen Fertilizer Partnership"). The Refining Partnership is an independent petroleum refiner and marketer of high value transportation fuels. The Nitrogen Fertilizer Partnership produces and markets nitrogen fertilizers in the form of UAN and 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 common stock is listed on the NYSE under the symbol "CVI." On May 7, 2012, an affiliate of Icahn Enterprises L.P. ("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"). As of March 31, 2016, IEP and its affiliates owned approximately 82% of the Company's outstanding shares.
CVR Partners, LP
On April 13, 2011, the Nitrogen Fertilizer Partnership completed the initial public offering of its common units representing limited partnership interests (the "Nitrogen Fertilizer Partnership IPO"). The common units, which are listed on the NYSE, began trading on April 8, 2011 under the symbol "UAN." In connection with the Nitrogen Fertilizer Partnership IPO and through May 27, 2013, the Company recorded a 30% noncontrolling interest for the common units sold into the public market. On May 28, 2013, Coffeyville Resources, LLC ("CRLLC"), a wholly-owned subsidiary of the Company, completed a registered public offering whereby it sold 12,000,000 Nitrogen Fertilizer Partnership common units to the public (the "Secondary Offering").
Immediately subsequent to the closing of the Secondary Offering and as of March 31, 2016, public security holders held approximately 47% of the outstanding Nitrogen Fertilizer Partnership common units, and CRLLC held approximately 53% of the outstanding Nitrogen Fertilizer Partnership common units. In addition, CRLLC owns 100% of the Nitrogen Fertilizer 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.
The Nitrogen Fertilizer Partnership has adopted a policy pursuant to which the Nitrogen Fertilizer Partnership will distribute all of the available cash it generates each quarter. The available cash for each quarter will be determined by the board of directors of the Nitrogen Fertilizer Partnership'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.
The Nitrogen Fertilizer Partnership is operated by CVR'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's general partner 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 Nitrogen Fertilizer Partnership's 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.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
On August 9, 2015, CVR Partners entered into an Agreement and Plan of Merger (the "Merger Agreement") with Rentech Nitrogen Partners, L.P., now known as East Dubuque Nitrogen Partners, L.P. ("East Dubuque"), and Rentech Nitrogen GP, LLC, now know as East Dubuque Nitrogen GP, LLC ("East Dubuque GP"), pursuant to which CVR Partners would acquire East Dubuque and East Dubuque GP by merging two newly-created direct wholly-owned subsidiaries of CVR Partners with and into those entities with East Dubuque and East Dubuque GP continuing as surviving entities and subsidiaries of CVR Partners (together, the "mergers"). On April 1, 2016, CVR Partners completed the previously announced transactions contemplated by the Merger Agreement. In accordance with the Financial Accounting Standards Board’s Accounting Standards Codification ("ASC") Topic 805 — Business Combinations, the Nitrogen Fertilizer Partnership will account for the mergers as an acquisition of a business with CVR Partners as the acquirer. Immediately subsequent to the mergers, CRLLC held approximately 34% of the Nitrogen Fertilizer Partnership's outstanding common units and 100% of the Nitrogen Fertilizer Partnership's general partner. Refer to Note 15 ("Subsequent Events") of this Report for further discussion of the mergers.
CVR Refining, LP
On January 23, 2013, the Refining Partnership completed the initial public offering of its common units representing limited partner interests. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR." On May 20, 2013, the Refining Partnership completed an underwritten offering (the "Underwritten Offering") by selling additional common units to the public. In connection with the Underwritten Offering, American Entertainment Properties Corporation ("AEPC"), an affiliate of IEP, also purchased common units in a privately negotiated transaction with a subsidiary of CVR, which was completed on May 29, 2013.
On June 30, 2014, the Refining Partnership completed a second underwritten offering (the "Second Underwritten Offering"). Additionally, on July 24, 2014, the Refining Partnership sold additional common units to the public in connection with the underwriters' exercise of their option to purchase additional common units.
Immediately subsequent to the closing of the underwriters' option for the Second Underwritten Offering and as of March 31, 2016, public security holders held approximately 34% of the Refining Partnership's outstanding common units (including common units owned by affiliates of IEP, representing approximately 4% of the Refining Partnership's outstanding common units), and CVR Refining Holdings, LLC (“CVR Refining Holdings”) held approximately 66% of the Refining Partnership's outstanding common units. In addition, CVR Refining Holdings owns 100% of the Refining Partnership’s general partner, CVR Refining GP, LLC ("CVR Refining GP"), 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 Refining Partnership.
The Refining Partnership has adopted a policy pursuant to which it will distribute all of the available cash it generates each quarter. The available cash for each quarter will be determined by the board of directors of the Refining Partnership'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.
The Refining Partnership is party to a services agreement pursuant to which the Refining Partnership and its general partner obtain certain management and other services from CVR Energy. The Refining Partnership's general partner manages the Refining Partnership's activities subject to the terms and conditions specified in the Refining Partnership's partnership agreement.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'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's general partner are not elected by the Refining Partnership's 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 Refining Partnership.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
Basis of Presentation
The accompanying condensed consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles ("GAAP") and in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC"). The condensed consolidated financial statements include the accounts of CVR and its direct and indirect subsidiaries including the Nitrogen Fertilizer Partnership, the Refining Partnership and their respective subsidiaries, as discussed further below. The ownership interests of noncontrolling investors in CVR'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, 2015 audited consolidated financial statements and notes thereto included in CVR's Annual Report on Form 10-K for the year ended December 31, 2015, which was filed with the SEC on February 19, 2016 (the "2015 Form 10-K").
The Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (“ASU”) 2015-02, "Consolidations (Topic 810) - Amendments to the Consolidation Analysis" (“ASU 2015-02”), which amended previous consolidation guidance, including introducing a separate consolidation analysis specific to limited partnerships and other similar entities. Under this analysis, limited partnerships and other similar entities are considered a variable interest entity (“VIE”) unless the limited partners hold substantive kick-out rights or participating rights. Management has determined that the Refining Partnership and the Nitrogen Fertilizer Partnership are VIEs because the limited partners of CVR Refining and CVR Partners lack both substantive kick-out rights and participating rights. As such, management evaluated the qualitative criteria under FASB ASC Topic 810 - Consolidation in conjunction with ASU 2015-02 to make a determination whether the Refining Partnership and the Nitrogen Fertilizer Partnership should be consolidated on the Company's financial statements. ASC Topic 810-10 requires the primary beneficiary of a variable interest entity's activities to consolidate the VIE. The primary beneficiary is identified as the enterprise that has a) the power to direct the activities of the VIE that most significantly impact the entity's economic performance and b) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. The standard requires an ongoing analysis to determine whether the variable interest gives rise to a controlling financial interest in the VIE. Based upon the general partner’s roles and rights as afforded by the partnership agreements and its exposure to losses and benefits of each of the partnerships through its significant limited partner interests, intercompany credit facilities, and services agreements, CVR determined that it is the primary beneficiary of both the Refining Partnership and the Nitrogen Fertilizer Partnership. Based upon that evaluation, the consolidated financial statements of CVR continue to consolidate both the Refining and Nitrogen Fertilizer Partnerships.
In the opinion of the Company'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 March 31, 2016 and December 31, 2015, the results of operations and comprehensive income for the three month periods ended March 31, 2016 and 2015, changes in equity for the three month period ended March 31, 2016 and cash flows of the Company for the three month periods ended March 31, 2016 and 2015.
The preparation of the condensed 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. 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 December 31, 2016 or any other interim or annual period.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
(2) Recent Accounting Pronouncements
In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The standard was originally effective for interim and annual periods beginning after December 15, 2016 and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. On July 9, 2015, the FASB approved a one-year deferral of the effective date making the standard effective for interim and annual periods beginning after December 15, 2017. The FASB will continue to permit entities to adopt the standard on the original effective date if they choose. The Company has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.
In February 2015, the FASB issued ASU No. 2015-02, "Consolidations (Topic 810) - Amendments to the Consolidation Analysis" ("ASU 2015-02"), which amended previous consolidation guidance, including introducing a separate consolidation analysis specific to limited partnerships and other similar entities. Under this analysis, limited partnerships and other similar entities will be considered a VIE unless the limited partners hold substantive kick-out rights or participating rights. The standard is effective for interim and annual periods beginning after December 15, 2015. The Company adopted ASU 2015-02 as of January 1, 2016. Refer to Note 1 ("Organization and History of the Company and Basis of Presentation") for more information.
In April 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs" ("ASU 2015-03"). The new standard requires that all costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. The standard is effective for interim and annual periods beginning after December 15, 2015 and is required to be applied on a retrospective basis. Early adoption is permitted. The Company adopted ASU 2015-03 as of January 1, 2016 and applied the standard retrospectively to the Condensed Consolidated Balance Sheet. Refer to Note 8 ("Long-Term Debt") for further details.
In February 2016, the FASB issued ASU 2016-02, “Leases” (“ASU 2016-02”). The new standard revises accounting for operating leases by a lessee, among other changes, and requires a lessee to recognize a liability to make lease payments and an asset representing its right to use the underlying asset for the lease term in the balance sheet. The standard is effective for the first interim and annual periods beginning after December 15, 2018, with early adoption permitted. At adoption, ASU 2016-02 will be applied using a modified retrospective approach. The Company is currently evaluating the standard and the impact on its consolidated financial statements and footnotes disclosures.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
(3) Share-Based Compensation
Long-Term Incentive Plan – CVR Energy
CVR has a Long-Term Incentive Plan ("LTIP"), which permits the grant of options, stock appreciation rights, restricted 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 March 31, 2016, only performance units and an immaterial amount of restricted stock units remain outstanding under the LTIP. Individuals who are eligible to receive awards and grants under the LTIP include the Company's or its subsidiaries' employees, officers, consultants, advisors and directors. The LTIP authorized a share pool of 7,500,000 shares of the Company's common stock, 1,000,000 of which may be issued in respect of incentive stock options.
Performance Unit Awards
In December 2015, the Company entered into a performance unit award agreement (the "2015 Performance Unit Award Agreement") with its Chief Executive Officer. Compensation cost for the 2015 Performance Unit Award Agreement will be recognized over the performance cycle from January 1, 2016 to December 31, 2016. The performance unit award represents the right to receive, upon vesting, a cash payment equal to a defined threshold in accordance with the award agreement, multiplied by a performance factor that is based upon the achievement of certain operating objectives. Total compensation expense for the three months ended March 31, 2016 related to the performance unit award was approximately $0.9 million. As of March 31, 2016, the Company had a liability of $0.9 million for non-vested performance unit awards, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheet.
Long-Term Incentive Plan – CVR Partners
Phantom Units
CVR Partners has a long-term incentive plan ("CVR Partners LTIP") that provides for the grant of options, unit appreciation rights, distribution equivalent rights, restricted units, phantom units and other unit-based awards. The maximum number of common units issuable under the CVR Partners LTIP is 5,000,000. Individuals who are eligible to receive awards under the CVR Partners LTIP include (i) employees of the Nitrogen Fertilizer Partnership and its subsidiaries, (ii) employees of its general partner, (iii) members of the board of directors of its general partner and (iv) employees, consultants and directors of CVR Energy.
Through the CVR Partners LTIP, awards of phantom units and distribution equivalent rights have been granted to employees of the Nitrogen Fertilizer Partnership and its subsidiaries and its general partner. These awards are generally graded-vesting awards, which are expected to vest over three years with one-third of the award vesting each year. Compensation expense is recognized on a straight-line basis over the vesting period of the respective tranche of the award. Each phantom unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (i) the average fair market value of one unit of the Nitrogen Fertilizer Partnership's common units in accordance with the award agreement, plus (ii) the per unit cash value of all distributions declared and paid by the Nitrogen Fertilizer Partnership from the grant date to and including the vesting date. The awards, which are liability-classified, are remeasured at each subsequent reporting date until they vest.
A summary of the phantom unit activity and changes under the CVR Partners LTIP during the three months ended March 31, 2016 is presented below:

| Phantom Units |  | Weighted-Average Grant-Date Fair Value
Non-vested at January 1, 2016 | 391,903 |  |  | $ | 8.71 |
Granted | 3,475 |  |  | 7.77 |
Vested | — |  |  | — |
Forfeited | — |  |  | — |
Non-vested at March 31, 2016 | 395,378 |  |  | $ | 8.70 |

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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
As of March 31, 2016, there was approximately $2.5 million of total unrecognized compensation cost related to the awards under the CVR Partners LTIP to be recognized over a weighted-average period of 1.5 years. Total compensation expense recorded for the three months ended March 31, 2016 and 2015 related to the awards under the CVR Partners LTIP was approximately $0.5 million and $0.6 million, respectively.
As of March 31, 2016 and December 31, 2015, the Nitrogen Fertilizer Partnership had a liability of $1.2 million and $0.7 million, respectively, for cash settled non-vested phantom unit awards and associated distribution equivalent rights, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.
Performance-Based Phantom Units
In May 2014, the Nitrogen Fertilizer Partnership entered into a Phantom Unit Agreement with the Chief Executive Officer and President of its general partner that included performance-based phantom units and distribution equivalent rights. Compensation cost is being recognized over the annual performance cycles, as the services are provided. Each phantom unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (i) the average closing price of the Nitrogen Fertilizer Partnership's common units in accordance with the award agreement, multiplied by a performance factor that is based upon the level of the Nitrogen Fertilizer Partnership's production of UAN, and (ii) the per unit cash value of all distributions declared and paid by the Nitrogen Fertilizer Partnership from the grant date to and including the vesting date. Total compensation expense recorded for the three months ended March 31, 2016 and 2015 related to the award was nominal. Based on current estimates of performance thresholds for the remaining 2016 performance cycle, unrecognized compensation expense and the liability associated with the unvested phantom units at March 31, 2016 were also nominal.
Long-Term Incentive Plan – CVR Refining
CVR Refining has a long-term incentive plan ("CVR Refining LTIP") that 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. The maximum number of common units issuable under the CVR Refining LTIP is 11,070,000. Individuals who are eligible to receive awards under the CVR Refining LTIP include (i) employees of the Refining Partnership and its subsidiaries, (ii) employees of the general partner, (iii) members of the board of directors of the general partner and (iv) certain employees, consultants and directors of CRLLC and CVR Energy who perform services for the benefit of the Refining Partnership.
Awards of phantom units and distribution equivalent rights have been granted to employees of the Refining Partnership and its subsidiaries, its general partner and certain employees of CRLLC and CVR Energy who perform services solely for the benefit of the Refining Partnership. The awards are generally graded-vesting awards, which are expected to vest over three years with one-third of the awards vesting each year. Compensation expense is recognized on a straight-line basis over the vesting period of the respective tranche of the award. Each phantom unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (i) the average fair-market value of one unit of the Refining Partnership's common units in accordance with the award agreement, plus (ii) the per unit cash value of all distributions declared and paid by the Refining Partnership from the grant date to and including the vesting date. The awards, which are liability-classified, are remeasured at each subsequent reporting date until they vest.
A summary of phantom unit activity and changes under the CVR Refining LTIP during the three months ended March 31, 2016 is presented below:

| Units |  | Weighted-Average Grant-Date Fair Value
Non-vested at January 1, 2016 | 511,591 |  |  | $ | 19.68 |
Granted | — |  |  | — |
Vested | — |  |  | — |
Forfeited | (6,911 | ) |  | 19.51 |
Non-vested at March 31, 2016 | 504,680 |  |  | $ | 19.69 |

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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
As of March 31, 2016, there was approximately $4.4 million of total unrecognized compensation cost related to the awards under the CVR Refining LTIP to be recognized over a weighted-average period of 1.5 years. Total compensation expense recorded for the three months ended March 31, 2016 and 2015 related to the awards under the CVR Refining LTIP was approximately $0.3 million and $1.4 million, respectively.
As of March 31, 2016 and December 31, 2015, the Refining Partnership had a liability of approximately $2.5 million and $2.3 million, respectively, for non-vested phantom unit awards and associated distribution equivalent rights, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.
In December 2014, the Company granted an award of 227,927 incentive units in the form of stock appreciation rights ("SARs") to an executive of CVR Energy. In April 2015, the award granted was canceled and replaced by an award of notional units in the form of SARs by CVR Refining pursuant to the CVR Refining LTIP. The replacement award is structured on the same economic and other terms as the incentive unit award and did not result in a material impact. Each SAR vests over three years and entitles the executive to receive a cash payment in an amount equal to the excess of the fair market value of one unit of the Refining Partnership's common units for the first ten trading days in the month prior to vesting over the grant price of the SAR. The fair value will be adjusted to include all distributions declared and paid by the Refining Partnership during the vesting period. The fair value of each SAR is estimated at the end of each reporting period using the Black-Scholes option-pricing model. Assumptions utilized to value the award have been omitted due to immateriality of the award. Total compensation expense during the three months ended March 31, 2016 and 2015 and the liability as of March 31, 2016 and December 31, 2015 were not material.
Incentive Unit Awards
The Company has granted awards of incentive units and distribution equivalent rights to certain employees of CRLLC, CVR Energy and CVR GP, LLC. The awards are generally graded vesting awards, which are expected to vest over three years with one-third of the award vesting each year. Compensation expense is recognized on a straight-line basis over the vesting period of the respective tranche of the award. Each incentive unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (i) the average fair market value of one unit of the Refining Partnership's common units in accordance with the award agreement, plus (ii) the per unit cash value of all distributions declared and paid by the Refining Partnership from the grant date to and including the vesting date. The awards, which are liability-classified, are remeasured at each subsequent reporting date until they vest.
A summary of incentive unit activity and changes during the three months ended March 31, 2016 is presented below:

| Incentive Units |  | Weighted-Average Grant-Date Fair Value
Non-vested at January 1, 2016 | 604,942 |  |  | $ | 19.64 |
Granted | 11,892 |  |  | 12.72 |
Vested | (884 | ) |  | 18.85 |
Forfeited | (21,281 | ) |  | 19.42 |
Non-vested at March 31, 2016 | 594,669 |  |  | $ | 19.51 |

As of March 31, 2016, there was approximately $5.2 million of total unrecognized compensation cost related to incentive unit awards to be recognized over a weighted-average period of approximately 1.5 years. Total compensation expense for the three months ended March 31, 2016 and 2015 related to the awards was approximately $0.3 million and $1.5 million, respectively.
As of March 31, 2016 and December 31, 2015, the Company had a liability of approximately $2.9 million and $2.6 million, respectively, for non-vested incentive units and associated distribution equivalent rights, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
(4) Inventories
Inventories consist primarily of domestic and foreign crude oil, blending stock and components, work-in-progress, fertilizer products, and refined fuels and by-products. For all periods presented, inventories are valued at the lower of the first-in, first-out ("FIFO") cost or market for fertilizer products, refined fuels and 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.
Inventories consisted of the following:

| March 31, 2016 |  | December 31, 2015
| (in millions)
Finished goods | $ | 95.8 |  |  | $ | 114.5 |
Raw materials and precious metals | 83.1 |  |  | 81.2 |
In-process inventories | 21.2 |  |  | 35.8 |
Parts and supplies | 59.3 |  |  | 58.4 |
Total Inventories | $ | 259.4 |  |  | $ | 289.9 |

(5) Property, Plant and Equipment
Property, plant and equipment consisted of the following:

| March 31, 2016 |  | December 31, 2015
| (in millions)
Land and improvements | $ | 38.8 |  |  | $ | 38.6 |
Buildings | 53.1 |  |  | 53.6 |
Machinery and equipment | 2,739.5 |  |  | 2,723.0 |
Automotive equipment | 24.7 |  |  | 24.8 |
Furniture and fixtures | 21.3 |  |  | 21.3 |
Leasehold improvements | 3.4 |  |  | 3.6 |
Aircraft | 3.6 |  |  | 3.6 |
Railcars | 16.3 |  |  | 16.3 |
Construction in progress | 150.2 |  |  | 122.3 |
| 3,050.9 |  |  | 3,007.1 |
Accumulated depreciation | 1,078.5 |  |  | 1,040.0 |
Total property, plant and equipment, net | $ | 1,972.4 |  |  | $ | 1,967.1 |

Capitalized interest recognized as a reduction in interest expense for the three months ended March 31, 2016 and 2015 totaled approximately $1.5 million and $0.4 million, respectively. Land, buildings and equipment that are under a capital lease obligation had an original carrying value of approximately $24.8 million at both March 31, 2016 and December 31, 2015. Amortization of assets held under capital leases is included in depreciation expense.
(6) Cost Classifications
Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks, purchased refined products, pet coke expenses, renewable identification numbers ("RINs") expenses and freight and distribution expenses. For the three months ended March 31, 2016 and 2015, cost of product sold excluded depreciation and amortization of approximately $1.7 million and $1.8 million, respectively.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, property taxes, environmental compliance costs, as well as chemicals and catalysts and other direct operating expenses. For the three months ended March 31, 2016 and 2015, direct operating expenses excluded depreciation and amortization of approximately $36.2 million and $38.5 million, respectively.
Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal expenses, treasury, accounting, marketing, human resources, information technology and maintaining the corporate and administrative offices in Texas and Kansas. For the three months ended March 31, 2016 and 2015, selling, general and administrative expenses excluded depreciation and amortization of approximately $2.1 million and $1.7 million, respectively.
(7) Income Taxes
On May 19, 2012, CVR became a member of the consolidated federal tax group of AEPC, a wholly-owned subsidiary of IEP, and subsequently entered into a tax allocation agreement with AEPC (the "Tax Allocation 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 March 31, 2016, the Company's Condensed Consolidated Balance Sheet reflected a receivable of $11.6 million for an overpayment of federal income taxes due to AEPC under the Tax Allocation Agreement. The overpayment will be applied as a credit against the Company's estimated tax. During the three months ended March 31, 2016 and 2015, no payments were made to AEPC under the Tax Allocation Agreement.
The Company recognizes liabilities, interest and penalties for potential tax issues based on its estimate of whether, and the extent to which, additional taxes may be due as determined under FASB ASC Topic 740 — Income Taxes. As of March 31, 2016, the Company had unrecognized tax benefits of approximately $44.1 million, of which $28.7 million, if recognized, would impact the Company’s effective tax rate. Approximately $25.9 million of unrecognized tax benefits were netted with deferred tax asset carryforwards. The remaining unrecognized tax benefits are included in other long-term liabilities in the Condensed Consolidated Balance Sheets. The Company has accrued interest of $6.0 million related to uncertain tax positions. The Company's accounting policy with respect to interest and penalties related to tax uncertainties is to classify these amounts as income taxes.
CVR and its subsidiaries file U.S. federal and various state income and franchise tax returns. At March 31, 2016, the Company's tax filings are generally open to examination in the United States for the tax years ended December 31, 2012 through December 31, 2015 and in various individual states for the tax years ended December 31, 2011 through December 31, 2015.
The Company's effective tax rate for the three months ended March 31, 2016 and 2015 was 41.4% and 22.1%, respectively, as compared to the Company's combined federal and state expected statutory tax rate of 39.5% and 39.6% for the three months ended March 31, 2016 and 2015, respectively. The Company's effective tax rate for the three months ended March 31, 2016 and 2015 varies from the statutory rate primarily due to the reduction of income (loss) subject to tax associated with the noncontrolling ownership interests of CVR Refining's and CVR Partners' earnings (loss), as well as benefits for domestic production activities and state income tax credits. The effective tax rate for the first quarter of 2016 is higher than the first quarter of 2015 due to the correlation between the amount of credits projected to be generated in each year in relative comparison with the projected pre-tax loss in the first quarter of 2016 and pre-tax income in the first quarter of 2015.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
(8) Long-Term Debt
Long-term debt consisted of the following:

| March 31, 2016 |  | December 31, 2015
| (in millions)
6.5% Senior Notes due 2022 | $ | 500.0 |  |  | $ | 500.0 |
CRNF credit facility | 125.0 |  |  | 125.0 |
Capital lease obligations | 48.1 |  |  | 48.5 |
Total debt | 673.1 |  |  | 673.5 |
Unamortized debt issuance cost | (6.0 | ) |  | (6.4 | )
Current portion of long-term debt and capital lease obligations | (126.7 | ) |  | (126.4 | )
Long-term debt, net of current portion | $ | 540.4 |  |  | $ | 540.7 |

During the first quarter of 2016, the Company adopted ASU 2015-03, which requires that costs incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. Prior to adoption of the ASU, all debt issuance costs were presented as assets. As a result of adoption of the standard, unamortized debt issuances costs of $6.0 million and $6.4 million were reclassified as a direct deduction from the carrying value of the related debt balances as of March 31, 2016 and December 31, 2015, respectively, in the Condensed Consolidated Balance Sheets (including $0.0 million and $0.2 million as a deduction from current portion of long-term debt and $6.0 million and $6.2 million as a deduction from long-term debt, respectively). Debt issuance costs related to the asset-based lending facilities continue to be presented as assets in the Condensed Consolidated Balance Sheets.
2022 Senior Notes
The Refining Partnership has $500.0 million aggregate principal amount of 6.5% Senior 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 and 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.
The 2022 Notes contain customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, the creation of liens on assets, the ability to dispose of assets, the ability to make certain payments on contractually subordinated debt, the ability to merge, consolidate with or into another entity and the ability to enter into certain affiliate transactions. The 2022 Notes provide that the Refining Partnership can make distributions to holders of its common units provided, among other things, it has a minimum fixed charge coverage ratio and there is no default or event of default under the 2022 Notes. As of March 31, 2016, the Refining Partnership was in compliance with the covenants contained in the 2022 Notes.
At March 31, 2016, the estimated fair value of the 2022 Notes was approximately $442.5 million. This estimate of fair value is Level 2 as it was determined by quotations obtained from a broker-dealer who makes a market in these and similar securities.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
Amended and Restated Asset Based (ABL) Credit Facility
The Refining Partnership has a senior secured asset based revolving credit facility (the "Amended and Restated ABL Credit Facility") with a group of lenders and Wells Fargo Bank, National Association ("Wells Fargo"), as administrative agent and collateral agent. The Amended and Restated ABL Credit Facility has an aggregate principal amount of up to $400.0 million with an incremental facility, which permits an increase in borrowings of up to $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 Refining Partnership and its 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. The Amended and Restated ABL Credit Facility is scheduled to mature on December 20, 2017.
The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Refining Partnership and its subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investments 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 March 31, 2016.
As of March 31, 2016, the Refining Partnership and its subsidiaries had availability under the Amended and Restated ABL Credit Facility of $245.3 million and had letters of credit outstanding of approximately $28.0 million. There were no borrowings outstanding under the Amended and Restated ABL Credit Facility as of March 31, 2016. Availability under the Amended and Restated ABL Credit Facility was limited by borrowing base conditions as of March 31, 2016.
Nitrogen Fertilizer Partnership Credit Facility
The Nitrogen Fertilizer Partnership credit facility that was in effect as of March 31, 2016 included a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with an uncommitted incremental facility of up to $50.0 million. No amounts were outstanding under the revolving credit facility at March 31, 2016. There is no scheduled amortization. The credit facility was scheduled to mature on April 13, 2016; therefore, the principal portion of the term loan is presented as current portion of long-term debt on the Condensed Consolidated Balance Sheets as of March 31, 2016. The carrying value of the Nitrogen Fertilizer Partnership's debt approximates fair value. On April 1, 2016, the Nitrogen Fertilizer Partnership repaid all amounts outstanding under the credit facility and the credit facility was terminated. See further discussion in Note 15 ("Subsequent Events").
Borrowings under the credit facility bore 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 was 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 Coffeyville Resources Nitrogen Fertilizers, LLC ("CRNF") and the Nitrogen Fertilizer Partnership.
The credit facility required the Nitrogen Fertilizer Partnership to maintain a minimum interest coverage ratio and a maximum leverage ratio and contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, the incurrence of liens, disposal of assets, making restricted payments, making investments or acquisitions and entry into sale-leaseback transactions or affiliate transactions. The credit facility provided 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 March 31, 2016, the Nitrogen Fertilizer Partnership and CRNF were in compliance with the covenants contained in the credit facility.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
On February 9, 2016, CRLLC and the Nitrogen Fertilizer Partnership entered into a guaranty, pursuant to which CRLLC agreed to guaranty the indebtedness outstanding under the Nitrogen Fertilizer Partnership's credit facility. If the credit facility becomes due prior to a refinancing by the Nitrogen Fertilizer Partnership, CRLLC is required to pay the indebtedness pursuant to this guaranty. On April 1, 2016, the Nitrogen Fertilizer Partnership entered into a senior term loan credit agreement with CRLLC and the guaranty was terminated. See further discussion in Note 15 ("Subsequent Events").
Capital Lease Obligations
The Refining Partnership maintains two leases, accounted for as a capital lease and a finance obligation, related to Magellan Pipeline Terminals, L.P. ("Magellan Pipeline") and Excel Pipeline LLC ("Excel Pipeline"). The underlying assets and related depreciation are 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 163 months remaining through September 2029. The financing agreement relates to the Magellan Pipeline terminals, bulk terminal and loading facility. The lease has 162 months remaining and will expire in September 2029.
(9) Earnings (Loss) Per Share
Basic and diluted earnings (loss) per share are computed by dividing net income (loss) attributable to CVR stockholders by the weighted-average number of shares of common stock outstanding. The components of the basic and diluted earnings (loss) per share calculation are as follows:

| Three Months Ended March 31,
| 2016 |  | 2015
Net income (loss) attributable to CVR Energy stockholders | $ | (16.2 | ) |  | $ | 54.9 |
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 (loss) per share | $ | (0.19 | ) |  | $ | 0.63 |
Diluted earnings (loss) per share | $ | (0.19 | ) |  | $ | 0.63 |

There were no dilutive awards outstanding during the three months ended March 31, 2016 and 2015, as all unvested awards under the LTIP were liability-classified awards. See Note 3 ("Share-Based Compensation").
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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
(10) Commitments and Contingencies
Leases and Unconditional Purchase Obligations
The minimum required payments for CVR’s lease agreements and unconditional purchase obligations are as follows:

| Operating Leases |  | Unconditional Purchase Obligations(1)
| (in millions)
Nine Months Ending December 31, 2016 | $ | 5.9 |  |  | $ | 140.5 |
Year Ending December 31, |  |  |
2017 | 5.5 |  |  | 130.6 |
2018 | 3.8 |  |  | 125.4 |
2019 | 2.1 |  |  | 124.6 |
2020 | 1.5 |  |  | 108.9 |
Thereafter | 2.5 |  |  | 738.1 |
| $ | 21.3 |  |  | $ | 1,368.1 |

(1) | This amount includes approximately $784.1 million payable ratably over fifteen years pursuant to petroleum transportation service agreements between Coffeyville Resources Refining & Marketing, LLC ("CRRM") and each of TransCanada Keystone Pipeline Limited Partnership and TransCanada Keystone Pipeline, LP (together, "TransCanada"). The purchase obligation reflects the exchange rate between the Canadian dollar and the U.S. dollar as of March 31, 2016, where applicable. 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 20 years on TransCanada's Keystone pipeline system.

CVR leases various equipment, including railcars and real properties, under long-term operating leases which expire at various dates. For each of the three months ended March 31, 2016 and 2015, lease expense totaled approximately $2.2 million. The lease agreements have various remaining terms. Some agreements are renewable, at CVR's option, for additional periods. It is expected, in the ordinary course of business, that leases may be renewed or replaced as they expire.
Additionally, in the normal course of business, the Company has long-term commitments to purchase oxygen, nitrogen, electricity, storage capacity and pipeline transportation services. For the three months ended March 31, 2016 and 2015, total expense of approximately $33.2 million and $27.1 million, respectively, was incurred related to long-term commitments.
Crude Oil Supply Agreement
On August 31, 2012, CRRM, and Vitol Inc. ("Vitol") entered into an Amended and Restated Crude Oil Supply Agreement (as amended, the "Vitol Agreement"). 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. The Vitol Agreement will automatically renew for successive one-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 any Renewal Term. The Vitol Agreement currently extends through December 31, 2016.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
Litigation
From time to time, the Company is involved in various lawsuits arising in the normal course of business, including matters such as those described below under, "Environmental, Health and Safety ("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'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 2015 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's beliefs or opinions with respect to liability for potential litigation matters will prove to be accurate.
Environmental, Health and Safety ("EHS") Matters
The petroleum and nitrogen fertilizer businesses are subject to various stringent federal, state, and local EHS rules and regulations. Liabilities related to EHS matters are recognized when the related costs are probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs and currently enacted laws and regulations. In reporting EHS liabilities, no offset is made for potential recoveries.
CRRM, CRNF, Coffeyville Resources Crude Transportation, LLC ("CRCT"), Wynnewood Refining Company, LLC ("WRC") and Coffeyville Resources Terminal, LLC ("CRT") own and/or operate manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution and nitrogen fertilizer manufacturing. Therefore, CRRM, CRNF, CRCT, WRC and CRT have exposure to potential EHS liabilities related to past and present EHS conditions at 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 Oil 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, which has been broadly interpreted to include most water bodies including intermittent streams.
CRRM, CRNF, CRCT, WRC and CRT are subject to extensive and frequently changing federal, state and local environmental and health and safety laws and regulations governing the emission and release of hazardous substances into the environment, the treatment and discharge of waste water, and 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.
As previously reported, the petroleum and nitrogen fertilizer businesses are party to, or otherwise subject to 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. The petroleum business also is subject to (i) the Mobile Source Air Toxic II ("MSAT II") rule which requires reductions of benzene in gasoline; (ii) the Renewable Fuel Standard ("RFS"), which requires refiners to either blend "renewable fuels" in with their transportation fuels or purchase renewable fuel credits, known as RINs, in lieu of blending; and (iii) "Tier 3" gasoline sulfur standards. Except as otherwise described below, there have been no new developments or material changes to the environmental accruals or expected capital expenditures related to compliance with the foregoing environmental matters from those provided in the 2015 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 or 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.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
At March 31, 2016, the Company's Condensed Consolidated Balance Sheet included total environmental accruals of $3.5 million, compared with $3.6 million at December 31, 2015. 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.
Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended March 31, 2016 and 2015, capital expenditures were approximately $3.6 million and $10.9 million, respectively. These expenditures were incurred for environmental compliance and efficiency of the operations.
The cost of RINs for the three months ended March 31, 2016 and 2015 was approximately $43.1 million and $36.6 million, respectively. As of March 31, 2016 and December 31, 2015, the petroleum business' biofuel blending obligation was approximately $24.3 million and $9.5 million, respectively, which was recorded in other current liabilities on the Condensed Consolidated Balance Sheets.
Affiliate Pension Obligations
Mr. Carl C. 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 CVR Energy by Mr. Icahn's affiliates, the Company is subject to the pension liabilities of all entities in which Mr. Icahn has a direct or indirect ownership interest of at least 80%. Two such entities, ACF Industries LLC ("ACF") and Federal-Mogul, are the sponsors 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 March 31, 2016 and December 31, 2015. If the ACF and Federal-Mogul plans were voluntarily terminated, they would be underfunded by approximately $583.8 million and $589.2 million as of March 31, 2016 and December 31, 2015, 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 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 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.
(11) Fair Value Measurements
In accordance with FASB ASC Topic 820 — Fair Value Measurements and Disclosures ("ASC 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.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
ASC 820 utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:

• | Level 1 — Quoted prices in active markets for identical assets and liabilities

• | Level 2 — Other significant observable inputs (including quoted prices in active markets for similar assets or liabilities)

• | Level 3 — Significant unobservable inputs (including the Company's own assumptions in determining the fair value)

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of March 31, 2016 and December 31, 2015:

| March 31, 2016
| Level 1 |  | Level 2 |  | Level 3 |  | Total
| (in millions)
Location and Description |  |  |  |  |  |  |
Cash equivalents | $ | 15.7 |  |  | $ | — |  |  | $ | — |  |  | $ | 15.7 |
Other current assets (investments) | 4.6 |  |  | — |  |  | — |  |  | 4.6 |
Other current assets (other derivative agreements) | — |  |  | 22.1 |  |  | — |  |  | 22.1 |
Total Assets | $ | 20.3 |  |  | $ | 22.1 |  |  | $ | — |  |  | $ | 42.4 |
Other current liabilities (other derivative agreements) | — |  |  | (0.1 | ) |  | — |  |  | (0.1 | )
Other current liabilities (biofuel blending obligations) | — |  |  | (0.5 | ) |  | — |  |  | (0.5 | )
Total Liabilities | $ | — |  |  | $ | (0.6 | ) |  | $ | — |  |  | $ | (0.6 | )

| December 31, 2015
| Level 1 |  | Level 2 |  | Level 3 |  | Total
| (in millions)
Location and Description |  |  |  |  |  |  |
Cash equivalents | $ | 15.7 |  |  | $ | — |  |  | $ | — |  |  | $ | 15.7 |
Other current assets (investments) | 0.1 |  |  | — |  |  | — |  |  | 0.1 |
Other current assets (other derivative agreements) | — |  |  | 44.7 |  |  | — |  |  | 44.7 |
Total Assets | $ | 15.8 |  |  | $ | 44.7 |  |  | $ | — |  |  | $ | 60.5 |
Other current liabilities (other derivative agreements) | — |  |  | (0.1 | ) |  | — |  |  | (0.1 | )
Other current liabilities (interest rate swaps) | — |  |  | (0.1 | ) |  | — |  |  | (0.1 | )
Other long-term liabilities (biofuel blending obligation) | — |  |  | (2.7 | ) |  | — |  |  | (2.7 | )
Total Liabilities | $ | — |  |  | $ | (2.9 | ) |  | $ | — |  |  | $ | (2.9 | )

As of March 31, 2016 and December 31, 2015, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Company's cash equivalents, investments, derivative instruments and the uncommitted biofuel blending obligation. Additionally, the fair value of the Company's debt issuances is disclosed in Note 8 ("Long-Term Debt"). In March 2016, CVR Energy purchased 400,000 East Dubuque common units in the public market. The fair value of the common units was based on quoted prices for the identical securities (Level 1 inputs). See further details in Note 15 ("Subsequent Events"). The Refining Partnership'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, are considered Level 2 inputs. The Nitrogen Fertilizer Partnership had interest rate swaps that were measured at fair value on a recurring basis using Level 2 inputs. The fair value of these interest rate swap instruments was based on discounted cash flow models that incorporated 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 had no transfers of assets and liabilities between any of the above levels during the three months ended March 31, 2016.
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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
The Company's investments in marketable securities are reported at fair market value using quoted market prices. During the three months ended March 31, 2015, the Company received proceeds of $42.1 million for the sale of a portion of its investment in available-for-sale securities. Additionally, as of March 31, 2015, the Company recorded a receivable of $25.9 million for additional available-for-sale securities, which is included in prepaid expenses and other current assets on the Condensed Consolidated Balances Sheets. The aggregate cost basis for the available-for-sale securities sold was approximately $47.9 million. Upon the sale of the available-for-sale securities, the Company reclassified an unrealized gain of $20.1 million from accumulated other comprehensive income ("AOCI") and recognized a realized gain in other income in the Condensed Consolidated Statements of Operations for the three months ended March 31, 2015. At the end of the first quarter of 2015, the Company's remaining available-for-sale securities with an aggregate cost basis of approximately $25.7 million were reclassified to trading securities based on management's ability and intent with respect to the securities. In connection with the transfer to trading securities, an unrealized gain previously recorded in AOCI of $11.7 million was reclassified to other income and is reflected in the Condensed Consolidated Statements of Operations for the three months ended March 31, 2015.
(12) Derivative Financial Instruments
Loss on derivatives, net and current period settlements on derivative contracts were as follows:

| Three Months Ended March 31,
| 2016 |  | 2015
| (in millions)
Current period settlements on derivative contracts | $ | 21.4 |  |  | $ | (6.3 | )
Loss on derivatives, net | (1.2 | ) |  | (51.4 | )

The Refining Partnership and Nitrogen Fertilizer Partnership are subject to price fluctuations caused by supply conditions, weather, economic conditions, interest rate fluctuations and other factors. To manage price risk on crude oil and other inventories and to fix margins on certain future production, the Refining Partnership from time to time enters into various commodity derivative transactions.
The Refining Partnership has adopted accounting standards which impose extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. The Refining Partnership holds derivative instruments, such as exchange-traded crude oil futures and certain over-the-counter forward swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges for GAAP purposes. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. 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.
The Refining Partnership maintains a margin account to facilitate other commodity derivative activities. A portion of this account may include funds available for withdrawal. These funds are included in cash and cash equivalents within the Condensed Consolidated Balance Sheets. The maintenance margin balance is included within other current assets within the Condensed Consolidated Balance Sheets. Dependent upon the position of the open commodity derivatives, the amounts are accounted for as other current assets or other current liabilities within the Condensed Consolidated Balance Sheets. From time to time, the Refining Partnership may be required to deposit additional funds into this margin account. For the three months ended March 31, 2016 and 2015, the Refining Partnership recognized net losses of $0.3 million and $1.0 million, respectively, which are recorded in loss on derivatives, net in the Condensed Consolidated Statement of Operations.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
Commodity Swaps
The Refining Partnership enters into commodity swap contracts in order to fix the margin on a portion of future production. Additionally, the Refining Partnership may enter into price and basis swaps in order to fix the price on a portion of its commodity purchases and product sales. 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. Quoted prices for similar assets or liabilities in active markets (Level 2) are considered to determine the fair values for the purpose of marking to market the hedging instruments at each period end. At December 31, 2015, the Refining Partnership had open commodity hedging instruments consisting of 2.5 million barrels of crack spreads primarily to fix the margin on a portion of its future gasoline and distillate production. During the first quarter of 2016, the Refining Partnership settled a number of the open crack spread positions and entered into offsetting positions to effectively lock in the gain on the remaining positions to be settled during 2016. At March 31, 2016, the Refining Partnership had open commodity hedging instruments consisting of 0.6 million barrels net of crack spreads and 1.0 million barrels of price and basis swaps. The fair value of the outstanding contracts at March 31, 2016 was a net unrealized gain of $22.0 million, of which $22.1 million was included in current assets and $0.1 million was included in current liabilities. For the three months ended March 31, 2016 and 2015, the Refining Partnership recognized a net loss of $0.9 million and a net loss of $50.4 million, respectively. These recognized net losses are recorded in loss on derivatives, net in the Condensed Consolidated Statements of Operations.
Nitrogen Fertilizer Partnership Interest Rate Swaps
CRNF had 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, as further discussed in Note 8 ("Long-Term Debt"). The aggregate notional amount covered under these agreements, which commenced on August 12, 2011 and expired on February 12, 2016, totaled $62.5 million (split evenly between the two agreements). Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF received a floating rate based on three month LIBOR and paid a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF received a floating rate based on three month LIBOR and paid a fixed rate of 1.975%. Both swap agreements settled every 90 days. The effect of these swap agreements was 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 facility. The agreements were designated as cash flow hedges at inception and accordingly, the effective portion of the gain or loss on the swap was reported as a component of AOCI and was reclassified into interest expense when the interest rate swap transaction affects earnings. Any ineffective portion of the gain or loss was recognized immediately in current interest expense on the Condensed Consolidated Statements of Operations. The interest rate swaps agreements terminated in February 2016.
The realized loss on the interest rate swaps re-classified from AOCI into interest expense and other financing costs on the Condensed Consolidated Statements of Operations was $0.0 million and $0.3 million for the three months ended March 31, 2016 and 2015, respectively. For each of the three months ended March 31, 2016 and 2015, the Nitrogen Fertilizer Partnership recognized a nominal decrease in fair value of the interest rate swap agreements, which was unrealized in AOCI.
Counterparty Credit Risk
The Refining Partnership'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 March 31, 2016, 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.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
Offsetting Assets and Liabilities
The commodity swaps and other commodity derivatives agreements discussed above include multiple derivative positions with a number of counterparties for which the Refining Partnership has entered into agreements governing the nature of the derivative transactions. Each of the counterparty agreements provides for the right to setoff each individual derivative position to arrive at the net receivable due from the counterparty or payable owed by the Refining Partnership. As a result of the right to setoff, the Refining Partnership's recognized assets and liabilities associated with the outstanding derivative positions have been presented net in the Condensed Consolidated Balance Sheets. 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.
The offsetting assets and liabilities for the Refining Partnership's derivatives as of March 31, 2016 are recorded as current assets and current liabilities in prepaid expenses and other current assets and other current liabilities, respectively, in the Condensed Consolidated Balance Sheets as follows:

| As of March 31, 2016
Description | Gross Current Assets |  | Gross Amounts Offset |  | Net Current Assets Presented |  | Cash Collateral Not Offset |  | Net Amount
| (in millions)
Commodity Swaps | $ | 22.4 |  |  | $ | (0.3 | ) |  | $ | 22.1 |  |  | $ | — |  |  | $ | 22.1 |
Total | $ | 22.4 |  |  | $ | (0.3 | ) |  | $ | 22.1 |  |  | $ | — |  |  | $ | 22.1 |

| As of March 31, 2016
Description | Gross Current Liabilities |  | Gross Amounts Offset |  | Net Current Liabilities Presented |  | Cash Collateral Not Offset |  | Net Amount
| (in millions)
Commodity Swaps | $ | 0.1 |  |  | $ | — |  |  | $ | 0.1 |  |  | $ | — |  |  | $ | 0.1 |
Total | $ | 0.1 |  |  | $ | — |  |  | $ | 0.1 |  |  | $ | — |  |  | $ | 0.1 |

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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
The offsetting assets and liabilities for the Refining Partnership's derivatives as of December 31, 2015 are recorded as current assets and current liabilities in prepaid expenses and other current assets and other current liabilities, respectively, in the Condensed Consolidated Balance Sheets as follows:

| As of December 31, 2015
Description | Gross Current Assets |  | Gross Amounts Offset |  | Net Current Assets Presented |  | Cash Collateral Not Offset |  | Net Amount
| (in millions)
Commodity Swaps | $ | 44.8 |  |  | $ | (0.1 | ) |  | $ | 44.7 |  |  | $ | — |  |  | $ | 44.7 |
Total | $ | 44.8 |  |  | $ | (0.1 | ) |  | $ | 44.7 |  |  | $ | — |  |  | $ | 44.7 |

| As of December 31, 2015
Description | Gross Current Liabilities |  | Gross Amounts Offset |  | Net Current Liabilities Presented |  | Cash Collateral Not Offset |  | Net Amount
| (in millions)
Commodity Swaps | $ | 0.1 |  |  | $ | — |  |  | $ | 0.1 |  |  | $ | — |  |  | $ | 0.1 |
Total | $ | 0.1 |  |  | $ | — |  |  | $ | 0.1 |  |  | $ | — |  |  | $ | 0.1 |

(13) Related Party Transactions
Icahn Enterprises
In May 2012, IEP announced that it had acquired control of CVR pursuant to a tender offer to purchase all of the issued and outstanding shares of the Company's common stock. As of March 31, 2016, IEP and its affiliates owned approximately 82% of the Company's outstanding common shares.
On March 7, 2016, we paid a cash dividend to the Company's stockholders of record at the close of business on February 29, 2016 for the fourth quarter of 2015 in the amount of $0.50 per share, or $43.4 million in the aggregate. IEP received $35.6 million in respect of its common shares.
Tax Allocation Agreement
CVR is a member of the consolidated federal tax group of AEPC, a wholly-owned subsidiary of IEP, and has entered into a Tax Allocation Agreement. Refer to Note 7 ("Income Taxes") for a discussion of related party transactions under the Tax Allocation Agreement.
Insight Portfolio Group
Insight Portfolio Group LLC ("Insight Portfolio Group") is an entity formed by Mr. Carl C. 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's operating expenses in 2013 and subsequent periods. The Company paid Insight Portfolio Group approximately $0.1 million and $0.0, respectively, during the three months ended March 31, 2016 and 2015. The Company may purchase a variety of goods and services as a 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.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
Commitment Letter
Simultaneously with the execution of the Merger Agreement, the Nitrogen Fertilizer Partnership entered into a commitment letter (the "Commitment Letter") with CRLLC, pursuant to which CRLLC committed to, on the terms and subject to the conditions set forth in the Commitment Letter, make available to the Nitrogen Fertilizer Partnership term loan financing of up to $150.0 million, which amounts would be available solely to fund the repayment of all of the loans outstanding under East Dubuque's $50.0 million credit facility, the cash consideration and expenses associated with the mergers. The term loan facility, if drawn, would have a one year term and would bear interest at a rate of three-month LIBOR plus 3.0% per annum. Calculation of interest would be on the basis of the actual number of days elapsed over a 360-day year.
CRLLC Guaranty
On February 9, 2016, CRLLC and the Nitrogen Fertilizer Partnership entered into a guaranty pursuant to which CRLLC agreed to guaranty the indebtedness outstanding under the Nitrogen Fertilizer Partnership's credit facility. Refer to Note 8 ("Long-Term Debt") for additional discussion of the guarantee.
CRLLC Facility with the Nitrogen Fertilizer Partnership
On April 1, 2016, in connection with the closing of the mergers, the Nitrogen Fertilizer Partnership entered into a senior term loan credit agreement with CRLLC and the Commitment Letter and the CRLLC guaranty were terminated. See further discussion in Note 15 ("Subsequent Events").
AEPC Facility with Nitrogen Fertilizer Partnership
On April 1, 2016, in connection with the closing of the mergers, the Nitrogen Fertilizer Partnership entered into a senior term loan facility with AEPC as the lender. See further discussion in Note 15 ("Subsequent Events").
(14) Business Segments
The Company measures segment profit as operating income for petroleum and nitrogen fertilizer, CVR's two reporting segments, based on the definitions provided in FASB ASC Topic 280 – Segment Reporting. All operations of the segments are located within the United States.
Petroleum
Principal products of the petroleum segment are refined fuels, propane, and petroleum refining by-products, including pet coke. The petroleum segment's Coffeyville refinery sells pet coke to CRNF for use in the manufacture of nitrogen fertilizer at the adjacent nitrogen fertilizer plant. For the petroleum segment, a per-ton transfer price is used to record intercompany sales on the part of the petroleum segment and corresponding intercompany cost of product sold (exclusive of depreciation and amortization) for the 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 segment for UAN (subject to a UAN based price ceiling and floor) and a pet coke price index for pet coke. Intercompany net sales included in petroleum net sales were approximately $0.4 million and $2.1 million for the three months ended March 31, 2016 and 2015, respectively.
For the three months ended March 31, 2016 and 2015, the petroleum segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen purchases described below under "Nitrogen Fertilizer" of approximately $1.1 million and $6.5 million, respectively.
Nitrogen Fertilizer
The principal product of the nitrogen fertilizer segment is nitrogen fertilizer. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was approximately $0.7 million and $1.8 million for the three months ended March 31, 2016 and 2015, respectively.
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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)
Pursuant to a feedstock agreement, the Company's segments have the right to transfer hydrogen between the Coffeyville refinery and nitrogen fertilizer plant. Sales of hydrogen to the petroleum segment have been reflected as net sales for the nitrogen fertilizer segment. Receipts of hydrogen from the petroleum segment have been reflected in cost of product sold (exclusive of depreciation and amortization) for the nitrogen fertilizer segment, when applicable. For the three months ended March 31, 2016 and 2015, the net sales generated from intercompany hydrogen sales were $1.1 million and $6.5 million, respectively. As these intercompany sales and cost of product sold are eliminated, there is no financial statement impact on the condensed consolidated financial statements.
Other Segment
The other segment reflects intercompany eliminations, corporate cash and cash equivalents, income tax activities and other corporate activities that are not allocated to the operating segments.
The following table summarizes certain operating results and capital expenditures information by segment:

| Three Months Ended March 31,
| 2016 |  | 2015
| (in millions)
Net sales |  |  |
Petroleum | $ | 834.0 |  |  | $ | 1,304.4 |
Nitrogen Fertilizer | 73.1 |  |  | 93.1 |
Intersegment elimination | (1.6 | ) |  | (8.6 | )
Total | $ | 905.5 |  |  | $ | 1,388.9 |
Cost of product sold (exclusive of depreciation and amortization) |  |  |
Petroleum | $ | 722.3 |  |  | $ | 1,056.1 |
Nitrogen Fertilizer | 16.3 |  |  | 25.8 |
Intersegment elimination | (1.8 | ) |  | (8.3 | )
Total | $ | 736.8 |  |  | $ | 1,073.6 |
Direct operating expenses (exclusive of depreciation and amortization) |  |  |
Petroleum | $ | 117.7 |  |  | $ | 87.0 |
Nitrogen Fertilizer | 23.7 |  |  | 24.4 |
Other | — |  |  | — |
Total | $ | 141.4 |  |  | $ | 111.4 |
Depreciation and amortization |  |  |
Petroleum | $ | 31.5 |  |  | $ | 34.0 |
Nitrogen Fertilizer | 7.0 |  |  | 6.8 |
Other | 1.5 |  |  | 1.2 |
Total | $ | 40.0 |  |  | $ | 42.0 |
Operating income (loss) |  |  |
Petroleum | $ | (56.0 | ) |  | $ | 109.2 |
Nitrogen Fertilizer | 19.7 |  |  | 31.5 |
Other | (3.6 | ) |  | (4.1 | )
Total | $ | (39.9 | ) |  | $ | 136.6 |
Capital expenditures |  |  |
Petroleum | $ | 44.0 |  |  | $ | 41.7 |
Nitrogen Fertilizer | 1.7 |  |  | 2.7 |
Other | 1.8 |  |  | 1.1 |
Total | $ | 47.5 |  |  | $ | 45.5 |

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CVR ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
March 31, 2016
(unaudited)

| As of March 31, 2016 |  | As of December 31, 2015
| (in millions)
Total assets |  |  |
Petroleum | $ | 2,116.9 |  |  | $ | 2,189.0 |
Nitrogen Fertilizer | 529.2 |  |  | 536.3 |
Other | 537.4 |  |  | 574.1 |
Total | $ | 3,183.5 |  |  | $ | 3,299.4 |
Goodwill |  |  |
Petroleum | $ | — |  |  | $ | — |
Nitrogen Fertilizer | 41.0 |  |  | 41.0 |
Other | — |  |  | — |
Total | $ | 41.0 |  |  | $ | 41.0 |

(15) Subsequent Events
Dividend
On April 27, 2016, the board of directors of the Company declared a cash dividend for the first quarter of 2016 to the Company's stockholders of $0.50 per share, or $43.4 million in aggregate. The dividend will be paid on May 16, 2016 to stockholders of record at the close of business on May 9, 2016. IEP will receive $35.6 million in respect of its 82% ownership interest in the Company's shares.
Nitrogen Fertilizer Partnership Distribution
On April 27, 2016, the board of directors of the Nitrogen Fertilizer Partnership's general partner declared a cash distribution for the first quarter of 2016 to the Nitrogen Fertilizer Partnership's unitholders of $0.27 per common unit, or $30.6 million in aggregate. The distribution will be paid on May 16, 2016 to unitholders of record at the close of business on May 9, 2016. The Company will receive $10.5 million in respect of its Nitrogen Fertilizer Partnership common units.
Rentech Mergers
On April 1, 2016, the Nitrogen Fertilizer Partnership completed the mergers with East Dubuque (formerly known as Rentech Nitrogen Partners, L.P.), a publicly traded partnership whose common units were listed on the NYSE under the ticker symbol "RNF" and East Dubuque GP (formerly known as Rentech Nitrogen GP, LLC), pursuant to which CVR Partners acquired East Dubuque and East Dubuque GP by merging two newly-created direct wholly-owned subsidiaries of CVR Partners with and into those entities with East Dubuque and East Dubuque GP continuing as the surviving entities and subsidiaries of CVR Partners.
East Dubuque owns a facility located in East Dubuque, Illinois that produces primarily ammonia and UAN using natural gas as the facility's primary feedstock. The primary reasons for the mergers were to expand CVR Partners geographical footprint, diversify its raw material feedstocks, widen its customer reach and increase its potential for cash-flow generation.
East Dubuque was required to sell or spin off its Pasadena facility as a condition to closing of the mergers, and the sale of the Pasadena facility to a third-party was consummated prior to the merger date. On March 14, 2016, East Dubuque completed the sale of 100% of the issued and outstanding membership interests of its subsidiary that owned the Pasadena facility to a third party. East Dubuque common unitholders received consideration for the Pasadena facility and may receive additional consideration according to the terms of the purchase agreement.
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Merger Consideration
Under the terms of the Merger Agreement, holders of East Dubuque common units eligible to receive consideration received 1.04 common units (the "unit consideration") representing limited partner interests in CVR Partners ("CVR Partners common units") and $2.57 in cash, without interest, (the "cash consideration" and together with the unit consideration, the "merger consideration") for each East Dubuque common unit. Pursuant to the Merger Agreement, CVR Partners issued approximately 40.2 million CVR Partners common units and paid approximately $99.2 million in cash consideration to East Dubuque common unitholders and certain holders of East Dubuque phantom units discussed below.
Phantom units granted and outstanding under East Dubuque’s equity plans and held by an employee who continued in the employment of a CVR Partners-affiliated entity upon closing of the mergers were canceled and replaced with new incentive awards of substantially equivalent value and on similar terms. Each phantom unit granted and outstanding and held by (i) an employee who did not continue in employment of a CVR Partners-affiliated entity, or (ii) a director of East Dubuque GP, upon closing of the mergers, vested in full and the holders thereof received the merger consideration.
In March 2016, CVR Energy purchased 400,000 East Dubuque common units. Pursuant to the Merger Agreement, any East Dubuque common units held of record by an affiliate of CVR Partners remained outstanding as East Dubuque common units following the effective time of the mergers and such affiliate did not receive any merger consideration for those units.
Merger-Related Indebtedness
East Dubuque’s debt arrangements that remained in place until the closing date of the mergers included $320.0 million of 6.5% second lien senior secured notes due 2021 (the "Second Lien Notes"). East Dubuque is required under the change of control provision within the indenture governing the Second Lien Notes to offer to purchase, within 90 days of the mergers, all outstanding Second Lien Notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest thereon to the date of purchase.
Immediately prior to the merger, East Dubuque had outstanding advances under a credit agreement with Wells Fargo, as successor-in-interest by assignment from General Electric Company, as administrative agent (the "Wells Fargo Credit Agreement"). The Wells Fargo Credit Agreement consisted of a $50.0 million senior secured revolving credit facility with a $10.0 million letter of credit sublimit. Simultaneous with the mergers, the Nitrogen Fertilizer Partnership paid $49.4 million to pay off the outstanding balance under the Wells Fargo Credit Agreement and the Wells Fargo Credit Agreement was canceled.
CRLLC Facility with the Nitrogen Fertilizer Partnership
On April 1, 2016, in connection with the closing of the mergers, the Nitrogen Fertilizer Partnership entered into a senior term loan credit facility with CRLLC (the "CRLLC Facility"), pursuant to which CRLLC loaned the Nitrogen Fertilizer Partnership an aggregate principal amount of $300.0 million, the maximum amount available under the CRLLC Facility. The CRLLC Facility has a term of 2 years and bears an interest rate of 12.0% per annum. Interest is calculated on the basis of the actual number of days elapsed over a 360-day year and payable quarterly. The Nitrogen Fertilizer Partnership may voluntarily prepay in whole or in part borrowings under the CRLLC Facility without premium or penalty.
The proceeds from the CRLLC Facility, discussed above, were used by the Nitrogen Fertilizer Partnership (i) to repay the $125.0 million outstanding loan under the credit facility discussed in Note 8 ("Long-Term Debt"), which was terminated, (ii) to fund the approximate $99.2 million cash portion of the merger consideration, (iii) to repay all of the loans outstanding under the Wells Fargo Credit Agreement and (iv) to pay the fees and expenses in connection with the mergers and related transactions.
In connection with the CRLLC Facility, the Commitment Letter and the CRLLC Guaranty discussed in Note 13 ("Related Party Transactions") were terminated.
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AEPC Facility with Nitrogen Fertilizer Partnership
On April 1, 2016, in connection with the closing of the mergers, the Nitrogen Fertilizer Partnership entered into a new $320.0 million senior term loan facility (the “AEPC Facility”) with AEPC as the lender, which (i) may be used by the Nitrogen Fertilizer Partnership to provide funds to East Dubuque to make a change of control offer and, if applicable, a “clean-up” redemption in accordance with the indenture governing the Second Lien Notes or (ii) may be used by the Nitrogen Fertilizer Partnership or East Dubuque to make a tender offer for the Second Lien Notes and, in each case, pay fees and expenses related thereto. The AEPC Facility is for a term of two years and bears interest at a rate of 12% per annum. Interest shall be calculated on the basis of the actual number of days elapsed over a 360-day year and payable quarterly. The Nitrogen Fertilizer Partnership may voluntarily prepay in whole or in part the borrowings under the AEPC Facility without premium or penalty.
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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and related notes and with the statistical information and financial data appearing in this Report, as well as our Annual Report on Form 10-K for the year ended December 31, 2015 filed with the Securities and Exchange Commission ("SEC") on February 19, 2016 (the "2015 Form 10-K"). Results of operations and cash flows for the three months ended March 31, 2016 are not necessarily indicative of results to be attained for any other period.
Forward-Looking Statements
This Report, including this Management's Discussion and Analysis of Financial Condition and Results of Operations, contains "forward-looking statements" as defined by the SEC, including statements concerning contemplated transactions and strategic plans, expectations and objectives for future operations. Forward-looking statements include, without limitation:

• | statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future;

• | statements relating to future financial or operational performance, future dividends, future capital sources and capital expenditures; and

• | any other statements preceded by, followed by or that include the words "anticipates," "believes," "expects," "plans," "intends," "estimates," "projects," "could," "should," "may" or similar expressions.

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Report, including this Management'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:

• | volatile margins in the refining industry and exposure to the risks associated with volatile crude oil prices;

• | the availability of adequate cash and other sources of liquidity for the capital needs of our business;

• | the ability to forecast our future financial condition or results of operations and future revenues and expenses of our businesses;

• | the effects of transactions involving forward and derivative instruments;

• | disruption of our petroleum business' ability to obtain an adequate supply of crude oil;

• | changes in laws, regulations and policies with respect to the export of crude oil or other hydrocarbons;

• | interruption of the pipelines supplying feedstock and in the distribution of the petroleum business' products;

• | competition in the petroleum and nitrogen fertilizer businesses;

• | capital expenditures and potential liabilities arising from environmental laws and regulations;

• | changes in ours or the Refining Partnership's or Nitrogen Fertilzer Partnership's credit profile;

• | the cyclical nature of the nitrogen fertilizer business;

• | the seasonal nature of the petroleum business;

• | the supply and price levels of essential raw materials of our businesses;

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• | the risk of a material decline in production at our refineries and nitrogen fertilizer plants;

• | potential operating hazards from accidents, fire, severe weather, floods or other natural disasters;

• | the risk associated with governmental policies affecting the agricultural industry;

• | the volatile nature of ammonia, potential liability for accidents involving ammonia that cause interruption to the nitrogen fertilizer business, severe damage to property and/or injury to the environment and human health and potential increased costs relating to the transport of ammonia;

• | the dependence of the nitrogen fertilizer operations on a few third-party suppliers, including providers of transportation services and equipment;

• | new regulations concerning the transportation of hazardous chemicals, risks of terrorism and the security of chemical manufacturing facilities;

• | the risk of security breaches;

• | the petroleum business' and the nitrogen fertilizer business' dependence on significant customers;

• | the potential loss of the nitrogen fertilizer business' transportation cost advantage over its competitors;

• | our nitrogen fertilizer business' partial dependence on customer and distributor transportation of purchased goods;

• | the potential inability to successfully implement our business strategies, including the completion of significant capital programs;

• | our ability to continue to license the technology used in the petroleum business and nitrogen fertilizer business operations;

• | our petroleum business' ability to purchase RINs on a timely and cost effective basis;

• | our petroleum business' continued ability to secure environmental and other governmental permits necessary for the operation of its business;

• | existing and proposed environmental laws and regulations, including those relating to climate change, alternative energy or fuel sources, and existing and future regulations related to the end-use and application of fertilizers;

• | refinery and nitrogen fertilizer facility operating hazards and interruptions, including unscheduled maintenance or downtime, and the availability of adequate insurance coverage;

• | the risk of labor disputes and adverse employee relations;

• | instability and volatility in the capital and credit markets; and

• | potential exposure to underfunded pension obligations of affiliates as a member of the controlled group of Mr. Icahn.

All forward-looking statements contained in this Report speak only as of the date of this Report. We undertake no obligation to publicly update or revise any forward-looking statements to reflect events or circumstances that occur after the date of this Report, or to reflect the occurrence of unanticipated events, except to the extent required by law.
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Company Overview
CVR Energy, Inc. ("CVR Energy," "CVR," "we," "us," "our" or the "Company") is a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries through our holdings in the Refining Partnership and the Nitrogen Fertilizer 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 UAN and ammonia. We own the general partner and approximately 66% and 34% respectively, of the outstanding common units representing limited partner interests in each of the Refining Partnership and the Nitrogen Fertilizer Partnership. As of March 31, 2016, Icahn Enterprises L.P. ("IEP") and its affiliates owned approximately 82% of our outstanding common stock.
We operate under two business segments: petroleum and nitrogen fertilizer, which are referred to in this document as our "petroleum business" and our "nitrogen fertilizer business," respectively.
Petroleum business. The petroleum business consists of our interest in the Refining Partnership. At March 31, 2016, we owned the general partner and approximately 66% of the common units of the Refining Partnership. The petroleum business consists of a 115,000 bpcd rated capacity complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and a 70,000 bpcd rated capacity complex crude oil refinery in Wynnewood, Oklahoma capable of processing 20,000 bpcd of light sour crude oil (within its rated capacity of 70,000 bpcd). In addition, its supporting businesses include (i) a crude oil gathering system with a gathering capacity of over 65,000 bpd serving Kansas, Nebraska, Oklahoma, Missouri, Colorado and Texas, which serves the two refineries, (ii) a 170,000 bpd pipeline system (supported by approximately 336 miles of active owned and leased pipeline) that transports crude oil to the Coffeyville refinery from the Broome Station facility located near Caney, Kansas, (iii) approximately 6.4 million barrels of owned and leased crude oil storage, including 0.5 million barrels completed in October 2015, (iv) 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's refined petroleum products distribution systems and (v) over 4.5 million barrels of combined refined products and feedstocks storage capacity.
The Coffeyville refinery is situated approximately 100 miles northeast of Cushing, Oklahoma, one of the largest crude oil trading and storage hubs in the United States and the Wynnewood refinery is approximately 130 miles southwest of Cushing. Cushing is supplied by numerous pipelines from U.S. domestic locations and Canada. In addition to rack sales (sales which are made at terminals into third-party tanker trucks), Coffeyville makes bulk sales (sales through third-party pipelines) into the mid-continent markets and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise, and NuStar.
Crude oil is supplied to the Coffeyville refinery through the gathering system and by a pipeline owned by Plains that runs from Cushing, Oklahoma to its Broome Station facility. The petroleum business maintains capacity on the Spearhead and Keystone pipelines from Canada to Cushing, Oklahoma. It also has contracted capacity on the Pony Express and White Cliffs pipelines, which originate in Colorado and extend to Cushing, Oklahoma. It also maintains leased and owned storage in Cushing to facilitate optimal crude oil purchasing and blending. Crude oil is supplied to the Wynnewood refinery through three third-party pipelines operated by Sunoco Pipeline, Excel Pipeline and Blueknight Pipeline and historically has mainly been sourced from Texas and Oklahoma. The access to a variety of crude oils coupled with the complexity of the refineries typically allows the petroleum business to purchase crude oil at a discount to WTI. The consumed crude oil cost discount to WTI for the first quarter of 2016 was $1.53 per barrel compared to a discount of $1.10 per barrel in the first quarter of 2015.
Nitrogen fertilizer business. The nitrogen fertilizer business consists of our interest in the Nitrogen Fertilizer Partnership. At March 31, 2016, we owned 100% of the general partner and approximately 53% of the common units of the Nitrogen Fertilizer Partnership. Following completion of the East Dubuque mergers on April 1, 2016, we now hold approximately 34% of the Nitrogen Fertilizer Partnership's outstanding common units and 100% of the Nitrogen Fertilizer Partnership's general partner. As of March 31, 2016, the nitrogen fertilizer business consisted of one nitrogen fertilizer manufacturing facility located in Coffeyville, Kansas ("Coffeyville Fertilizer Facility") that utilizes a petroleum coke, or pet coke, gasification process to produce nitrogen fertilizer. The Coffeyville Fertilizer Facility includes a 1,300 ton-per-day ammonia unit, a 3,000 ton-per-day UAN unit and a gasifier complex having a capacity of 89 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. With the completion of the UAN expansion in February 2013, the Coffeyville Fertilizer Facility now upgrades substantially all of the ammonia it produces to higher margin UAN fertilizer, an aqueous solution of urea and ammonium nitrate which has historically commanded a premium price over ammonia. For the three months ended March 31, 2016, the nitrogen fertilizer business produced 0.2 million tons of UAN and 0.1 million tons of ammonia, respectively. For the three months ended March 31, 2016, approximately 89% of the produced ammonia tons and the majority of purchased ammonia tons were upgraded into UAN, respectively.
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The primary raw material feedstock utilized in the nitrogen fertilizer production process at the Coffeyville Fertilizer Facility is pet coke, which is produced during the crude oil refining process. In contrast, substantially all of the nitrogen fertilizer 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. The Coffeyville Fertilizer facility's pet coke gasification process results in a significantly higher percentage of fixed costs than a natural gas-based fertilizer plant. The nitrogen fertilizer business currently purchases most of its pet coke used at the Coffeyville Fertilizer Facility from the Refining Partnership pursuant to a long-term agreement having an initial term that ends in 2027, subject to renewal. On average, during the past five years, over 70% of the pet coke utilized by the Coffeyville Fertilizer Facility was produced and supplied by the Refining Partnership's crude oil refinery in Coffeyville.
As a result of the East Dubuque mergers, we also now own a nitrogen fertilizer facility located in East Dubuque, Illinois ("East Dubuque Fertilizer Facility"), which produces primarily ammonia and UAN. For a discussion of the East Dubuque mergers, refer to "Recent Developments" below in Part I. Item 2 of this Report and Note 15 ("Subsequent Events") of Part I. Item 1 of this Report.
Recent Developments
On April 1, 2016, the Nitrogen Fertilizer Partnership completed the previously announced transactions (the "mergers") contemplated by the Agreement and Plan of Merger, dated as of August 9, 2015 (the "Merger Agreement"), with East Dubuque Nitrogen Partners, L.P. (formerly known as Rentech Nitrogen Partners, L.P.) ("East Dubuque") and East Dubuque Nitrogen GP, LLC (formerly known as Rentech Nitrogen GP, LLC) ("East Dubuque GP"). Refer to Part I, Item 1, Note 15 ("Subsequent Events") of this Report for further discussion of the mergers.
Major Influences on Results of Operations
Petroleum Business
The earnings and cash flows of the petroleum business are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks that are processed and blended into refined products. The cost to acquire crude oil and other feedstocks and the price for which refined products are ultimately sold depend on factors beyond the petroleum business' control, including the supply of and demand for crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. Because the petroleum business applies first-in, first-out ("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.
The prices of crude oil and other feedstocks and refined product prices are also affected by other factors, such as product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs and the prices of refined products have historically been subject to wide fluctuations. Widespread expansion or upgrades of 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 Renewable Fuel Standard ("RFS") of the United States Environmental Protection Agency (the "EPA"), which requires it to either blend "renewable fuels" in with its transportation fuels or purchase renewable fuel credits, known as renewable identification numbers ("RINs"), in lieu of blending.
On December 14, 2015, the EPA published in the Federal Register a final rule establishing the renewable fuel volume mandates for 2014, 2015 and 2016, and the biomass-based diesel mandate for 2017. The volumes included in the EPA's final rule increase each year, but are lower, with the exception of the volumes for biomass-based diesel, than the volumes required by the Clean Air Act. The EPA used its waiver authority to lower the volumes, but its decision to do so has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit. In addition, in the final rule establishing the renewable volume obligations for 2014-2016 and bio-mass based diesel for 2017, the EPA articulated a policy to incentivize additional investments in renewable fuel blending and distribution infrastructure by increasing the price of RINs.
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The cost of RINs for the three months ended March 31, 2016 and 2015 was approximately $43.1 million and $36.6 million, respectively. The price of RINs has been extremely volatile and has increased over the last year. The future cost of RINs for the petroleum business is difficult to estimate. Additionally, the cost of RINs is dependent upon a variety of factors, which include EPA regulations, the availability of RINs for purchase, 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 its refineries and downstream terminals, all of which can vary significantly from period to period. Based upon recent market prices of RINs and current estimates related to the other variable factors, the petroleum business currently estimates that the total cost of RINs will be approximately $160.0 million to $190.0 million for the year ending December 31, 2016.
If sufficient RINs are unavailable for purchase at times when the petroleum business seeks to purchase RINs, if the petroleum business has to pay a significantly higher price for RINs or if the petroleum business is otherwise unable to meet the EPA’s RFS mandates, its business, financial condition and results of operations could be materially adversely affected.
In order to assess the operating performance of the petroleum business, we compare net sales, less cost of product sold (exclusive of depreciation and amortization), or the refining margin, against an industry refining margin benchmark. The industry refining margin benchmark is calculated by assuming that two barrels of benchmark light sweet crude oil are converted into one barrel of conventional gasoline and one barrel of distillate. This benchmark is referred to as the 2-1-1 crack spread. Because we calculate the benchmark margin using the market value of NYMEX gasoline and heating oil against the market value of NYMEX WTI, we refer to the benchmark as the NYMEX 2-1-1 crack spread, or simply, the 2-1-1 crack spread. The 2-1-1 crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude oil refinery would earn assuming it produced and sold the benchmark production of gasoline and distillate.
Although the 2-1-1 crack spread is a benchmark for refining margin, because the refineries have certain feedstock costs and logistical advantages as compared to a benchmark refinery and their product yield is less than total refinery throughput, the crack spread does not account for all the factors that affect refining margin. The Coffeyville refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that has historically cost less than WTI. The Wynnewood refinery has the capability to process blends of a variety of crude oil ranging from medium sour to light sweet crude oil, although isobutene, gasoline components and normal butane are also typically used. We measure the cost advantage of the crude oil slate by calculating the spread between the price of the delivered crude oil and the price of WTI. The spread is referred to as the consumed crude oil differential. Refining margin can be impacted significantly by the consumed crude oil differential. The consumed crude oil differential will move directionally with changes in the WTS differential to WTI and the WCS differential to WTI as both these differentials indicate the relative price of heavier, more sour, slate to WTI. The correlation between the consumed crude oil differential and published differentials will vary depending on the volume of light medium sour crude oil and heavy sour crude oil the petroleum business purchases as a percent of its total crude oil volume and will correlate more closely with such published differentials the heavier and more sour the crude oil slate.
The petroleum business produces a high volume of high value products, such as gasoline and distillates. The fact that the actual product specifications used to determine the NYMEX 2-1-1 crack spread are different from the actual production in its refineries is because the prices the petroleum business realizes are different than those used to determining the 2-1-1 crack spread. The difference between its price received and the price used to calculate the 2-1-1 crack spread is referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and Ultra-Low Sulfur Diesel PADD II, Group 3 vs. NYMEX basis, or Ultra-Low Sulfur Diesel basis. If both gasoline and Ultra-Low Sulfur Diesel basis are greater than zero, this means that prices in its marketing area exceed those used in the 2-1-1 crack spread.
The petroleum business is significantly affected by developments in the markets in which it operates. For example, numerous pipeline projects expanded the connectivity of the Cushing and Permian Basin markets to the gulf coast, resulting in a decrease in the domestic crude advantage. The refining industry is directly impacted by these events and could see a downward movement in refining margins as a result.
The direct operating expense structure is also important to the petroleum 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 three months ended March 31, 2016, a $1.00 change in natural gas prices would have increased or decreased the petroleum business' natural gas costs by approximately $2.8 million.
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Because crude oil and other feedstocks and refined products are commodities, the petroleum business has no control over the changing market. Therefore, the lower target inventory the petroleum business is able to maintain significantly reduces the impact of commodity price volatility on its earnings. Because most of its titled inventory is valued under the FIFO costing method, price fluctuations on its target level of titled inventory may have a major effect on the petroleum business' financial results from period to period.
Safe and reliable operations at our refineries are key to our financial performance and results of operations. Unscheduled downtime at our refineries may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of scheduled 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. Our 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 first phase of the Coffeyville refinery’s current turnaround was completed in November of 2015. The second phase of the Coffeyville turnaround was completed during the first quarter of 2016. During the three months ended March 31, 2016, we incurred $29.4 million of major scheduled turnaround expenses for the Coffeyville refinery turnaround. The total estimated cost of the second phase, including demobilization, breakdown and clean-up work is expected to be approximately $32.0 million. The next turnaround at our Wynnewood refinery is scheduled to occur in the second half of 2017.
Nitrogen Fertilizer Business
In the nitrogen fertilizer business, earnings and cash flows from operations are primarily affected by the relationship between nitrogen fertilizer product prices, on-stream factors and direct operating expenses. Natural gas is the most significant raw material required in its competitors' production of nitrogen fertilizer. Unlike its competitors, the nitrogen fertilizer business' Coffeyville Fertilizer Facility does not use natural gas as a feedstock and uses a minimal amount of natural gas as an energy source in its operations. Instead, the adjacent Coffeyville refinery supplies the Coffeyville Fertilizer Facility with most of the pet coke feedstock it needs pursuant to a 20-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.
Nitrogen fertilizer prices are also affected by local factors, including local market conditions and the operating levels of competing facilities. An expansion or upgrade of competitors' facilities, 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.
In order to assess the operating performance of the nitrogen fertilizer business, the nitrogen fertilizer business calculates the product pricing at gate as an input to determine operating margin. Product pricing at gate represents net sales less freight revenue divided by product sales volume in tons. The nitrogen fertilizer business believes product pricing at gate is a meaningful measure because it sells products at its plant gate and terminal locations' gates ("sold gate") and delivered to the customer's designated delivery site ("sold delivered"). The relative percentage of sold gate versus sold delivered can change period to period. The product pricing at gate provides a measure that is consistently comparable period to period.
The nitrogen fertilizer business and other competitors in the U.S. farm belt share a significant transportation cost advantage when compared to out-of-region competitors in serving the U.S. farm belt agricultural market; therefore, the nitrogen fertilizer business is able to cost-effectively sell substantially all of its products in the higher margin agricultural market. In contrast, a significant portion of its competitors’ revenues is derived from the lower margin industrial market. The nitrogen fertilizer business' products leave the Coffeyville Fertilizer Facility either in railcars for destinations located principally on the Union Pacific Railroad or in trucks for direct shipment to customers. The nitrogen fertilizer business does not currently incur significant intermediate transfer, storage, barge freight or pipeline freight charges; however, it does incur costs to maintain and repair its railcar fleet for the Coffeyville Fertilizer Facility. Selling products to customers within economic rail transportation limits of the Coffeyville Fertilizer Facility and keeping transportation costs low are keys to maintaining profitability.
The Coffeyville Fertilizer Facility's largest raw material expense used in the production of ammonia is pet coke, which it purchases from the petroleum business and third parties. For the three months ended March 31, 2016 and 2015, the nitrogen fertilizer business incurred approximately $2.1 million and $3.6 million, respectively, for the cost of pet coke, which equaled an average cost per ton of $17 and $29, respectively.
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Safe and reliable operations at the nitrogen fertilizer plants are critical to its financial performance and results of operations. Unplanned downtime of the nitrogen fertilizer plants may result in lost margin 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 plants generally undergo a full facility turnaround every two to three years. Turnarounds are expected to last 14-21 days. The Coffeyville Fertilizer Facility underwent a full facility turnaround in the third quarter of 2015 and is planning to undergo the next scheduled full facility turnaround in the second half of 2017. The East Dubuque Fertilizer Facility is planning to undergo the next scheduled full facility turnaround in the second quarter of 2016, which is expected to last between 25-30 days.
Agreements with the Refining Partnership and the Nitrogen Fertilizer Partnership
We are party to several agreements with the Nitrogen Fertilizer Partnership that govern the business relations among the nitrogen fertilizer business and us and our subsidiaries (including the Refining Partnership). In connection with the Refining Partnership IPO in January 2013, some of our subsidiaries party to these agreements became subsidiaries of the Refining Partnership.
These intercompany agreements include (i) the pet coke supply agreement mentioned above, under which the petroleum business sells pet coke to the nitrogen fertilizer business; (ii) a services agreement, pursuant to which our management operates the nitrogen fertilizer business; (iii) a feedstock and shared services agreement, which governs the provision of feedstocks, including hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; (iv) a raw water and facilities sharing agreement, which allocates raw water resources between the two businesses; (v) an easement agreement; (vi) an environmental agreement; and (vii) a lease agreement pursuant to which the petroleum business leases office space and laboratory space to the Nitrogen Fertilizer Partnership. These agreements were not the result of arm's-length negotiations and the terms of these agreements are not necessarily at least as favorable to the parties to these agreements as terms which could have been obtained from unaffiliated third parties.
In connection with the Refining Partnership IPO, we entered into a number of agreements with the Refining Partnership, including (i) a $250.0 million intercompany credit facility between CRLLC and the Refining Partnership and (ii) a services agreement, pursuant to which our management operates the petroleum business.
On April 1, 2016, in connection with the closing of the mergers with East Dubuque GP and East Dubuque, we entered into a $300.0 million senior term loan credit facility with the Nitrogen Fertilizer Partnership, with CRLLC as the lender. Refer to Part I, Item 2, “Liquidity and Capital Resources” for further discussion of the credit facility.
Crude Oil Supply Agreement
On August 31, 2012, Coffeyville Resources Refining and Marketing, LLC ("CRRM") and Vitol Inc. ("Vitol") entered into an Amended and Restated Crude Oil Supply Agreement (as amended, the "Vitol Agreement"). Under the agreement, Vitol supplies the petroleum business with crude oil and intermediation logistics, which helps the petroleum business to reduce its inventory position and mitigate crude oil pricing risk. The Vitol Agreement will automatically renew for successive one-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 any Renewal Term. The Vitol Agreement currently extends through December 31, 2016.
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Factors Affecting Comparability
Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons presented and discussed below.

| Three Months Ended March 31,
| 2016 |  | 2015
| (in millions)
Loss on derivatives, net | 1.2 |  |  | 51.4 |
Major scheduled turnaround expenses(1) | 29.4 |  |  | — |

_______________________________________

(1) | Represents expense associated with major scheduled turnaround activities performed at the Coffeyville refinery.

Noncontrolling Interest
Prior to the Refining Partnership IPO on January 23, 2013, the noncontrolling interest reflected in our consolidated financial statements represented the approximately 30% interest in the Nitrogen Fertilizer Partnership held by public common unitholders, which was adjusted each reporting period for the noncontrolling ownership percentage of the Nitrogen Fertilizer Partnership'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 to the public, which represented an approximately 19% interest of the Refining Partnership. Effective with the Refining Partnership's IPO, the noncontrolling interest reflected on the 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's closing of the Underwritten Offering, the noncontrolling interest related to the Refining Partnership reflected in our consolidated financial statements subsequent to the completion of the offering in the second quarter of 2013 and prior to June 30, 2014 was approximately 29%. Upon completion of the Second Underwritten Offering on June 30, 2014 and through June 23, 2014, the noncontrolling interest reflected in our condensed consolidated financial statements was approximately 33%. On July 24, 2014, upon exercise of the underwriters' option associated with the Second Underwritten Offering, the noncontrolling interest reflected in our condensed consolidated financial statements from such date and for the three months ended March 31, 2016 was approximately 34%. Additionally, as a result of the Nitrogen Fertilizer Partnership's Secondary Offering, the noncontrolling interest related to the Nitrogen Fertilizer Partnership reflected in our condensed consolidated financial statements subsequent to the completion of the Secondary Offering on May 28, 2013 and for the three months ended March 31, 2016 was approximately 47%.
Distributions to CVR Partners Unitholders
The current policy of the board of directors of the Nitrogen Fertilizer Partnership'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's general partner following the end of such quarter, subject to the limitations discussed below. The board of directors of the Nitrogen Fertilizer Partnership's general partner calculates available cash for distribution starting with Adjusted Nitrogen Fertilizer EBITDA reduced for (i) cash needed for net cash interest expense (excluding capitalized interest) and debt service and other contractual obligations, (ii) maintenance capital expenditures, (iii) to the extent applicable, major scheduled turnaround expenses and reserves for future operating or capital needs that the board of directors of the Nitrogen Fertilizer Partnership's general partner deems necessary or appropriate, and (iv) expenses associated with the East Dubuque mergers, if any. Available cash for distribution may be increased by the release of previously established cash reserves, if any, at the discretion of the board of directors of the Nitrogen Fertilizer Partnership's general partner. Actual distributions are set by the board of directors of the Nitrogen Fertilizer Partnership's general partner, and, prior to April 1, 2016, were subject to the limitations in accordance with the Merger Agreement discussed below. The board of directors of the Nitrogen Fertilizer Partnership'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 Merger Agreement with East Dubuque and East Dubuque GP included customary restrictions on the conduct of the Nitrogen Fertilizer Partnership's business prior to the completion of the mergers, generally requiring the Nitrogen Fertilizer Partnership to conduct its business in the ordinary course and subjecting the Nitrogen Fertilizer Partnership to a variety of specified limitations. In accordance with the terms of the Merger Agreement, beginning with the distribution for the third quarter of 2015 and until the closing of the mergers, the Nitrogen Fertilizer Partnership could not make or declare distributions in excess of available cash for distribution in respect of any quarter. The mergers closed on April 1, 2016, and this restriction terminated.
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On March 7, 2016, the Nitrogen Fertilizer Partnership paid a cash distribution to the Nitrogen Fertilizer Partnership's unitholders of record at the close of business on February 29, 2016 for the fourth quarter of 2015 in the amount of $0.27 per common unit, or $19.7 million in aggregate. We received $10.5 million in respect of our common units.
On April 27, 2016, the board of directors of the Nitrogen Fertilizer Partnership's general partner declared a cash distribution for the first quarter of 2016 to the Nitrogen Fertilizer Partnership's unitholders of $0.27 per common unit or $30.6 million in aggregate. The cash distribution will be paid on May 16, 2016 to the unitholders of record at the close of business on May 9, 2016. We will receive $10.5 million in respect of our common units.
Distributions to CVR Refining Unitholders
The current policy of the board of directors of the Refining Partnership'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's general partner following the end of such quarter and will generally equal Adjusted Petroleum EBITDA reduced for (i) cash needed for debt service, (ii) reserves for environmental and maintenance capital expenditures, (iii) reserves for major scheduled turnaround expenses and, (iv) to the extent applicable, reserves for future operating or capital needs that the board of directors of the Refining Partnership's general partner deems necessary or appropriate, if any. Available cash for distribution may be increased by the release of previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of the Refining Partnership's general partner. Actual distributions are set by the board of directors of the Refining Partnership's general partner. The board of directors of the Refining Partnership'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.
CVR Energy Dividends
On March 7, 2016, the Company paid a cash dividend to stockholders of record at the close of business on February 29, 2016 for the fourth quarter of 2015 in the amount of $0.50 per share, or $43.4 million in aggregate.
On April 27, 2016, our board of directors declared a dividend for the first quarter of 2016 of $0.50 per share, or $43.4 million in aggregate. The dividend will be paid on May 16, 2016 to stockholders of record at the close of business on May 9, 2016.
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Results of Operations
The following tables summarize the financial data and key operating statistics for CVR and our two operating segments for the three months ended March 31, 2016 and 2015. 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 Discussion and Analysis of Financial Condition and Results of Operations," except for the balance sheet data as of December 31, 2015, is unaudited.

| Three Months Ended March 31,
| 2016 |  | 2015
| (in millions, except per share data)
Consolidated Statement of Operations Data |  |  |
Net sales | $ | 905.5 |  |  | $ | 1,388.9 |
Cost of product sold(1) | 736.8 |  |  | 1,073.6 |
Direct operating expenses(1) | 141.4 |  |  | 111.4 |
Selling, general and administrative expenses(1) | 27.2 |  |  | 25.3 |
Depreciation and amortization | 40.0 |  |  | 42.0 |
Operating income (loss) | (39.9 | ) |  | 136.6 |
Interest expense and other financing costs | (12.1 | ) |  | (12.7 | )
Interest income | 0.2 |  |  | 0.2 |
Gain (loss) on derivatives, net | (1.2 | ) |  | (51.4 | )
Other income (expense), net | 0.3 |  |  | 36.0 |
Income (loss) before income tax expense | (52.7 | ) |  | 108.7 |
Income tax expense (benefit) | (21.8 | ) |  | 24.0 |
Net income (loss) | (30.9 | ) |  | 84.7 |
Less: Net income (loss) attributable to noncontrolling interest | (14.7 | ) |  | 29.8 |
Net income (loss) attributable to CVR Energy stockholders | $ | (16.2 | ) |  | $ | 54.9 |
Basic earnings (loss) per share | $ | (0.19 | ) |  | $ | 0.63 |
Diluted earnings (loss) per share | $ | (0.19 | ) |  | $ | 0.63 |
Dividends declared per share | $ | 0.50 |  |  | $ | 0.50 |
Adjusted EBITDA(2) | $ | 36.2 |  |  | $ | 163.7 |
Weighted-average common shares outstanding: |  |  |
Basic | 86.8 |  |  | 86.8 |
Diluted | 86.8 |  |  | 86.8 |

| As of March 31, 2016 |  | As of December 31, 2015
|  |  | (audited)
| (in millions)
Balance Sheet Data |  |  |
Cash and cash equivalents | $ | 681.8 |  |  | $ | 765.1 |
Working capital (3) | 679.5 |  |  | 789.0 |
Total assets (3) | 3,183.5 |  |  | 3,299.4 |
Total debt, including current portion (3) | 667.1 |  |  | 667.1 |
Total CVR Energy stockholders' equity | 924.5 |  |  | 984.1 |

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| Three Months Ended March 31,
| 2016 |  | 2015
| (in millions)
Cash Flow Data |  |  |
Net cash flow provided by (used in): |  |  |
Operating activities | $ | 21.6 |  |  | $ | 178.2 |
Investing activities | (51.7 | ) |  | (3.4 | )
Financing activities | (53.2 | ) |  | (76.3 | )
Net cash flow | $ | (83.3 | ) |  | $ | 98.5 |
Capital expenditures for property, plant and equipment | $ | 47.5 |  |  | $ | 45.5 |

(1) | Amounts are shown exclusive of depreciation and amortization.

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:

| Three Months Ended March 31,
| 2016 |  | 2015
| (in millions)
Depreciation and amortization excluded from cost of product sold | $ | 1.7 |  |  | $ | 1.8 |
Depreciation and amortization excluded from direct operating expenses | 36.2 |  |  | 38.5 |
Depreciation and amortization excluded from selling, general and administrative expenses | 2.1 |  |  | 1.7 |
Total depreciation and amortization | $ | 40.0 |  |  | $ | 42.0 |

(2) | EBITDA and Adjusted EBITDA. EBITDA represents net income (loss) before (i) interest expense and other financing costs, net of interest income, (ii) income tax expense and (iii) depreciation and amortization. Adjusted EBITDA represents EBITDA adjusted for (i) FIFO impact (favorable) unfavorable, (ii) loss on extinguishment of debt, (iii) major scheduled turnaround expenses, (iv) (gain) loss on derivatives, net, (v) current period settlements on derivative contracts and (vi) expenses associated with the East Dubuque mergers. EBITDA and Adjusted EBITDA are not recognized terms under GAAP and should not be substituted for net income (loss) or cash flow from operations. Management believes that EBITDA and Adjusted EBITDA enable investors to better understand and evaluate our ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economic performance. EBITDA and Adjusted EBITDA presented by other companies may not be comparable to our presentation, since each company may define these terms differently.

EBITDA for the three months ended March 31, 2015 was also adjusted for share-based compensation expense in calculating Adjusted EBITDA. Beginning in 2016, share-based compensation expense is no longer utilized as an adjustment to derive Adjusted EBITDA as no equity-settled awards remain outstanding for CVR Energy or any of its subsidiaries, and CVR Partners and CVR Refining are responsible for reimbursing CVR Energy for their allocated portion of all outstanding awards. Management believes, based on the nature, classification and cash settlement feature of the currently outstanding awards, that it is no longer necessary to adjust EBITDA for share-based compensation expense to derive Adjusted EBITDA. For comparison purposes we have also provided Adjusted EBITDA for the three months ended March 31, 2015 without adjusting for share-based compensation expense in order to provide a comparison to Adjusted EBITDA for the three months ended March 31, 2016.

(3) | Prior period amounts have been retrospectively adjusted for Accounting Standard Update No. 2015-03, which requires that costs incurred to issue debt be presented in the balance sheet as a direct reduction from the carrying value of the debt.

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Below is a reconciliation of net income (loss) to EBITDA and EBITDA to Adjusted EBITDA for the three months ended March 31, 2016 and 2015:

| Three Months Ended March 31,
| 2016 |  | 2015
| (in millions)
Net income (loss) attributable to CVR Energy stockholders | $ | (16.2 | ) |  | $ | 54.9 |
Add: |  |  |
Interest expense and other financing costs, net of interest income | 11.9 |  |  | 12.5 |
Income tax expense (benefit) | (21.8 | ) |  | 24.0 |
Depreciation and amortization | 40.0 |  |  | 42.0 |
EBITDA adjustments included in noncontrolling interest | (18.4 | ) |  | (19.4 | )
EBITDA | (4.5 | ) |  | 114.0 |
Add: |  |  |
FIFO impact, unfavorable | 8.8 |  |  | 24.5 |
Share-based compensation(a) | — |  |  | 4.0 |
Major scheduled turnaround expenses | 29.4 |  |  | — |
Loss on derivatives, net | 1.2 |  |  | 51.4 |
Current period settlement on derivative contracts(b) | 21.4 |  |  | (6.3 | )
Expenses associated with the East Dubuque mergers(c) | 1.2 |  |  | — |
Adjustments included in noncontrolling interest | (21.3 | ) |  | (23.9 | )
Adjusted EBITDA | $ | 36.2 |  |  | $ | 163.7 |

(a) | Adjusted EBITDA for the three months ended March 31, 2015 would have been $159.7 million without adjusting for share-based compensation expense of $4.0 million.

(b) | Represents the portion of 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.

(c) | Represents legal and other professional fees and other merger related expenses incurred by the Nitrogen Fertilizer Partnership in regards to the East Dubuque mergers. Refer to Part I, Item 1, Note 1 ("Organization and History of the Company and Basis of Presentation") for further details.

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Consolidated Results of Operations
Three Months Ended March 31, 2016 Compared to the Three Months Ended March 31, 2015 (Consolidated)
Net Sales. Consolidated net sales were $905.5 million for the three months ended March 31, 2016 compared to $1,388.9 million for the three months ended March 31, 2015. The reduction of $483.4 million year over year was primarily attributable to the decrease in sales in the petroleum business. The petroleum segment's net sales decreased $470.4 million due to significantly lower sales prices for the transportation fuels and petroleum by-products. The petroleum segment's average sales price per gallon for the three months ended March 31, 2016 of $1.04 for gasoline and $1.05 for distillates decreased by 29.7% and 37.9%, respectively, as compared to the three months ended March 31, 2015. The nitrogen fertilizer segment's net sales also decreased by approximately $20.0 million mainly as a result of lower UAN sales prices and volumes, partially offset by higher ammonia sales volumes.
Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was $736.8 million for the three months ended March 31, 2016, as compared to $1,073.6 million for the three months ended March 31, 2015. The decrease of $336.8 million or 31% primarily resulted from a decrease in cost of consumed crude. This decrease was due to reduced crude oil throughput volume and crude prices (WTI benchmark crude price decreased 30.8%). The crude oil throughput volume decreased by approximately 7.7% for the three months ended March 31, 2016 due to the second phase of a major scheduled turnaround at the Coffeyville refinery in the first quarter of 2016. The nitrogen fertilizer segment's cost of product sold decrease d by $9.5 million, or 32%, primarily due to reduced ammonia purchases and decreased market prices of petroleum coke during the three months ended March 31, 2016.
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $141.4 million for the three months ended March 31, 2016, as compared to $111.4 million for the three months ended March 31, 2015. The increase of $30.0 million was primarily the result of expenses for major scheduled turnaround activities performed at the Coffeyville refinery of $29.4 million in the first quarter of 2016. Direct operating expenses per barrel of crude oil throughput for the three months ended March 31, 2016 increased to $7.02 per barrel, as compared to $4.79 per barrel for the three months ended March 31, 2015, primarily due to the turnaround costs incurred and lower throughput volumes.
Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $27.2 million for the three months ended March 31, 2016, as compared to $25.3 million for the three months ended March 31, 2015. The increase of $1.9 million was primarily attributable to expenses associated with the East Dubuque mergers and certain other employee and third-party expenses.
Operating Income (Loss). Consolidated operating loss was $39.9 million for the three months ended March 31, 2016, as compared to operating income of $136.6 million for the three months ended March 31, 2015, a decrease of $176.5 million. The decrease in operating income was primarily due to a decrease of $165.2 million at the petroleum business as a result of lower refining margins and increases in direct operating expenses due to the second phase of the Coffeyville refinery turnaround. Additionally, the decrease of $11.8 million at the Nitrogen fertilizer business was largely due to a decrease in net sales coupled with increased selling general and administrative expenses due to costs associated with the East Dubuque mergers.
Interest Expense. Consolidated interest expense for the three months ended March 31, 2016 was $12.1 million, as compared to $12.7 million for the three months ended March 31, 2015. The decrease of $0.6 million primarily resulted from higher capitalized interest for the three months ended March 31, 2016 compared to the three months ended March 31, 2015.
Loss on Derivatives, net. For the three months ended March 31, 2016, the petroleum segment recorded a $1.2 million net loss on derivatives. This compares to a $51.4 million net loss on derivatives for the three months ended March 31, 2015. This change was primarily due to changes in crack spreads during the period, year over year. The petroleum segment regularly enters into over-the-counter commodity swaps to fix the margin on a portion of its future gasoline and distillate production.
Income Tax Expense (Benefit). Income tax benefit for the three months ended March 31, 2016 was $21.8 million or 41.4% of loss before income taxes, as compared to income tax expense for the three months ended March 31, 2015 of $24.0 million or 22.1% of income before income taxes. Our 2016 effective tax rate varies from the expected statutory rate primarily due to the reduction of income (loss) subject to tax associated with the noncontrolling ownership interests in CVR Refining's and CVR Partners' earnings (loss) and the benefits related to state income tax credits.
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Petroleum Business Results of Operations
The petroleum business includes the operations of both the Coffeyville and Wynnewood refineries. The following tables below provide an overview of the petroleum business' results of operations, relevant market indicators and its key operating statistics for the three months ended March 31, 2016 and 2015:

| Three Months Ended March 31,
| 2016 |  | 2015
| (in millions)
Petroleum Segment Summary Financial Results |  |  |
Net sales | $ | 834.0 |  |  | $ | 1,304.4 |
Cost of product sold(1) | 722.3 |  |  | 1,056.1 |
Direct operating expenses(1)(2) | 88.3 |  |  | 87.0 |
Major scheduled turnaround expenses | 29.4 |  |  | — |
Selling, general and administrative expenses(1) | 18.5 |  |  | 18.1 |
Depreciation and amortization | 31.5 |  |  | 34.0 |
Operating income (loss) | (56.0 | ) |  | 109.2 |
Interest expense and other financing costs | (10.8 | ) |  | (11.3 | )
Interest income | — |  |  | 0.1 |
Loss on derivatives, net | (1.2 | ) |  | (51.4 | )
Other income, net | — |  |  | 0.1 |
Income (loss) before income tax expense | (68.0 | ) |  | 46.7 |
Income tax expense | — |  |  | — |
Net income (loss) | $ | (68.0 | ) |  | $ | 46.7 |
Gross profit (loss)(3) | $ | (37.5 | ) |  | $ | 127.3 |
Refining margin(4) | $ | 111.7 |  |  | $ | 248.3 |
Adjusted Petroleum EBITDA(5) | $ | 35.1 |  |  | $ | 161.7 |

| Three Months Ended March 31,
| 2016 |  | 2015
| (dollars per barrel)
Key Operating Statistics |  |  |
Per crude oil throughput barrel: |  |  |
Refining margin(4) | $ | 6.67 |  |  | $ | 13.68 |
Gross profit (loss)(3) | $ | (2.24 | ) |  | $ | 7.02 |
Direct operating expenses and major scheduled turnaround expenses(1)(2) | $ | 7.02 |  |  | $ | 4.79 |
Direct operating expenses and major scheduled turnaround expenses per barrel sold(1)(6) | $ | 6.40 |  |  | $ | 4.44 |
Barrels sold (barrels per day)(6) | 201,970 |  |  | 217,686 |

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| Three Months Ended March 31,
| 2016 |  | 2015
|  |  | % |  |  |  | %
Refining Throughput and Production Data (bpd) |  |  |  |  |  |  |
Throughput: |  |  |  |  |  |  |
Sweet | 170,728 |  |  | 87.2 |  | 175,376 |  |  | 81.6
Medium | 1,513 |  |  | 0.8 |  | 6,630 |  |  | 3.1
Heavy sour | 11,914 |  |  | 6.0 |  | 19,658 |  |  | 9.1
Total crude oil throughput | 184,155 |  |  | 94.0 |  | 201,664 |  |  | 93.8
All other feedstocks and blendstocks | 11,704 |  |  | 6.0 |  | 13,359 |  |  | 6.2
Total throughput | 195,859 |  |  | 100.0 |  | 215,023 |  |  | 100.0
Production: |  |  |  |  |  |  |
Gasoline | 105,878 |  |  | 54.2 |  | 109,096 |  |  | 50.2
Distillate | 77,996 |  |  | 39.9 |  | 89,436 |  |  | 41.1
Other (excluding internally produced fuel) | 11,519 |  |  | 5.9 |  | 18,857 |  |  | 8.7
Total refining production (excluding internally produced fuel) | 195,393 |  |  | 100.0 |  | 217,389 |  |  | 100.0
Product price (dollars per gallon): |  |  |  |  |  |  |
Gasoline | $ | 1.04 |  |  |  |  | $ | 1.48 |  |  |
Distillate | 1.05 |  |  |  |  | 1.69 |  |  |

| Three Months Ended March 31,
| 2016 |  | 2015
Market Indicators (dollars per barrel) |  |  |
West Texas Intermediate (WTI) NYMEX | $ | 33.63 |  |  | $ | 48.57 |
Crude Oil Differentials: |  |  |  |
WTI less WTS (light/medium sour) | 0.13 |  |  | 0.99 |
WTI less WCS (heavy sour) | 13.62 |  |  | 13.62 |
NYMEX Crack Spreads: |  |  |  |
Gasoline | 15.84 |  |  | 18.54 |
Heating Oil | 11.91 |  |  | 27.06 |
NYMEX 2-1-1 Crack Spread | 13.88 |  |  | 22.80 |
PADD II Group 3 Basis: |  |  |  |
Gasoline | (5.88 | ) |  | (3.50 | )
Ultra Low Sulfur Diesel | (1.01 | ) |  | (4.52 | )
PADD II Group 3 Product Crack Spread: |  |  |  |
Gasoline | 9.97 |  |  | 15.04 |
Ultra Low Sulfur Diesel | 10.90 |  |  | 22.54 |
PADD II Group 3 2-1-1 | 10.43 |  |  | 18.79 |

(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 do not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period.

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(3) | Gross profit (loss) 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 (loss) per crude oil throughput barrel, we utilize the total dollar figures for gross profit (loss) 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 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 are 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 performance.

(5) | Petroleum EBITDA represents net income (loss) for the petroleum segment before (i) interest expense and other financing costs, net of interest income, (ii) income tax expense and (iii) depreciation and amortization. Adjusted Petroleum EBITDA represents Petroleum EBITDA adjusted for (i) FIFO impact (favorable) unfavorable, (ii) share-based compensation, non-cash, (iii) loss on extinguishment of debt, (iv) major scheduled turnaround expenses, (v) (gain) loss on derivatives, net and (vi) current period settlements on derivative contracts.

We present Adjusted Petroleum EBITDA because it is the starting point for calculating the Refining Partnership's available cash for distribution. Petroleum EBITDA and Adjusted Petroleum EBITDA are not recognized terms under GAAP and should not be substituted for net income (loss) as a measure of performance. Management believes that Petroleum EBITDA and Adjusted Petroleum EBITDA enable investors to better understand the Refining Partnership's ability to make distributions to its common unitholders, help investors evaluate the petroleum segment's ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economic performance. Petroleum EBITDA and 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 net income (loss) for the petroleum segment to Petroleum EBITDA and Petroleum EBITDA to Adjusted Petroleum EBITDA for the three months ended March 31, 2016 and 2015:

| Three Months Ended March 31,
| 2016 |  | 2015
| (in millions)
Petroleum: |  |  |
Petroleum net income (loss) | $ | (68.0 | ) |  | $ | 46.7 |
Add: |  |  |
Interest expense and other financing costs, net of interest income | 10.8 |  |  | 11.2 |
Income tax expense | — |  |  | — |
Depreciation and amortization | 31.5 |  |  | 34.0 |
Petroleum EBITDA | (25.7 | ) |  | 91.9 |
Add: |  |  |
FIFO impact, unfavorable(a) | 8.8 |  |  | 24.5 |
Share-based compensation, non-cash | — |  |  | 0.2 |
Major scheduled turnaround expenses(b) | 29.4 |  |  | — |
Loss on derivatives, net | 1.2 |  |  | 51.4 |
Current period settlements on derivative contracts(c) | 21.4 |  |  | (6.3 | )
Adjusted Petroleum EBITDA | $ | 35.1 |  |  | $ | 161.7 |

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(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 a favorable FIFO impact when crude oil prices increase and an unfavorable FIFO impact 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 major scheduled turnaround activities performed at the Coffeyville refinery.

(c) | Represents the portion of 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 total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of barrels sold for the period to derive the metric.

| Three Months Ended March 31,
| 2016 |  | 2015
| (in millions)
Coffeyville Refinery Financial Results |  |  |
Net sales | $ | 528.0 |  |  | $ | 851.7 |
Cost of product sold (exclusive of depreciation and amortization) | 462.7 |  |  | 700.9 |
Direct operating expenses (exclusive of depreciation and amortization) | 47.6 |  |  | 50.4 |
Major scheduled turnaround expenses | 29.4 |  |  | — |
Depreciation and amortization | 16.9 |  |  | 19.4 |
Gross profit (loss) | $ | (28.6 | ) |  | $ | 81.0 |
Plus: |  |  |
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | 77.0 |  |  | 50.4 |
Depreciation and amortization | 16.9 |  |  | 19.4 |
Refining margin | $ | 65.3 |  |  | $ | 150.8 |

| Three Months Ended March 31,
| 2016 |  | 2015
| (dollars per barrel)
Coffeyville Refinery Key Operating Statistics |  |  |
Per crude oil throughput barrel: |  |  |
Refining margin | $ | 6.75 |  |  | $ | 13.21 |
Gross profit (loss) | $ | (2.96 | ) |  | $ | 7.10 |
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | $ | 7.96 |  |  | $ | 4.42 |
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold | $ | 6.89 |  |  | $ | 3.97 |
Barrels sold (barrels per day) | 122,838 |  |  | 140,974 |

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| Three Months Ended March 31,
| 2016 |  | 2015
|  |  | % |  |  |  | %
Coffeyville Refinery Throughput and Production Data (bpd) |  |  |  |  |  |  |
Throughput: |  |  |  |  |  |  |
Sweet | 92,938 |  |  | 80.3 |  | 100,532 |  |  | 73.4
Medium | 1,513 |  |  | 1.3 |  | 6,630 |  |  | 4.8
Heavy sour | 11,914 |  |  | 10.3 |  | 19,658 |  |  | 14.3
Total crude oil throughput | 106,365 |  |  | 91.9 |  | 126,820 |  |  | 92.5
All other feedstocks and blendstocks | 9,344 |  |  | 8.1 |  | 10,227 |  |  | 7.5
Total throughput | 115,709 |  |  | 100.0 |  | 137,047 |  |  | 100.0
Production: |  |  |  |  |  |  |
Gasoline | 64,033 |  |  | 54.8 |  | 67,853 |  |  | 48.3
Distillate | 47,147 |  |  | 40.3 |  | 59,415 |  |  | 42.3
Other (excluding internally produced fuel) | 5,768 |  |  | 4.9 |  | 13,228 |  |  | 9.4
Total refining production (excluding internally produced fuel) | 116,948 |  |  | 100.0 |  | 140,496 |  |  | 100.0

| Three Months Ended March 31,
| 2016 |  | 2015
| (in millions)
Wynnewood Refinery Financial Results |  |  |
Net sales | $ | 304.8 |  |  | $ | 451.7 |
Cost of product sold (exclusive of depreciation and amortization) | 259.4 |  |  | 355.6 |
Direct operating expenses (exclusive of depreciation and amortization) | 40.6 |  |  | 36.6 |
Major scheduled turnaround expenses | — |  |  | — |
Depreciation and amortization | 12.7 |  |  | 12.5 |
Gross profit (loss) | $ | (7.9 | ) |  | $ | 47.0 |
Plus: |  |  |
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | 40.6 |  |  | 36.6 |
Depreciation and amortization | 12.7 |  |  | 12.5 |
Refining margin | $ | 45.4 |  |  | $ | 96.1 |

| Three Months Ended March 31,
| 2016 |  | 2015
| (dollars per barrel)
Wynnewood Refinery Key Operating Statistics |  |  |
Per crude oil throughput barrel: |  |  |
Refining margin | $ | 6.41 |  |  | $ | 14.27 |
Gross profit (loss) | $ | (1.11 | ) |  | $ | 6.98 |
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | $ | 5.74 |  |  | $ | 5.43 |
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold | $ | 5.64 |  |  | $ | 5.30 |
Barrels sold (barrels per day) | 79,132 |  |  | 76,712 |

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| Three Months Ended March 31,
| 2016 |  | 2015
|  |  | % |  |  |  | %
Wynnewood Refinery Throughput and Production Data (bpd) |  |  |  |  |  |  |
Throughput: |  |  |  |  |  |  |
Sweet | 77,790 |  |  | 97.1 |  | 74,844 |  |  | 96.0
Medium | — |  |  | — |  | — |  |  | —
Heavy sour | — |  |  | — |  | — |  |  | —
Total crude oil throughput | 77,790 |  |  | 97.1 |  | 74,844 |  |  | 96.0
All other feedstocks and blendstocks | 2,360 |  |  | 2.9 |  | 3,132 |  |  | 4.0
Total throughput | 80,150 |  |  | 100.0 |  | 77,976 |  |  | 100.0
Production: |  |  |  |  |  |  |
Gasoline | 41,845 |  |  | 53.4 |  | 41,243 |  |  | 53.7
Distillate | 30,849 |  |  | 39.3 |  | 30,021 |  |  | 39.0
Other (excluding internally produced fuel) | 5,751 |  |  | 7.3 |  | 5,629 |  |  | 7.3
Total refining production (excluding internally produced fuel) | 78,445 |  |  | 100.0 |  | 76,893 |  |  | 100.0

Three Months Ended March 31, 2016 Compared to the Three Months Ended March 31, 2015 (Petroleum Business)
Net Sales. Petroleum net sales were $834.0 million for the three months ended March 31, 2016 compared to $1,304.4 million for the three months ended March 31, 2015. The decrease of $470.4 million was largely the result of significantly lower sales prices for our transportation fuels and by-products. For the three months ended March 31, 2016, our average sales price per gallon of gasoline of $1.04 decreased by approximately 29.7%, as compared to the three months ended March 31, 2015, and our average sales per gallon for distillates of $1.05 for the three months ended March 31, 2016 decreased approximately 37.9%, as compared to the three months ended March 31, 2015. Overall sales volumes decreased approximately 4.4% for the three months ended March 31, 2016, as compared to the three months ended March 31, 2015. Sales volumes for the three months ended March 31, 2016 were impacted by decreased production as a result of the second phase of the major scheduled turnaround completed at the Coffeyville refinery.
The following table demonstrates the impact of changes in sales volumes and sales prices for gasoline and distillates for the three months ended March 31, 2016 compared to the three months ended March 31, 2015:

| Three Months Ended March 31, 2016 |  | Three Months Ended March 31, 2015 |  | 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 | 10.8 |  |  | $ | 43.60 |  |  | $ | 470.1 |  |  | 10.7 |  |  | $ | 62.36 |  |  | $ | 667.6 |  |  | 0.1 |  |  | $ | (197.5 | ) |  | $ | (202.2 | ) |  | $ | 4.6 |
Distillates | 7.4 |  |  | $ | 44.07 |  |  | $ | 324.2 |  |  | 8.2 |  |  | $ | 70.88 |  |  | $ | 581.0 |  |  | (0.8 | ) |  | $ | (256.8 | ) |  | $ | (197.3 | ) |  | $ | (59.6 | )

(1) | Barrels in millions

(2) | Sales dollars in millions

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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 and transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciation and amortization) was $722.3 million for the three months ended March 31, 2016 compared to $1,056.1 million for the three months ended March 31, 2015. The decrease of $333.8 million was primarily the result of decreases in the cost of consumed crude. The decrease in consumed crude oil costs was due to a decrease in crude oil throughput volume and crude prices. The WTI benchmark crude price decreased approximately 30.8% from the three months ended March 31, 2015. The average cost per barrel of crude oil consumed for the three months ended March 31, 2016 was $31.72 compared to $47.51 for the comparable period in 2015, a decrease of approximately 33.2%. Our crude oil throughput volume decreased by approximately 7.7% for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015 due primarily to the completion of the second phase of the major scheduled turnaround at the Coffeyville refinery in the first quarter of 2016. Under the FIFO method of accounting, changes in crude oil prices can also cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable or unfavorable FIFO inventory impact when crude oil prices increase or decrease. For the three months ended March 31, 2016, our petroleum business had an unfavorable FIFO inventory impact of $8.8 million compared to an unfavorable FIFO inventory impact of $24.5 million for the comparable period of 2015.
Refining margin per barrel of crude oil throughput decreased to $6.67 for the three months ended March 31, 2016 from $13.68 for the three months ended March 31, 2015. Refining margin adjusted for FIFO impact was $7.19 per crude oil throughput barrel for the three months ended March 31, 2016, as compared to $15.03 per crude oil throughput barrel for the three months ended March 31, 2015. Gross profit (loss) per barrel was a loss of $2.24 for the three months ended March 31, 2016, as compared to gross profit per barrel of $7.02 in the equivalent period in 2015. The decrease in refining margin and gross profit (loss) per barrel was primarily due to a weaker spread between crude oil and transportation fuels. The NYMEX 2-1-1 crack spread for the three months ended March 31, 2016 was $13.88 per barrel, a decrease of approximately 39.1% over the NYMEX 2-1-1 crack spread of $22.80 per barrel for the three months ended March 31, 2015.
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for the petroleum business include costs associated with the actual operations of the 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 and major scheduled turnaround expenses (exclusive of depreciation and amortization) were $117.7 million for the three months ended March 31, 2016 compared to direct operating expenses of $87.0 million for the three months ended March 31, 2015. The increase of $30.7 million was primarily the result of major scheduled turnaround activities performed at the Coffeyville refinery of $29.4 million. Direct operating expenses per barrel of crude oil throughput for the three months ended March 31, 2016 increased to $7.02 per barrel, as compared to $4.79 per barrel for the three months ended March 31, 2015. The increase in the direct operating expenses per barrel of crude oil throughput is primarily a function of higher overall expenses and lower throughput volumes.
Operating Income (loss). Petroleum operating loss was $56.0 million for the three months ended March 31, 2016, as compared to operating income of $109.2 million for the three months ended March 31, 2015. The decrease of $165.2 million was primarily the result of a decrease in the refining margin of $136.6 million due to significant drop in sale price of our transportation fuels and by-products, and an increase in direct operating expenses of $30.7 million primarily due to the second phase of the Coffeyville refinery turnaround during the first quarter of 2016.
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Nitrogen Fertilizer Business Results of Operations
The tables below provide an overview of the nitrogen fertilizer business' results of operations, relevant market indicators and key operating statistics for the three months ended March 31, 2016 and 2015:

| Three Months Ended March 31,
| 2016 |  | 2015
| (in millions)
Nitrogen Fertilizer Business Financial Results |  |  |
Net sales | $ | 73.1 |  |  | $ | 93.1 |
Cost of product sold(1) | 16.3 |  |  | 25.8 |
Direct operating expenses(1) | 23.7 |  |  | 24.4 |
Selling, general and administrative(1) | 6.4 |  |  | 4.6 |
Depreciation and amortization | 7.0 |  |  | 6.8 |
Operating income | 19.7 |  |  | 31.5 |
Interest expense and other financing costs | (1.7 | ) |  | (1.7 | )
Other income, net | — |  |  | — |
Income before income tax expense | 18.0 |  |  | 29.8 |
Income tax expense | — |  |  | — |
Net income | $ | 18.0 |  |  | $ | 29.8 |
Adjusted Nitrogen Fertilizer EBITDA(2) | $ | 27.9 |  |  | $ | 38.4 |

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| Three Months Ended March 31,
| 2016 |  | 2015
Key Operating Statistics |  |  |
Production volume (thousand tons): |  |  |
Ammonia (gross produced)(3) | 113.7 |  |  | 96.0 |
Ammonia (net available for sale)(3)(4) | 15.1 |  |  | 14.6 |
UAN | 248.2 |  |  | 252.1 |
Pet coke consumed (thousand tons) | 126.9 |  |  | 124.9 |
Pet coke consumed (cost per ton)(5) | $ | 17 |  |  | $ | 29 |
Sales (thousand tons): |  |  |
Ammonia | 24.4 |  |  | 12.8 |
UAN | 267.0 |  |  | 274.5 |
Product pricing at gate (dollars per ton)(6): |  |  |
Ammonia | $ | 367 |  |  | $ | 553 |
UAN | $ | 209 |  |  | $ | 263 |
On-stream factor(7): |  |  |
Gasification | 97.7 | % |  | 99.4 | %
Ammonia | 97.2 | % |  | 94.4 | %
UAN | 91.4 | % |  | 97.8 | %
Reconciliation of net sales (dollars in millions): |  |  |
Sales net at gate | $ | 64.8 |  |  | $ | 79.2 |
Freight in revenue | 6.9 |  |  | 7.0 |
Hydrogen revenue | 1.1 |  |  | 6.5 |
Other revenue | 0.3 |  |  | 0.4 |
Total net sales | $ | 73.1 |  |  | $ | 93.1 |

| Three Months Ended March 31,
| 2016 |  | 2015
Market Indicators |  |  |
Natural gas NYMEX (dollars per MMBtu) | $ | 1.98 |  |  | $ | 2.81 |
Ammonia — Southern Plains (dollars per ton) | 375 |  |  | 553 |
UAN — Corn belt (dollars per ton) | 229 |  |  | 313 |

(1) | Amounts are shown exclusive of depreciation and amortization.

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(2) | Nitrogen Fertilizer EBITDA represents nitrogen fertilizer net income adjusted for (i) interest expense and other financing costs, net of interest income, (ii) income tax expense and (iii) depreciation and amortization. Adjusted Nitrogen Fertilizer EBITDA represents Nitrogen Fertilizer EBITDA adjusted for (i) share-based compensation, non-cash, (ii) major scheduled turnaround expenses, (iii) loss on extinguishment of debt and (iv) expenses associated with the East Dubuque mergers, as applicable. We present Adjusted Nitrogen Fertilizer EBITDA because we have found it helpful to consider an operating measure that excludes expenses relating to transactions not reflective of the Nitrogen Fertilizer Partnership's core operations, such as major scheduled turnaround expense, loss on extinguishment of debt and expenses associated with the East Dubuque mergers. In addition, we believe that it is useful to exclude from Adjusted Nitrogen Fertilizer EBITDA share-based compensation, non-cash, although it is a recurring cost incurred in the ordinary course of business. We believe share-based compensation, non-cash, reflects a non-cash cost which may obscure, for a given period, trends in the underlying business, due to the timing and nature of the equity awards.

We also present Adjusted Nitrogen Fertilizer EBITDA because it is the starting point for calculating 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 net income as a measure of performance. Management believes that Nitrogen Fertilizer EBITDA and Adjusted Nitrogen Fertilizer EBITDA enable investors and analysts to better understand the Nitrogen Fertilizer Partnership's ability to make distributions to its common unitholders, help investors and analysts evaluate its ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economic performance by allowing investors to evaluate the same information used by management. Nitrogen Fertilizer EBITDA and 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 net income for the nitrogen fertilizer segment to Nitrogen Fertilizer EBITDA and Adjusted Nitrogen Fertilizer EBITDA for the three months ended March 31, 2016 and 2015:

| Three Months Ended March 31,
| 2016 |  | 2015
| (in millions)
Nitrogen Fertilizer: |  |  |
Nitrogen fertilizer net income | $ | 18.0 |  |  | $ | 29.8 |
Add: |  |  |
Interest expense and other financing costs, net | 1.7 |  |  | 1.7 |
Income tax expense | — |  |  | — |
Depreciation and amortization | 7.0 |  |  | 6.8 |
Nitrogen Fertilizer EBITDA | 26.7 |  |  | 38.3 |
Add: |  |  |
Share-based compensation, non-cash | — |  |  | 0.1 |
Expenses associated with the East Dubuque mergers | 1.2 |  |  | — |
Adjusted Nitrogen Fertilizer EBITDA | $ | 27.9 |  |  | $ | 38.4 |

(3) | Gross tons produced for ammonia represent total ammonia produced, including ammonia produced that was upgraded into UAN. Net tons available for sale represent ammonia available for sale that was not upgraded into UAN.

(4) | In addition to the produced ammonia, the Nitrogen Fertilizer Partnership acquired approximately 3,018 and 21,200 tons of ammonia during the three months ended March 31, 2016 and 2015, respectively.

(5) | The Nitrogen Fertilizer Partnership's pet coke cost per ton purchased from CVR Refining averaged $9 and $21 for the three months ended March 31, 2016 and 2015, respectively. Third-party pet coke prices averaged $33 and $44 for the three months ended March 31, 2016 and 2015, respectively.

(6) | Product pricing at gate represents 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.

(7) | 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.

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Three Months Ended March 31, 2016 Compared to the Three Months Ended March 31, 2015 (Nitrogen Fertilizer Business)
Net Sales. Nitrogen fertilizer net sales were $73.1 million for the three months ended March 31, 2016 compared to $93.1 million for the three months ended March 31, 2015. The decrease of $20.0 million was primarily the result of lower UAN sales prices ($14.2 million), lower hydrogen sales volume ($4.8 million), lower ammonia sales prices ($4.6 million) and lower UAN sales volumes ($2.1 million), partially offset by higher ammonia sales volumes ($6.5 million). For the three months ended March 31, 2016, UAN and ammonia made up $62.6 million and $9.1 million of nitrogen fertilizer net sales, respectively. This compared to UAN and ammonia net sales of $78.9 million and $7.2 million, respectively, for the three months ended March 31, 2015. The following table demonstrates the impact of changes in sales volumes and pricing for UAN, ammonia and hydrogen for the three months ended March 31, 2016, as compared to the three months ended March 31, 2015:

| Three Months Ended March 31, 2016 |  | Three Months Ended March 31, 2015 |  | Total Variance |  | Price Variance |  | Volume Variance
| Volume(1) |  | $ per ton(2) |  | Sales $(3) |  | Volume(1) |  | $ per ton(2) |  | Sales $(3) |  | Volume(1) |  | Sales $(3) |  |
|  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | (in millions)
UAN | 267,049 |  |  | $ | 234 |  |  | $ | 62.6 |  |  | 274,540 |  |  | $ | 288 |  |  | $ | 78.9 |  |  | (7,491 | ) |  | $ | (16.3 | ) |  | $ | (14.2 | ) |  | $ | (2.1 | )
Ammonia | 24,397 |  |  | $ | 373 |  |  | $ | 9.1 |  |  | 12,821 |  |  | $ | 562 |  |  | $ | 7.2 |  |  | 11,576 |  |  | $ | 1.9 |  |  | $ | (4.6 | ) |  | $ | 6.5 |
Hydrogen | 160,408 |  |  | $ | 7 |  |  | $ | 1.1 |  |  | 600,278 |  |  | $ | 11 |  |  | $ | 6.5 |  |  | (439,870 | ) |  | $ | (5.4 | ) |  | $ | (0.6 | ) |  | $ | (4.8 | )

(1) UAN and ammonia sales volumes are in tons. Hydrogen sales volumes are in MSCF.
(2) Includes freight charges. Hydrogen is based on $ per MSCF.
(3) Sales dollars in millions
The decrease in UAN and ammonia sales prices for the three months ended March 31, 2016 compared to the three months ended March 31, 2015 was primarily attributable to pricing fluctuation in the market. The increase of ammonia sales volume for the three months ended March 31, 2016 compared to the three months ended March 31, 2015 was primarily attributable to the seasonality and timing demands of our ammonia customers. On-stream factors (total number of hours operated divided by total hours in the reporting period) for the gasification, ammonia and UAN units were 97.7%, 97.2% and 91.4 %, respectively for the three months ended March 31, 2016. Product pricing at gate for the three months ended March 31, 2016 compared to the three months ended March 31, 2015 decreased 20.5% for UAN and decreased 33.6% for ammonia.
Cost of Product Sold (Exclusive of Depreciation and Amortization). Nitrogen fertilizer cost of product sold (exclusive of depreciation and amortization) includes cost of freight and distribution expenses, pet coke expense and purchased ammonia costs. Cost of product sold (exclusive of depreciation and amortization) for the three months ended March 31, 2016 was $16.3 million compared to $25.8 million for the three months ended March 31, 2015. The $9.5 million decrease resulted from a decrease in purchased ammonia and lower pet coke costs. The decrease in coke costs was primarily related to the decrease in market prices of petroleum coke.
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Nitrogen fertilizer direct operating expenses (exclusive of depreciation and amortization) consist primarily of energy and utility costs, direct costs of labor, property taxes, plant-related maintenance services, including turnaround and environmental and safety compliance costs as well as catalyst and chemical costs. Direct operating expenses (exclusive of depreciation and amortization) for the three months ended March 31, 2016 were $23.7 million as compared to $24.4 million for the three months ended March 31, 2015. The $0.7 million decrease resulted primarily from lower utilities, net ($1.7 million), partially offset by higher outside services ($0.9 million). The lower utilities, net is primarily the result of lower electrical pricing as a result of rate decreases.
Operating Income. Nitrogen fertilizer operating income was $19.7 million for the three months ended March 31, 2016, as compared to operating income of $31.5 million for the three months ended March 31, 2015. The decrease of $11.8 million for the three months ended March 31, 2016, as compared to the three months ended March 31, 2015 was the result of the decrease in net sales ($20.0 million) and increases in selling, general and administrative expenses ($1.8 million) and depreciation and amortization ($0.2 million), partially offset by decreases in cost of product sold ($9.5 million) and direct operating expenses ($0.7 million).
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Liquidity and Capital Resources
Although results are consolidated for financial reporting, CVR Energy, CVR Refining and CVR Partners are independent business entities and operate with independent capital structures. With 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 historically been met independently from the cash needs of CVR Energy and each other with a combination of existing cash and cash equivalent balances, cash generated from operating activities, credit facility borrowings and other debt. As discussed below, we entered into certain financing arrangements with CVR Partners in connection with the East Dubuque mergers. However, CVR Partners is considering various options to refinance the debt incurred in those arrangements with third-party borrowings. The Refining Partnership's and the Nitrogen Fertilizer 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.
We believe that the petroleum business and the nitrogen fertilizer business' cash flows from operations and existing cash and cash equivalents, along with borrowings under their respective credit facilities, as necessary, will be sufficient to satisfy the anticipated cash requirements associated with their existing operations for at least the next 12 months, including commitments and expenditures associated with the consummation of the East Dubuque mergers for the nitrogen fertilizer business. Additionally, we believe 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 outside of our control.
Cash Balance and Other Liquidity
As of March 31, 2016, we had consolidated cash and cash equivalents of $681.8 million. Of that amount, $483.9 million was cash and cash equivalents of CVR Energy, $145.9 million was cash and cash equivalents of the Refining Partnership and $52.0 million was cash and cash equivalents of the Nitrogen Fertilizer Partnership. As of April 26, 2016, we had consolidated cash and cash equivalents of approximately $416.6 million.
The Refining Partnership's senior secured asset based revolving credit facility (the "Amended and Restated ABL Credit Facility") provides the Refining Partnership with borrowing availability of up to $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 March 31, 2016, the Refining Partnership had $245.3 million available under the Amended and Restated ABL Credit Facility. Availability under the Amended and Restated ABL Credit Facility was limited by borrowing base conditions.
The Nitrogen Fertilizer Partnership's credit facility that was in effect at March 31, 2016 included a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with an uncommitted incremental facility of up to $50.0 million. The Nitrogen Fertilizer Partnership's credit facility was scheduled to mature in April 2016. The Nitrogen Fertilizer Partnership's credit facility was used to finance on-going working capital, capital expenditures, letter of credit issuances and general needs of CRNF. As of March 31, 2016, the Nitrogen Fertilizer Partnership had $25.0 million available under its credit facility.
As discussed in Note 8 ("Long-Term Debt") to Part I, Item 1 of this Report, the Nitrogen Fertilizer Partnership's credit facility was scheduled to mature in April 2016 and the $125.0 million principal portion of the term loan facility is presented as a current liability as of March 31, 2016. On February 9, 2016, CRLLC and the Nitrogen Fertilizer Partnership entered into a guaranty, pursuant to which CRLLC agreed to guaranty the indebtedness outstanding under the Nitrogen Fertilizer Partnership's credit facility. On April 1, 2016, the Nitrogen Fertilizer Partnership repaid all amounts outstanding under the credit facility using proceeds from a new credit facility provided by CRLLC and the credit facility was terminated. See further discussion in Part I, Item I, Note 15 (“Subsequent Events”) and below under “Merger-Related Financing Arrangements”.
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The Refining Partnership and the Nitrogen Fertilizer Partnership have distribution policies pursuant to which they will generally distribute all of their available cash each quarter, within 60 days after the end of each quarter. The distributions will be made to all common unitholders. At March 31, 2016, we held approximately 66% and 53% of the Refining Partnership's and the Nitrogen Fertilizer Partnership'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.
Borrowing Activities
2022 Notes. On October 23, 2012, CVR Refining, LLC ("Refining LLC") and its wholly-owned subsidiary, Coffeyville Finance Inc. ("Coffeyville Finance"), issued $500.0 million aggregate principal amount of 6.5% Senior Notes due 2022 (the "2022 Notes"). As a result of the issuance, approximately $8.7 million of debt issuance costs were incurred, which are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. As of March 31, 2016, the 2022 Notes had an aggregate principal balance and a net carrying value of $500.0 million.
The 2022 Notes were issued by Refining LLC and Coffeyville Finance and are fully and unconditionally guaranteed by CVR Refining and each of Refining LLC's existing domestic subsidiaries (other than the co-issuer, Coffeyville Finance) on a joint and several basis. After January 23, 2013, the 2022 Notes were no longer secured. CVR Refining has no independent assets or operations and Refining LLC is a 100% owned finance subsidiary of CVR Refining. CVR Partners and Coffeyville Resources Nitrogen Fertilizers ("CRNF") (a subsidiary of the Nitrogen Fertilizer Partnership) are not guarantors.
On September 17, 2013, Refining LLC and Coffeyville Finance consummated a registered 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, as amended. 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 2022 Notes bear interest at a rate of 6.5% per annum and 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, to holders of record at the close of business on April 15 and October 15, as the case may be, immediately preceding each such interest payment date.
The issuers have the right to redeem the 2022 Notes at a redemption price of (i) 103.250% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2017; (ii) 102.167% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2018; (iii) 101.083% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2019 and (iv) 100% of the principal amount, if redeemed on or after November 1, 2020, plus in each case, any accrued and unpaid interest. Prior to November 1, 2017, some or all of the 2022 Notes may be redeemed at a price equal to 100% of the principal amount thereof, plus a make-whole premium and any accrued and unpaid interest.
In the event of a "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 (i) 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), (ii) liquidation or dissolution of Refining LLC, or (iii) any person, other than a qualifying owner, directly or indirectly acquiring 50% of the membership interest of Refining LLC.
The indenture governing the 2022 Notes imposes covenants that restrict the ability of the issuers and guarantors to (i) issue debt, (ii) incur or otherwise cause liens to exist on any of their property or assets, (iii) declare or pay dividends, repurchase equity, or make payments on contractually subordinated debt, (iv) make certain investments, (v) sell certain assets, (vi) merge or consolidate with or into another entity, or sell all or substantially all of their assets, and (vii) enter into certain transactions with affiliates. Most of the foregoing covenants would cease to apply at such time that the 2022 Notes are rated investment grade by both Standard & Poor's Rating Services and Moody'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.
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The indenture governing the 2022 Notes prohibits the Refining Partnership from making distributions to its unitholders if any default or event of default (as defined in the indenture) exists. In addition, the indenture limits the Refining Partnership's ability to pay distributions to unitholders. The covenants will apply differently depending on the Refining Partnership'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 will generally be permitted to make restricted payments, including distributions to its unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, the Refining Partnership will generally be permitted to make restricted payments, including distributions to its unitholders, up to an aggregate $100.0 million basket plus certain other amounts referred to as "incremental funds" under the indenture. The Refining Partnership was in compliance with the covenants as of March 31, 2016, and the ratio was satisfied (not less than 2.5 to 1.0).
Amended and Restated Asset Based (ABL) Credit Facility. On December 20, 2012, CRLLC and certain subsidiaries (collectively, the "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 prior 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 million asset-based revolving credit facility, with sub-limits for letters of credit and swingline loans of $360.0 million and $40.0 million, respectively. The Amended and Restated ABL Credit Facility also includes a $200.0 million uncommitted incremental 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 three-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 six-month period following the distribution is greater than 25% at all times, then the following condition in 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 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).
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 equal to or greater than 50% of the lesser of the borrowing base and the total commitments. The Refining Partnership is also required to pay customary letter of credit fees equal to, for standby letters of credit, the applicable margin 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.
The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Credit Parties and their subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investments 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 March 31, 2016.
Nitrogen Fertilizer Partnership Credit Facility. On April 13, 2011, CRNF, as borrower, and the Nitrogen Fertilizer Partnership, as guarantor, entered into a credit facility (the "Nitrogen Fertilizer Partnership credit facility") with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent. The Nitrogen Fertilizer Partnership credit facility included a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with an uncommitted incremental facility of up to $50.0 million. There was no scheduled amortization and the Nitrogen Fertilizer Partnership credit facility was scheduled to mature in April 2016, but was repaid and terminated subsequent to March 31, 2016 as discussed below.
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Borrowings under the Nitrogen Fertilizer Partnership credit facility bore interest based on a pricing grid determined by the trailing four quarter leverage ratio. As of March 31, 2016, the initial pricing for Eurodollar rate loans under the Nitrogen Fertilizer Partnership credit facility was based on 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 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 was the borrower under the Nitrogen Fertilizer Partnership credit facility. All obligations under the Nitrogen Fertilizer Partnership credit facility were unconditionally guaranteed by the Nitrogen Fertilizer Partnership and substantially all of its future, direct and indirect, domestic subsidiaries. Borrowings under the credit facility were non-recourse to the Company and its direct subsidiaries.
As of March 31, 2016, no amounts were drawn under the Nitrogen Fertilizer Partnership's $25.0 million revolving credit facility.
On April 1, 2016, the Nitrogen Fertilizer Partnership repaid all amounts outstanding under the credit facility utilizing amounts drawn on the CRLLC Facility (as defined below) and the credit facility was terminated.
Merger-Related Financing Arrangements
On April 12, 2016, East Dubuque and East Dubuque Finance Corporation (formerly known as Rentech Nitrogen Finance Corporation), a wholly-owned subsidiary of East Dubuque (“Finance Corporation”), issued $320.0 million of 6.5% second lien senior secured notes due 2021 (the “Second Lien Notes”) to qualified institutional buyers and non-United States persons in a private offering exempt from the registration requirements of the Securities Act of 1933, as amended. The Second Lien Notes bear interest at a rate of 6.5% per year, payable semi-annually in arrears on April 15 and October 15 of each year. The Second Lien Notes will mature on April 15, 2021, unless repurchased or redeemed earlier in accordance with their terms.
East Dubuque is required under the change of control provision within the indenture governing the Second Lien Notes to offer to purchase all outstanding Second Lien Notes at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest thereon to the date of purchase. Under the terms of the indenture, no later than 30 days following the consummation of the mergers, East Dubuque is required to send notice to each holder of the Second Lien Notes and the trustee describing the merger transaction and offer to repurchase the notes on a settlement date specified in the notice. The settlement date specified in the notice must be no earlier than 30 days and no later than 60 days from the date such notice is mailed. On or after April 15, 2016, East Dubuque may redeem some or all of the Second Lien Notes at a premium that will decrease over time, plus accrued and unpaid interest, if any, to the redemption date.
The Second Lien Notes are fully and unconditionally guaranteed, jointly and severally, by each of the East Dubuque’s existing domestic subsidiaries, other than Finance Corporation. In addition, the Second Lien Notes and the guarantees thereof are collateralized by a second priority lien on substantially all of East Dubuque’s and the guarantors’ assets, subject to permitted liens.
Immediately prior to the mergers, East Dubuque had outstanding advances under a credit agreement with Wells Fargo Bank, National Association, as successor-in-interest by assignment from General Electric Company, as administrative agent (the "Wells Fargo Credit Agreement"). The Wells Fargo Credit Agreement consisted of a $50.0 million senior secured revolving credit facility with a $10.0 million letter of credit sublimit.
AEPC Facility. On April 1, 2016, in connection with the closing of the mergers, the Nitrogen Fertilizer Partnership entered into a $320.0 million senior term loan facility (the "AEPC Facility") with American Entertainment Properties Corporation ("AEPC"), an affiliate of IEP, as the lender, which (i) may be used by the Nitrogen Fertilizer Partnership to provide funds to East Dubuque to make a change of control offer and, if applicable, a "clean-up" redemption in accordance with the indenture governing the Second Lien Notes or (ii) may be used by the Nitrogen Fertilizer Partnership or East Dubuque to make a tender offer for the Second Lien Notes and, in each case, pay fees and expenses related thereto. The AEPC Facility is for a term of two years and bears interest at a rate of 12% per annum. Calculation of interest shall be on the basis of the actual number of days elapsed over a 360-day year and payable quarterly. The Nitrogen Fertilizer Partnership may voluntarily prepay in whole or in part the borrowings under the AEPC Facility without premium or penalty.
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The AEPC Facility contains covenants that require the Nitrogen Fertilizer Partnership to, among other things, notify AEPC of the occurrence of any default or event of default and provide AEPC with information in respect of the Nitrogen Fertilizer Partnership’s business and financial status as it may reasonably require, including, but not limited to, copies of the Nitrogen Fertilizer Partnership’s unaudited quarterly financial statements and audited annual financial statements. In addition, the AEPC Facility contains customary events of default, including, among others, failure to pay any sum payable when due and the occurrence of a default of other indebtedness in excess of $25.0 million.
The Nitrogen Fertilizer Partnership is also considering various third-party refinancing options in association with funding the change of control offer, which may be used in lieu of, or in combination with, borrowings under the AEPC Facility.
CRLLC Facility. On April 1, 2016, in connection with the closing of the mergers, the Nitrogen Fertilizer Partnership entered into a $300.0 million senior term loan credit facility (the "CRLLC Facility") with CRLLC, as the lender, the proceeds of which were used by the Nitrogen Fertilizer Partnership (i) to fund the repayment of amounts outstanding under the Wells Fargo Credit Agreement (ii) to pay the cash consideration and to pay fees and expenses in connection with the mergers and related transactions and (iii) to repay all of the loans outstanding under the Nitrogen Fertilizer Partnership credit facility. The CRLLC Facility has a term of two years and bears an interest rate of 12.0% per annum. Interest is calculated on the basis of the actual number of days elapsed over a 360-day year and payable quarterly. The Nitrogen Fertilizer Partnership may voluntarily prepay in whole or in part the borrowings under the CRLLC Facility without premium or penalty. In April 2016, the Nitrogen Fertilizer Partnership borrowed $300.0 million under the CRLLC Facility. In connection with the CRLLC Facility, the commitment letter and guarantee previously provided by CRLLC to the Nitrogen Fertilizer Partnership in connection with the mergers were terminated.
The CRLLC Facility contains covenants that require the Nitrogen Fertilizer Partnership to, among other things, notify CRLLC of the occurrence of any default or event of default and provide CRLLC with information in respect of the Nitrogen Fertilizer Partnership’s business and financial status as it may reasonably require, including, but not limited to, copies of unaudited quarterly financial statements and audited annual financial statements. In addition, the CRLLC Facility contains customary events of default, including, among others, failure to pay any sum payable when due and the occurrence of a default of other indebtedness in excess of $25.0 million.
The Nitrogen Fertilizer Partnership is considering various third-party refinancing options to refinance the outstanding amounts under the CRLLC Facility.
Nitrogen Fertilizer Partnership Interest Rate Swaps
Prior to the termination of the Nitrogen Fertilizer Partnership credit facility on April 1, 2016, the Nitrogen Fertilizer Partnership's profitability and cash flows were affected by changes in interest rates on credit facility borrowings, specifically LIBOR and prime rates. The primary purpose of the Nitrogen Fertilizer Partnership's interest rate risk management activities is to hedge the exposure to changes in interest rates by using interest rate derivatives to convert some or all of the interest rates on borrowings from a floating rate to a fixed interest rate.
The Nitrogen Fertilizer Partnership has determined that the two interest rate swaps agreements entered into in 2011 qualified for hedge accounting treatment. The impact recorded for each of the three months ended March 31, 2016 and 2015 was $0.0 million and $0.3 million in interest expense. For the three months ended March 31, 2015, the Nitrogen Fertilizer Partnership recognized a nominal decrease of $0.1 million in fair value of the interest rate swap agreements, which was unrealized in accumulated other comprehensive income (loss). The interest rate swap agreements expired in February 2016.
Capital Spending
We divide the petroleum business and the nitrogen fertilizer 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.
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The following table summarizes our total actual capital expenditures for the three months ended March 31, 2016 and current estimated capital expenditures for the remainder of 2016 by operating segment and major category. These estimates may change as a result of unforeseen circumstances or a change in our plans, and amounts may not be spent in the manner allocated below:

| Three Months Ended March 31, 2016 |  | 2016 Estimate(1) |
| (in millions)
Petroleum Business (the Refining Partnership): |  |  |  |
Coffeyville refinery: |  |  |  |
Maintenance | $ | 17.7 |  |  | $ | 74.0 |  |
Growth | 18.2 |  |  | 48.0 |  |
Coffeyville refinery total capital spending | 35.9 |  |  | 122.0 |  |
Wynnewood refinery: |  |  |  |
Maintenance | 5.8 |  |  | 40.0 |  |
Growth | 0.1 |  |  | 4.0 |  |
Wynnewood refinery total capital spending | 5.9 |  |  | 44.0 |  |
Other Petroleum: |  |  |  |
Maintenance | 1.8 |  |  | 10.0 |  |
Growth | 0.3 |  |  | 4.0 |  |
Other petroleum total capital spending | 2.1 |  |  | 14.0 |  |
Petroleum business total capital spending | 43.9 |  |  | 180.0 |  |
Nitrogen Fertilizer Business (the Nitrogen Fertilizer Partnership): |  |  |  |
Maintenance | 0.8 |  |  | 8.0 |  |
Growth | 1.0 |  |  | 4.0 |  |
Nitrogen fertilizer business total capital spending | 1.8 |  |  | 12.0 |  |
Corporate | 1.8 |  |  | 10.0 |  |
Total capital spending | $ | 47.5 |  |  | $ | 202.0 |  |

(1) | Includes amounts already spent during the three months ended March 31, 2016.

The petroleum business' and the nitrogen fertilizer business' estimated capital expenditures are subject to change due to unanticipated increases in the cost, scope and completion time for capital projects. For example, they may experience increases in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of the refineries or nitrogen fertilizer plants. Capital spending for the Nitrogen Fertilizer Partnership's nitrogen fertilizer business and the Refining Partnership's petroleum business is determined by each partnership's respective board of directors of its general partner.
In October 2014, the board of directors of the general partner of the Refining Partnership approved the construction of a hydrogen plant at the Coffeyville refinery. The hydrogen plant will increase the overall plant liquid volume recovery and provide additional hydrogen that is needed for environmental compliance. The estimated cost of this project, excluding capitalized interest, is approximately $108.3 million with an anticipated completion date in the second quarter of 2016. As of March 31, 2016, the Refining Partnership had incurred costs of approximately $84.6 million, excluding capitalized interest, for the hydrogen plant.
The East Dubuque fertilizer plant acquired in the mergers has started an ammonia synthesis converter project, the cost of which is categorized as growth capital spending. Replacement of an ammonia synthesis converter at the East Dubuque plant is expected to increase reliability, production and plant efficiency. The project is expected to be completed before the end of summer 2016, and post-merger expenditures for this project are estimated to be between $8.0 million to $11.0 million. Maintenance capital expenditures for the East Dubuque Facility subsequent to the completion of the mergers are expected to be approximately $10.0 million to $12.0 million for nine months ending December 31, 2016. The capital spending table above does not include actual or estimated capital expenditures for East Dubuque. The East Dubuque fertilizer plant is planning to undergo the next scheduled full facility turnaround in the second quarter of 2016. The turnaround is expected to last between 25-30 days. Expenses associated with the East Dubuque turnaround are estimated to be between $5.0 million and $7.0 million.
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Our estimated capital expenditures are subject to change due to unanticipated increases/decreases in the cost, scope and completion time for our capital projects. For example, we may experience increases/decreases in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of our refineries.
The Refining Partnership's and the Nitrogen Fertilizer Partnership'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 credit facilities, 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 depending on market conditions, and may not be able to refinance such indebtedness on commercially reasonable terms or at all. 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.
Cash Flows
The following table sets forth our consolidated cash flows for the periods indicated below:

| Three Months Ended March 31,
| 2016 |  | 2015
| (unaudited)
| (in millions)
Net cash provided by (used in): |  |  |
Operating activities | $ | 21.6 |  |  | $ | 178.2 |
Investing activities | (51.7 | ) |  | (3.4 | )
Financing activities | (53.2 | ) |  | (76.3 | )
Net increase (decrease) in cash and cash equivalents | $ | (83.3 | ) |  | $ | 98.5 |

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 three months ended March 31, 2016 were $21.6 million. The positive cash flow from operating activities generated over this period was primarily driven by current period settlements on derivative contracts of $21.4 million and favorable impacts to trade working capital, offset by net loss before noncontrolling interest of $30.9 million and unfavorable impacts to other working capital. Derivative settlements for the three months ended March 31, 2016 resulted in a cash inflow of $21.4 million, which was attributable to the refining business's settlement of a portion of its outstanding commodity swap positions previously scheduled to settle throughout 2016. Trade working capital for the three months ended March 31, 2016 resulted in a net cash inflow of $7.8 million, which was primarily attributable to a decrease in inventory of $30.5 million, offset by an increase in accounts receivable of $14.2 million and a decrease in accounts payable of $8.5 million. The decrease in inventory was primarily due to a reduction in gasoline and other in-process inventory at the petroleum business during the first quarter of 2016. Other working capital activities resulted in a net cash inflow of $1.5 million, which was primarily related to a decrease in prepaid expenses and other current assets of $1.9 million and an increase in other current liabilities of $1.9 million, partially offset by a decrease in deferred revenue of $2.3 million.
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Net cash flows provided by operating activities for the three months ended March 31, 2015 were $178.2 million. The positive cash flow from operating activities generated over the period was primarily driven by $84.7 million of net income before noncontrolling interest and favorable impacts to both trade working capital and other working capital. Trade working capital for the three months ended March 31, 2015 resulted in a net cash inflow of $14.4 million, which was attributable to a decrease in inventory of $18.2 million, partially offset by a decrease in accounts payable of $3.8 million. The decrease in inventory was primarily due to a reduction in gasoline inventory at the petroleum business during the first quarter of 2015. Other working capital activities resulted in a net cash inflow of $20.9 million, which was primarily related to a decrease in due to parent of $35.5 million, partially offset by a decrease in deferred revenue of $7.3 million, an increase in prepaid expenses and other current assets of $5.0 million and a decrease in other current liabilities of $4.9 million. The decrease in due from parent was the result of an overpayment of income taxes to AEPC for the year ended December 31, 2014, which has been applied to the Company's tax liability for the three months ended March 31, 2015. The decrease in deferred revenue was primarily attributable to lower market demand for prepaid contracts and increased sales at the nitrogen fertilizer business for the first quarter of 2015. The increase in prepaid expenses and other current assets was primarily due to an increase in receivables related to the sale of certain investments during the first quarter of 2015, partially offset by a reduction in prepaid insurance and the timing of payments related to certain other prepaid items. The decrease in other current liabilities was primarily due to decreased personnel accruals and lower accrued railcar regulatory inspections at the nitrogen fertilizer business, partially offset by an increase in accrued interest related to the 2022 Notes and an increase in the biofuel blending obligation at the petroleum business.
Cash Flows Used in Investing Activities
Net cash used in investing activities for the three months ended March 31, 2016 was $51.7 million compared to $3.4 million for the three months ended March 31, 2015. The increase of $48.3 million in cash used in investing activities for the three months ended March 31, 2016 was attributable to capital spending of $47.5 million and purchase of Rentech Nitrogen common units in March 2016 for approximately $4.2 million. Net cash used in investing activities for the three months ended March 31, 2015 was comprised of $45.5 million of capital spending offset by $42.1 million of proceeds from sale of available-for-sale securities. The increase in capital spending was primarily the result of higher spending by the petroleum business for growth projects.
Cash Flows Used In Financing Activities
Net cash used in financing activities for the three months ended March 31, 2016 was approximately $53.2 million, as compared to $76.3 million for the three months ended March 31, 2015. The net cash used in financing activities for the three months ended March 31, 2016 was primarily attributable to dividend payments to common stockholders of $43.4 million and distributions from the Nitrogen Fertilizer Partnership to common unitholders of $9.2 million. The net cash used in financing activities for the three months ended March 31, 2015 was primarily attributable to dividend payments to common stockholders of $43.4 million and distributions to the Refining Partnership and Nitrogen Fertilizer Partnership common unitholders of $32.6 million.
As of and for the three months ended March 31, 2016, there were no borrowings or repayments under the Amended and Restated ABL credit facility or the Nitrogen Fertilizer Partnership credit facility.
Contractual Obligations
As of March 31, 2016, our contractual obligations included long-term debt, operating leases, capital lease obligations, unconditional purchase obligations, environmental liabilities and interest payments. There were no material changes outside the ordinary course of our business with respect to our contractual obligations during the three months ended March 31, 2016 from those disclosed in our 2015 Form 10-K, except for the obligations relating to the mergers disclosed in Note 1 ("Organization and History of the Company and Basis of Presentation") to Part I, Item 1 of this Report.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of March 31, 2016, as defined within the rules and regulations of the SEC.
Recent Accounting Pronouncements
Refer to Part I, Item 1, Note 2 ("Recent Accounting Pronouncements") of this Report for a discussion of recent accounting pronouncements applicable to the Company.
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Critical Accounting Policies
Our critical accounting policies are disclosed in the "Critical Accounting Policies" section of our 2015 Form 10-K. No modifications have been made to our critical accounting policies.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices and interest rates. Except as discussed below, information about market risks for the three months ended March 31, 2016 does not differ materially from that discussed under Part II — Item 7A of our 2015 Form 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.
Our earnings and cash flows and estimates of future cash flows are sensitive to changes in energy prices. The prices of crude oil and refined products have fluctuated substantially in recent years. These prices depend on many factors, including the overall demand for crude oil and refined products, which in turn depends, among other factors, on general economic conditions, the level of foreign and domestic production of crude oil and refined products, the availability of imports of crude oil and refined products, the marketing of alternative and competing fuels, the extent of government regulations and global market dynamics. The prices we receive for refined products are also affected by factors such as local market conditions and the level of operations of other refineries in our markets. The prices at which we can sell gasoline and other refined products are strongly influenced by the price of crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products. The timing of the relative movement of the prices, however, can impact profit margins, which could significantly affect our earnings and cash flows.
Commodity Price Risk
At March 31, 2016 the Refining Partnership had open commodity hedging instruments consisting of approximately 1.0 million barrels to fix the price on a portion of its future crude oil purchases and the basis on a portion of its future product sales. A change of $1.00 per barrel in the fair value of the benchmark crude or product basis would result in an increase or decrease in the related fair value of the commodity hedging instruments of $1.0 million.
Interest Rate Risk
The interest rate swaps agreements expired February 12, 2016, and subsequently, the Nitrogen Fertilizer Partnership had exposure to interest rate risk on 100% of its $125.0 million floating rate debt under the Nitrogen Fertilizer Partnership credit facility. A 1.0% increase over the Eurodollar floor spread of 3.5%, as specified in the credit agreement, would increase interest cost to the Nitrogen Fertilizer Partnership by approximately $1,250,000 on an annualized basis, thus decreasing net income by the same amount. On April 1, 2016, the Nitrogen Fertilizer Partnership repaid all amounts outstanding under the Nitrogen Fertilizer Partnership credit facility and the credit facility was terminated.
Foreign Currency Exchange
Given that our business is currently based entirely in the United States, we are not significantly exposed to foreign currency exchange rate risk. A portion of the petroleum business' pipeline transportation costs are transacted in Canadian dollars. Commitments for future periods under this agreement reflect the exchange rate between the Canadian Dollar and the U.S. Dollar as of the end of the reporting period. Based on the short period of time between the billing and settlement of these transportation costs in Canadian dollars, the exposure to foreign currency exchange rate risk and the resulting foreign currency gain (loss) is not material.
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Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of March 31, 2016, 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 Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). 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'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.
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting required by Rule 13a-15 of the Exchange Act that occurred during the fiscal quarter ended March 31, 2016 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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Part II. Other Information
Item 1. Legal Proceedings
See Note 10 ("Commitments and Contingencies") to Part I, Item 1 of this Report, which is incorporated by reference into this Part II, Item 1, for a description of certain litigation, legal and administrative proceedings and environmental matters.
Item 1A. Risk Factors
You should carefully consider the information regarding certain factors which could materially adversely affect our business, financial condition, cash flows or results of operations as set forth under Item 1A. "Risk Factors" in our 2015 Form 10-K. Except as set forth below in this Item 1A. "Risk Factors," we do not believe that there have been any material changes to the risk factors previously disclosed in our 2015 Form 10-K. We may disclose changes to such risk factors or disclose additional risk factors from time to time in our future filings with the SEC. Additional risks and uncertainties not presently known to us or that we currently believe not to be material may also materially adversely affect our business, financial condition, cash flows or results of operations.
Risks Related to the Nitrogen Fertilizer Business
The costs associated with operating the nitrogen fertilizer plants include significant fixed costs. If nitrogen fertilizer prices fall below a certain level, the nitrogen fertilizer business may not generate sufficient revenue to operate profitably or cover its costs.
Unlike our competitors, whose primary costs are related to the purchase of natural gas and whose costs are therefore largely variable, the Coffeyville Fertilizer Facility has largely fixed costs. In addition, the East Dubuque Fertilizer Facility has a significant amount of fixed costs. As a result of the fixed cost nature of its operations, downtime, interruptions or low productivity due to reduced demand, adverse weather conditions, equipment failure, a decrease in nitrogen fertilizer prices or other causes can result in significant operating losses which could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
Continued low natural gas prices could impact the nitrogen fertilizer business' relative competitive position when compared to other nitrogen fertilizer producers.
Most nitrogen fertilizer manufacturers rely on natural gas as their primary feedstock, and the cost of natural gas is a large component of the total production cost for natural gas-based nitrogen fertilizer manufacturers. Low natural gas prices benefit the nitrogen fertilizer business' competitors and disproportionately impact our operations by making the nitrogen fertilizer business less competitive with natural gas-based nitrogen fertilizer manufacturers. Although our nitrogen fertilizer business diversified its operations in connection with the acquisition of the East Dubuque Fertilizer Facility, which relies on natural gas feedstock, continued low natural gas prices could impair the ability of the Coffeyville Fertilizer Facility to compete with other nitrogen fertilizer producers who utilize natural gas as their primary feedstock if nitrogen fertilizer pricing drops as a result of low natural gas prices, and therefore have a material adverse impact on the cash flows of the nitrogen fertilizer business.
The market for natural gas has been volatile. Natural gas prices are currently at a relative low point. An increase in natural gas prices could impact the nitrogen fertilizer business' relative competitive position when compared to other foreign and domestic nitrogen fertilizer producers, and if prices for natural gas increase significantly, our nitrogen fertilizer business may not be able to economically operate the East Dubuque Fertilizer Facility.
The operation of the East Dubuque Fertilizer Facility with natural gas as the primary feedstock exposes the nitrogen fertilizer business to market risk due to increases in natural gas prices, particularly if the price of natural gas in the United States were to become higher than the price of natural gas outside the United States. An increase in natural gas prices would impact the East Dubuque Fertilizer Facility's operations by making it less competitive with competitors who do not use natural gas as their primary feedstock, and could therefore have a material adverse impact on the nitrogen fertilizer business' results of operations, financial condition and cash flows. In addition, if natural gas prices in the United States were to increase relative to prices of natural gas paid by foreign nitrogen fertilizer producers, this may negatively affect the nitrogen fertilizer business' competitive position in the farm belt and thus have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
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The profitability of operating the East Dubuque Fertilizer Facility is significantly dependent on the cost of natural gas, and, prior to the East Dubuque mergers, the East Dubuque Fertilizer Facility operated, and could operate in the future, at a net loss. Local factors may affect the price of natural gas available to the nitrogen fertilizer business, in addition to factors that determine the benchmark prices of natural gas. Since the nitrogen fertilizer business expects to purchase natural gas for use at the East Dubuque Fertilizer Facility on the spot market and pursuant to forward purchase contracts, the nitrogen fertilizer business will be susceptible to fluctuations in the price of natural gas in general and in local markets in particular. The nitrogen fertilizer business also may use short-term, fixed supply, fixed price forward purchase contracts to lock in pricing for a portion of our natural gas requirements. The nitrogen fertilizer business' ability to enter into forward purchase contracts is dependent upon creditworthiness and, in the event of a deterioration in the nitrogen fertilizer business' credit, counterparties could refuse to enter into forward purchase contracts on acceptable terms. If unable to enter into forward purchase contracts for the supply of natural gas, the nitrogen fertilizer business would need to purchase natural gas on the spot market, which would impair its ability to hedge exposure to risk from fluctuations in natural gas prices. If the nitrogen fertilizer business fixes the price of natural gas with forward purchase contracts, and natural gas prices decrease, then its cost of sales could be higher than it would have been in the absence of the forward purchase contracts. However, forward purchase contracts may not protect the nitrogen fertilizer business from all of the increases in natural gas prices. A hypothetical increase of $0.10 per MMBtu of natural gas would increase our cost to produce one ton of ammonia by approximately $3.35. These increased costs could materially and adversely affect the nitrogen fertilizer business' results of operations and financial condition.
Any interruption in the supply of natural gas to the nitrogen fertilizer business' East Dubuque Fertilizer Facility through Nicor Inc. ("Nicor") could have a material adverse effect on the nitrogen fertilizer business' results of operations and financial condition.
Our nitrogen fertilizer business' East Dubuque operations depend on the availability of natural gas. East Dubuque has an agreement with Nicor pursuant to which it accesses natural gas from the ANR Pipeline Company and Northern Natural Gas pipelines. East Dubuque's access to satisfactory supplies of natural gas through Nicor could be disrupted due to a number of causes, including volume limitations under the agreement, pipeline malfunctions, service interruptions, mechanical failures or other reasons. The agreement, as amended, extends for a final 12-month period ending October 31, 2016. For each extension period under the agreement, Nicor may establish a bidding period during which East Dubuque may match the best bid received by Nicor for the natural gas capacity provided under the agreement. East Dubuque could be out-bid for any of the remaining periods under the agreement. In addition, upon expiration of the last period, East Dubuque may be unable to renew the agreement on satisfactory terms, or at all. Any disruption in the supply of natural gas to the East Dubuque Fertilizer Facility could restrict our nitrogen fertilizer business' ability to continue to make products at the facility. In the event our nitrogen fertilizer business needed to obtain natural gas from another source, it would need to build a new connection from that source to the East Dubuque Fertilizer Facility and negotiate related easement rights, which would be costly, disruptive and/or unfeasible. As a result, any interruption in the supply of natural gas through Nicor could have a material adverse effect on our nitrogen fertilizer business' results of operations and financial condition.
The nitrogen fertilizer business is seasonal, which may result in carrying significant amounts of inventory and seasonal variations in working capital. The inability to predict future seasonal nitrogen fertilizer demand accurately may result in excess inventory or product shortages.
Our nitrogen fertilizer business is seasonal. Farmers tend to apply nitrogen fertilizer during two short application periods, one in the spring and the other in the fall. In contrast, our nitrogen fertilizer business and other nitrogen fertilizer producers generally produce products throughout the year. As a result, our nitrogen fertilizer business and our customers generally build inventories during the low demand periods of the year in order to ensure timely product availability during the peak sales seasons. Variations in the proportion of product sold through prepaid sales contracts and variations in the terms of such contracts can increase the seasonal volatility of our nitrogen fertilizer business' cash flows and cause changes in the patterns of seasonal volatility from year-to-year.
In most instances, our nitrogen fertilizer business’ East Dubuque customers take delivery of nitrogen products at the East Dubuque Facility. Customers arrange and pay to transport our nitrogen products to their final destinations. At our nitrogen fertilizer business’ East Dubuque Fertilizer Facility, inventories are accumulated to allow for customer to take delivery to meet the seasonal demand, which require significant storage capacity. The accumulation of inventory to be available for seasonal sales creates significant seasonal working capital requirements.
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Most of our nitrogen fertilizer business’ Coffeyville Fertilizer Facility nitrogen products are delivered by railcar to its customer’s storage facilities. Therefore, it is less dependent on storage capacity at the Coffeyville Fertilizer Facility and, as a result, experience lower seasonal fluctuations as compared to the East Dubuque Fertilizer Facility. At our nitrogen fertilizer business’ Coffeyville Fertilizer Facility, the strongest demand for our products typically occurs during the spring planting season. The seasonality of nitrogen fertilizer demand results in our nitrogen fertilizer business’ sales volumes and net sales being highest during the North American spring season and its working capital requirements typically being highest just prior to the start of the spring season.
If seasonal demand exceeds our nitrogen fertilizer business' projections, the nitrogen fertilizer business will not have enough product and its customers may acquire products from its competitors, which would negatively impact our nitrogen fertilizer business' profitability. If seasonal demand is less than expected, our nitrogen fertilizer business will be left with excess inventory and higher working capital and liquidity requirements. The degree of seasonality of our nitrogen fertilizer business can change significantly from year to year due to conditions in the agricultural industry and other factors. As a consequence of this seasonality, it is expected that distributions we receive from our nitrogen fertilizer business' will be volatile and will vary quarterly and annually.
The nitrogen fertilizer business' operations are dependent on third-party suppliers, including the following: Linde, which owns an air separation plant that provides oxygen, nitrogen and compressed dry air to the Coffeyville Fertilizer Facility; the City of Coffeyville, which supplies the Coffeyville Fertilizer Facility with electricity; and Jo-Carroll Energy, Inc., which supplies the East Dubuque Fertilizer Facility with electricity. A deterioration in the financial condition of a third- party supplier, a mechanical problem with the air separation plant supplying the Coffeyville Fertilizer Facility, or the inability of a third-party supplier to perform in accordance with its contractual obligations could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
Our nitrogen fertilizer business' Coffeyville Fertilizer Facility operations depend in large part on the performance of third-party suppliers, including, Linde for the supply of oxygen, nitrogen and compressed dry air, and the City of Coffeyville for the supply of electricity. With respect to Linde, the operations of the Coffeyville Fertilizer Facility could be adversely affected if there were a deterioration in Linde's financial condition such that the operation of the air separation plant located adjacent to the Coffeyville Fertilizer Facility was disrupted. Additionally, this air separation plant in the past has experienced numerous short-term interruptions, causing interruptions in our gasifier operations. With respect to electricity, in 2010 our nitrogen fertilizer business entered into an amended and restated electric services agreement with the City of Coffeyville, Kansas which allows for an option to extend the term of such agreement through June 30, 2024.
Our nitrogen fertilizer business' East Dubuque Fertilizer Facility operations also depend in large part on the performance of third-party suppliers, including, Jo-Carrol Energy, Inc. ("Jo-Carrol Energy") for the purchase of electricity. Our nitrogen fertilizer business entered into a utility service agreement with Jo-Carroll Energy, which is scheduled to expire on February 7, 2017.
Should Linde, the City of Coffeyville, Jo-Carrol Energy or any of our other third-party suppliers fail to perform in accordance with existing contractual arrangements, or should our nitrogen fertilizer business otherwise lose the services of any third-party suppliers, our nitrogen fertilizer business' operations (or a portion of our operations) could be forced to halt. Alternative sources of supply could be difficult to obtain. Any shutdown of our nitrogen fertilizer business' operations (or a portion of our operations), even for a limited period, could have a material adverse effect on our nitrogen fertilizer business' results of operations, financial condition and ability to make cash distributions to us.
The nitrogen fertilizer business' results of operations, financial condition and cash flows may be adversely affected by the supply and price levels of pet coke.
The profitability of the nitrogen fertilizer business' Coffeyville Fertilizer Facility is directly affected by the price and availability of pet coke obtained from the Coffeyville refinery pursuant to a long-term agreement and pet coke purchased from third parties, both of which vary based on market prices. Pet coke is a key raw material used by the Coffeyville Fertilizer Facility in the manufacture of nitrogen fertilizer products. If pet coke costs increase, the nitrogen fertilizer business may not be able to increase its prices to recover these increased costs, because market prices for nitrogen fertilizer products are not correlated with pet coke prices.
The Coffeyville Fertilizer Facility may not be able to maintain an adequate supply of pet coke. In addition, it could experience production delays or cost increases if alternative sources of supply prove to be more expensive or difficult to obtain. The nitrogen fertilizer business' Coffeyville Fertilizer Facility currently purchases 100% of the pet coke that the Coffeyville refinery produces. Accordingly, if the Coffeyville Fertilizer Facility increases production, it will be more dependent on pet coke purchases from third-party suppliers at open market prices. The Coffeyville Fertilizer Facility is party to a pet coke supply agreement with HollyFrontier Corporation. The term of this agreement ends in December 2016. There is no assurance that the Coffeyville Fertilizer Facility would be able to purchase pet coke on comparable terms from third parties or at all.
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The nitrogen fertilizer business relies on third-party providers of transportation services and equipment, which subjects it to risks and uncertainties beyond its control that may have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
The nitrogen fertilizer business relies on railroad and trucking companies to ship finished products to customers of the Coffeyville Fertilizer Facility. The nitrogen fertilizer business also leases railcars from railcar owners in order to ship its finished products. Additionally, although customers of the East Dubuque Fertilizer Facility generally pick up products at the facility, the facility occasionally relies on barge and railroad companies to ship products to customers. These transportation operations, equipment and services are subject to various hazards, including extreme weather conditions, work stoppages, delays, spills, derailments and other accidents and other operating hazards. For example, barge transport can be impacted by dock closures resulting from inclement weather or surface conditions, including fog, rain, snow, wind, ice, strong currents, floods, droughts and other unplanned natural phenomena, lock malfunction, tow conditions and other conditions. Further, the limited number of towing companies and of barges available for ammonia transport may also impact the availability of transportation for our nitrogen fertilizer business' products.
These transportation operations, equipment and services are also subject to environmental, safety and other regulatory oversight. Due to concerns related to terrorism or accidents, local, state and federal governments could implement new regulations affecting the transportation of the nitrogen fertilizer business' finished products. In addition, new regulations could be implemented affecting the equipment used to ship its finished products.
Any delay in the nitrogen fertilizer business' ability to ship its finished products as a result of these transportation companies' failure to operate properly, the implementation of new and more stringent regulatory requirements affecting transportation operations or equipment, or significant increases in the cost of these services or equipment could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
Ammonia can be very volatile and extremely hazardous. Any liability for accidents involving ammonia or other products the nitrogen fertilizer business produces or transports that cause severe damage to property or injury to the environment and human health could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows. In addition, the costs of transporting ammonia could increase significantly in the future.
The nitrogen fertilizer business manufactures, processes, stores, handles, distributes and transports ammonia, which can be very volatile and extremely hazardous. Major accidents or releases involving ammonia could cause severe damage or injury to property, the environment and human health, as well as a possible disruption of supplies and markets. Such an event could result in civil lawsuits, fines, penalties and regulatory enforcement proceedings, all of which could lead to significant liabilities. Any damage to persons, equipment or property or other disruption of the ability of the nitrogen fertilizer business to produce or distribute its products could result in a significant decrease in operating revenues and significant additional cost to replace or repair and insure its assets, which could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows. The Coffeyville Fertilizer Facility and East Dubuque Fertilizer Facility periodically experience minor releases of ammonia related to leaks from its equipment. Similar events may occur in the future and could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
In addition, the nitrogen fertilizer business may incur significant losses or costs relating to the operation of railcars used for the purpose of carrying various products, including ammonia. Due to the dangerous and potentially toxic nature of the cargo, in particular ammonia, on board railcars, a railcar accident may result in fires, explosions and pollution. These circumstances may result in sudden, severe damage or injury to property, the environment and human health. In the event of pollution, the nitrogen fertilizer business may be held responsible even if it is not at fault and it complied with the laws and regulations in effect at the time of the accident. Litigation arising from accidents involving ammonia and other products the nitrogen fertilizer business produces or transports may result in the nitrogen fertilizer business or us being named as a defendant in lawsuits asserting claims for large amounts of damages, which could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
Given the risks inherent in transporting ammonia, the costs of transporting ammonia could increase significantly in the future. Ammonia is most typically transported by pipeline and railcar. A number of initiatives are underway in the railroad and chemical industries that may result in changes to railcar design in order to minimize railway accidents involving hazardous materials. In addition, in the future, laws may more severely restrict or eliminate the ability of the nitrogen fertilizer business to transport ammonia via railcar. If any railcar design changes are implemented, or if accidents involving hazardous freight increase the insurance and other costs of railcars, freight costs of the nitrogen fertilizer business could significantly increase.
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If licensed technology were no longer available, the nitrogen fertilizer business may be adversely affected.
The nitrogen fertilizer business has licensed, and may in the future license, a combination of patent, trade secret and other intellectual property rights of third parties for use in its business. In particular, the gasification process used at the Coffeyville Fertilizer Facility to convert pet coke to high purity hydrogen for subsequent conversion to ammonia is licensed from General Electric. The license, which is fully paid, grants the nitrogen fertilizer business perpetual rights to use the pet coke gasification process on specified terms and conditions and is integral to the operations of the Coffeyville Fertilizer Facility. If this license or any other license agreements on which the nitrogen fertilizer business' operations rely, were to be terminated, licenses to alternative technology may not be available, or may only be available on terms that are not commercially reasonable or acceptable. In addition, any substitution of new technology for currently-licensed technology may require substantial changes to manufacturing processes or equipment and may have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
There can be no assurance that the transportation costs of the nitrogen fertilizer business' competitors will not decline.
Our nitrogen fertilizer business' nitrogen fertilizer plants are located within the U.S. farm belt, where the majority of the end users of its nitrogen fertilizer products grow their crops. Many of our nitrogen fertilizer business' competitors produce fertilizer outside of this region and incur greater costs in transporting their products over longer distances via rail, ships and pipelines. There can be no assurance that competitors' transportation costs will not decline or that additional pipelines will not be built, lowering the price at which competitors can sell their products, which would have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
A portion of our nitrogen fertilizer business is dependent on customers and distributors to transport purchased goods from the East Dubuque Fertilizer Facility because it do not maintain a fleet of trucks or rail cars.
Our nitrogen fertilizer business does not maintain a fleet of trucks and, unlike operations for the Coffeyville Fertilizer Facility and some of our nitrogen fertilizer business' major competitors, does not maintain a fleet of rail cars for its East Dubuque Fertilizer Facility. Historically, prior to the mergers, the customers and distributors of the East Dubuque Fertilizer Facility generally were located close to the facility and have been willing and able to transport purchased goods from the East Dubuque Fertilizer Facility. In most instances, those customers and distributors have purchased products for delivery at the East Dubuque Fertilizer Facility and then arranged and paid for the transport of them to their final destinations by truck. However, in the future, the transportation needs of those customers and distributors as well as their preferences may change, and those customers and distributors may no longer be willing or able to transport purchased goods from the East Dubuque Fertilizer Facility. In the event that our nitrogen fertilizer business' competitors are able to transport their products more efficiently or cost effectively than those customers and distributors, and our nitrogen fertilizer business is unable to reallocate or provide alternative transportation resources that service its other facilities, those customers and distributors may reduce or cease purchases of our nitrogen fertilizer business' products. If this were to occur, our nitrogen fertilizer business could be forced to make a substantial investment in a fleet of trucks and/or rail cars to meet the delivery needs of those customers and distributors, which could be expensive and time consuming. Our nitrogen fertilizer business may not be able to obtain transportation capabilities on a timely basis or at all, and our inability to provide transportation for products could have a material adverse effect on our nitrogen fertilizer business' results of operations, financial condition and cash flows.
Risks Related to Our Entire Business
Instability and volatility in the capital, credit and commodity markets in the global economy could negatively impact our business, financial condition, results of operations and cash flows.
Our business, financial condition and results of operations could be negatively impacted by difficult conditions and volatility in the capital, credit and commodities markets and in the global economy. For example:

• | Although we believe the petroleum business has sufficient liquidity under its ABL credit facility and the intercompany credit facility to operate both the Coffeyville and Wynnewood refineries, and that the nitrogen fertilizer business has sufficient liquidity under its debt facilities and instruments to run the nitrogen fertilizer business, under extreme market conditions there can be no assurance that such funds would be available or sufficient, and in such a case, we may not be able to successfully obtain additional financing on favorable terms, or at all.

• | As disclosed, our nitrogen fertilizer business assumed and incurred debt in connection with the completion of the East Dubuque mergers. Our nitrogen fertilizer business is considering various third-party refinancing options for this debt. There can be no assurance that it will be able to refinance the merger-related debt on favorable terms, or at all.

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• | Market volatility could exert downward pressure on the price of the Refining Partnership's or the Nitrogen Fertilizer Partnership's common units, which may make it more difficult for either or both of them to raise additional capital and thereby limit their ability to grow, which could in turn cause our stock price to drop.

• | The petroleum business' and nitrogen fertilizer business' debt facilities and instruments contain various covenants that must be complied with, and if either business is not in compliance, there can be no assurance that either business would be able to successfully amend the agreement in the future. Further, any such amendment may be expensive. In addition, any new debt facilities and instruments the petroleum business or nitrogen fertilizer business may enter into may require them to agree to additional covenants.

• | Market conditions could result in significant customers experiencing financial difficulties. We are exposed to the credit risk of our customers, and their failure to meet their financial obligations when due because of bankruptcy, lack of liquidity, operational failure or other reasons could result in decreased sales and earnings for us.

The refineries and nitrogen fertilizer facilities face significant risks due to physical damage hazards, environmental liability risk exposure, and unplanned or emergency partial or total plant shutdowns resulting in business interruptions. We could incur potentially significant costs to the extent there are unforeseen events which cause property damage and a material decline in production which are not fully insured. The commercial insurance industry engaged in underwriting energy industry risk is specialized and there is finite capacity; therefore, the industry may limit or curtail coverage, may modify the coverage provided or may substantially increase premiums in the future.
Our operations are subject to significant operating hazards and interruptions. If any of our production plants or individual units within our plants, logistics assets, key pipeline operations serving our plants, or key suppliers sustains a catastrophic loss and operations are shutdown or significantly impaired, it would have a material adverse impact on our operations, financial condition and cash flows. The risk exposures we have at the Coffeyville, Kansas plant complex are greater due to production facilities for refinery and fertilizer production, distribution and storage being in relatively close proximity and potentially exposed to damage from one incident, such as resulting damages from the perils of explosion, windstorm, fire, or flood. In addition, our nitrogen fertilizer business is currently replacing an ammonia synthesis converter at its East Dubuque Fertilizer Facility, which is expected to be completed before the end of summer 2016. However, if the existing ammonia synthesis converter were to fail or suffer damage prior to completion of its replacement, this could cause a shutdown of the East Dubuque Fertilizer Facility. Operations at any of the refineries and the nitrogen fertilizer plants could be curtailed or partially or completely shut down for an extended period of time as the result of unexpected circumstances, which may not be within our control, including:

• | major unplanned maintenance requirements

• | catastrophic events caused by mechanical breakdown, electrical injury, pressure vessel rupture, explosion, contamination, fire, or natural disasters, including, floods, windstorms and other similar events;

• | labor supply shortages, or labor difficulties that result in a work stoppage or slowdown;

• | cessation of all or a portion of the operations at a plant or specific operations dictated by environmental authorities; and

• | an event or incident involving a large clean-up, decontamination, or the imposition of laws and ordinances regulating the cost and schedule of demolition or reconstruction, which can cause significant delays in restoring property to its pre-loss condition.

We have sustained losses over the past ten-year period at our plants, which are illustrative of the types of risks and hazards that exist. These losses or events resulted in costs assumed by us that were not fully insured due to policy retentions or applicable exclusions. These events were as follows:

• | June 2007: Coffeyville refinery and nitrogen fertilizer plant; flood

• | September 2010: secondary urea reactor rupture at the Coffeyville Fertilizer Facility

• | December 2010: Coffeyville refinery; FCCU fire

• | December 2010: Wynnewood refinery; hydrocracker unit fire

• | September 2012: Wynnewood refinery; boiler explosion

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• | July/August 2013: Coffeyville refinery; FCCU outage

• | November 2013: East Dubuque Fertilizer Facility fire

• | July 2014: Coffeyville refinery; isomerization unit fire

Currently, we are insured under casualty, environmental, property and business interruption insurance policies. The property and business interruption coverage has a combined policy limit of $1.25 billion for each occurrence. The property and business interruption policies insure real and personal property, and contain limits and sub-limits which insure all CVR Energy assets. There is potential for a common occurrence to impact both the Coffeyville Fertilizer Facility and Coffeyville refinery, in which case, the insurance limitations would apply to all damages combined. Under this insurance program, there is a $10.0 million property damage retention for all properties ($2.5 million in respect of either nitrogen fertilizer plant). For business interruption losses, the insurance program has a 45-day waiting period retention for any one occurrence. In addition, the insurance policies contain a schedule of sub-limits which apply to certain specific perils or areas of coverage. Sub-limits which may be of importance depending on the nature and extent of a particular insured occurrence are: flood, earthquake, contingent business interruption insuring key suppliers, pipelines and customers, debris removal, decontamination, demolition and increased cost of construction due to law and ordinance, and others. Such conditions, limits and sub-limits could materially impact insurance recoveries and potentially cause us to assume losses which could impair earnings.
There is finite capacity in the commercial insurance industry engaged in underwriting energy industry risk, and there are risks associated with the commercial insurance industry reducing capacity, changing the scope of insurance coverage offered, and substantially increasing premiums due to adverse loss experience or other financial circumstances. Factors that impact insurance cost and availability include, but are not limited to: industry wide losses, natural disasters, specific losses incurred by us and the investment returns earned by the insurance industry. If the supply of commercial insurance is curtailed due to highly adverse financial results, we may not be able to continue our present limits of insurance coverage or obtain sufficient insurance capacity to adequately insure our risks for property damage or business interruption.
We could incur significant cost in cleaning up contamination at our refineries, terminals, fertilizer plant and off-site locations.
Our businesses are subject to the occurrence of accidental spills, discharges or other releases of petroleum or hazardous substances into the environment. Past or future spills related to any of our current or former operations, including the refineries, pipelines, product terminals, fertilizer plants or transportation of products or hazardous substances from those facilities, may give rise to liability (including strict liability, or liability without fault, and potential clean-up responsibility) to governmental entities or private parties under federal, state or local environmental laws, as well as under common law. For example, we could be held strictly liable under CERCLA, and similar state statutes for past or future spills without regard to fault or whether our actions were in compliance with the law at the time of the spills. Pursuant to CERCLA and similar state statutes, we could be held liable for contamination associated with facilities we currently own or operate (whether or not such contamination occurred prior to our acquisition thereof), facilities we formerly owned or operated (if any) and facilities to which we transported or arranged for the transportation of wastes or byproducts containing hazardous substances for treatment, storage, or disposal.
The potential penalties and clean-up costs for past or future releases or spills, liability to third parties for damage to their property or exposure to hazardous substances, or the need to address newly discovered information or conditions that may require response actions could be significant and could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, we may incur liability for alleged personal injury or property damage due to exposure to chemicals or other hazardous substances located at or released from our facilities. We may also face liability for personal injury, property damage, natural resource damage or for clean-up costs for the alleged migration of contamination or other hazardous substances from our facilities to adjacent and other nearby properties.
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Five of our facilities, including the Coffeyville refinery, the now-closed Phillipsburg terminal (which operated as a refinery until 1991), the Wynnewood refinery, the Coffeyville Fertilizer Facility and the East Dubuque Fertilizer Facility, have environmental contamination. We have assumed Farmland's responsibilities under certain administrative orders under the RCRA related to contamination at or that originated from the Coffeyville refinery and the Phillipsburg terminal. The Coffeyville refinery has agreed to assume liability for contamination that migrated from the refinery onto the nitrogen fertilizer plant property while Farmland owned and operated the properties. At the Wynnewood refinery, known areas of contamination have been partially addressed but corrective action has not been completed and some portions of the Wynnewood refinery have not yet been investigated to determine whether corrective action is necessary. Limited subsurface investigation has indicated the presence of certain contamination at the East Dubuque Fertilizer Facility and Coffeyville Fertilizer Facility. If significant unknown liabilities are identified at or migrating from any of our facilities, that liability could have a material adverse effect on our results of operations, financial condition and cash flows and may not be covered by insurance.
We may incur future liability relating to the off-site disposal of hazardous wastes. Companies that dispose of, or arrange for the treatment, transportation or disposal of, hazardous substances at off-site locations may be held jointly and severally liable for the costs of investigation and remediation of contamination at those off-site locations, regardless of fault. We could become involved in litigation or other proceedings involving off-site waste disposal and the damages or costs in any such proceedings could be material.
Climate change laws and regulations could have a material adverse effect on our results of operations, financial condition and cash flows.
The EPA regulates GHG emissions under the Clean Air Act. In October 2009, the EPA finalized a rule requiring certain large emitters of GHGs to inventory and report their GHG emissions to the EPA. In accordance with the rule, we have begun monitoring and reporting our GHG emissions to the EPA. In May 2010, the EPA finalized the "Greenhouse Gas Tailoring Rule," which established new GHG emissions thresholds that determine when stationary sources, such as the refineries and the nitrogen fertilizer plants, must obtain permits under PSD and Title V programs of the federal Clean Air Act. Under the rule, facilities already subject to the PSD and Title V programs that increase their emissions of GHGs by a significant amount are required to undergo PSD review and to evaluate and implement air pollution control technology, known as "best available control technology," to reduce GHG emissions.
In the meantime, in December 2010, the EPA reached a settlement agreement with numerous parties under which it agreed to promulgate NSPS to regulate GHG emissions from petroleum refineries and electric utilities by November 2012. In September 2014, the EPA indicated that the petroleum refining sector risk rule, proposed in June 2014 to address air toxics and volatile organic compounds from refineries, may make it unnecessary for the EPA to regulate GHG emissions from petroleum refineries at this time. The final rule, which was published in the Federal Register on December 1, 2015, places additional emission control requirements and work practice standards on FCCUs, storage tanks, flares, coking units and other equipment at petroleum refineries. Therefore, we expect that the EPA will not be issuing NSPS standards to regulate GHG from the refineries at this time but that it may do so in the future.
During the State of the Union address in each of the last three years, President Obama indicated that the United States should take action to address climate change. At the federal legislative level, this could mean Congressional passage of legislation adopting some form of federal mandatory GHG emission reduction, such as a nationwide cap-and-trade program. It is also possible that Congress may pass alternative climate change bills that do not mandate a nationwide cap-and-trade program and instead focus on promoting renewable energy and energy efficiency.
In addition to potential federal legislation, a number of states have adopted regional greenhouse gas initiatives to reduce carbon dioxide and other GHG emissions. In 2007, a group of Midwest states, including Illinois (where the East Dubuque Fertilizer Facility is located) and Kansas (where the Coffeyville refinery and Coffeyville Fertilizer Facility is located), formed the Midwestern Greenhouse Gas Reduction Accord, which calls for the development of a cap-and-trade system to control GHG emissions and for the inventory of such emissions. However, the individual states that have signed on to the accord must adopt laws or regulations implementing the trading scheme before it becomes effective. To date, neither Illinois nor Kansas has taken meaningful action to implement the accord, and it is unclear whether either state intends to do so in the future.
Alternatively, the EPA may take further steps to regulate GHG emissions. The implementation of EPA regulations and/or the passage of federal or state climate change legislation may result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. Increased costs associated with compliance with any current or future legislation or regulation of GHG emissions, if it occurs, may have a material adverse effect on our results of operations, financial condition and cash flows.
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In addition, climate change legislation and regulations may result in increased costs not only for our business but also users of our refined and fertilizer products, thereby potentially decreasing demand for our products. Decreased demand for our products may have a material adverse effect on our results of operations, financial condition and cash flows.
Both the petroleum and nitrogen fertilizer businesses depend on significant customers and the loss of several significant customers may have a material adverse impact on our results of operations, financial condition and cash flows.
The petroleum and nitrogen fertilizer businesses both have a significant concentration of customers. The five largest customers of the petroleum business represented 39% of its petroleum net sales for the year ended December 31, 2015. In the aggregate, the top five UAN customers of our nitrogen fertilizer business' Coffeyville Fertilizer Facility represented 40% of that facility's fertilizer sales for the year ended December 31, 2015. Additionally, in the aggregate, the top five ammonia customers of our nitrogen fertilizer business' East Dubuque Fertilizer Facility represented 60% of that facility’s ammonia sales, and its top five UAN customers represented 66% of sales for the year ended December 31, 2015. Given the nature of our businesses, and consistent with industry practice, we do not have long-term minimum purchase contracts with our customers. The loss of several of these significant customers, or a significant reduction in purchase volume by several of them, could have a material adverse effect on our results of operations, financial condition and cash flows.
A substantial portion of our workforce is unionized and we are subject to the risk of labor disputes and adverse employee relations, which may disrupt our business and increase our costs.
As of December 31, 2015, approximately 54% of the employees at the Coffeyville refinery and 59% of the employees at the Wynnewood refinery were represented by labor unions under collective bargaining agreements. At Coffeyville, the collective bargaining agreement with five Metal Trades Unions (which covers union represented employees who work directly at the Coffeyville refinery) expires in March 2019. The collective bargaining agreement with the United Steelworkers (which covers the balance of the petroleum business' unionized employees, who work in crude transportation) expires in March 2017, and automatically renews on an annual basis thereafter unless a written notice is received sixty days in advance of the relevant expiration date. The collective bargaining agreement with the International Union of Operating Engineers with respect to the Wynnewood refinery expires in June 2017. As of December 31, 2015, approximately 60% of the employees at the East Dubuque Fertilizer Facility were represented by the International Union of United Automobile, Aerospace, and Agricultural Implement Workers under a collective bargaining agreement that expires in October 2016. We may not be able to renegotiate our collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreements may not prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage could negatively affect our results of operations, financial condition and cash flows.
Our business may suffer if any of our key senior executives or other key employees unexpectedly discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.
Our future success depends to a large extent on the services of our key senior executives and key senior employees. Our business depends on our continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including accounting, business operations, finance and other key back-office and mid-office personnel. Furthermore, our operations require skilled and experienced employees with proficiency in multiple tasks. In particular, the Coffeyville Fertilizer Facility relies on gasification technology that requires special expertise to operate efficiently and effectively. We have a collective bargaining agreement in place covering unionized employees at our East Dubuque Facility which will expire in October 2016. We may not be able to locate or employ such qualified personnel on acceptable terms or at all. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resign unexpectedly or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain any "key man" life insurance for any executives.
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The Refining Partnership's and the Nitrogen Fertilizer Partnership's level of indebtedness may increase, which would reduce their financial flexibility and the distributions they make on their common units.
As of April 26, 2016, the Refining Partnership had (i) $500.0 million aggregate principal amount of 6.5% senior notes due 2022 (the "2022 Notes") outstanding, (ii) availability under the Amended and Restated ABL Credit Facility of $245.3 million, with letters of credit outstanding of approximately $28.0 million and (iii) $31.5 million borrowed under an intercompany credit facility with availability under the intercompany credit facility of $218.5 million. Availability under the Amended and Restated ABL Credit Facility was limited by borrowing base conditions. As of April 26, 2016, the Nitrogen Fertilizer Partnership had $300.0 million of outstanding borrowings under the CRLLC Facility and $320.0 million Second Lien Notes outstanding. In the future, the Refining Partnership and the Nitrogen Fertilizer Partnership may incur additional significant indebtedness in order to make future acquisitions, expand their businesses or develop their properties. Their level of indebtedness could affect their operations in several ways, including the following:

• | a significant portion of their cash flows could be used to service their indebtedness, reducing available cash and their ability to make distributions on their common units (including distributions to us);

• | a high level of debt would increase their vulnerability to general adverse economic and industry conditions;

• | the covenants contained in their debt agreements will limit their ability to borrow additional funds, dispose of assets, pay distributions and make certain investments;

• | a high level of debt may place them at a competitive disadvantage compared to competitors that are less leveraged and who therefore may be able to take advantage of opportunities that their indebtedness would prevent them from pursuing;

• | their debt covenants may also affect flexibility in planning for, and reacting to, changes in the economy and in their industries;

• | a high level of debt may make it more likely that a reduction in the petroleum business' borrowing base following a periodic redetermination could require the Refining Partnership to repay a portion of its then-outstanding bank borrowings under its ABL Credit Facility; and

• | a high level of debt may impair their ability to obtain additional financing in the future for working capital, capital expenditures, debt service requirements, acquisitions, general corporate or other purposes.

In addition, borrowings under their respective debt facilities and instruments and other debt facilities and instruments they may enter into in the future will bear interest at variable rates. If market interest rates increase, such variable-rate debt will create higher debt service requirements, which could adversely affect their ability to make distributions to common unitholders (including us).
In addition to debt service obligations, their operations require substantial investments on a continuing basis. Their ability to make scheduled debt payments, to refinance debt obligations and to fund capital and non-capital expenditures necessary to maintain the condition of operating assets, properties and systems software, as well as to provide capacity for the growth of their businesses, depends on their respective financial and operating performance. General economic conditions and financial, business and other factors affect their operations and their future performance. Many of these factors are beyond their control. They may not be able to generate sufficient cash flows to pay the interest on their debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt.
In addition, the bank borrowing base under the Refining Partnership's Amended and Restated ABL Credit Facility will be subject to periodic redeterminations. It could be forced to repay a portion of its bank borrowings due to redeterminations of its borrowing base. If it is forced to do so, it may not have sufficient funds to make such repayments. If the Refining Partnership does not have sufficient funds and is otherwise unable to negotiate renewals of its borrowings or arrange new financing, it may have to sell significant assets. Any such sale could have a material adverse effect on the Refining Partnership's business and financial condition and, as a result, its ability to make distributions to common unitholders (including us).
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The Second Lien Notes Indenture prohibits East Dubuque from making distributions if any Default (except a Reporting Default) or Event of Default (each as defined in the Indenture) exists. In addition, the Indenture contains covenants limiting East Dubuque’s ability to pay distributions. The covenants apply differently depending on East Dubuque’s Fixed Charge Coverage Ratio (as defined in the Indenture). If the Fixed Charge Coverage Ratio is not less than 1.75 to 1.0, the Nitrogen Fertilizer Partnership will generally be permitted to make restricted payments, including distributions to our common unitholders, without substantive restriction. If the Fixed Charge Coverage ratio is less than 1.75 to 1.0, the Nitrogen Fertilizer Partnership will generally be permitted to make restricted payments, including distributions to common unitholders, up to an aggregate $60.0 million basket plus certain other amounts referred to as “incremental funds” under the Indenture. For the year ended December 31, 2015, the Nitrogen Fertilizer Partnership's Fixed Charge Coverage ratio was 4.81 to 1.00. In addition, any defaults could trigger cross defaults under other or future credit agreements. The Nitrogen Fertilizer Partnership's operating results may not be sufficient to service its indebtedness or to fund its other expenditures and it may not be able to obtain financing to meet these requirements.
The Refining Partnership and the Nitrogen Fertilizer Partnership may not be able to generate sufficient cash to service all of their indebtedness and may be forced to take other actions to satisfy their debt obligations that may not be successful.
The Refining Partnership's and the Nitrogen Fertilizer Partnership's ability to satisfy their debt obligations will depend upon, among other things:

• | their future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control; and

• | the Refining Partnership's ability to borrow under its Amended and Restated ABL Credit Facility and the intercompany credit facility between the Refining Partnership and us, and the Nitrogen Fertilizer Partnership's ability to borrow under its debt facilities and instruments, the availability of which depends on, among other things, compliance with their respective covenants.

We cannot offer any assurance that our businesses will generate sufficient cash flow from operations, or that the Refining Partnership will be able to draw under its Amended and Restated ABL Credit Facility or the intercompany credit facility, or that the Nitrogen Fertilizer Partnership will be able to draw under its debt facilities and instruments, or from other sources of financing, in an amount sufficient to fund their respective liquidity needs.
If cash flows and capital resources are insufficient to service their indebtedness, the Refining Partnership or the Nitrogen Fertilizer Partnership may be forced to reduce or delay capital expenditures, sell assets, seek additional capital or restructure or refinance their indebtedness. These alternative measures may not be successful and may not permit them to meet their scheduled debt service obligations. Their ability to restructure or refinance debt will depend on the condition of the capital markets and their financial condition at such time. Any refinancing of their debt could be at higher interest rates and may require them to comply with more onerous covenants, which could further restrict their business operations, and the terms of existing or future debt agreements may restrict us from adopting some of these alternatives. In addition, in the absence of adequate cash flows or capital resources, they could face substantial liquidity problems and might be required to dispose of material assets or operations, or sell equity, in order to meet their debt service and other obligations. They may not be able to consummate those dispositions for fair market value or at all. The Refining Partnership's Amended and Restated ABL Credit Facility and the indenture governing its 6.5% senior notes and the Nitrogen Fertilizer Partnership's debt facilities and instruments may restrict, or market or business conditions may limit, their ability to avail themselves of some or all of these options. Furthermore, any proceeds that we realize from any such dispositions may not be adequate to meet their debt service obligations when due. None of the Company's stockholders or any of their respective affiliates has any continuing obligation to provide us with debt or equity financing.
The borrowings under the Refining Partnership's Amended and Restated ABL Credit Facility and intercompany credit facility and the Nitrogen Fertilizer Partnership's debt facilities and instruments bear interest at variable rates and other debt we or they incur could likewise be variable-rate debt. If market interest rates increase, variable-rate debt will create higher debt service requirements, which could adversely affect their respective distributions to us. The Refining Partnership or the Nitrogen Fertilizer Partnership may enter into agreements limiting their exposure to higher interest rates, but any such agreements may not offer complete protection from this risk.
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Covenants in our subsidiaries' debt instruments could limit their ability to incur additional indebtedness and engage in certain transactions, which could adversely affect our liquidity and our ability to pursue our business strategies.
The indenture governing the Refining Partnership's 2022 Notes and the Amended and Restated ABL Credit Facility and the Nitrogen Fertilizer Partnership's debt facilities and instruments contain a number of restrictive covenants that will impose significant operating and financial restrictions on them and their subsidiaries and may limit their ability to engage in acts that may be in their long-term best interest, including restrictions on their ability, among other things, to:

• | incur, assume or guarantee additional debt or issue redeemable or preferred units

• | make distributions or prepay, redeem, or repurchase certain debt;

• | enter into agreements that restrict distributions from restricted subsidiaries;

• | incur liens;

• | sell or otherwise dispose of assets, including capital stock of subsidiaries;

• | enter into transactions with affiliates; and

• | merge, consolidate or sell substantially all of their assets.

In particular, the indenture governing the Refining Partnership's 2022 Notes prohibits it from making distributions to unitholders (including us) if any default or event of default (as defined in the indenture) exists. In addition, the indenture governing the Refining Partnership's 2022 Notes contains covenants limiting the Refining Partnership's ability to pay distributions to unitholders. The covenants will apply differently depending on the Refining Partnership'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 will generally be permitted to make restricted payments, including distributions to its unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, the Refining Partnership will generally be permitted to make restricted payments, including distributions to its unitholders, up to an aggregate $100.0 million basket plus certain other amounts referred to as "incremental funds" under the indenture. In addition, the Refining Partnership's Amended and Restated ABL Credit Facility requires it to maintain a minimum excess availability under the facility as a condition to the payment of distributions to its unitholders. The Nitrogen Fertilizer Partnership's debt facilities and instruments requires that, before the Nitrogen Fertilizer Partnership can make distributions to us, it must be in compliance with leverage ratio and interest coverage ratio tests. Any new indebtedness could have similar or greater restrictions.
A breach of the covenants under the foregoing debt instruments could result in an event of default. Upon a default, unless waived, the holders of the Refining Partnership's 2022 Notes and lenders under the Refining Partnership's Amended and Restated ABL Credit Facility and the Nitrogen Fertilizer Partnership's debt facilities and instruments would have all remedies available to a secured lender, and could elect to terminate their commitments, cease making further loans, institute foreclosure proceedings against the Refining Partnership or the Nitrogen Fertilizer Partnership (as applicable) or its respective subsidiaries' assets, and force it and its subsidiaries into bankruptcy or liquidation, subject to intercreditor agreements. In addition, any defaults could trigger cross defaults under other or future credit agreements or indentures. The Refining Partnership's or Nitrogen Fertilizer Partnership's operating results may not be sufficient to service their indebtedness or to fund our other expenditures and they may not be able to obtain financing to meet these requirements. As a result of these restrictions, they may be limited in how they conduct their respective businesses, unable to raise additional debt or equity financing to operate during general economic or business downturns or unable to compete effectively or to take advantage of new business opportunities.
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Item 6. Exhibits

Exhibit Number |  | Exhibit Title
10.1** |  | Guaranty, dated as of February 9, 2016, by and between CVR Partners, LP and Coffeyville Resources, LLC (incorporated by reference to Exhibit 10.1 of the Form 8-K filed on February 12, 2016 (Commission File No. 001-33492)).
10.2** |  | Senior Term Loan Credit Agreement dated as of April 1, 2016 between CVR Partners, LP, as Borrower, and American Entertainment Properties Corp., as Lender (incorporated by reference to Exhibit 10.1 of the Form 8-K filed by CVR Partners, LP on April 7, 2016 (Commission File No. 001-35120)).
10.3** |  | Senior Term Loan Credit Agreement dated as of April 1, 2016 between CVR Partners, LP, as Borrower, and Coffeyville Resources, LLC, as Lender (incorporated by reference to Exhibit 10.2 of the Form 8-K filed by CVR Partners, LP on April 7, 2016 (Commission File No. 001-35120)).
31.1* |  | Rule 13a-14(a)/15(d)-14(a) Certification of Chief Executive Officer and President.
31.2* |  | Rule 13a-14(a)/15(d)-14(a) Certification of Chief Financial Officer and Treasurer.
32.1* |  | Section 1350 Certification of Chief Executive Officer and President.
32.2* |  | Section 1350 Certification of Chief Financial Officer and Treasurer.
101* |  | The following financial information for CVR Energy, Inc.'s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016 formatted in XBRL ("Extensible Business Reporting Language") includes: (i) Condensed Consolidated Balance Sheets (unaudited), (ii) Condensed Consolidated Statements of Operations (unaudited), (iii) Condensed Consolidated Statements of Comprehensive Income (loss) (unaudited), (iv) Condensed Consolidated Statement of Changes in Equity (unaudited), (v) Condensed Consolidated Statements of Cash Flows (unaudited) and (vi) the Notes to Condensed Consolidated Financial Statements (unaudited), tagged in detail.

* | Filed herewith.

** | Previously filed.

PLEASE NOTE: Pursuant to the rules and regulations of the SEC, we may file or incorporate by reference agreements as exhibits to the reports that we file with or furnish to the SEC. The agreements are filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about the Company, its business, operations or the mergers. 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'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, its business, operations or the mergers on the date hereof.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
CVR Energy, Inc.

May 2, 2016 |  | By: | /s/ JOHN J. LIPINSKI |
|  |  | Chief Executive Officer and President |
|  |  | (Principal Executive Officer) |
May 2, 2016 |  | By: | /s/ SUSAN M. BALL |
|  |  | Chief Financial Officer and Treasurer |
|  |  | (Principal Financial and Accounting Officer) |

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